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Exelon Corp
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Good morning and welcome to Exelon 2018 Second Quarter Earnings Call. My name is Nora and I will be facilitating the audio portion of today's interactive broadcast.
This event also features streaming audio which allows you to listen to the show through your PC speakers. And for those of you on the stream, please take note of the option available in your event console.
At this time, I'd like turn the show over to Dan Eggers, Exelon's Senior Vice President of Investor Relations. Please go ahead, sir.
Thank you, Nora. Good morning, everyone, and thank you for joining our second quarter 2018 earnings conference call. Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer; and Joe Nigro, Exelon's Chief Financial Officer. They're joined by other members of Exelon's senior management team who will be available to answer your questions following our prepared remarks.
We issued our earnings release this morning along with the presentation, both of which can be found in the Investor Relations section on Exelon's website. The earnings release and other matters which we'll discuss during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today's material and comments made during this call. Please refer to today's 8-K and Exelon's other SEC filings for discussions of risk factors and factors that may cause results to differ from management's projections, forecast and expectations.
Today's presentation also includes references to adjusted operating earnings and other non-GAAP measures. Please refer to the information contained in the Appendix of our presentation and our earnings release for reconciliations between the non-GAAP measures and the nearest equivalent GAAP measures. We scheduled 45 minutes for today's call.
I'll now turn the call over to Chris Crane, Exelon's CEO.
Thanks, Dan, and good morning, everybody. Thank you for joining us today. We understand it's a busy earnings release period. So thanks for being with us.
Starting on slide 5, we're pleased to deliver another great quarter. We achieved strong financial results while continuing to enhance our operational performance and make meaningful gains at our utilities on both the regulatory side and the legislative fronts. Taken together these advances will support our continued strategy to invest in infrastructure, in technology at our utilities delivering better service for our customers.
For the quarter, on a GAAP basis, we earned $0.56 per share versus $0.10 last year. On a non-GAAP basis, we earned $0.71 per share versus $0.56 last year, which is above the midpoint of our $0.55 to $0.65 per share in the guidance range and puts us in a strong footing for the year.
Turning to slide 6, at the utilities, we continue to execute at top quartile levels across key customer satisfaction and operating metrics. The investments we are making are paying off in improving reliability, strong customer satisfaction, which in turn strengthens our relationships with our regulators. All of our utilities are achieving top decile performance in KD, which measures the average speed, which we are able to restore power when outages occur. We are also delivering leading performance across the utilities on customer service metrics as we share best practices and give customers more tools to connect with the utilities when they need service. Safety still remains our highest priority and the targeted programs implemented last quarter are driving improved results.
At ExGen, nuclear generation output was 39 terawatt hours with a capacity factor of 93.2%. We had 41 fewer outage days compared to last year. Our gas and hydro fleet continue to perform very well with economic dispatch match rate of 97.8%.
Turning to slide 7, I'm happy to report that the tax savings from our FERC regulated transmission assets will benefit our customers by an additional $175 million, adding these benefits to the $500 million of savings from our distribution operations that we discussed on last call. Our 10 million utility customers will realize over $675,000 of an annual benefit from tax reform. We're pleased that our constructive relationships with our state regulators in FERC allow us to pass these benefits back to our customers in a very timely fashion.
Flipping over to slide 8, in June, Delaware and Pennsylvania both passed important legislation that reflect our utility priorities in the present and for the future supporting infrastructure investment and positioning for the utility of the future, respectively. In Delaware, state regulators passed the Distribution System Investment Charge. This will support needed infrastructure investment to enhance the system improve service to our customers. It will provide a mechanism for a more consistent and gradual rate increase for our customers, while also allowing for a more timely recovery on our infrastructure investments. Delmarva Power, Delaware plans to make its first filing in the fourth quarter with new rates effective by the first quarter of 2019.
In Pennsylvania, Governor Wolf signed legislation authorizing the Pennsylvania Public Utility Commission to review and approve alternate rate mechanisms that will better position PECO to make investments in the utility of the future. The forward-looking regulatory design options in the legislation include a decoupling mechanism, formula rates, multi-year rate plans and performance-based rates. Both of these laws will help to ensure that our utilities can deploy much needed capital to support reliability and performance of the grid for our customers, while also decreasing the frequency of traditional rate cases.
