公共服務電力與天然氣 (PEG) 2017 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Jamie, and I am your event operator today. I would like to welcome everyone to today's conference. Public Service Enterprise Group Second Quarter 2017 Earnings Conference Call and Webcast. (Operator Instructions) As a reminder, this conference is being recorded, Friday, July 28, 2017, and will be available for telephone replay beginning at 1:00 p.m. Eastern Time today until 11:30 p.m. Eastern on Friday, August 4, 2017.

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 call -- conference over to Kathleen Lally. Please go ahead.

Thank you, Jamie. Good morning. Thank you, everyone, for participating in our earnings call this morning. As mentioned, PSEG released earnings statements for the second quarter 2017 earlier today. And you will find the release and attachments on our website, www.pseg.com, under the Investors section.

We also posted a series of slides that detail operating results by company for the quarter. Our 10-Q for the period ended June 30, 2017, is expected to be filed shortly.

As you know, the earnings release and other matters that we will discuss in today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. And although we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so even if our estimate changes, unless required to do so.

We also provide commentary with regard to the difference between non-GAAP operating earnings and non-GAAP adjusted EBITDA and net income reported in accordance with Generally Accepted Accounting Principles in the United States.

We won't go through the full disclaimer statements or the comments we have on the difference between non-GAAP financial measures, but I do ask that you read those comments contained in our slides and on our website.

PSEG believes that the non-GAAP financial measures providing information on operating earnings and adjusted EBITDA offers a consistent and comparable measure of performance to help shareholders understand operating and financial results.

Now I'd like to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. And 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. Thank you.

Thank you, Kathleen, and thank you, everyone, for joining us today. PSEG delivered solid results for the second quarter, and has had a good first half, putting us on a solid path to meeting our full year objectives.

Earlier this morning, we reported net income for the quarter of $0.22 per share. PSEG's non-GAAP operating earnings for the second quarter of 2017 increased 9% against the prior year comparable quarter, reflecting strong performance at both PSE&G and PSEG Power. The results for the quarter bring non-GAAP operating earnings for the first half of 2017 to $1.54 per share, which is a 4% increase over non-GAAP operating earnings of $1.48 per share earned in 2016's first half.

Slides 5 and 6 contain the detail on the results for the quarter and the first half. At PSE&G, earnings increased $0.06 per share from the prior year comparable quarter. Continued infrastructure investment was the primary driver of this growth. PSE&G's focus remains on providing customers with what they want in terms of enhanced reliability, resiliency and green energy, while keeping bills affordable.

PSE&G continues to make progress in its 2017 plan to invest approximately $3.4 billion in transmission and distribution upgrades. The investment will allow PSE&G to meet its commitment to provide customers with high quality service.

Yesterday, PSE&G filed for continuation and acceleration of its Gas System Modernization Program. PSE&G is proposing to invest $540 million per year over a 5-year period beginning in 2019. The program would allow PSE&G to shorten to within 20 years the replacement of its aging cast-iron and unprotected steel mains and associated services. The filing is consistent with the draft regulations that the BPU issued in June regarding infrastructure investment programs. We applaud the BPU's efforts in this regards.

While PSE&G has received approval from the BPU for several multi-year invest programs in recent years, they have generally been 2 to 3 years in duration, limiting the opportunity to plan as efficiently as we could with longer term programs. The BPUs infrastructure investment proposal would address this, encouraging needed infrastructure investment through timely recovery of investments and providing increased predictability by expansion of the investment time horizon to 5 years. The longer timeframe provides for better planning with contractors, vendors, municipalities where the work takes place, our own workforce and, of course, helps to promote economic growth in the state of New Jersey.

PSE&G has made progress advancing its investment initiatives. Earlier this week, PSE&G reached an agreement in principle with the BPU staff and the REIT counsel, which provides for $69 million extension of its investment in energy efficiency equipment for hospitals, multi-family housing and other sectors. The agreement represents more than 90% of PSE&G's original request and will bring PSE&G's cumulative investment in energy efficiency to approximately $400 million. We believe an investment in energy efficiency programs is a cost-effective tool to lower air emissions and control the growth and customer bills.

