公共服務電力與天然氣 (PEG) 2018 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Nicole, and I will be your events operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's First Quarter Earnings -- 2018 Earnings Conference Call and Webcast. (Operator Instructions)

As a reminder, this conference is being recorded, Monday, April 30, 2018, and will be available for telephone replay beginning at 1:00 p.m. Eastern today until 11:30 p.m. Eastern on Tuesday, May 8, 2018. It will also be available for audio webcast on PSEG's corporate website at www.pseg.com.

I would now like to turn the conference over to Kathleen Lally. Please go ahead.

Thank you, Nicole. Good morning, everyone. Thank you for participating in our earnings call.

As you are aware, we released first quarter 2018 earnings statements earlier this morning. The release and attachments are posted on our website at www.pseg.com, under the Investors section. We also posted a series of slides that detail operating results by our company for the quarter. Our 10-Q for the period ended March 31, 2018, is expected to be filed shortly.

I'm not going to read the full disclaimer statement or the comments we have on the difference between operating earnings and adjusted EBITDA and GAAP results, but I do ask that you all read those comments contained in our slides and on our website.

The disclaimer statement regarding forward-looking statements details a number of risks and uncertainties that could cause actual results to differ materially from forward-looking statements made therein. And although we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so even in light of new information or future events, unless required by applicable securities laws. 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.

PSEG believes that the non-GAAP financial measures of operating earnings and adjusted EBITDA provide a consistent and comparable measure of performance to help shareholders understand operating and financial trends, but should not be considered an alternative to our correspondent GAAP measure net income.

I would now 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. (Operator Instructions)

Thank you. Ralph?

Thank you, Kathleen, and thank you, everyone, for joining us today. Earlier this morning, we reported non-GAAP operating earnings for the first quarter of 2018 of $0.97 per share versus non-GAAP operating earnings of $0.92 per share in the last year's first quarter.

Our GAAP results for the first quarter of $1.10 per share reflect solid operating and financial contributions from both businesses. This compares to GAAP results of $0.22 per share in last year's first quarter, which included expenses associated with our decision to retire the Hudson and Mercer coal-fired generating stations. Details on the results for the quarter can be found on Slide 5. Non-GAAP operating earnings for the first quarter benefited from an increase in earnings at both the PSE&G and Power.

On the operating front, our service area experienced 4 consecutive nor'easters in March that wreaked havoc on trees and power lines. The repeated battering of freezing rain, heavy snow and high winds caused widespread service outages to over 500,000 customers during 2 of the back-to-back storms. PSEG employees once again rose to the challenge. Beginning with comprehensive storm preparation and then efficiently and safely completing PSE&G and PSEG Long Island customer restorations, the utility then actually offered assistance to neighboring utilities.

The diversity at PSEG Power's generating fleet was also responsive to the extremes in weather that range from the near 0 temperatures experienced in January to the very mild weather in February. 8 days of severe weather in January, however, demonstrated again the importance of fuel diversity. Power's high nuclear availability and greater use of oil was able to meet weather-related demand. For the quarter, PSEG's nuclear plants achieved a near-perfect capacity factor of 99.5%, anchored by a record-setting 517-consecutive day run at the Hope Creek generating station.

We have successfully advanced many policy and regulatory initiatives during the quarter. Last week, PSE&G reached a settlement to expand and extend its Gas System Modernization Program. The settlement, which is awaiting approval by the Board of Public Utilities, would allow PSE&G to invest approximately $1.9 billion over 5 years, beginning in 2019. This next phase of GSMP will replace approximately 875 miles of gas mains and make other improvements that will reduce methane emissions and ensure we have the critical infrastructure needed to grow New Jersey's economy.

PSE&G has also implemented transmission and distribution rate reductions to pass through the benefits of recently enacted lower federal corporate tax rates to our customers. In addition, PSE&G filed with the BPU this past January its first base rate case since 2010.

PSEG Power made significant progress in its continuing efforts to make sure the economic viability of its nuclear plants. With broad bipartisan support, the New Jersey legislature passed the Zero Emissions Certificate bill in early April. Key provisions of the ZEC bill, as we refer to it, are outlined on Slide 6. We are hopeful that this safety net mechanism, to be implemented by the BPU upon Governor Murphy's signature, will secure Power's nuclear fleet as a major source of New Jersey's carbon-free energy supply and acts as a bridge to a cleaner energy future as this stage implements companion legislation to further promote renewable energy. The major energy policy goals of the new clean energy bill are outlined on Slide 7.

PSEG has been incorporating climate change considerations into its business planning and investment decisions for many years. We look forward to working with the Murphy administration as New Jersey pursues energy policies which recognize the value of existing carbon-free energy resources and promotes new opportunities to advance New Jersey's clean energy goals.

Also in the category of good news, we have reached the full and final resolution of the long-standing FERC investigation into Power's cost base bidding matter. PSEG continues to focus on its strategic investment program of $13 billion to $15 billion over the 2018 to 2022 period. Earnings for PSE&G are expected to grow by 5% in 2018, so it represents 65% of our full year 2018 non-GAAP operating earnings. The previously mentioned $1.9 billion settlement, providing for the second phase of PSE&G's Gas System Modernization Program, is aligned with our investment goals and supports annual growth in PSE&G's rate base at the upper end of our forecasted rate of growth of 7% to 9% through 2022.