I want to especially thank the broad group of stakeholders in both Delaware and Pennsylvania for the support of these laws. We look forward to finding common ground across all our jurisdictions, as we focus on improving customer service and investing in the utility of the future.
Slide 9, turning to the ZEC programs, in both Illinois and New York, we are awaiting final decision from the Federal Appeals Court. We are pleased with the Solicitor General's brief filed in the Illinois case in the Seventh Circuit, which agreed that the states have the authority to enact the ZEC programs. We remain confident in our legal position in both the cases, and continue to collect the ZEC revenues as they are being adjudicated.
In New Jersey, following Governor Murphy's signature, the Board of Public Utilities is beginning to implement the ZEC program there, which we expect to take effect around the end of the first quarter 2019.
On the Federal Energy policy front, FERC issued an order on PJM two capacity market mitigation proposals. The order rejected the two-stage capacity re-pricing of multiple RECs proposal submitted by PJM and it also determined that the existing tariff is unjust and unreasonable. Instead FERC established a new proceeding to introduce a two part proposal. The first proposal is to expand the current MOPR to ensure that most if not all plants that receive out-of-market payments will be subject to a minimum offer requirement.
The second proposal, however, would allow the plants receiving out-of-market payments to avoid the MOPR and instead be withdrawn from the market along with the commensurate amount of load. This asset specific FRR can be implemented by the states to align with the state's environmental policies. FERC has set a schedule to allowing 60 days for comments, 30 days for replies, and a goal of reaching the final decision by January 4.
We disagree that the MOPR is necessary. We are encouraged that FERC has now said that all assets receiving out-of-market payments should be treated the same. The implementation details will matter but we believe that the partial FRR design could allow states to advance their energy policy goals, which we think is critical to ensure the needed reduction in carbon emissions.
With respect to PJMs work on price formation, we continue to look forward for a decision from FERC on the fast start by September and PJM has committed to implement the rule changes in a timely fashion after the FERC order, including reengaging stakeholders on a full integral relaxation. PJM continues to work through reforms to which storage pricing rules included those related to reserves in the operating reserves demand curve pursuant to the deadlines it had set for those rule changes.
Finally on resiliency, PJM has taken the input and the assumptions and the scenarios that it needs to model in order to assess fuel security of its generation fleet. This will allow PJM to move forward on evaluating potential changes to market design to ensure that it is properly valuing the fuel security, while it awaits further direction from FERC in the open resilience docket. We see all these changes as essential to preserve the effective competitive market in PJM and we applaud the ongoing efforts to design and implement these changes.
Now, I'll turn it over to Joe and he can walk through some of the numbers.
Thank you, Chris, and good morning, everyone. Turning to slide 10, we had a strong quarter financially, delivering adjusted non-GAAP operating earnings of $0.71 per share which is above the $0.56 per share we earned in the second quarter of 2017 as well as our guidance range of $0.55 to $0.65 per share. Exelon's utilities less Holding Company expenses delivered a combined $0.37 per share. Compared to our plan, the utility results were better on higher distribution revenue from the approval of the Pepco Maryland settlement, a transmission revenue true-up at BG&E and favorable weather impacts at PECO.
Generation earned $0.34 per share in the second quarter, which was also better than planned. Upside came from realized gains from our nuclear decommissioning trust. Our nuclear plants had another strong quarter with fewer outage days compared to both last year and what was budgeted for this year. And we benefited from favorable market conditions including FTR settlements in PJM. These were partially offset by higher allocated transmission costs.
We are reaffirming our full year guidance range of $2.90 to $3.20 per share, which you can see on slide 19. We expect to deliver operating earnings of $0.80 to $0.90 per share in the third quarter compared with $0.85 last year.
Turning to slide 11, the $0.71 per share in the second quarter of this year was $0.15 per share higher than the second quarter of 2017. Our utility earnings were collectively up $0.04 per share compared to last year, driven primarily by higher rate base and mill rates associated with completed rate cases. Generation earnings were up $0.12 per share compared with last year benefiting from fewer planned and unplanned nuclear outage days, contributions from the Illinois ZEC program and higher realized nuclear decommissioning trust gains partially offset by lower power price realizations.
