Ladies and gentlemen, thank you for standing by. My name is Nicole, and I will be your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group First Quarter Earnings 2018 Earnings Conference Call and Webcast. At this time, all participants are on a listen-only mode. Later, we will conduct a question-and-answer session for members of the financial community. At that time, if you have a question, you may press the star and the number one on your touch-tone phone. To withdraw your question, please press the pound key. As a reminder, this conference is being recorded Monday, April 30th, 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 8th, 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 Murray. 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 investor section. We also posted a series of slides that detail operating results by a company for the quarter. Our 10-Q for the period ended March 31st, 2018, is expected to be filed shortly. I am 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. 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.
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. We ask that you limit yourself to one question and one follow-up to provide enough time for everyone. 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 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 five. Non-GAAP operating earnings for the first quarter benefited from an increase in earnings at both PSEG and Power. On the operating front, our service area experienced four 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 two 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 PSEG and PSEG Long Island customer restorations, the utility then actually offered assistance to neighboring utilities. The diversity of PSEG Power's generating fleet was also responsive to the extremes in weather that ranged from the near-zero temperatures experienced in January to the very mild weather in February. Eight 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, PSEG reached the 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 five 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 ensure 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 six. 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 the state implements companion legislation to further promote renewable energy. The major energy policy goals of the new Clean Energy Bill are outlined on slide seven.
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 longstanding FERC investigation into Power's cost-based bidding matter. PSEG continues to focus on its strategic investment program of $13 billion-$15 billion over the 2018 to 2022 period. Earnings for PSE&G are expected to grow by 5% in 2018 to represent 65% of our full year 2018 non-GAAP operating earnings.
The previously mentioned $1.9 billion settlement, providing for the phase 2 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%-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 two of Power's three combined cycle gas turbines under construction is expected to conclude around mid-year 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. Good morning, everyone. As 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 five, we've provided you with a reconciliation of non-GAAP operating earnings to net income for the quarter. 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 in 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. Recovery of investments made under the Gas System Modernization Program improved net income by $0.02 per share. 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 four storms that occurred over a 30-day period. The increase in storm costs, when combined with a change in pension accounting standards for non-service costs, increased O&M by $0.01. 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 1st, after factoring in the $148 million decrease in its revenue requirement associated with a lower federal tax rate. PSE&G 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 1st. Combined, that's $262 million of benefit to customers. As Ralph mentioned, PSE&G settled the GSMP2 filing with the staff of the New Jersey BPU, Rate Council, and other parties, which remains 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 five 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 five-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. The return on equity for the GSMP2 investment will be determined in PSE&G's pending base rate case. As part of the settlement, PSE&G agreed to file a base rate case no later than five years from the commencement of GSMP2. We are maintaining our forecast of PSE&G's net income for 2018 of $1 billion-$1.03 billion.
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. 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 and 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 2017, along with lower interest expense, added $0.02 per share versus the year ago quarter. A 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 hour 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 1st, 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. 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. 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 55-57 terawatt-hours. For the remainder of 2018, Power has hedged 80%-85% of total forecast production at an average price of $38 per megawatt-hour. For 2019, Power has hedged 60%-65% of forecast production of 59-61 terawatt-hours at an average price of $37 per megawatt-hour. For 2020, output is forecast to be 63-65 terawatt-hours, with 35%-40% of forecast output hedged at an average price of $36 per megawatt-hour. The forecasted increase in output for 2018 to 2020 includes generation associated with the mid-2018 commercial startup 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 startup 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-based 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 pre-tax charge to income in accordance with the order, which included an $8 million non-tax-deductible penalty, so a $0.02 impact from that item. 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-$560 million and $1.075 billion-$1.180 billion, respectively. Let me briefly address the operating results from PSEG Enterprise and Other.
For the first quarter, PSEG Enterprise and Other reported net income of $5 million or a $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 pre-tax charge related to the continuing liquidity issues facing NRG REMA, partially offset by tax benefits at PSEG Energy Holdings. 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 five-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-$3.20 per share. That concludes my remarks, and I'll now turn the call back to Nicole for a question and answer session.
Ladies and gentlemen, we will now begin the question and answer session for members of the financial community. If you have questions, please press the star and the number one on your telephone keypad. If your question has been answered and you wish to withdraw your polling request, you may do so by pressing the pound key. If you're on a speakerphone, please pick up your handset before entering your request. One moment please for the first question. The first question is from Julien Dumoulin-Smith from Bank of America Merrill Lynch. Please proceed with your question.
