公共服務電力與天然氣 (PEG) 2018 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Eva, and I'm your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's 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 1:00 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, Eva. Good morning, everyone, and thank you for participating in our earnings call. Earlier today, PSEG released earnings statements for the second quarter 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 contains forward-looking statements and estimates are 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 Cregg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions. Ralph?

Thank you, Carlotta, and thank you, 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 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 the 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 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 in meeting our objectives for the full year. On Slides 6 and 7, we summarized 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. Continued investment in PSE&G's 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 electric and 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 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 BLC line, our transmission project portfolio will focus on our 69kV system upgrade program, enhanced storm hardening, as well as life cycle replacement to maintain reliability, increase grid resilience and modernize aging plants.

Turning to our ongoing distribution programs. PSE&G's 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 to work on GSMP II in 2019. This next phase, a 5-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 2, with the BPU. The key components of the $2.5 billion, 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&G's pending distribution base rate case is proceeding according to the schedule, including early-stage settlement meetings with the parties held in July, which will continue until August. Three public hearings across the state were recently completed in early July, and then next week, we will file a scheduled update with financial data for the full past year ended June 30.

We also expect the BPU staff and others to file their initial testimony in the following 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 investigative report conducted in response to the multiple March 2018 nor'easters that left many customers throughout the state without power. PSE&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 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 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&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 Certificates, or ZEC, was also signed into law by Governor Murphy in May. The legislation calls for the BPU within 330 days to establish a process for ZEC, including determining eligibility and certification of need and ultimately selecting nuclear plants to receive ZEC 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 of all 3 of its nuclear -- of its New Jersey's 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 Sewaren 7 combined-cycle units, 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 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, one, 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 two, establish an option that would allow on a resource-specific basis resources receiving out-of-market support to be removed from the PJM capacity market, along with the 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&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 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'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 financials in greater detail, and then 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 last year's second quarter. 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 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 are shown on Slide 15. PSEG'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 Gas System Modernization Programs drove improved margin and second quarter net income comparisons by $0.02 per share. Distribution O&M savings added $0.01 per share over the second quarter of 2017 results.

Changes to the accounting treatment of the nonservice component of pension and OPEB expenses resulted in a favorable $0.02 per share comparison over 2017's second quarter. 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 2017's 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 billion 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 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 reflect the 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 in 2018 over 2017 from both the Energy Strong and GSMP programs is forecast to be approximately $53 million.

Economic indicators from 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 are 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 at PSE&G's net income for 2018 is unchanged at $1 billion to $1,030,000,000.

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 or $0.19 per share for the second quarter 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 second quarter of 2018 were $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. We've also provided you with generation statistics for the quarter and for the first half of the year on Slides 22 and 23.

Power's non-GAAP results for the second quarter of 2018 reflect the impact of lower market prices on recontracting 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 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's Hope Creek refueling outage compared to the year-ago outage of our 57% owned selling unit. An increase in capacity pricings in both PJM and New England starting on June 1 improved quarter-over-quarter results by $0.03 per share, and higher gas send out as a result of cold April temperatures added $0.01 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 second quarter 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 of 46% and produced 3.5 terawatt hours of output during the second quarter of 2018, down by 11% over the year-ago quarter reflecting outages and lower market demand. PJM 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 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 in power prices was 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 to 59 terawatt hours and 2020 output of 62 to 64 terawatts 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 updated Power's hedge position is provided in Slide 25. For the remainder of 2018, Power has hedged 90% to 95% of total forecasted production of 28 to 30 terawatts hours at an average price of $38 per megawatt hour. For 2019, Power has hedged 65% to 70% of forecasted production of 57 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 loss, including imposing a temporary surtax 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 at Power and to a lesser extent on Enterprise and other as each begins to accrue the surcharge starting July 1, 2018. Our forecasted Power's full year 2018 non-GAAP operating earnings and non-GAAP adjusted EBITDA remains unchanged at $485 million to $560 million and $1.75 billion to $1.80 million, respectively.

Now let me turn to PSEG Enterprise and other, which reported a net loss of $3 million or $0.01 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 pretax charge of $20 million related to the ongoing liquidity challenges facing NRG REMA compared to a similar pretax 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 PSEG Enterprise and other non-GAAP operating earnings remains unchanged at $35 million.

Now I'd 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 5-year $12 billion to $15.5 billion 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 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 adds the full investment positions contained in our pending $2.5 billion Energy Strong II program and our anticipated $2.9 billion Clean Energy Future program that, when combined, total approximately $3.5 billion through 2022. The time frames 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 PSEG's 2018 to 2022 capital spending window.

PSEG's financial position remains strong. Power's free cash flow is expected to improve in 2018 with a decline in capital spending following the completion of construction at Keys and Sewaren. 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 million 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 2.7x at the midpoint of Power's 2018 non-GAAP adjusted EBITDA forecast and well within Power's solid investment grade credit metrics.

I would note that in May, Standard & Poor's affirmed the credit ratings of PSEG, PSE&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 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 time frame, and we stand firm in our commitment to providing our shareholders 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 Eva, we are now ready to take some questions.

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

This is actually Claire, subbing in for Julien here. So I appreciate the update on the rate case settlement negotiation. Just if you could provide a little more color on maybe progress on some of the critical issues and just any more color you can give there.

Gee, Claire, it's 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 strong cost and recovery of that. But we are under a confidentiality agreement with the other parties to not discuss the negotiation at this point. I think we just stick what we said in the script that we're engaged in a 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 9 months after filing date of January. So as much as I'd like to share with you, we do have this confidentiality limitation.