Moving to slide 12, our utilities continued to execute financially as we look at our trailing 12-month earned ROEs. Starting with PHI, we made modest gains at each utility as we continue to deliver improved operational and financial performance since the merger. Pepco's higher earnings reflect the distribution rate cases from last fall and the recent Pepco Maryland settlement that took effect on June 1, 2018.
Looking to next quarter, Pepco's earned returns should benefit from a full quarter of the Maryland settlement reached in April and a partial quarter benefit from the pending DC settlement.
Delmarva's earned ROEs now include the benefits of interim rates in Delaware that took effect in March 2018, and at Atlantic City Electric we saw higher earnings from the ACE settlement effective October 2017, which was largely offset with higher O&M and depreciation expense. We expect to see ROE improvement with full flow through of the October 2017 settlement. For all of the PHI utilities, trailing 12 month ROEs in the fourth quarter should show additional uplift as the FAS 109 changes from the fourth quarter of 2017 drop out of the calculation.
For the legacy Exelon utilities, our earned ROEs remained over 10%, lifting the consolidated utilities platform to nearly 9.5% including PHI. We are happy with our overall utility performance but still see room for improvement at PHI as the better operating performance translates into higher earned returns. And as we have said before, we are confident in our ability to deliver on our plan and still expect earned ROEs in 2019 to be in the 9% to 10% range across the utilities.
Turing to slide 13, we remain busy on the regulatory front. On the last call, we discussed settlement arrangements in April at both Pepco DC and Pepco Maryland, providing revenue decreases of $24.1 million and $15 million respectively after reflecting tax savings benefits for customers. On May 31, the Maryland PSC approved the settlement for Pepco Maryland with rates effective on June 1. For Pepco DC, the Commission is expected to approve the settlement in the third quarter with rates effective shortly thereafter. We are also able to reach a settlement in our Delmarva, Delaware electric distribution case on June 27, 2018 making it the second consecutive electric case we have settled in recent history. The case will provide a $7 million revenue reduction inclusive of tax benefits. We expect a final order in the third quarter.
As Chris noted earlier, Delmarva Power, Delaware expects to make its first filing under the Distribution System Investment Charge tracker in the fourth quarter of 2018, with the new charge appearing on customer bills by the first quarter of 2019.
We also have a number of rate cases still in play. On June 8th, BG&E filed for a $63 million increase to its gas revenues and a $22 million STRIDE surcharge reset with an order expected in January 2019. BGE's continued investments in STRIDE and gas systems safety and reliability programs are driving the need for this requested increase. In Delaware, we have an outstanding gas distribution rate case at Delmarva that is scheduled for completion in the fourth quarter. In Pennsylvania, PECO filed for an electric distribution base rate case in March for the first time in three years. We expect to receive an order in the second half of this year. Finally, on April 16th, we filed for rate updates at ComEd as part of the standard annual formula process. We expect to receive an order in the fourth quarter.
We appreciate the hard work of our utilities and regulatory teams. Our investment is focused on improving system reliability and the customer experience are having positive benefits in the communities we serve. By delivering on a regulatory strategy, we're able to make these investments, while also earning a fair and timely return on the capital being deployed. More details on the rate cases and their schedules can be found on slides 27 through 33 in the Appendix.
Turning to slide 14 and continuing on the topic of capital investment at our utilities, we invested $1.3 billion of capital at the utilities during the second quarter and are at $2.6 billion year-to-date. We remain on track to meet our $5.5 billion capital budget for 2018.
Today, I would like to highlight two additional projects that are part of our overall budget and offer real benefits to our customers and communities. The first is PECO's gas main and service replacement program. The project will replace nearly 1,800 miles of gas mains and service lines of which 520 miles has already been completed.
We continue to work with the state to accelerate the implementations having shortened the replacement cycle at the start of the program from 30 years to 20 years, today. These efforts will reduce risk on the distribution system by replacing aged materials, which we believe is good for our customers.