Hey, good morning.
Morning, Julien.
Hey, I wanted to follow up on the latest clean energy bill side of the legislation that passed. Can you define a little bit 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? Then separately and related, just the palatability of pursuing offshore wind, given its risk profile and given your current position. How do you think about approaching or tackling that opportunity here, or if at all?
Julien, thanks for the question. We're genuinely excited by the Murphy administration's stated energy policies. As you know, we've been strong advocates of energy efficiency. We've done it in kind of small bites, though I think total over the past 10 years, we have maybe a little bit north of $400 million worth of energy efficiency programs. The Clean Energy Act anticipates a 1.5% or 2% reduction, depending on whether it's electric or gas. I think it's 2% on electric and about three-quarters of a percent on gas. The BPU is going to come up with rules, but suffice to say, we've been thinking about this for a good long time. The legislation also talks about recovering, that utilities have the right to file annually to recover their costs, including return on and of their capital and lost revenues as well.
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, that's part of a JV that we have in place. I would say that whether it's 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. 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.
Just to clarify on the EE piece of this, how do you think about that in the context of decoupling specifically? Maybe that's more of a rate case question. Separately, if I can recharacterize a little bit how you described it, you talked about sort of initial $400 million of cumulative spending. How does that compare versus what prospectively you're talking about, even order of magnitude?
Yeah. No, I'd say that's right, an order of magnitude different. I don't think we've released our planned number for a filing, but we have said that we anticipate putting a filing in 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 pre-filing meeting we need to go through at the Board of Public Utilities, and they deserve to hear that candidly before we start bloating it out in the quarterly earnings call. It is an order of magnitude difference in terms of the opportunity.
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.
Right. Exactly. Thank you.
Our next question comes from the line of Praful Mehta from Citigroup. Please proceed with your questions.
Great. Thanks so much. Hi, guys.
Hi, Praful.
Hi. On the GSMP and the settlement and the distribution rate case, just wanted to understand, were you saying that if you achieve both, you would be at the upper end of the 7%-9%? Just wanted to confirm that.
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 GSMP2, which takes out $300 million per year prior GSMP program up to about a $375 million per year program. There's still the number one investment area that we will be focused on, which is transmission and our expectations there. Then there's some expectation for a continuation of Energy Strong and energy efficiency, but not at numbers that we have completely disclosed yet. When you add all of that together, it leads us to think that we're biased towards the higher end of the 7%-9% range. Dan, you may want to tell them the real story.
Yeah. We said we're on the higher end of that, and we anticipate being there. Praful, I guess if you think about the rate case, the rate base element of that is a couple things. One, it's the roll-in of some remaining portion of some prior clauses, but it's also rolling in the give back on some of the tax effects. The way we characterized that earlier in the year was that we always talked about our growth rate, and as we continue the capital program that we have, the existing rate base goes up. You're jumping off of a higher base. Last year, we were at about 7%-9% growth rate. This year, we're at about 7%-9% growth. That higher base was really offset by some of the tax flow back that we would anticipate.
That is what basically the rate case and that flow back would hold you about steady. With the existing GSMP settlement plus Energy Strong II, 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. Just to clarify, I think you had said $600 million was the unprotected DTL from, I think, previous calls. Is that refund expected to happen pretty soon? Is that part of the growth that's kind of flowing into the rate base?
That'll ultimately be determined in the rate case. 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. 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. We'll know more about that as we move towards the end of the year.
Fair enough. Just quickly on ZEC. Congratulations to where it's kind of come out so far. Just wanted to understand, in terms of the 3-year extension, it sounds like it is if prices don't change meaningfully, you have a shot at continuous extensions. 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?
First of all, it's important to realize that the ZEC price is not tied to a market price, 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 ZEC 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. That's what the 3-year review is for, right? Can New Jersey continue to afford to pay for zero emissions energy? That's a question the BPU will have to answer 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 to capital on a risk-adjusted basis. If they are not, then we will close the plants. That's not saber-rattling, that's not threatening. That's just our fiduciary responsibility. 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. I just think, as you know, in nuclear space, nothing happens in less than a year anyway. In RPM and PJM world, things tend to happen in 3-year increments. Just checking in every 3 years as to affordability, economic viability, seem like a very natural rhythm to put into public policy.
Fair enough. Thanks so much, guys.
