Good morning. Thank you for standing by, and welcome to the Exelon Corporation 2017 Q3 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Mr. Dan Eggers, Senior Vice President of Investor Relations for Exelon, you may begin your conference.

Thank you, Tony. Good morning, everyone, and thank you for joining our third quarter 2017 earnings conference call. Leading the call today are Chris Crane, Exelon’s President and Chief Executive Officer; and Jack Thayer, 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 of Exelon’s website. The earnings release and other matters which we 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, forecasts 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. I’ll now turn the call over to Chris Crane, Exelon’s CEO.

Thanks, Dan, and good morning and thank you, all, for joining us. We had a solid third quarter of 2017, with GAAP earnings of $0.85 per share, up versus the prior year. Our adjusted EPS was $0.85 as well, reaching the midpoint of our guidance. Strong utility and Genco performance more than offset headwinds from the mild summer weather that impacted our PECO, ACE utilities as well as volumes at Constellation. As we head into year-end, we have a lot to be encouraged about. Our regulatory utilities are continuing to execute very well, running ahead of plan for the year operationally, we are performing in top quartile across most performance measures. We are registering significant improvements at PHI, even relative to last year. We are doing exactly what we said we would do as part of our merger commitments, improving performance and reliability for our customers. We are executing on our CapEx program for 2017. We’re excited about the valuable technologies investments we’re deploying to our customers’ benefit. The FERC is making strides to address pressing resiliency needs for the power system, we see that in a two-step process. Starting with empowering PJM to fix deficiencies in the power price formation by the summer of 2018, and then a longer term FERC process to address resiliency. The Department of Energy Section 403 filing noted a clause in the current price formation are part of the reason that nuclear units, the most resilient and cost effective Zero Emission resources in PJM are being lost of premature retirements. Given our size of our PJM fleet, each dollar or megawatt hour of distortion caused by a flood market design undermines the Genco’s economics by approximately $135 million per year on an unhedged basis. We believe that DOE’s focus on price formation will lead…

Thank you, Chris, and good morning, everyone. Turning to Slide 8. For the third quarter, our adjusted non-GAAP operating earnings were $0.85 per share, which was at the midpoint of our guidance range of $0.80 to $0.90 per share. Exelon’s utilities less Holdco expenses delivered a combined $0.49 per share. Versus our plan, utility results were slightly favorable due to lower O&M and reduced storm activity over the third quarter. Generation earned $0.36 per share, which was a little behind our plan. The third quarter was hurt by mild weather that reduced Constellation load volumes and a lack of price volatility, which reduced optimization opportunities. We did offset some weakness for payable O&M timing. Turning to Slide 9. Our $0.85 per share in the third quarter of this year was $0.06 per share lower than the third quarter of 2016. Overall, utilities benefited from improved earned ROEs and higher rate base, partly offset by adverse year-over-year weather impacts. ExGen was down primarily on lower power prices, lower load volumes due to mild weather and fewer optimization opportunities, partially offset by the addition of New York ZEC revenue and higher capacity prices. Turning to Slide 10. We are updating our 2017 guidance range. We had expected the Illinois power authority to finalize procurement for the ZEC programs in December, which based on our assumptions, would have contributed $0.09 of EPS in 2017 since the revenues are retroactive to the beginning of program on June 1. However, last week, the Illinois power authority updated their schedule pushing the final contract date to January 30, 2018. The delayed timing has no impact on the amount we expect to receive or our free cash flow outlook. But it will change the timing of earnings recognition, shifting EPS into 2018. With that in mind, we…