The second project relates to BGE's investments in Trade Point Atlantic or TPA. Over the next five years BGE will invest $150 million in transmission and distribution infrastructure including construction of a 93 megawatt substation. These investments will support the new 3,100 acre commercial industrial TPA development in Baltimore County, which is projected to generate 17,000 permanent jobs, plus an additional 21,000 during construction. This project is another example of our efforts to continuously work with our states to identify and support development efforts that drive economic growth in our service territories.
Turning to slide 15, it provides our gross margin update for ExGen. This quarter we have included the New Jersey ZEC revenue in our 2019 and 2020 disclosures for the first time. Relative to our last update, we saw some movement within the buckets. Our total gross margin in each year is unchanged from our last update with the exception of an additional $50 million in both 2019 and 2020 associated with the New Jersey ZEC revenue. For 2018, open gross margin was up $100 million primarily due to higher NI Hub and PJM West Hub prices, offset by weakening ERCOT spark spreads and our hedges. We had a strong quarter in new business execution creating $200 million of Power New Business in our retail and wholesale channels as we capitalized on ERCOT volatility.
In 2019 and 2020, total gross margins are up $50 million in each year with the New Jersey ZEC revenue, which shows up in the capacity and ZEC line. Open gross margin is up $100 million in 2019 due to higher prices in New York Zone A and PJM West Hub. Open gross margin is flat in 2020. We also executed $50 million of Power New Business in 2019 and 2020.
We ended the quarter basically in line with our ratable hedging program in 2018 and 10% to 13% behind ratable in 2019 and 6% to 9% behind ratable in 2020 when considering cross commodity hedges where we have increased our concentration. We remain comfortable being more open when we look at the market fundamentals compared to forward prices particularly at NI Hub.
Turning to slide 16, we remain committed to maintaining a strong balance sheet and our efforts on this front have been noticed with Fitch placing Exelon, PECO, and BG&E all on positive outlook in June. Our consolidated corporate credit metrics remain above our target ranges and meaningfully above S&P thresholds. We are forecasting ExGen's leverage to be 2.6 times debt-to-EBITDA at year-end 2018, which is below our long-term target of 3.0 times.
On a recourse debt basis, we are at 2.1 times, which is well below our target. We will continue to manage our balance sheet at ExGen over time to the 3.0 debt-to-EBITDA level. So look for us to focus on debt reduction at both HoldCo and GenCo.
I will now turn the call back to Chris. Thank you.
Thanks, Joe. Turning to slide 17, again, we had a strong financial quarter and operationally that is a testament to the hard work and dedication of our employees. Our financial footing and sounding continues to gain momentum. Here again, I'll restate our proposition value.
We continue to focus on growing our utilities targeting 7.4% rate base growth and 6% to 8% EPS growth through 2021. We continue to use free cash from the GenCo to fund incremental equity needs at the utilities, pay down debt over the next four years at ExGen and the HoldCo and fund part of the faster dividend growth. We continue to focus on optimizing value for the ExGen business by seeking fair compensation for our carbon free generation fleet, supporting proper price formation in PJM and resiliency initiatives at FERC and working to develop capacity market reforms at PJM pursuant to the recent FRR order. We continue to close uneconomic plants and sell assets where it makes sense to accelerate our debt reduction plans and maximize value through the gentle load matching. We continue to sustain strong investment-grade credit metrics, as Joe pointed out, in our growth driven consistently at 5% through 2020.
With that operator, we can now open it up for questions.
Thank you. Your first question comes from the line of Ali of SunTrust. Your line is open.
Thank you. Good morning.
Good morning, Ali.
Good morning. The first question on the PHI utilities, what's the aspiration there? I mean, are those utilities and the way the system is set up, are they set up that they can ultimately earn their authorized ROE or will there be a permanent lag in the system and when do you think you will be at the maximum in terms of your earned versus allowed ROE (24:22)?