Yes, from a schedule standpoint, we'll provide the latest update as we step through time, so the (inaudible) will be submitted on the 8th of August and things are moving according to schedule.

Just a reminder that our ask is net of the tax give back 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&G will get fully compensated for its transmission investment 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 Corridor and its impact on the New York ISO seams. 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 the 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 just possibly one more color on some of the discussions at PJM to lower transmission cost? 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 PJM has presented. The stuff that comes out of the ARTEP regional transmission expansion program, and that is generated by PJM. And then there are additional non-ARTEP 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 ARTEP projects are bigger. So if you have one $750 million project like the Susquehanna-Roseland, you can understand why you want to treat that different than 10 $75 million projects like a 69kV upgrade. But recognizing that customers and load-serving entities and suppliers and all of the stakeholders at PJM have a right to 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 we're diminishing returns, where literally the 8-figure project is -- or the 7-figure project is getting the same amount of upfront time and disclosure that the 9- and 10-figure projects demand, because that would just paralyze the whole process.

And your next question comes from the line of Praful Mehta from Citigroup.

So, Ralph, wanted to get your view on this whole 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 first, we wanted 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 to the state to kind of get that refund for the capacity that they lost? Just some color, that would be really appreciated.

Sure, Praful. So I don't think I'm very 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 clawback prior RPM options, 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 deterministically capacity prices. So for 3 years, I think we're -- 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 one, they said that they want to allow states flexibility in choosing their own resources. Well, when you get 60 out of 80 votes in this assembly and 28 out of 40 votes in the Senate and a governor who signed 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 at our nuclear plants. Now the devil's in the detail 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 RECs, it's regulated generation in the market today that these out-of-market payments were 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 all 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, 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 suppression for the things that aren't receiving out-of-market payments, check that box for our fossil units; and number two, allow states to support those resources that 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 it, Praful. But now, again, for the third time, we are actively engaged in the details of how we want to choose 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 will also have an effect. But that would serve if it was megawatt for megawatt load in 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 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 168,000-megawatt 13-state region so.

Yes. No, that's -- it's super helpful color. I mean, almost the depth of your answer also suggests the wood to chop here as you said. So do you really think that it can get done in the January timeframe? Or do you think it's kind of going to take more time?

Instinctively, I'd say probably we'll take more time, but I don't want to second-guess the FERC and their 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.

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, Ralph, you 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 been held off 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 30 has 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 and 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 other 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 to (inaudible) the detail.

What you're saying seems to imply it might evolve a little bit, but is this what you showed us? Is that a fair...

Yes, the program elements but I wouldn't -- I mean, we are determined to go in with this dollar amount. If anything, you have this interesting 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, was so do you have an early sort of feel of what a full deployment would cost? And yes, it sounds like you're saying that would be incremental rather than displacing something else, but I don't want to put words in your...

Yes, 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. I'd rather not have them hear it for the first time in one of your reports, even though they're well-written and wonderful report, Jonathan.

Okay. But to put to the point of being incremental or instead of, what's the...

I would think it would be more incremental. We don't want to take away from the others.

From a dollar amount standpoint as well, Jonathan, if you look at the spend that's been identified than that we had 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. 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 the -- why the changes in '19 and '20.

Yes. 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. And as we step through 2019 and 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, so we're just providing that from a standpoint of our forecasted output.

And your next question comes from the line of Greg Gordon from Evercore.

Not to layer uncertainty upon uncertainty, but in addition to the 206 related to capacity market, Power markets are -- as was sort of articulated in the last answer to the last question, pretty low and moribund pricing-wise, but we've got this past our pricing decision pending. There also seems to be a continued desire around the part of PJM leadership to address the overall pricing model from an energy perspective. So it seemed 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. I think what we're hearing is that fast start can and should be implemented beginning of '19 and then the broader inflexible unit aspects of price formation PJM has committed to filing something at the end of this year. So I would agree with you, Greg, my sense, and this is not the -- 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 is allowed to set price, that's 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 that's what PJM was saying, and yet we're not there yet. So there's going to be some degree of discounting going on in the forward price curve, but we don't out just 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 accounts for, I think, some of the skepticism that might not have fully priced to the sense of the forward curve.

And your next question comes from the line of Steven Fleishman from Wolfe Research.

So just on the -- just to kind of get a better understand the scenario from the FERC structure. I get what you say that you kind of have a protection for nonsubsidized 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 it's...

No.

No? It could 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 requirement that, for example, it's got legislation right now that's been signed by the governor saying he 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 mechanisms that we've already start talking about, 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, 1,400 megawatts of solar, 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 million cap on the ZECs 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 and...

Okay. And then I'm just curious if – in trying to figure 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 the 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 worship 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 for when we'll get an update on that?

So if we file 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-dated. That could spill into the end of this year.

And your next question comes from the line of Paul Patterson from Glenn Rock.

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 FERC has said, and it's second step of the process, was that, okay, states, if you want to assure your own resource inadequacy 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 with Praful and we were talking about was that second half of that sense is, well, 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've got a big problem. So maybe resource adequacy then says you've got to have -- you're only taking -- your reserve margin needs to be 35%. I'm making stuff up here. So the state, 1 set 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.

Yes. 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 original 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 energy REMA, how much more do we have left there? What's the net investment after all this?

For Keystone Conemaugh there's an aggregate total of $20 million 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 net it. That would be the other element that I would point out to.

(Operator Instructions) Mr. Izzo, Mr. Cregg, 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 the Power portfolio and the construction of the new units going into service and the ongoing growth at the utility with no shortage of opportunities continue surface, the strength of the balance sheet, 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.