The work PSE&G has done in promoting solar energy in New Jersey was recently acknowledged by the Smart Electric Power Alliance, also referred to as SEPA, which named PSE&G the 2017 Investor Owned Utility of the Year. The award honors PSE&G for its ongoing commitment to increasing the amount of solar power in New Jersey and specifically for its work to build solar farms on landfills and brownfield sites in the state.

PSE&G, as you know, will be filing a distribution base rate case with the New Jersey BPU no later than November 1 of this year. The timing of this filing was agreed to in the settlement of the Energy Strong program. The case will provide PSE&G with the opportunity to reset assumptions on sales and O&M growth as well as provide the opportunity to recover investments not recognized in various clauses since our last base rate proceeding, which was settled in 2010.

It will also give us the opportunity to recover prior approved storm costs. PSE&G, as part of the filing, will request approval for a decoupling of distribution revenue from sales volume to support larger scale energy efficiency investments. We believe strongly that this latter action will incentivize continued investment in energy efficiency and help lower participating customer bills.

We expect PSE&G's initiatives to provide value for the customer and our shareholders. For the 5-year period ending 2021, PSE&G's successful execution of its investment program is expected to result in compound annual growth and rate base of 7% to 9%.

At PSEG Power, non-GAAP operating earnings increased by 6% to $0.19 per share as ongoing programs to reduce operating expenses supported earnings. PSEG Power retired its Hudson and Mercer coal-fired generating stations on June 1 and made good progress on construction activities related to its 3 new natural gas combined cycle generation stations.

The new stations will add 1,800 megawatts of efficient capacity over 2018 and '19, and represents a reconfiguration of Power's merchant generation fleet that will improve its competitiveness in the market. We've seen some improvement in energy pricing in the PS zone relative to the PJM West Hub, a higher gas price with the opening up of more outlets for gas supply and the completion of work on transmission lines has relieved congestion and improved energy prices in the East.

Power's primary market at PJM has also experienced an improvement in capacity prices. In May of this year, PJM announced the results of the RPM capacity auction for the 2020 and 2021 delivery year. Power cleared approximately 7,800 megawatts of its generating capacity at an average price of $174 per megawatt day. The average price received by Power was higher than prior auctions and continues to represent a premium to the price for capacity in the RTO.

However, the number of megawatts, which cleared the auction declined from the amount we have cleared in the past. Our results reflect the higher price resulting from the increased risk in the market associated with PJM's move to 100% capacity performance requirements and the absence of available capacity to meet emergency situations following the retirement of Hudson and Mercer. The results of the latest auction provides stability in Power's capacity revenue through calendar year 2020.

The energy markets, on the other hand, continue to be impacted by flat demand and excess capacity, which has hurt the return on our base load resources as the average price in energy hedges declined. Power continues to advocate for policies at the federal level that would correct flaws in the wholesale market design that suppressed prices and provide adequate recognition of the value that fuel diversity brings to a competitive wholesale market.

We believe that state action is also critical and can be done in a way that both maintains the integrity of the wholesale market and serves as a bridge until a regional or federal solution is in place. A strong legal foundation for state action appears to have been set with recent district court rulings upholding the legislative and regulatory actions in Illinois and New York.

We continue to educate stakeholders at the state level about the need to preserve the diversity and resiliency of our electric generating mix. Successful execution of PSEG's key policy and regulatory initiatives would ensure the company's ability to provide customers with the service, reliability and resiliency they want and need at an affordable price in today's technologically advanced society.

Our non-GAAP operating earnings for the first half of 2017 are solidly within our outlook for the full year. So we are maintaining our guidance for 2017's non-GAAP operating earnings of $2.80 to $3 per share. We expect the growth prospects of 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, while we maintain a strong balance sheet and credit metrics.