So there is a lag component at a couple of the PHI utilities now that we're working on. We've talked about ACE. We think we have the right legislative package to help that reduce that in Delaware and we're also working on different proceedings at Pepco Maryland and Pepco DC. We project it to be within the 9.5% range by the end of 2019. We're on track to do that. We have the developed activities that are helping. We also have the efficiency programs we're putting in place. So, I think we're well on plan. We recognize the legacy issues that were happening around that and are having constructive dialogue with our legislators as we've done in Delaware, our regulators, as we're doing with the filing in New Jersey and we'll continue to focus on that.
Okay. And then Chris to the extent that Forex proposal for PJM and the FRR aspect of it does become law and moves forward. How do you look at that relative to your portfolio and what that means for Exelon?
Well, you can imagine. I'm going to let Kathleen Barrón cover that. But, as you can imagine, there's a lot of evaluation that we have to do right now to really choose the path that benefits our customers and our fleets. So, Kathleen?
Yeah. Thanks for the question, Ali. I think what we're facing here is markets that because they're not pricing pollution are making emitting resources look less expensive and they're pushing out clean resources, including ours, as you know, 10.6 gigawatts of uncleared nuclear in the last auction.
I think what FERC is saying in this order is that rather than letting RPM continue to push those units out, they're giving safety opportunity to pull them in and instead of paying PJM to support units that perhaps they don't want to support they can directly pay those assets. And so, as Chris said in the opening of the call, implementation details certainly matter. But we think this is an extremely constructive approach to allowing states to choose the resources, the clean resources that they need to continue to keep running to achieve the our goals of reducing carbon and air pollution for their citizens.
Okay. And last question with regards to the pending litigation in New York and Illinois, any marker we should be keeping an eye on to give us some framework of when the decision might come from either of those states?
Unfortunately, we have no way to know exactly when those orders will issue but the cases have been fully briefed and we expect them to issue any time. There is nothing that we know that's holding them up.
Thank you.
Your next question comes from the line of Greg from Evercore ISI. Your line is open.
Hey, good morning. I'm happy we're on a first name basis now.
Thank you, Greg.
Joe, just a question for you with regard to the quarter. I mean, obviously the numbers were quite robust, but there was $0.05 of positive earnings from NDT. I mean that's not necessarily – I know that that moves around every quarter, but I wouldn't consider that necessarily the highest quality earnings. But even if you exclude that, you were still ahead of your prior guidance range. So can you just walk us through what you think sort of a clean basis and was that still in excess of your expectations?
Yeah. If you subtract the $0.05 for NDT, Greg, what I would say is, when you look at it overall, the midpoint of our range was $0.60. We obviously earned $0.71 on an operating basis. A little more than 50% of that was coming from the utilities. And as I mentioned in my prepared remarks, it is driven by three things: the transmission settlement at BG&E, the yearly implementation of the rate settlement at Pepco Maryland, and as well as stable weather at PECO were the big drivers there. And then the balance was GenCo and NDT was a big piece of that but we also had favorable market conditions related to the FDR option during the quarter. Our Generation performance was stellar, and then it was offset by some transmission costs. So you could see even subtracting out the NDTs, the performance was very strong across the operating businesses.
Right. And I heard you indicate that you're – and show that you're running well below your debt to EBITDA target and thus you can address that by using your cash to – in addition to funding rate-based growth, dividend, not just think just think about paying down ExGen debt, but also working down parent debt. But there's a bigger issue here, which is that you know the FFO to debt targets that the rating agencies are holding you to seem excessively high relative to the declining risk profile of the company. What has to happen to evolve the conversation with the rating agencies to get a lower threshold? And is it really dependent on getting more certainty on capacity and energy market reforms at this point since you've shown demonstrably that you're one of the best operators on the utility side of the house in the country?
Yes. So Greg, we have been and will continue to have dialogue with all the rating agencies. You heard Joe's conversation on Fitch. We've had a good dialogue with S&P. They understand our strategy, they're wanting to see it consistently implemented. They recognize that it is being consistently implemented. I think you know a couple of milestones coming through with the final approval from the Appellate Court on the ZECs, making that revenue look much more like regulated revenue, continuing to follow our path on debt reduction, which part of that is building balance sheet space, de-risking, but also part of it is liability matching with the nuclear assets and their life into the 30s and 40s. So we just have to continue to execute on our plan. We're having very positive dialogue. We appreciate the Fitch positive. We look forward to hearing from the others and hopefully shortly that they're seeing it and we'll be able to talk about not only moving thresholds, but potentially a more positive rating.