Thanks, Jack. Turning to Slide 17, I want to take a moment to highlight the contributions made by Exelon and our employees to help the impact by hurricanes Harvey, Irma and Maria. Exelon utilities sent more than 2,200 employees and contractors and support personnel from our six utilities to help with the recovery efforts at Hurricane Irma. Our crews travel to Florida and Georgia where they, for more than two weeks, worked in very difficult conditions. We’re very proud of our employees and the hard work that they do to help the communities come back from after these disasters. A very special thanks to all those who helped in the restoration and support efforts. Exelon employees also stepped up from a volunteer perspective. Our employees have donated their time and resources to communities impacted by the storms. We also had a number of our Constellation employees in Houston directly displaced by the storms and to see coworkers come to their aid illustrates the value that we embody here at Exelon. Slide 18, we want to reinforce our value proposition, which remains the foundation of our commitment to our investors. We’ve continued to grow the utilities rate base at 6.5% and the regulated EPS to 6% to 8% annually through 2020, underpinning the capital investments that directly benefit the customers in each of our jurisdictions. We continue to use free cash flow generated at the Genco to fund incremental equities at the utilities and pay down debt over the next four years at ExGen in the holding company. We’re focused on optimizing the value of our ExGen business by seeking fair compensation for our carbon-free generation fleet, closing uneconomic plants, selling assets where it makes sense to accelerate our debt reduction plans, and maximizing our value through gen-to-load matching strategies. We continue to focus on sustaining strong investment-grade credit metrics and grow our dividend in a stable consistent manner. As many of you are aware, our dividend growth as of October end gets for 2.5% annually from 2016 through 2018. We are working with our board and expect to provide an update on a multiyear outlook for the dividend growth plan as part of our planning and budgeting process that are undertaking currently. Before I go to questions, I want to come back to where we started off in the call. We have a number of positives underlying our outlook. The utilities are growing and executing well. We are confident that the FERC actions around resiliency will facilitate needed power price reforms in PJM that will fairly compensate our generating assets. We continue to improve operations where we’re finding ways to run our business more efficiently and taking out an additional $250 million in cost as discussed. And we’re still on track to generate $6.8 billion of free cash flow through 2020 at ExGen that will support our utility growth, reduce our debt and facilitate growing our dividend. Thank you again for your interest and now we’re ready for your questions.

[Operator Instructions] And your first question comes from the line of Greg Gordon from Evercore ISI.

Hey, Greg good morning.

So just to summarize here, you gave us a negative adjustment on several – I think ExGen that totaled $200 million, but since that mark, you’ve seen $50 million come back. So 2019 is negative $150 million and if you achieved your cost-cutting goals, you essentially have eliminated that. And so we’re at the push in 2019 with those offset, is that correct?

Yes, Greg. And I think as you think about it and you listen on our comments on the low volatility period we’re in, we believe that with the return to normal weather and even potentially future volatility events that, that’s decline in Constellation business could prove temporary. Obviously, the $250 million are permanent cost savings and capitalize all in terms of value creation.

Okay. So as per usual protocol, you’re using the current forward curves for power – what the current margin outlook looks like for retail, you’re not assuming any changes, no volatility premium coming back in the market, no PJM price reform, et cetera?

Hi, Greg its Joe. Yes, we are using the current forward curves for power. I think the big thing to note on the retail side and Jack said this in his script, when we did our planning at the first of the year, our renewal rates for C&I power were up close to 80%. As was the case back in 2012 and 2013, we have seen a downturn in most renewal rates down close to the 70%. And we’re marking this closer to that 70% number. I think the big thing though is back in 2012 and 2013, we saw power – C&I power margins dipped below $2 per megawatt hour. And we’ve said historically our origination margins for that business are somewhere between $2 and $4. We’re still within that $2 to $4 range. So I think the big thing, the takeaway is, we’re going to serve about 200 million-megawatt hours of load this year across our platform between retail and wholesale. And we expect to do the same thing next year. The thing is, we’re just not going to achieve the growth that we expected in our C&I power business. And as Chris said and Jack said, the reason for that is, we don’t think it’s prudent to chase the market. And we’re going to remain disciplined what we think value is and that has served us well historically and quite frankly, has allowed us to acquire companies a few times as well. So we’ll continue to remain disciplined.

Thanks. Sorry, go ahead.

I’ve just said so, the beginning of the question, all the numbers that you hear are on the gross margin are marked at the end of third quarter. So it’s the end of September 29 or 31, whatever the market closed on.

Got you. One – two more questions. One, looking at Slide 20, your cash flow profile, looks slightly better and looks like it’s mainly coming from the utilities and specifically from ComEd. Can you comment on what the changes in the improved cash flow profile there?