With that, I'll turn the call over to Dan who will discuss our financials in greater detail.

Thank you, Ralph, and thanks, everybody, for joining us today. As Ralph said, PSEG reported non-GAAP operating earnings for the second quarter of 2017 of $0.62 per share versus non-GAAP operating earnings of $0.57 per share in last year's second quarter. And a reconciliation of non-GAAP operating earnings to net income for the quarter can be found on Slide 4.

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, which provides you the changes in non-GAAP operating earnings on a year-to-date basis.

I'll now review each company in more detail starting with PSE&G. PSE&G reported net income for the second quarter of 2017 of $0.41 per share compared with $0.35 per share for the second quarter of 2016. And results for the quarter are shown on Slide 15.

PSE&G's operating results for the second quarter reflect the benefits of revenue growth associated with its expanded investment and the continued control of growth and operating expenses. Growth in PSE&G's investment in transmission improved second quarter net income comparisons by $0.04 per share. And revenue recovery from investments made to enhance system resiliency under the energy's strong and Gas System Modernization Program's, GSMP, drove improved margin and second quarter net income comparisons by $0.02 per share. And an increase in depreciation expenses offset by a reduction in O&M and other expenses.

Recall that transmission revenues are adjusted each year to reflect an update of the company's investment program. PSE&G's investment in transmission is expected to grow to represent approximately $7.6 billion of rate base at the end of 2017, which will be 45% of the company's year-end consolidated rate base.

Under Energy Strong, electric rates are adjusted 2 times during the year in March and September and gas rates are adjusted each year in September. Under the Gas System Modernization Program, gas rates are adjusted each year in January to reflect the investment made during the prior year. The combined annual revenue increase in 2017 from these programs is forecasted to be approximately $56 million.

Economic conditions in New Jersey continue to show steady growth, particularly in the level of employment. On a trailing 12-month basis, weather-normalized electric sales were flat year-over-year, due to the impact of increased efficiency in solar net metering, which offset customer growth. Gas sales on the same basis were slightly higher with growth in demand from the commercial sector.

PSE&G has had significant advances on a number of fronts. As mentioned by Ralph, the company filed earlier this week for an extension of the Gas System Modernization Program. This program, which calls for an average investment of $540 million per year, would accelerate the pace of replacement of aging cast-iron and unprotected steel mains to 250 miles per year from the current GSMP pace of 170 miles per year.

In addition, PSE&G reached an agreement in principle with BPU staff and rate council, which provides for a $69 million increase in the company's investment in energy efficiency equipment for hospitals and multi-family housing as well as for new residential energy efficiency offerings for smart thermostats and data analytics. The agreement calls for a 9.75% allowed ROE and is subject to review by the BPU in the near future.

PSE&G continues to advance its 5-year $12.3 billion program in transmission and distribution and continues to identify incremental investments. We expect to see growth in rate base through 2021 of 7% to 9% per year. Assumed within that $12.3 billion capital program is the extension of our existing GSMP program at the current rate of $300 million per year. Our filing yesterday reflecting investment of $540 million per year would increase our forecast capital program by investments made in excess of that $300 million per year amount. These important service quality-related initiatives builds confidence in PSE&G's ability to expand its growth through its 5-year capital cycle.

Based on results for the first half of the year, the forecast of PSE&G's net income for 2017 remains unchanged at $945 million to $985 million.

Now let's turn to power. PSEG Power reported a net loss for the quarter of $97 million or $0.19 per share compared with a net loss of $11 million or $0.02 per share for the year ago quarter. Non-GAAP operating earnings was $0.19 per share and non-GAAP adjusted EBITDA was $261 million in the quarter compared with non-GAAP operating earnings of $0.18 per share and non-GAAP adjusted EBITDA of $250 million for the second quarter of 2016.