PSEG Power continues to operate its assets safely and efficiently and remains focused on the cost discipline essential in today's power market. Construction of 2 of Power's 3 combined-cycle gas turbines under construction is expected to conclude around midyear and will add 1,300 megawatts of clean, highly efficient gas-fired generating capacity in favorable locations.

This significant list of accomplishments could not have been achieved without the tireless effort of many talented teams across PSEG, from the utility's line crews and Power's plant operations to state government affairs, communications, regulatory, legal and finance. I'd like to recognize their exceptional contributions to our progress.

Today, we are reaffirming our non-GAAP operating earnings guidance for the full year of $3 to $3.20 per share. At the midpoint, this represents a 6% increase over 2017's full year non-GAAP results of $2.93 per share.

With the support of our 13,000 dedicated employees, we expect to be able to successfully deliver on the promise of our investment programs that should provide growth for our shareholders and a sustainable energy future for our customers.

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

Thank you, Ralph, and good morning to everyone. As a Ralph said, PSEG reported non-GAAP operating earnings for the first quarter of 2018 of $0.97 per share versus non-GAAP operating earnings of $0.92 per share in last year's first quarter.

On Slide 5, we've provided you with the reconciliation of non-GAAP operating earnings to net income for the quarter, and we've provided you with information on Slide 10 regarding the contribution to non-GAAP operating earnings by business for the quarter. Slide 11 contains a waterfall chart that takes you through the net changes quarter-over-quarter in non-GAAP operating earnings by major business. I will now review each company more detail, starting with PSE&G.

PSE&G, as shown on Slide 13, reported net income for the first quarter of 2018 of $0.63 per share compared to $0.59 per share for the first quarter of 2017. PSE&G's first quarter results reflected continued successful execution of our infrastructure investment programs. Growth in PSE&G's investment in transmission added $0.03 per share for the first quarter. And recovery of investments made under the Gas System Modernization Program improved net income by $0.02 per share, and favorable weather comparisons added $0.01 per share versus the year-ago quarter.

PSE&G experienced higher costs associated with restoring service to customers following 4 storms that occurred over a 30-day period. The increase in storm costs, when combined with the change in pension accounting standards for non-service costs, increased O&M by $0.01. In addition, higher depreciation expense, reflecting the utility's expanded asset base, reduced net income by $0.01 per share versus the first quarter of 2017.

Weather-normalized electric sales to residential and commercial customers rose by 0.4% compared to the first quarter of 2017. Weather-normalized gas sales were higher by 1.6% in the quarter, led by increased residential and commercial usage. Residential/commercial growth continues to trend higher at 0.8% per year.

PSE&G implemented a revised $64 million annual increase in transmission revenue under the company's FERC-approved formula rate effective January 1, after factoring in the $148 million decrease in its revenue requirement associated with the lower federal tax rate. PSE&G also reduced its distribution revenue by $114 million in response to the BPU's order to accelerate returning the benefits of federal tax reform to customers effective April 1. Combined, that's $262 million of benefit to customers.

As Ralph mentioned, PSE&G settled the GSMP II filing with the staff of the New Jersey BPU, Rate Counsel and other parties, which remain subject to BPU approval. The details of the agreement are summarized on Slide 16.

Modeled after the BPU's recently enacted Infrastructure Investment Program or IIP initiative, the agreement will allow PSE&G to invest $1.9 billion over 5 years, beginning in 2019, to continue and accelerate the replacement of cast iron and unprotected steel mains in addition to other improvements to the gas system.

The settlement provides 5-year project visibility to efficiently plan labor, materials, vendors and permitting. Approximately $1.6 billion of the total program will be eligible for semiannual rate roll-ins, with the remaining $300 million to be addressed in a future base rate case.

Return on equity for the GSMP II investment will be determined in PSE&G's pending base rate case. And as part of the settlement, PSE&G agreed to file a base rate case no later than 5 years from the commencement of GSMP II. We are maintaining our forecast of PSE&G's net income for 2018 of $1 billion to $1,030,000,000.

Moving on to Power. PSEG Power reported non-GAAP operating earnings for the first quarter of $0.33 per share and non-GAAP adjusted EBITDA of $313 million. This compares to non-GAAP operating earnings of $0.30 per share and non-GAAP adjusted EBITDA of $359 million for the first quarter of 2017.

Non-GAAP adjusted EBITDA includes the same items as our non-GAAP operating earnings measure as well as income tax expense, interest expense, depreciation and amortization expense. The earnings release and Slide 21 provide you with detailed analysis of the items having an impact on Power's non-GAAP operating earnings relative to net income quarter-over-quarter. And we've also provided you with more detail on generation for the quarter in Slide 22.

Power's net income comparison for the first quarter reflects an increase in capacity prices of $0.01 per share. Recontracting at lower market demand reduced results by $0.06 per share versus the first quarter of 2017.