So it’s primarily related to the collection of the ZEC regulatory asset as well as cash taxes.

Okay. Final question, when looking at your – at the value proposition you guys are delivering, if we get PJM price formation improvements and you hit on your other financial goals, you’ll start to have a earnings growth profile that looks more comparable to the regulated peer group. They trade at 18 times earnings you’re trading at 14 times current expectations. But your dividend growth – their dividend growth rates average around 5% and yours is 2.5%. I know you said you’re reviewing this, but what do you need to see in terms of your financial outlook to be able to close or eliminate that dividend growth half gap, because I think it’s one amongst several things that keeps your stock from trading at a higher valuation?

Yes, great. We do believe we’re undervalued. And everything that we’re doing is to drive that improvement in valuation. As you can see from the free cash flow, the debt reduction plan, the recovery and rate case, we’re positioning ourselves much better for a potential to have the board conversation in the upcoming LRP planning process to evaluate the dividend. And our expectation is – and has been since we have to cut the dividend four years ago is to get it back to build the business on a strong balance sheet to get the dividend to be in line with our peers. And that is our pursuit and as you can see from these numbers, things are improving that have us – able to have a much more positive conversation with the board. Ultimately, it’s the board’s discretion, but that’s where we want to be.

Thank you very much. Have a great morning.

Thanks, Greg.

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

Good morning, guys.

Good morning.

I wanted to just make sure, at the beginning, Chris, I believe you just gave $1 of market price improvement sensitivity based of your volumes to PJM price reform was $135 million. Did I hear that correctly?

Yes. For a $1 of fully opened position in PJM, 135 terawatt hours, $135 million, so you can – that was just the dollar reference.

Okay. So my question is, I mean, as you look at the kinds of reforms that PJM is considering in flexible unit and the like, what’s your view of the range of potential uplift to any translated into ATC basis that we would rather than view?

Hey Jonathan, this is Joe. We’re still waiting to see some additional details from PJM. But – and so we’re not going to put out a number until we get all of those details. But I have seen the reports that a number of you have compiled on this subject with the range that is somewhere between $2 and $5 ATC movement as a result of the elimination and discrimination. And I think that’s the right range to be thinking about and probably the middle part of that range makes a lot of sense to us.

Okay, that’s helpful. Thank you for that. And then Chris, you’ve said, I think earlier in the year, this dividend revisit in the longer-range growth outlook would be a Q1. And I believe what you’ve just said is pretty consistent with that if you do at is part of the LRP. Is that correct?

Yes. I think we’ve said back in 2016 when we have our dividend strategy, we want to give you a multi-year plan. We gave you 2016 through 2018. That would be the time in the first quarter to be updating, in my belief, set the board’s discussion, and where we go with that, but that would be our timing in my mind in our current plans and communicating with all of you.

What should we be expecting you to give us next week the EEI. No, no [indiscernible]

Yes. EEI, I think we’ll be able to have more of the one-on-one details, get into more of the details on the capital investments and the growth and the rate case strategies as we improve the customer experience at the utilities. We’ll also have more time to go into the detail on the numbers on the free cash flow, debt reduction plans, and the optimization of gen-to-load growth. I’m sure more people are going to want to talk in detail about the basis for our 250, and we can do the deep dive on that, but it will be detailed on what you’re seeing today and an opportunity to have some one-on-one dialogue about it.

Great, thank you. And then I guess, just one other – did you have any thoughts? I know it’s all a bit moving target you’ve been talking. But what’s your level of confidence that you’re going to get to things that you want to see out of the tax reform?

Well, its 11:15, I think or 11:30 Eastern when we see the draft. And we’ll have to rally together with EEI and take a look at how – we as a sector have been positioned. Kind of early to say now if you’ve gone over the last 24 hours, things have been all over the board. So I think to speculate, but we work together in a sector at EEI, and I’m sure Tom Kuhn will be getting us all together and figure out. Our next steps as of the rewrites as they discuss our finalized and getting our input as a sector in there. We’re totally unified at EEI on what we’re looking for and what we think will benefit our customers the most in tax reform. So more to come on that, and maybe we’ll have a little bit of insight of that in EEI as we work through the weekend and see the effect on the proposed and still we got to go back to this is proposed. You don’t know what’s going to happen in D.C., but we’ll be ready to talk about it more, as not only a company, but as a sector.