Non-GAAP adjusted EBITDA excludes the same items as our nonstop operating earnings measure as well as income tax expense, interest expense and depreciation and amortization. The earnings release on Slide 20 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 more details on generation for the quarter and the first half of the year on Slides 21 and 22. Power's non-GAAP operating results for the second quarter of 2017 reflect the benefit of ongoing programs to reduce operating expenses and an increase in output, which offset a decline in average energy hedge prices.

PSEG Power's net loss for the second quarter reflects the impact of incremental depreciation and other expenses of $387 million pretax associated with the June 1, 2017, retirement of the Hudson and Mercer coal-fired generating stations. This incremental depreciation expense associated with the retirement of these units is now complete and will not continue into the second half of the year.

An increase in capacity prices in both PJM and New England on June 1 for the 2017-2018 energy year improved quarter-over-quarter non-GAAP operating earnings by $0.01 per share. Growth in output improved second quarter non-GAAP operating earnings comparisons by $0.01 per share.

A reduction in O&M associated with fewer nuclear and fossil unit outage-related days in the quarter, and the June 1 retirement of the Hudson and Mercer coal stations improved non-GAAP operating earnings by $0.02 per share. A decline in the average price received on energy hedges reduced non-GAAP operating earnings by $0.03 per share. And an increase in depreciation expense was offset by a decline in interest expense.

Power's O&M for the remainder of 2017 is expected to compare favorably against 2016, and this reflects the absence of a refueling outage at Power's 100% owned Hope Creek Nuclear Station, a decline in major maintenance expense of the fossil stations and, of course, the retirement of Hudson and Mercer coal-fired generating stations.

Now let's turn to Power's operations. Output of Power's generating facilities increased 4% in the second quarter. The improvement reflects a 30-day reduction in nuclear refueling outage days in 2017 relative to the year-ago quarter, which improved the nuclear fleet's capacity factor to 89.6% from 82.7%.

And you may recall Salem 1 underwent an extended refueling outage in 2016 to inspect and replace that unit's baffle bolts. The outage lasted through the month of July, and the work requiring -- the work required during Salem 2's recent refueling outage to inspect and replace baffle bolts was less extensive and has been completed. And no further work associated with this issue at Salem is currently contemplated.

An increase in the price of gas improved the economic competitiveness of our base load coal fleet during the quarter. And during the quarter, that fleet saw an improvement in its capacity factor to 32.6% from 18.4%. Conversely, the gas-fired CCGT fleet operated at an average capacity factor of 55.3% versus 62.3% last year.

As we indicated earlier this year, we experienced a more modest decline in our hedged energy pricing in the second quarter than in the first quarter, as weather-related risk has not been priced into the market to the same extent as was experienced in prior years.

Gas prices have improved year-over-year, but we have not seen a similar improvement in Power prices, which has led to a compression in Western hub spark spreads. In the PS zone, spark spreads have held up relative to what we experienced a year ago with an improvement in basis.

Power continues to forecast output of 49 to 50 terawatt hours for 2017, and approximately 90% of production for the remainder of the year is hedged at an average price of $46 per megawatt hour. Power has hedged approximately 65% to 70% of 2018's forecast production of 52 to 54 terawatt hours at an average price of $41 per megawatt hour.

And for 2019, Power has hedged 25% to 30% of forecast production of 58 to 60 terawatt hours at an average price of $41 per megawatt hour. Power continues to assume deliveries in 2017 under the basic generation service, or BGS contract, will represent approximately 11 terawatt hours of hedged volume.

The forecast increase in output in both '18 and '19 reflects the commercial start-up in mid-'18 of 1,300 megawatts of gas-fired combined cycle capacity at the Keys Energy Center in Maryland and the Sewaren facility in New Jersey and the mid-2019 commercial start-up of the 485-megawatt gas-fired combined cycle generation unit in Bridgeport Harbor, Connecticut.

Our forecast of Power's full year 2017 non-GAAP operating earnings remains unchanged at $435 million to $510 million, and the forecast represents non-GAAP adjusted EBITDA of $1,080,000,000 to $1,210,000,000.