Nicole, do we have any other questions?
Your next question comes from the line of Jonathan Arnold from Deutsche Bank. Please proceed with your question.
Oh, good morning, guys.
Hey, Jonathan.
On the energy efficiency, I hear your comment about filing by the middle of the year and then needing to go through a pre-file 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, we should definitely have the pre-file done before the Analyst Day, Jonathan. We'll tell you everything that we plan to file at that point, correct.
The filing itself might not have been made, you'll have a better sense of the scope of it.
It won't be because the pre-file meeting is, there's a 30-day clock that starts from then. As you know, the Analyst Day is on the 31st, we haven't had the pre-file meeting yet, although we are close.
I'm hearing you'll tell us a bit more than you've told us today.
We'll tell you lots more. We're just too excited not to tell you a lot more.
Oh, well-
This is a favor.
Switching to something a little different, slide 22 on the power generation measures. 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. Is that just the fact that you're less hedged than you've been in the 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. 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.
Yeah. I didn't do the numbers, Jonathan. If you look at that slide, you'll see that Pennsylvania's down a little bit and Connecticut's up quite a bit, and Pennsylvania's got more expensive coal.
Okay, that's helpful. Thank you. On the oil piece, presumably the denominator for those fuel, that $25 million of cost is in the gas segment.
That's correct.
Yeah.
Again, I guess what I'm trying to get a feel for is to what extent the weather may have actually hurt you at PSEG Power this quarter.
Well, I think it had a lot to do with what you're seeing on the delta quarter-over-quarter from the standpoint of oil. That number under normal situations would be much, much lower. What you saw was prices moving up and gas getting a little bit tighter and gas prices going to extreme levels for the quarter. I think what you saw was much more an anomaly with respect to oil burn for the quarter.
Did you make that up in price, or was that really just lost margin?
We were economic when we were running on oil.
If we weren't economic, we wouldn't have been running. If you took a look at where gas prices were, gas prices during that part of the year, the very early part of the year, were drifting up, looking like very healthy wholesale power prices as opposed to gas prices, well up into the double digits.
You don't feel that there was a net-net, this was a drag on the quarter. It's just the moving pieces within the revenue and cost lines?
Yeah, I think that's right. I think some anticipated spark for earlier January wasn't quite where we would've wanted it to be because gas prices basically push you into oil, which had lower margin. It was a fairly short-term phenomenon in January and an anomaly. It really does drive all the oil burn that you see there for the quarter.
Great. Thank you.
Your next question comes from the line of Greg Gordon from Evercore ISI. Please proceed with your question.
Thanks. Good morning. While we are on the subject of PSEG Power, there are several initiatives at PJM that are sort of in their pendency, whether it is capacity market design updates, ORDC pricing, fast-start pricing. I believe Andy Ott put out a letter recently indicating that he hoped those three things would get done this year. Can you review what your expectation is for the timing on those and the potential impacts on power? There is one thing extant, which is while the management of PJM still seems supportive of overall price reform, there has not been much progress there. You can give us an update on your expectations on that front.
Sure, Greg. On capacity market reform, we have been public that we prefer the two-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 2019. Obviously, that will not have any effect on the current RPM. I think that is 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 price formation. Fast Start does have now a proposed zero threshold element to it, which is a characteristic of inflexible units, that they cannot 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 Ott himself has said that 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 2019. That is a delay. I think that once upon a time, there was talk of fall of 2018 for some of these reforms, but I think a combination of factors has introduced that bit of delay.
I think the good news, if I might, is that the PJM board appears to be willing to undertake what's called a liaison process as opposed to the 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 two-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 the middle of May. Middle of May, if I'm not mistaken.
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 into the market.
Thank you for the update.
Next question comes from the line of Travis Miller from Morningstar. Please proceed with your question.
Thank you.
Hi, Travis.
Reading through those, 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.
Travis, you absolutely are reading it correctly. The bill simply says that New Jersey wants 40% of its power supplied by nuclear energy, it does not limit it 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, 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. The short answer to your question is yes, out-of-state plants would be eligible, but New Jersey would not support, according to the legislation, more than 40% of its energy being supplied by nuclear power.
Okay. With the thought that Peach Bottom would rank at the bottom, just given it's not in New Jersey.
Well, no, I don't want to predetermine what the BPU will do. Peach Bottom will compete with Salem and Hope Creek and Susquehanna and Limerick. It probably doesn't have to worry about Salem, no, very much, but it does
Yeah, sure. Second question on the clean energy bill, what components specifically could generate rate base growth, if any? Just clarifying a couple of areas.