Okay. My last question you may have already demonstrably answered previously, but if in fact, you're given – you and the states are given the option of pursuing an FRR type structure for plants that are deemed to be important in those regions. Does the legislation that you currently have in Illinois and New Jersey for instance create the flexibility to do that or would you need to go back to your legislators and engage them in a restructuring of that legislation to give them the flexibility they would need to bring those assets out of the capacity market and properly compensate them?
Hey, Greg. It's Kathleen. We're currently looking at existing legislative authority in all of our states. And so I think it's going to depend on the jurisdiction. And it's also going to depend on what FERC's order ultimately says about what authority states will be to exercise in order to take advantage of this option. So I think, it's going to differ depending on the state. But we're currently evaluating the best path forward in each of the states that have clean energy targets that we think this order will help them meet.
Okay. Thank you all. Have a great day.
Thanks, Greg.
Your next question comes from the line of Steve of Wolfe Research. Your line is open.
Hi. Good morning. Hey, Chris.
Hi.
Just I guess, you know it's hard to kind of interpret a lot of these FERC proposals in different directions. You also had the Mystic decision. And so, maybe you can just give a broader perspective of what they're trying to achieve here and just what could change versus this initial proposal before we hear kind of I guess a final structure by early next year?
Yeah. So the fight – the disagreement within the stakeholders is around the supplemental income that is being received for the social benefit of carbon reduction within our states. We lack a federal policy as you know on carbon, although the conversation continues and that would be the ultimate fix. That would really level the playing field and allow the states to skip (34:15) support of federal policy. Short of that, the states have deemed – the majority of states that we operate in that they want to preserve the low carbon output that they have.
They understand that 60% of the power in the State of Illinois is carbon-free, 90% of that is nuclear. We start shutting down nuclear plants like you look at the FE announcement, every penny that's been spent in PJM and outside of PJM on REX to achieve a lower carbon output would be wiped out. It's like we threw the money away. So you've got a very passionate belief within some of our states that they want to keep these assets. PJM has been unable under the current tariffs to be able to separate and support at this point the environmental needs of their stakeholders. So what this allows from FERC is a positive move to say if the administration and the legislation in New Jersey wants to preserve a low carbon future for its state and for its citizens. It allows Illinois to do the same thing. If New York wanted to look at something, it could do something for New York. So I think, this is finally setting the final decision on how we manage these assets that may be out of the capacity revenue stream, not clearing, but the state wants to keep them. We had Secretary Perry at the FitzPatrick Plant yesterday with Congressman Katko and it was very positive. I mean we are gaining momentum, but not only in his opening comments, in the press conference and with our tour in discussion with local officials, is he concerned about the economic benefits of the plant. He's concerned about the reliability and the resiliency on the fuel diversity and he's also commented on their capabilities for low carbon.
So you've seen us go back and forth between ZECs and between other programs to try to save. We've seen the arguments from other stakeholders against it and I think this gives us a path to finally put it to bed.
Okay. That's helpful. And just one other question on it, if you were to get into kind of an FRR structure like, do you have any sense on like how long that would be i.e., you know if that's kind of a form of reregulation of the plant, is that for good, is that for you know a set amount of time like the ZECs are?
Yeah. Steve, I'll jump in on that, that's certainly one of the implementation details that will be worked out through the FERC docket, but it's important to know we're not talking about reload (37:27) regulation, we're talking about an alternative way to pay the units for capacity, and let the states choose which units they'd like to pay for capacity as opposed to letting RPM select the assets. So it's a step towards the future that Chris identified, that we anticipate will be short-term. The current FRR structure as you know allows units or zones to step out of RPM for a five year period with the option to come back in. And ultimately if we get this to the longer term carbon solution that Chris identified, then these decisions will be made by the market through a carbon price and that will be a longer term structure that will benefit our customers.
Got it. Thank you very much.