Planned maintenance increased O&M expense and reduced net income comparisons by $0.01 per share. And lower depreciation associated with the early retirement of Hudson and Mercer generating stations in June of '17, along with lower interest expense, added $0.02 per share versus the year-ago quarter. The reduction in the corporate tax rate from recently enacted federal tax reform and other tax items improved first quarter net income comparisons by $0.07 per share.

Gross margin in the first quarter declined to $35 per megawatt hour from $37 per megawatt hour in the year-ago quarter. Although power prices were higher on average, driven by extreme temperatures in early January, lower market demand experienced in February lowered dispatch of Power's intermediate fleet.

Compared to last year's first quarter, Power experienced a $4 per megawatt decline in the average hedge price. This decline is lower than the anticipated annual reduction of $6 per megawatt hour forecasted for the full year as results in the first quarter benefited from the cold weather experienced in January. We forecast average hedge prices for the remainder of the year to decline by more than $6 per megawatt hour, resulting in an average decline for the full year of $6 per megawatt hour.

Capacity revenues by comparison are expected to increase throughout the remainder of the year, with the average price received scheduled to increase on June 1, 2018, to $205 per megawatt hour in PJM and to $314 per megawatt day in ISO New England. That's $205 per megawatt day in PJM.

Now let's turn to Power's operations. Generation output declined modestly compared to the first quarter of 2017. Output was affected by severe winter weather at the start of the year. And in conjunction with an unseasonably warm February and higher planned outage hours at the Bergen and Linden combined-cycle units, Power's gas-fired CCGT fleet operated at an average capacity factor of 37% and produced 2.7 terawatt hours of output. A higher price for gas in the quarter favored a shift to more production from coal, which generated 1.5 terawatt hours and a doubling of peaking output.

Power's nuclear fleet operated at an average capacity factor of 99.5% for the quarter, producing 8.4 terawatt hours, representing 66% of total generation for the fleet. And of note, Hope Creek's strong performance was evidenced by a breaker-to-breaker run of 517 consecutive days of production before entering its planned refueling and maintenance outage on April 13.

Power continues to forecast an improvement in output for 2018 to 55 to 57 terawatts hours. For the remainder of 2018, Power has hedged 80% to 85% of total forecast production at an average price of $38 per megawatt hour. For 2019, Power has hedged 60% to 65% of forecast production of 59 to 61 terawatt hours at an average price of $37 per megawatt hour. And for 2020, output is forecast to be 63 to 65 terawatt hours, with 35% to 40% of forecast output hedged at an average price of $36 per megawatt hour.

Forecasted increase in output for 2018 to 2020 includes generation associated with the mid-2018 commercial start-up of 1,300 megawatts of combined-cycle capacity at the Keys Energy Center in Maryland and at Sewaren in New Jersey and the mid-2019 commercial start-up of the 485-megawatt combined-cycle unit at Bridgeport Harbor, Connecticut that will also mark the conclusion of Power's construction program.

I'd also like to update you on the conclusion of the FERC investigation for Power's cost base bidding matter that has been pending since 2014. Last week, FERC issued an order fully resolving this issue. Financially, Power has recorded an incremental $5 million pretax charge to income in accordance with the order, which included an $8 million nontax-deductible penalty, so a $0.02 impact from that item. And operationally, we do not believe that the order will have any material impact on Power's ongoing business operations.

We continue to forecast Power's non-GAAP operating earnings for 2018 and non-GAAP adjusted EBITDA at $485 million to $560 million and $1,075,000,000 to $1,180,000,000, respectively.

Now let me briefly address the operating results from Enterprise and Other. And for the first quarter, Enterprise and Other reported net income of $5 million or $0.01 per share versus a net loss of $15 million or $0.03 per share in the first quarter of 2017.

Net income for the first quarter of 2018 reflects the absence of tax benefits in the year-ago quarter at PSEG Energy Holdings and higher interest expense at the parent. The net loss in the first quarter of 2017 included a $55 million pretax charge related to the continuing liquidity issues facing NRG REMA, partially offset by tax benefits at PSEG Energy Holdings. And the forecast for PSEG Enterprise and Other net income remains unchanged at $35 million.

PSEG closed the quarter with $118 million of cash on the balance sheet, with debt at the end of March representing 49% of our consolidated capital and debt at Power representing 28% of its capital at the end of the quarter. Based on our strong balance sheet and credit metrics, we are able to fund our 5-year capital investment program without the need to issue equity. We continue to forecast our non-GAAP operating earnings for the full year of $3 to $3.20 per share.

That concludes my remarks. And I'll now turn the call back to Nicole for our question-and-answer session.

(Operator Instructions) And the first question is from Julien Dumoulin-Smith from Bank of America Merrill Lynch.

I wanted to follow up on the latest Clean Energy bill cited, the legislation that passed. Can you provide a little more specifically the energy efficiency opportunity at the utility and just how to think about the net income impacts at the end of the day? And then separately and related, just the palatability to pursue an offshore wind given its risk profile and given your current position, I mean, how do you think about approaching or tackling that opportunity here or if at all?