Oh, my goodness. Well, there's multiple, right? The utility has done grid-connected solar. The utility's done rooftop solar. The utility has done energy efficiency. It has done pilot programs in battery storage technology. 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. I think you just have to really remember what the governor said, is he sees nuclear power as an important bridge to a renewable future. The renewable future he has in that bill, which he has not signed yet, is a 50% renewable target in 2035. We expect to be participants in every aspect of that sustainable energy agenda.
Got you. Those investments you foresee could go into rate base then, not just the-
Oh, yes
earnings neutral type collection. Okay.
That's correct. Yeah. Well, look, the reality is in New Jersey, just given 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's either in the form of a renewable energy credit or some other mechanism. 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. As I said a moment ago, we are all in on the energy efficiency piece.
Okay, great.
I think some elements of the legislation, Travis talked specifically about utilities investing and having recovery on and of 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.
Okay, great. Yeah, that's helpful. Thank you very much.
Your next question comes from the line of Paul Patterson from Glenrock Associates. Please proceed with your question.
Hey, good morning.
Hi, Paul.
Just, sorry if I missed this, but when is the governor expected to sign the nuclear legislation?
Paul, in New Jersey, the governor has 45 days to act on legislation, and that action could be either an outright veto, which would require a two-thirds majority of the legislature 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. Those are the options for the governor.
Okay. 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?
We never comment on our bidding plans prior to the auction. 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.
I see. Okay, I gotcha. Okay. Absent a veto, you guys sort of are expecting that this bill will be enacted.
You never, ever want to pretend to be constraining your governor, right?
Sure. I gotcha.
He's a very important person, and he's a talented person and one that we admire. I'm not going to try to tell him what to do on an earnings call. Having said that, 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 to South Jersey. I feel pretty good about those public statements on his part.
Okay, awesome. 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?
Yeah
or electricity demand working in the state?
Paul Patterson, 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. PSEG'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 a clean energy future. I am absolutely convinced that we can continue to invest in a resilient grid, cleaner energy, and more efficient use of energy, which that third piece would help lower customers' bills and put bigger smiles on our shareholders.
Okay.
I think that energy efficiency is an important part of controlling the bill from the point of view of the extra cost associated with renewable energy and making the grid more resilient.
You guys have demonstrated that too. You guys have been ahead of the curve on that. I guess I'm sort of wondering, though, it does have an impact, perhaps, though, on non-regulated generation, not just in your state, but all over. 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, what you see the demand forecast kind of being.
I see. Oh, yeah. Well, 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 in 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.
Okay. Thank you very much.
Your next question comes from the line of Michael Roberts from Goldman Sachs. Please proceed with your question.
Hey guys, thank you for taking my question. 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 to fund incremental rate base growth or incremental renewable growth at PSEG Power? Just when you think about your credit metrics in a post-tax reform world and the balance sheet strength, how big is that balance sheet strength?
Yeah, Michael, I think you'd want to think about it really in two steps, right? We've talked about the ability to fund the capital plan such as we have without the need for any additional equity. 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've got 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. That can be matched with debt, you'd come up with about 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. Any increment for potential incremental holding company leverage, or do you just think about it as if opportunities came up for incremental investment at Power or at PSE&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, we tend to take a look at what makes the most sense from an economics standpoint when looking to source that debt. I think that it could be at either location, I think you're in the same ballpark when I talk about the numbers that I just referenced.
Got it. Thank you, Dan. Much appreciated.
You got it.
Your next question comes from the line of Paul Fremont from Mizuho . Please proceed with your question.
Thanks. I guess the first question would be on the Clean Energy Act. When I think of the 7%-9% rate base growth target and the fact that you guys are seeing yourself sort of at the upper end, do the investment opportunities under the Clean Energy Act keep you within that 7%-9% band, or would that potentially put you outside of that band?
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 of our pre-filing meeting with the board staff, and we'll definitely have resolution of the nuclear bill by that point in time.
Okay. Sort of a quick question on Hope Creek. The 60-megawatt upgrade that was approved, when would that take effect?
Was it 60 or 16?
16.