Sure.
Your next question comes from the line of Julien of Bank of America. Your line is open.
Hey, good morning.
Good morning, Julien, how are you doing?
Good. Great. Thank you. Just to clarify the last question actually if we can start there. I just want to make sure I'm hearing this correctly. Is your expectation that states would actually move through the motions to file for this FRR or is it rather that your expectation that status quo would maintain itself with respect to just continue to clear assets or attempt to clear assets given wherever your avoided costs might be?
Julien, it's Kathleen. I think it's the former that we would expect states to be looking very closely at this opportunity, not just because of course of the nuclear [Technical Difficulty] (39:02) the renewable fleet effects, any asset efficiency demand response that's receiving support from customers directly. And so there are a lot of stakeholders who have an interest in making sure that the states are going to be able to do clean capacity procurements and have that capacity recognized by RPM – by PJM rather.
And you've confidence that you can indeed find a way from a regulatory path to support an FRR implementation including compensation for the units, if that's where it goes in both Illinois and New Jersey, to be clear?
Yes, sir.
All right, excellent. Now, let me turn back to the utility side of the equation here where things are booming obviously. Can you comment on the New Jersey side with CapEx? I mean we've talked a lot about New Jersey in the context of the nuclear plants, but obviously the Governor is implementing a lot more than that, maybe energy efficiency filings, offshore wind seems to generate some opportunities at ACE. Just curious how you're thinking about that and what's reflected in the budget as it stands today?
Hi, Julien, it's Anne Pramaggiore. How are you?
Good, thank you.
Good morning. On the New Jersey side, obviously with the new legislation, there's a couple of areas that we're looking into, it's subject to – a lot of it's subject to regulatory proceedings that are yet to come. So you would not see what we would be looking at reflected in the budgets or the earnings to-date. But there's an area around energy efficiency, we traditionally have not been involved in energy efficiency programs except for some program funding in the past, and that's one of the things we'll look toward going forward.
So to the extent that there's capital investment in energy efficiency, voltage conservation programs, you could start to see those reflected going forward. We also have opportunity to invest in storage and solar going forward in New Jersey. But again, these are all subject to proceedings, at the commission before we have a sense of exactly what that looks like. But we think there's tremendous opportunity here especially as we think about utility of the future, the kind of businesses that we can be in looking forward, serving customers with the types of programs and products and services that they like. So we think there's a great platform there, but some work to do with the regulatory agency.
The only thing I'd add to that is, we have a very high sensitivity to rates on our customers. As you know that that part of the state has gone through a downturn. And so as we make the investments which we can do efficiently, we're going to keep a constant focus on those rates. So we're not impairing the future development of commercial, industrial or residential customers.
Excellent. Thank you all very much.
Your next question comes from the line of Michael of Credit Suisse. Your line is open.
Hi, guys. Thanks for taking my call.
Hi, Mike.
Hey. Can you talk a little bit about what your expectations are for the summer power market in Texas, given I guess it's gotten off to kind of a mild start? And then also talk about the recent acquisition on the retail side that you guys executed with FES and what the implications are for Constellation from that?
Okay. Hi, Michael. It's Jim McHugh from Constellation. As far as ERCOT summer, what we've seen is some volatility in the forward markets and the weekly markets going into delivery and even in the day ahead markets, we've seen some pricing that exhibited on the ORDC curve, some higher price spikes. In the real-time market, it hasn't come to fruition. So it's led to a large spread between day ahead and real-time. In real-time, we really saw great operating conditions. The wind performed at or better than forecast. There were minimal generation force outages, so the generators all performed very well, and there were some good demand response availability.
But prior to going into the period, we saw weeks trading as high as $800 or $900 and the month of July and August trading in the $200 range. As far as our portfolio, performed well, we're able to take advantage of some of that market volatility we saw in the forward markets. You saw that we executed $200 million of new business this quarter for 2018 on the power side, a good chunk of that is represented by our activity in Texas and what we're able to do and our gen-to-load strategy proved valuable once again. We were able to serve the high load and the high demand with our peaking fleet and the options that we owned.