Yes, no. So Julien, thanks for the question. I mean, we're genuinely excited by the Murphy administration's stated energy policies. As I think you know, we've been strong advocates of energy efficiency. We've done it in kind of small bites. So I think in total, over past 10 years, we have maybe a little bit north of $400 million worth of Energy Efficiency programs. And the Clean Energy bill anticipates a 1.5% or 2% reduction, depending on whether it's electric or gas. I think it's 2% on electric, and it's about 0.75% on gas. And the BPU is going to come up with rules, but suffice it to say, we've been thinking about this for a good long time. The legislation also talks about recovering -- utilities have the right to file annually to recover their costs, including return on and of their capital and the lost revenues as well. So this is great news. And we will jump into this feet first and deliver universal access to energy efficiency for all New Jerseyans. On the offshore wind piece, we don't have a track record in offshore wind, but we do have a lease offshore, and we do have a partner. And that's part of a JV that we have in place. So I would say that whether as a participant in the transmission aspects or in the offshore wind aspects of the farm itself, that's probably not quite as mature in our own thinking as the energy efficiency. But overall, this notion of a sustainable energy future is one we've been talking about for a decade or more, and we're excited by the prospects that are created.

But just to clarify on the EEP for this, I mean, how do you think about that in the context of decoupling specifically? And maybe that's more of a rate case question. And then separately, if I can recharacterize a little bit how you described it, you talked about sort of initial $400 million of cumulative spending. I mean, how does that compare versus what prospectively you're talking about, even order of magnitude?

Yes, no, I'd say that's right. In order of magnitude, different. We -- I don't think we've released our planned number for a filing, but we have said that we anticipate putting a filing before the middle of the year, and we still are on track to do that. I'd rather not give a specific number because there's a prefiling meeting we need to go throughout with the Board of Public Utilities. And they deserve to hear that, candidly, before we start blabbing it out in a quarterly earnings call. But it is in order of magnitude different in terms of the opportunity.

And to your point, Julien, related to the rate case, we did file a decoupling mechanism as part of the rate case. And that really fits hand in glove with what's going on from an energy efficiency standpoint.

Our next question comes from the line of Praful Mehta from Citigroup.

So on the GSMP and the settlement and the distribution rate case, just want to understand, were you saying that if you achieved both, you would be at the upper end of the 7% to 9%? Just wanted to confirm that.

So it's a combination of multiple factors, Praful. There's the rate case, which includes various tax givebacks that have to do with both the change in federal tax policy and deferred tax balances. There's GSMP II, which takes up $300 million per year prior GSMP program up to about a $375 million per year program. There's still the #1 investment area that we will be focused on, which is transmission and our expectations there. And then there's some expectation for a continuation of Energy Strong and Energy Efficiency, but not at numbers that we have completely disclosed yet. But when you add all of that together, that leads us to think that we're biased towards the higher end of the 7% to 9% range. But Dan, you may want to tell the real story.

Yes. We said we're on the higher end of that, and we anticipate being there. And Praful, I guess if you think about the rate case, the rate base element of that is a couple of things. One, it's the roll-in of some remaining portion of some prior clauses, but it's also rolling in the giveback on some of the tax effect. So the way we characterized that earlier in the year was that we always talk about our growth rate, and as we continue the capital program that we have, the existing rate base goes up. So you're jumping off of at a higher base. And last year, we were at about 7% to 9% growth rate. This year, we're at about 7% to 9% growth. But that higher base was really offset by some of the tax flowback that we would anticipate. So that is what's basically the rate case, and that flowback would hold you about steady. And then with existing GSMP settlement plus Energy Strong, too, which we've talked a little bit about and plus a Clean Energy filing, we would anticipate moving higher up within that range.

Got you, that's super helpful. So just to clarify, I think you had said $600 million was the unprotected DTL on, I think, previous calls. Is that refund expected to happen pretty soon? And is that part of like the growth that's kind of flowing into the rate case?

That'll ultimately be determined in the rate case. So I think that the bulk of the excess deferreds are going to be through the average rate assumption method, which will be a longer-term period. But some of that, in addition to some of the excess deferreds, is going to be worked through the rate case related to some other items. So we'll know more about that as we move towards the end of the year.

Fair enough. And then just quickly on ZECs, congratulations to where it's kind of come out so far. Just want to understand, in terms of the 3-year extension, it sounds like it is -- if prices change, don't change meaningfully, you have a shot at continuous extensions. But just wanted to understand, from your perspective, how do you see that extension discussion going? Because if you do get the 3-year, what does it take to kind of happen, next 3-year extension?

So first of all, it's important to realize that the ZEC price is not tied to a market price, all right? The ZEC price is an attribute payment for the carbon and fuel diversity dimensions of nuclear power. There is a consumer protection put in the bill that goes to simply the affordability of ZECs when viewed in the context of overall energy prices that customers have to pay as well as a provision in the bill that anticipates a review by the BPU as to whether or not the plants are in any kind of economic duress. So that's what the 3-year review is for, right? Can New Jersey continue to afford to pay for a 0 emissions energy? And that's a question the BPU will have to answer for on behalf of customers. We will always be mindful, both on behalf of customers but on behalf of our shareholders, as to whether or not the plants are making their cost of capital on a risk-adjusted basis. And if they are not, then we will close the plant. That's not saber rattling, that's not threatening, that's just our fiduciary responsibility. And we will always work extra hard to make sure New Jersey is aware of those situations and what that means in terms of the loss of attributes. So I just think it's a -- and as you know, in the nuclear space, nothing happens in less than a year anyway. And in RPM and PJM worlds, things tend to happen in 3-year increments. So just checking in every 3 years as to affordability, economic viability seem like a very natural rhythm to put into public calls.