Now turning to PSEG Enterprise and other. We reported a net loss of $2 million for the second quarter of 2017 versus net income of $19 million or $0.04 per share for the second quarter of 2016. Non-GAAP operating earnings for the second quarter of 2017 were $11 million or $0.02 per share compared to $19 million or $0.04 per share for the second quarter of 2016. The net loss for the second quarter includes a pretax charge of $22 million related to ongoing liquidity challenges facing energy arena and deterioration of market conditions affecting the residual value of the leverage leased portfolio. The decrease in non-GAAP operating earnings quarter-over-quarter reflects the absence of certain tax-related items at PSEG Energy Holdings and higher parent interest expense.

Lastly, discussing our financial position, our financial position remains strong. Moody's recent upgrade of PSEG's senior unsecured rating to Baa1 stable from Baa2 positive a test to the strength of the balance sheet and the changing composition of earnings with PSE&G forecast represent 2/3 of 2017's non-GAAP operating earnings.

PSEG closed the quarter ended June 30, 2017, with $430 million of cash on its balance sheet with debt representing 49% of consolidated capital. PSEG Power's debt at the end of the quarter represented 31% of its capitalization providing a debt-to-EBITDA ratio of 2.1x at the midpoint of 2017's powered non-GAAP adjusted EBITDA forecasts.

As Ralph mentioned, we are maintaining our forecast of operating earnings for the full year at $2.80 to $3 per share.

And Jamie, we are now ready to take your questions.

(Operator Instructions) First question is with Neel Mitra with Tudor, Pickering.

I was wondering if you could comment on the dispute against the Transmission ROE, I believe the 11.68% base level. And then basically, how was it redacted, how that process went? And if you anticipate any complaints in the future, or how we should kind of interpret that?

Neel, I mean, 3 New Jersey towns did file and then they withdrew a couple of weeks later. We're not at liberty to disclose anything other than that, as you know. Large customers always can challenge a lot of ROEs, but at this point, those are the only attempts we've had.

The next question is from Jonathan Arnold with Deutsche Bank.

The -- Ralph, I missed a little bit of this. I think you made some generic comments about support for nuclear-friendly market reforms and legislation. I'm curious whether you could just give us an insight into what you believe the prospects might be for moving something like that in New Jersey this fall. And also, what you're -- from your perspective, what is the most effective format for something like that to take?

Yes, I don't want to predict any kind of timing stuff, Jonathan. But I did comment that the court decisions, when they came out of Illinois and New York, the federal districts relative -- relevant to the states. Yes, I've solidified the fact that the states have the ability to act in these matters, and that's good news. We have been maintaining, this is both a local and national issue, and it's good to see that it's getting national attention. But the problem, according to the forward price curve, is at New Jersey's doorstep, there's no denying it. So we've continued an education campaign, and I'm pleased that actually in those conversations, we've received just about, not exactly, but just about universal support for the continued operation of those plants. But we're going to work at all levels, primarily at the state, but also at PJM and at FERC to do what we can to just make sure those plants are continuing their operation, that they don't prematurely retire, and they do so with economics that are satisfactory to customers and shareholders. So we don't have specific solutions. We just -- really, right now, are in a kind of education mode. And we're pleased with the kind of feedback we're getting.

The next question is from the line of Praful Mehta with Citigroup.

So I wanted to follow up little bit on the strategic direction, I guess. And we've talked about this before, but with ZEC and design discussion happening in New Jersey, obviously, something around the nuclear support, how do you think about strategic direction affect power. And also given what IPPs are going through in terms of number of them either merging or going private, how do you see the long-term vision of this business? Do you still see separation as a possibility? Or now you're thinking of it more as an integrated platform?