Going forward, I think we expect that volatility to continue. You'll have continued demand growth of 1 gigawatt to 1.5 gigawatts a year with really some wind and solar build out and very little thermal gas combined cycle generation build out. So that volatility will continue, next summer is trading right around the $100 right now and we would expect you would see the same exhibited volatility on the forward curve between now and delivery period of next summer.
For the acquisition of FirstEnergy, it's a great fit for our portfolio. We would be paying $140 million subject to price adjustments based on market moves before the process is over. But there's 900,000 customers on the C&I side and residential side across six states. It'd be a great fit for our gen-to-load and gen-to-customer strategy that we've been deploying. We'd also be buying some certain power in basis hedges as part of the process. So it's a strong complement to our existing portfolio and it would provide repeatable and sustainable customer business through renewals and brand recognition for us.
Hey, just a quick follow-up. I think you said that earlier in the call that you're a little closer to ratable in hedging for 2020 I think it was versus 2019. And I'm just wondering, should I be reading anything into that that you're becoming closer to ratable as you go further out, is that sort of a negative take on the power markets or?
No, Michael, it's not. It's actually we're just building that position, as we hedged the third year of our three year program, we'll continue to grow that behind ratable position. We're currently about 7% or 8% behind ratable in 2020. We've added some gas hedges and cross-commodity hedges to further expose ourselves to upside in power markets. The concentration of our behind ratable position is largely in NI Hub and ERCOT. So I wouldn't read into that. I think our position is similar and growing to be similar across both those years.
Great. Thank you very much.
Your next question comes from the line of Praful of Citigroup. Your line is open.
Thanks so much. Hi, guys.
Hi.
So just wanted to get a sense for getting back to the capacity auction on the capacity market reform piece. If the states are required to kind of support the asset both from the ZEC payment as well as (46:33), are there any winners, losers in terms of states, I think would make it more difficult to get done especially in this timeframe. Are there some states who will be more inclined to get this versus others?
I can take that one as well. It's certainly going to depend on the state's readiness, how quickly this gets implemented. So I take the question to be one of what kind of transition period might we be looking at, and I think that's going to be a subject of active debate in the paper hearing at FERC, as to whether there needs to be some sort of transition period to allow states to understand what the rules are and take advantage of them. So I think you should look for that to play out as part of the FERC process.
Got you. Thank you. And then in terms of ERCOT, if the volatility clearly has been high, should we expect that if there are retail players struggling at the back end of extreme volatility that you're looking to expand your retail position or is there any goals that you see to kind of expand your portfolio position in ERCOT at all?
Hi Praful, it's Jim again. I think we did see going into the summer, one small retailer go out of business with the new collateral posting requirements by ERCOT, which include a look at the forward markets. It might be harder for some of the smaller retail providers to manage their balance sheet if they're undercapitalized through those collateral requirements. For us, I think strategy is the same. We'll look for good value propositions. Our track record with Integrys and Con Ed and what we're looking at now with the FES book will continue to be the same to look for value. As far as the lag effect, you may see the impact of the volatility for the larger players impact maybe in the longer term as the contract tenures and the extended start dates are further out in the curve. So they're currently contracting for load out two or three years forward.
Got you. Thanks. And just quickly just, I mean, ExGen O&M cost reductions, I noticed their target, I think 75% in 2018, 50% by 2019. Is that all on track right now?
It's not only on track, it's Crane, Praful, it's not only on track. We are continuing to work to become more efficient, continue to compete in the markets we're in. We are on track to achieve those if not to exceed those, so we're in good shape.
Excellent. Good to hear. Thanks so much, guys.
Thank you so much. I would like to turn the call over back to speaker, Chris Crane. Please go ahead, sir.
Yes. Thanks. And thanks again for everybody joining the call. As you can see from the strategy that we put together years ago, we're right on track, if not ahead of schedule and we will continue to keep you updated. Look forward to the third quarter calls, but also Dan and Joe and I are getting back out and making sure we drop in and answer any of your questions, so making ourselves available during the third quarter will be a big part of our plan to continue to communicate. We thank you very much and have a good day.
This concludes today's conference call. You may now disconnect.