Your next question comes from the line of Jonathan Arnold from Deutsche Bank.

Just so on the energy efficiency, and I hear you comment about filing by the middle of the year and then needing to go through a meeting -- prefile with the BPU. Is it a reasonable expectation that you'd be through that and able to give us a little more flavor by the time of the Analyst Day?

Yes. So we should definitely have the prefile done before the Analyst Day, Jonathan, and then we'll tell you everything that we plan to file at that point, correct.

So the filing itself might not have been made, but you'll have a better sense of the scope of it?

We -- it won't be because the prefile meeting is -- there's a 30-day clock that starts from then. And as you know, the Analyst Day is on the 31st, and we haven't had the prefiled meeting yet, although we are close.

Because I'm hearing you'll tell us a bit more than you've told us today.

Oh, yes, yes, that -- we'll tell you a lot more. We're just too excited not to tell you a lot more. So -- this is a favorite. So...

And then switching to something a little different, Slide 22 on the power generation measures. And just wanted to understand a little better, the coal costs up $9 million, it's about over 25%, and the generation was up more like mid-single digits. So is that just the fact that you're less hedged than you've been in past and you're buying some spot to cover the extreme weather? Or is it a contract rolling off? Or how should we think about that as we're trying to calibrate coal costs for the rest of the year?

I don't think I would put too much weight into that, Jonathan. I think that -- especially if I think about it from an overall component of the generation, I think what we saw really was a little bit more reliance on coal because of the weather. And I think on an ongoing basis, I don't anticipate it to be much of an impact as we go through the rest of the year.

Yes. And I don't -- I didn't do the numbers, Jonathan, but if you look at that slide, you'll see that Pennsylvania is down a little bit and Connecticut's up quite a bit, and Pennsylvania's got more expensive coal.

Okay, that's helpful. But then on the oil piece, presumably the denominator for those fuel -- that $25 million of cost is in the GAAP segment.

That's correct.

Yes.

And again, is there -- I mean, is there any -- I'm trying to -- well, I guess what I'm trying to get a feel for is to what extent the weather may have actually hurt you at power this quarter.

Well, I think it had a lot to do with what you're seeing on the delta quarter-versus-quarter from the standpoint of oil. That number under normal situations would be much, much lower. And what you saw was prices moving up and gas getting a little bit tighter and gas prices going to extreme levels for the quarter. So I think what you saw was much more an anomaly with respect to oil burn for the quarter. And that's also...

Did you make that up in price? So is that -- was that really just lost margin?

If it -- we were economic when we were running on oil. So the -- if we weren't economic, we wouldn't have been running. But if you took a look at where gas prices were, I mean, gas prices during that part of the year, the very early part of the year, were drifting up, looking like very healthy age-old power prices as opposed to gas prices, well, well up into the double digits.

No, as you said, those -- you guys feel that there was the -- net-net, this was a drag on the quarter, it's just the moving pieces within the revenue and cost lines?

Yes, I think that's right. I think some anticipated spark for earlier January wasn't quite where we would have wanted it to be because gas prices basically pushed you into oil, which has lower margin. But it was a fairly short-term phenomenon in January and an anomaly, but it really does drive all the oil burn that you see there for the quarter.

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

While we're on the subject of PSE&G power, there's several initiatives at PJM that are sort of in their pendency, whether it's capacity market design updates, ORDC pricing, fast start pricing. I believe Andy Ott put out a letter recently indicating that he hoped those 3 things would get done this year. Can you review what your expectation is for the timing on those and the potential impacts on Power? And then there's one thing extant, which is -- well, the management of PJM still seems supportive of overall price reform. There hasn't been much progress there, so you can give us an update on your expectations on that front?

Sure, Greg. So on capacity market reform, we've been public that we prefer the 2-phase approach, which is the PJM preferred approach even though they have submitted the Market Monitor's MOPR-based approach as well. I think we have every reason to believe that will go into effect by May of '19. Obviously, that won't have any effect on the current RPM. So I think that's the timing there. I would view fast start as yet another piece of the price formation puzzle. I know that many people, including us, have talked about the inflexible unit dimension of the price formation, but fast start does have now a proposed 0 threshold element to it, which is characteristic of inflexible units, right, but they can't move over the time frames that PJM is seeking. We've never been one to quote whether or not the forward price curve has these numbers in it nor have we been one to quote what these changes will mean to the forward price curve. We just say the market is the best determinant of that, and our own internal views will influence whether we hedge a little bit to the high side or to the low side of our own internal disciplined approach. I think Andy himself has said that these should go into -- should be able to -- the energy price fixes should be able to be put in place by a little bit more than a year from now but sometime in the summer of '19. So that is a delay. I think that once upon a time, there was talk of fall of '18 for some of these reforms, but I think a combination of factors has introduced that delay. I think the good news, if I might, is that the PJM board appears to be willing to undertake what's called the liaison process as opposed to a full-fledged stakeholder process, which can put a little bit more of a limitation on the amount of time. I should, by the way, point out that in terms of RPM, we prefer the status quo, but of the submittals that PJM has made, we think that the 2-phase approach is better than the one-phase approach. I don't think PJM has given up on the full inflexible unit pricing. They see that as part of their resiliency discussion, which continues with comments due back from, I think, the rest of us. The RTOs have already made their comments. Ours are due back, I think, in the middle of June or middle of May. Middle of May, that's what I'm saying. So it's still a work in process, not over by any stretch. And some things have a bit more of a date certain, i.e., the capacity market reforms and the energy market reforms we think will still creep in to the market.