So , Praful, if you -- I think the best way to look at strategic direction is to look at how we're allocating our investment dollars. And if you look back over the past 10 years, you probably see a 75%, 25% split utility PSEG Power. And if you look ahead 5 years, that's ratio has changed a little bit, now it's 82% PSE&G at the Utility and 18% at Power. So the strength of the company and its growth is clearly at PSE&G, but we are not making VCRs or buggy whips, right? We're producing electricity and power, and people still need that. So we're constantly optimizing that portfolio. We retired 4,000 megawatts of uncompetitive assets. We're now building 1,800 megawatts of competitive assets, and we're warning people about 3,500 megawatts that are at some parallel that actually is a greater parallel to the customer and policymakers than it is to our shareholders, that being nuclear. If there is a strategic opportunity to do something different, we'll entertain it. But right now, we are quite happy with the cash being generated by Power and the Utility's ability to deploy it very, very productively, which gives us an extremely healthy balance sheet, one that the rating agencies are looking more favorably upon, and robust growth of the utility without any need for additional equity and solid support for a dividend that continuously grow at 4% a year. So we're in a good place.

The next question is from Paul Patterson with Glenrock Associates.

On the new rules at the BPU that they've filed with the New Jersey -- or they're going to file with the New Jersey register, I was wondering if you could just -- is there any flavor you can give us in terms of what that means quantitatively in terms of earnings or where your CapEx prospects or what have you?

So Paul, I don't think of it necessarily as an increase or a decrease in earnings prospects. I think of it as greater predictability of those earnings. So, for example, we talk about GSMP and the extension we're filing, that we filed yesterday. And the reality is that our filing followed those proposed new rules, so that makes life a little bit simpler in terms of discussion. But think about this for a second. GSMP 2 is a bit of a misnomer. We could just have easily have called it GSMP 4 or 5, because it's prior incarnation, it was called Capital Infrastructure Program and then it was called Capital Infrastructure Program 2. And then it was the gas improvement within Energy Strong. And so we've had great dialogue with the board staff, and consistent recognition of the need to replace this aging infrastructure. But it's been going on in 18-month increments and more recently, in 36-month increments. And from an operational point-of-view, it just makes life difficult. And I think the board realized it. Okay, we've got 100 years. And we got down to 30 years and then hopefully, get down to 20 years of this pipe that needs to be replaced. Why are we doing this in such small increments? So as you can see, we filed for a 9.75% on the GSMP program. It's similar to what -- it's exactly the same as what we've been getting in other programs. The mechanism is what's anticipating in the rule, in the proposed rule. So it's not a question of how much or how much more, how much less the earnings will be, but just greater predictability, greater clarity, longer duration.

The next question is from Michael Lapides with Goldman Sachs.

An easy one. Just trying to think about PSE&G's capital spending over the next 3 to 4 years, 3 to 5 years, and a little bit what's changed since your March Analyst Conference. If I go back and look at, like, that Slide 13, I think, or one of the other CapEx slides, how should we think about how different the CapEx level is today going forward, for the next few years versus what you discussed 3 or 4, or 4 or 5 months ago?

Michael, this is Dan. I don't think about it as being very dramatically different. I think that one of the things that we sought to address and as we talked about at 7% to 9% rate base growth and identifying things that weren't necessarily in the base plan. But we're on our radar screen to layer into the back end of the plan because of the nature of how we put forth our capital plan based upon what we know. I think what you've seen is very, very consistent with that. As we moved from a 7% rate base CAGR over 5 years and targeted a 9% rate base CAGR, one of the things we identified to be able to fill that gap was energy efficiency. And we talked today about $69 million being approved for energy efficiency. Another is GSMP and embedded within our base plan was $300 million a year on GSMP, which is the consistent run rate, but we thought that we could expand that. And we talked about maybe another $100 million or more that we could put into that plan to be able to get us from 7% to 9%. And what you saw us file is very consistent with that. So I don't think that I would describe the capital plan as being very different. I think I would describe it as executing on the upsides that we saw within it and being able to achieve the higher end of that range. And we will continue to look for opportunities to do exactly that same thing.