16. It was much smaller. I have to get back to you on that, Paul. I don't know the answer. Our nuclear has been jammed with broader issues than the 16 out of the 11. It wasn't equipment. This was a change, I believe, in our probabilistic risk assessment that allowed us to run the plant at different numbers. I'm tempted to say it's coming back. I think coming out of this outage is the right answer, but we can confirm that for you.
Okay.
Any questions we can answer for you, Paul?
No, that's good. Thank you very much, and congratulations.
Your next question comes from the line of Angie Storozynski from Macquarie. Your line is open.
Thank you. 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 heard much about it. Do you think that this is still something you will be interested in? If so, do you think that this would be done organically, or would you need to acquire a retail book? Thank you.
Yeah, Angie. Thanks for the question. No, 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. Whatever book we bought, we'd have to sell off a piece of it, and that would be suboptimal. We're continuing to pursue an organic growth strategy there.
Cool. My other question on the regulated side. Even if your rate base were to grow at 9%, would you consider acquisitions of other regulated under-invested systems around your service territory or in the same state?
Well, 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. We always look at those, right? 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, we've not been able to pencil those in in a way that works. We always look at those possibilities.
Okay, thank you.
Your next question comes from the line of Steven Fleishman from Wolfe Research. Please proceed with your question.
Yeah, hi. Good morning. Sorry to bug you with some clarifications, just on the rate base growth comment, could you clarify 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 seven to nine?
Hi, Steve. I think I'll let Dan dive into that.
Yeah. It's just a year-end 2016 number. 2017 number, which is $17 billion.
Okay. The base is still the same base.
Yep.
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, some opportunity related to future filings. I would say that if we had nothing beyond the GSMP filing, we'd be more middle of the road within that range. With the opportunity for future filings, we could see the opportunity to go higher than the middle of the range.
Okay, it may include some of these clean energy investments or
Yeah, any other adjustments as we step forward through time. Yes.
Okay. Then, yeah, I'm good. Thank you.
Yeah.
Your next question comes from the line of Michael Weinstein from Credit Suisse. Please proceed with your question.
Hi, Ralph. Hey, it's Mike Weinstein. Hey, a quick question. You said before that you prefer the status quo for the current capacity market reforms, I believe. 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 the status quo has new plants being MOPRed as opposed to existing plants being MOPRed. It doesn't interfere with the state's ability to price attributes that the market isn't currently pricing. We just don't see a need for this kind of modification at the current time.
Do you think any-
Okay.
Is it that you think the modifications won't have an effect at all, or?
No. They'll have different effects. I think that the two-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 40-year depreciable life, or if your cost of capital is X or 1.1X or 0.9X. 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. That's not necessarily consistent with markets.
I mean, look, what we're all dancing around here is we need a price on carbon, then let the market pick the technology. 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?
Yeah, absolutely.
You think the capacity market reforms are kind of a distraction of some sort maybe?
You've got a collapse in infra-marginal revenues because there's no carbon price in energy markets. Because of that collapse in infra-marginal revenues, high fixed cost participants are getting crushed. Yet people are saying they want the attributes of these high fixed cost participants. You have the De-contracting . The high fixed cost participant is a nuclear plant. Yet people are paying ZEC prices of anywhere from $5-$200 per ton of carbon. The market's just got these inherent inconsistencies built into it. If we could get a single price on carbon in energy markets, the infra-marginal revenues would increase, the fixed cost recovery would be mitigated. Then capacity markets could do what they were supposed to do, be reliability mechanisms and nothing more.
Got it. Okay. Thank you.
You're welcome. Nicole, I think we have time for one more question. Then we'll, I think, let folks have their day back.
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 public speaking. If you say one more question, there's never more questions, but that's great. Anyway. 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. They range from the continuation of our $13 billion-$15 billion investment program, 90% of which is going to the utility, and leads us to be biased towards the upper end of that 7%-9% rate base growth looking out to 2022 off of the higher base at the end of 2017. Again, we've got to give kudos to the great work done by our utility crews and our power plant operations during what were some very difficult circumstances, certainly in January.
Kudos to our regulatory team and all of our support functions for the strides they've made on some of the policy fronts with the settlement of GSMP2 and the legislation that recognizes the value of Power's 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 that they are much cheaper to keep than they are to let shut down.
Of course, our ongoing commitment to maintain our financial strength, which gives us the 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. Hopefully we'll see all of you on May 31st. I know that's the weekend after. That's Memorial Day. Come in your Chubbies or whatever other beachwear you have, 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 of clothing is what-
Is it?
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. Thank you for your participation.