And next question comes from the line of Travis Miller from Morningstar.

Reading through the ZEC, it sounds like there could be out-of-state plants that would be eligible. And I'm most interested in your thoughts on the Peach Bottom plant, if that is true, if I'm, in fact, reading that ZEC correctly.

Yes. So Travis, you absolutely are reading it correctly. The bill simply says that New Jersey wants 40% of its power supplied by nuclear energy, and it does not limit geographically. In terms of there being more than 40% of New Jersey's electricity being deliverable by nuclear power plants, whether it's Salem, Hope Creek, Peach Bottom or a variety of others, then there's a ranking system that the BPU is encouraged to undertake that is really driven off of the greatest impact on New Jersey from an air quality point of view and various other parameters that are detailed in the legislation. But the short answer to your question is, yes, out-of-state plants would be eligible. But New Jersey would not support, according to legislation, more than 40% of its energy being supplied by nuclear power.

Okay. I would have thought that Peach Bottom would rank at the bottom just given it's not in New Jersey.

Well, no, no, no. I don't want to predetermine what the BPU will do. Peach Bottom will compete with Salem and Hope Creek and Susquehanna and probably don't have to work on San Onofre much, but it does -- I think so...

Yes, sure. So -- and on -- second question on the Clean Energy bill. What components specifically could generate rate base growth, if any? Just clarifying a couple of your previous...

Well, there's multiple, right? So the utility has done grid-connected solar, the utility has done rooftop solar, and the utility has done Energy Efficiency. It has done pilot programs in battery storage technology. So there is no shortage of opportunities that are expanded in the clean energy world. There's a transmission component to offshore wind. There's offshore wind itself. So I think you just have to -- remember, what the governor said is he sees nuclear power as an important bridge to a renewable future, and the renewable future he has in that bill, which he has not signed yet, is a 50% renewable target in 2035. And we expect to be participants in every aspect of that sustainable energy agenda.

Got it. And those investments you foresee could go in the rate base then, not just an earnings-neutral-type collection?

That's correct. Yes, well, I mean, look, the reality is, in New Jersey, just given our geographic and natural resource profile, you're not going to be able to do merchant solar or merchant offshore wind. Those will have to be supported through some type of regulatory revenue stream that feeds in the form of a renewable energy credit and/or some other mechanism. And again, on the offshore wind piece, I just want to emphasize that while we have a lease, we've never done that before. So we would be interested in the transmission component probably as much, if not more than the actual wind farms. And we are, as I said a moment ago, we are all in on the Energy Efficiency piece. And I think some elements of the legislation, Travis, talk specifically about utilities investing and having recovery on and out, like the Energy Efficiency. Offshore wind, very different situation, not specifically laid out as to how that will work out. In fact, the legislation really calls for a study for that to be determined, things like that to be determined.

Your next question comes from the line of Paul Patterson from Glenrock Associates.

Just sorry if I missed this, but when is the governor expected to sign the nuclear legislation?

Paul, so he has -- so in New Jersey, the governor has 45 days to act on legislation. And that action could be either an outright veto, which would require 2/3 majority of the legislation to override; something called a conditional veto, which is, "Hey, I like this except for...," and then he sends it back to the legislature to change the piece that he liked except for; or to sign into law. In addition, if he doesn't act for 45 days, it automatically goes into law. So those are the options for the governor.

Okay. And -- okay, so let me ask you this. If we don't get him signing it by the RPM auction, which isn't that far from now, how should we think about how that might affect how you guys would be bidding into the capacity auction?

Well, we never comment on our bidding plans prior to the auction. But I -- but what I'd say is this, that we would view things differently if he were to veto the legislation versus simply not get around to signing it yet. And so those are 2...

Okay, I got you. So if he feel -- okay. After the veto, you guys sort of are expecting that this bill will be enacted.

Yes, I think he's -- the governor -- look, you never ever want to pretend to be constraining your governor, right?

Sure, I got it.

He's a very important person, and he's a talented person and one that we admire. So I'm not going to try to tell him what to do on an earnings call. But having said that, I mean, he has been outspoken and supportive of nuclear as a bridge to renewable energy in the future. And he's also been outspoken in support of the importance of those jobs for Southern -- South Jersey. So I feel pretty good about those public statements on his part.

Okay, awesome. And then the Energy Efficiency program, just how should we think about how that impacts the demand forecast longer term, and just in general, how we should think about how you see energy demand or electricity demand working in the state?