Okay. But if I go back and look at the Analyst Day deck, and I think it was actually Slide 15, that's maybe the most appropriate one or so. It kind of showed a role-off or roll down of CapEx from close to $3.5 billion at E&G this year, going to $2.5 billion or even less in '18 and beyond. Do you still think you're at that $2.5 billion level in '18 and beyond? Or do you think the run rate might look a little bit more something closer to the 2017 level?

Well, I think I would say that directionally, it's not inconsistent with how we have talked about it in the past. And as we step forward into these years, we have been able to find appropriate investments for -- that the system needs to have done. And as we stepped through time, that number has tended to grow. So 2017 is a high year for us with respect to capital. But I do think what we represented then through some historical data and how the years have progressed through time, and what we anticipated on a go-forward basis was an opportunity to grow that capital program. And I think that's what we conveyed then. And I think we still believe that now.

(Operator Instructions) The next question is from Steven Fleishman with Wolfe Research.

The -- you talked about the different avenues that you're watching with -- for your nuclear generation state, but also PJM and FERC. Could you focus a little bit on the PJM, FERC and DOE side and just kind of how much progress do you think is occurring there? And really, can they do enough, I guess?

So I think if you look at DOE first, it's just good that from a policy point-of-view, DOE recognizes a challenge with base load generation and fuel diversity. As you know, Steve, they don't have day-to-day regulatory authority, they have some emergency powers and various things of that sort. But most of the attention, I think, needs at the -- at our -- from our point-of-view to be at FERC and PJM. And there, we've been talking about price formation for quite some time. The recent PJM proposals on how to deal with inflexible units is potentially quite helpful to the market, overall, in terms of the missing money issue associated with the fixed cost component of energy that's -- that is not recovered as clearly the market design is to drive towards short-run variable cost. I think that could benefit all Power generators from a point-of-view of more accurate pricing. This bifurcated capacity marker or different approaches to the capacity market could also be helpful in terms of mitigated units. At the end of the day, there are some policy objectives that states and others have sought to pursue typically environmental, but it may be resiliency policy objectives that unless they're explicitly targeted by FERC and PJM, states will continue to reserve that right to go forward. So I guess what I'm saying is that, we're encouraged by the reception at DOE and the administration at the importance of these reliability, national security, fuel diversity issues. It's going to be up to FERC to translate that into a price. And there was a recognition that price formation has not delivered on the workshops of 2 years ago all the benefits it can. What is missing in everything I just described at the national levels of price on carbonate. We don't anticipate that being made explicit in the near term, and that's probably going to be the domain that states will continue to probably add incremental value in terms of the environmental benefit. So to me at least, Steve, as I've said, we're not shy from retiring plants. Hopefully, we've proved that. But in the case of nuclear, that's a state, local and national disaster in the making. And we're just working double time everywhere we can to point that out to people that this is something that they don't want to let happen and then say 5 years or 10 years from now, "Oops, what were we thinking."

(Operator Instructions) Your next question is from Jonathan Arnold with Deutsche Bank.

At the Analyst Day, in addition to the incremental items you've added, you had the expansion of ESMP or a continuation. Is that still something you see as possible? What should we be thinking around timing there, size wise? Anything you can give us on that?

Yes. Sure, Jonathan. So that one was more of a fourth quarter event of this year. It will be after the rate case is filed. The rate case won't be over by then. You should think of that in terms of balance of Energy Strong. If you remember, back to Energy Strong, we asked for close to $3 billion. And because we have never done anything like that before, the board staff suggested that we just do the most critical components first and see how it goes. The board then actually hired a third party consultant to oversee our work, and that's gone a very, very well. So I would say it could be an additional $200 million to $300 million per year nominally in terms of electric system modernization that we would be filing in Q4. Well, probably in Q1 of next year, file our large, much, much larger energy efficiency program. So there's no shortage of things that need to be done to continue the aging infrastructure replacement for further enhancement of the grid and now it's by the energy-efficient to help those participating customers control their bill.

Would that be a 5-year-type program, Ralph, or $200 million to $300 million...

You should expect in all of these cases, we will comply with the infrastructure program rule -- proposed rule. Stumbling on my words there. So yes, it would be a 5-year for the current proposal.