Paul, we've been working hard to try to remind investors that the utility growth story is really independent of demand growth. Demand growth or the absence of it has significant implications for how regulation needs to be rethought to avoid the compounding of inevitable O&M growth and regulatory lag on investment returns. But PSE&G's growth over the past 10 years and its continued future growth really is about an aging infrastructure that needs replacement and a higher degree of customer service and customer demands for clean energy future. And I am absolutely convinced that we can continue to invest in a resilient grid, cleaner energy and more efficient use of energy, which would help -- that third piece would help lower customer bills and put bigger smiles on our shareholders. So I think that Energy Efficiency is an important part of controlling the bill from the point of view of the actual costs associated with renewable energy and making the grid more resilient.

And you guys have demonstrated that, too, so you guys have been ahead of the curve on that. But I guess I'm sort of wondering, though, it does have an impact perhaps, though, on nonregulated generation, not just in your state but all over. So what you guys might be doing could have an impact there. I'm just sort of curious as to what you guys think, just roughly speaking, all this demand -- what you see the demand forecast kind of being.

I see. Oh, yes, well, I mean, I think RPM is a good example. Demand forecast is down yet again. I don't know, that's the nth consecutive year, where n is some large single-digit number where that's been the case. We've obviously made the decision on our own service territory that Power has a much bigger market in which it can play. And therefore, to the extent that our own efforts cannibalize Power, we've been willing and continue to be willing to do that. I do think that the primary supply/demand economics in the wholesale market are going to be determined as much by the shrinkage of supply as it is going to be determined by any changes in demand.

Your next question comes from the line of Michael Lapides from Goldman Sachs.

One easy one. You have talked about this at prior earnings calls or Analyst Day. I haven't circled back on this in a bit. Can you just talk about how much extra balance sheet capacity that you think the company has right now? Meaning, either the fund incremental rate base growth or incremental renewable growth at PS Power. Just kind of when you think about your credit metrics in a posttax reform world and the balance sheet strength, how big is that balance sheet strength?

Yes. Michael, and I think you'd want to think about it really in 2 steps, right? We've talked about the ability to fund the capital plans, such as we have, without the need for any additional equity. And then as you mentioned, consistent with how we've talked about it in the past, if you take a look at our existing credit statistics and you take a look at where some of the threshold points are, you have somewhere in the order of $1 billion of excess at PSEG Power, which then can be utilized at the utility within the existing regulatory capital structure. So that can be matched with debt, and so you'd come up with double that if you think about it from a utility overall investment incremental spend standpoint without having any impact on the existing ratings.

Got it. And any incremental or potential holding -- incremental holding company leverage? Or do you just think about it as, if opportunities came up for incremental investment at Power or at E&G, you would simply make the leverage down at Power?

Well, I think that the leverage could happen at Power or at the parent company. I think we've had some parent company debt of late, and we tend to take a look at what makes the most sense from an economic standpoint when looking to source that debt. So I think that it could be at either location. But I think you're in the same ballpark when I talk about the numbers that I just referenced.

Your next question comes from the line of Paul Fremont from Mizuho.

I guess the first question would be on the Clean Energy bill. When I think of the 7% to 9% rate base growth target and the fact that you guys are seeing yourselves sort of at the upper end, does -- do the investment opportunities under the Clean Energy bill keep you within that 7% to 9% band? Or would that potentially put you outside of that band?

So I'd rather give more detail on the band at the upcoming investor conference, Paul, right now because I think we'll have more information coming out at our prefiling meeting with the board staff and, well, hopefully a resolution -- well, we'll definitely have resolution of the nuclear bill by that point in time.

Okay. And then sort of a quick question on Hope Creek. The 60-megawatt upgrade that was approved, when would that take effect?

It was 60 or 16?

16.

16. It was much smaller, and I'd have to get back to you on that, Paul. I don't know the answer. We've -- our nuclear has been jammed with broader issues than 16 out of the 1,100. It wasn't a quick one. I mean, this is -- this was a change, I believe, in our probabilistic risk assessment that allowed us to run the plant at different numbers. But I'm tempted to say it's...

I think coming out of this outage is the right number, but we can confirm that for you. Any questions we can answer for you, Paul?

No, that's good.

Your next question comes from the line of Angie Storozynski from Macquarie.

So my only question is, you guys in the past mentioned that you might try to pursue electric retail in the mid-Atlantic. We haven't actually had much -- haven't heard much about it. And do you think that this is still something you will be interested in? And if so, do you think that this would be done organically? Or would you need to acquire a retail book?

Yes, Angie, so thanks for the question. We're still at work. It is exclusively an organic effort. We did look at the potential for acquisitions, but given the purely defensive nature of this effort and our desire for it to basically help us improve our margins based on our own assets, there's been no book that kind of fit that to a high enough degree of accuracy that the transaction costs wouldn't have swamped the benefits. So -- because whatever book we bought, we'd have to sell off a piece of it, and that would be suboptimal. So we're continuing to pursue an organic growth strategy there.

Cool. And my other question, on the regulated side. So even if your rate base were to grow at 9%, would you consider acquisitions of other regulated underinvested systems in your -- around your service territory or in the same state?

Well, we always -- there aren't too many left in our state. I don't know of any that are available in our state that aren't part of a bigger entity. So we always look at those, right? But we've been very public that we are quite enamored with our organic growth strategy. And without any disrespect to our colleagues in the industry, sometimes are puzzled by the premiums that others are willing to pay, and we've not been able to pencil those in the way that we expect. We always look at those possibilities.

Your next question comes from the line of Steve Fleishman from Wolfe Research.

Sorry to bug you with some clarifications, but just on the rate base growth comment, could you clarify if -- what the base of your growth forecast is? Has that changed due to some of the tax reform adjustments? Or is it the same kind of base level for your 7% to 9%?

Steve, I'll let Dan dive into that.

Yes. It's just the year-end 2016 number -- 2017 number, which is $17 billion.

Okay. So that -- so the base is still the same base?

Yes.

And then in saying that you might be toward the high end, that is including the GSMP agreement but nothing else different?

It would include, as we look forward, the opportunity -- some opportunity related to future filings, right? So I would say that if we had nothing beyond the GSMP filing, we'd be more middle of the road within that range. And with the opportunity for future filings, we could see the opportunity to go higher than the middle of the range.

Okay. So it may include some of these clean energy investments or...

Yes. And any other adjustments as we step forward through time. Yes, yes.

Your next question comes from the line of Michael Weinstein from Crédit Suisse.

It's Mike Weinstein. A quick question. You said before that you prefer the status quo for the current capacity market reforms, I believe. I think I've heard some similar sentiment over from Exelon. I'm just wondering, what is it about the status quo that's better than any of the proposals that's been put out there?

It's just that it -- the status quo has new plants being MOPR-ed as opposed to existing plants being MOPR-ed. And it doesn't interfere with the state's ability to price attributes that the market isn't currently pricing. So we just don't see a need for this kind of modification at the current time.

And do you think the modifications won't have an effect at all? Or...

No, no, no. I mean, they'll have different effects. I think that the 2-phase approach at least continues to allow states to recognize the value of renewables and carbon-free energy sources. The Market Monitor's approach is this protracted administrative battle over what constitutes the appropriate minimal offer price, which, as you know, can be moved quite a bit, depending upon whether you believe something has a 30-year life or a 40-year depreciable life if your cost of capital is x or 1.1x or 0.9x. And so to characterize that as a correction to ensure the market is working properly, I think is inaccurate. I think it's just a correction to ensure administrative power reverts to people who want to have administrative power, right? And that's not necessarily consistent with markets. I mean, look, we're all dancing around here as we need a price on carbon and then let the market pick the technology, and then I think you'd see every participant in the market sign up for that, well, except for maybe the carbon-heavy participants, I guess.

Is that more handled better on the energy side basically then, you think?

Yes, absolutely, yes.

Yes. So the capacity market reforms are kind of a distraction of some sort maybe?

Yes. And you've got to collapse inframarginal revenues because there's no carbon price in energy markets. And because of that collapse in inframarginal revenues, high-fixed cost participants are getting crushed, and that's and yet people are saying they want the attributes of these high-fixed cost participants. You have the decoder ring right? The high-fixed cost participant is a nuclear plant. And yet people are paying retro prices of anywhere from $5 to $200 per ton of carbon. And so the market's just got these inherent inconsistencies built into it. So if we could get a single price on carbon and energy markets, then the inframarginal revenues would increase, and the fixed cost recovery would be mitigated, and then capacity markets could do what they were supposed to do, be reliability mechanisms and nothing more.

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

It's always magic. No matter where you are, whether it's a teleconference or a public speaking, if you say one more question, there's never more questions, but that's all right.

So anyway, so thank you, folks, for joining us today. And I hope you heard from Dan and I that there's a lot of good things happening at PSEG and it may range from the continuation of our $13 billion to $15 billion investment program, which -- 90% of which is going to the utility and leads us to be biased towards the upper end of that 7% to 9% rate base growth looking out to 2022 off of the higher base in -- at the end of '17. Again, we've got to give kudos to the great work done by our utility crews and our power plant operations doing what were some very, very difficult circumstances certainly in January.

And kudos to our regulatory team and all of our support functions for the strides they've made on some of the policy funds with the settlement of GSMP II and the legislation that recognizes the value of Power as nuclear generation. I mean, getting 60 out of 80 votes in the assembly and 30 out of 40 votes in the Senate on a bipartisan basis, I think, validates what we've been saying all along, that New Jersey will recognize the importance of these plants to our environment, to our cost of energy, to our economic well-being and they are much cheaper to keep than they are to let shut down.

And then of course, our ongoing commitment to maintain our financial strength, which gives us flexibility to support the growth in the dividend, fund these rate base growth investments, no need to issue equity and still some balance sheet capacity left over. So hopefully, we'll see all of you on May 31. I know that's the weekend after. That's Memorial Day, so come in your Chubbies or whatever other beachwear you have that -- and we'll host you, and we'll have a great conversation about the rate base growth in detail, where we are with RPM. And I think there's a brand at closing, is what...

Is it?

And we'll see you soon. Thanks a lot, everyone. Take care.

Very good.

Ladies and gentlemen, this does conclude your conference call for today. You may disconnect, and thank you for your participation.