Okay. So you would -- we may see more about that in 4Q.

Yes, you will.

May I just ask one other thing, while I'm on?

Sure.

You're up 4% in the first half. Your guidance is still midpoint. It's kind of a flat year. Are there other specific drivers in the second half that you can point us to that would sort of tamper things back down.

There's 2 things going on. Number one is that I think with only 1 year being the exception that we changed our numbers after Q2, it's also 72 degrees in New Jersey today on July 28. So the third quarter, while not a big pricing event for Power, is still a big volume event for Power. And Dan is waving at me. He may want to add to that.

Yes. I think just -- the last year, there was a little bit of tax help that we saw towards the end of the year that we may not end up seeing for this year. So that and just some of the pricing in what we'll see over the summer. And we talk a little bit within the prepared remarks about how hedged prices are coming down. So I would point to that and some tax help we got at the end of last year.

The next question is from Travis Miller with Morningstar.

I was wondering if we look out a few years, and if you get the nuclear support that you're thinking about wherever that comes from, what would you think about uprates and investments in uprates at your existing plant?

So Travis, good morning. We are actually looking at a very modest uprate at -- Hope Creek. Yes.

I'm pretty sure it's Hope Creek.

And it's mostly -- I don't mean to diminish this, a paper exercise, it's the way in which one can measure, monitor and calculate operational risk associated with different operating parameters. So the risk of stating the obvious, you're not going to see any major equipment investments at the same time that I'm talking about the forward price curve coming down and putting tremendous economic pressure on the plants. But to the extent that we have the same staffing levels and the same overhead cost and we can squeeze out a couple more megawatts by doing better probabilistic risk assessment, we're going to do that. We do have a couple of uprates going on in our fossil plants that we've announced in the past, at both our Bergen and our Bethlehem plants, and those are more -- a bit more meaningful in terms of their size. But at the nuclear plants right now, Salem and Hope Creek, We're just looking at Hope Creek, and it's about 18 megawatts, I think, is the exact number.

Yes, that's right. And so the incremental benefit that you would get versus the incremental cost is very favorable, given the fact that you have the base plant running as Ralph mentioned.

Sure. Okay. Good uprates and promises to expand nuclear power, could that you think considerably be part of some kind of negotiation at state legislative level?

So from the point-of-view that, as we just tried to suggest that getting a few more megawatt hours without increasing the cost is helpful. Let me be 1,000% clear, we are working our tails off to make sure we don't need any help from anybody, right? I mean, we -- the most important thing is to control what we can control and make sure we run those plants as well as we can, as at lower cost structures as we can so they're -- so that even with the flaws in the market, they can still win. And if that means pay for uprates, then we'll do that. If it means more staff optimization, we'll do that. And so that's job #1, 2 and 3. I -- the comment I made before about near universal desires to see those plants operate is accurate. Obviously, our competitors don't want to see those plants operate, and that's a very rational position on their part. But I don't think that we get the same universal reaction to new nuclear or building additional plants, and not that we would even consider that in the current gas price environment. So I think to the extent that getting more out of the plants is something that helps make them more competitive, the answer is yes. But no one has talked to us about, well build another plant and we'll let you keep these running. I mean that's not part of anybody's calculus right now.

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

Thank you, Jamie. So thanks, everyone, for joining us. And hope you -- we genuinely hope you're as pleased as we are with the results we've had year-to-date. And also, hope you are as encouraged as we are with the growth prospects that we have anchored by the Utility with programs, such as GSMP. As Dan said, it was just a few months ago, we thought that was probably going to be a $300 million year program and maybe winding down in '19. And now we have some good hopes that it could be a $500 million-plus program and have 5 years of life after '19. So as always, Kathleen and Carlotta and the rest of the team are available to you for follow-up.

And with that, I'll just wish a very happy and pleasant rest of the summer. And we'll see you, I'm sure, at various different venues. Thanks, everyone. Take care.