Sure. I’m sorry to put you on spot on that on a real-time issue.

No, that’s okay.

Thank you, guys.

Sure.

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

Yes. Hey, good morning, Chris.

Hey, Steve.

So just – curious how are you strategizing on your retail business with respect to these potential DOE, PJM changes? And are you doing things to make sure that you don’t have like a big delay in capturing the uptick because of retail hedges, like are you making sure your back to backing your retail and the like I mean just curious how you’re thinking about that?

Hey Steve, good morning. It’s a Joe. We are thinking about that and I think the first thing is, when as Jack said in his script and we said for a while, we’re carrying the longer position relative to our ratable sales plan. So we have the opportunity to capture any upside associated with price increases related to the reforms you’re talking about. I think specifically though the retail, there’s a couple elements to that. The first one is, we’ve done some preliminary remodeling and we take into account kind of the seasonality as well as the differences between on and off peak. So we try to be more surgical in just saying, we’re going to buyback this. We have a view of the things we need to do. I think as it specifically relates to our retail contracts there is two elements. One is obviously, we have contracts from the books already. And we have some hedges on the books already, so there will be a feathering in effect to the value proposition of this. But most importantly, from our perspective, I think one of the things we offer our customers, and it’s really important, is transparency. And what I mean by that is, when they’re signing a contract with us, they completely understand what they’re doing and what the components of that are fixed-price and the components that are going to be passed through in time. And I’m not sure that’s always the case across the industry. So from our perspective, there’s lot of elements, and we are thinking about it and we are really managing our portfolio from a natural long position as well as the seasonality and the products. And we’re keeping the customer in mind.

Okay. And just in terms of just the – that’s helpful. In terms of just the power new business change that you made, what – your sense in making the change. Do you feel like you’ve encompassed kind of a pretty conservative case here at this point, so that this doesn’t become like a series of changes?

Yes. I think – yes. The answer to your question is, yes. We think we’ve covered it and I’ll tell you why. When you look at it, it’s really all driven by load business. About 60% of it’s on our retail C&I business at about 40%. It’s associated with our wholesale polar business and there’s really two elements that is different one on each side. On the retail side, as we said, our renewal rates are lower than we expected them to be, but our margins are well within the range that we expect it. And that’s very different when we have these challenges five years ago, where our margins and our renewal rates both dropped pretty appreciably. On the wholesale side, it’s much more of a margin story, where the volumes are there, but the margins are lower than they’ve been historically. I mean, it’s a very competitive environment. Quite frankly, it’s being driven by a lot of smaller players on the retail side and not the bigger players. On the wholesale side, we’ve seen kind of competition across the spectrum. But we’re confident that we’ve captured the changes we need to make.

Great. And I just finally – I guess in the hindsight, congratulations on adding your Texas gas plants months before all the coal plants shut. But – I’m sure you planned that out. But did you plan that out? But, I’m just curious given that fact just have your thoughts on the Texas kind of market and potential there changed for you? How you’re thinking about that?

It’s Joe again. And we’ve talked about this for a while. When you look at ERCOT reports on what they thought reserve margins were going to be. We never really thought they were going to get the generation group that they expected. And in our own modeling, we have sensitivities, we ran some sensitivities looking at the possibility for retirements. And if you look at our positioning in ERCOT, we’re carrying a long position there relative to our ratable plan as well. And we see the opportunity for volatility. I think this summer, we’ve skewed the some, obviously, with the problems with the hurricane in August and, quite frankly, the biggest thing down there as we continue to see load growth, which is really important. And we don’t see a lot of kind of newbuild of gas generation. You have continued growth on the renewable side, but it’s more concentrated in South Texas than it is West Texas. And when you put all that together, we see the opportunity for increased volatility, and we think we have a fleet that will benefit that.

Thank you.

Your next question comes from the line of Julien Dumoulin-Smith from Bank of America.

Hey good morning.

Good morning, Julien.

Hey, so couple of quick questions, may be going back a little bit on some of the previous discussion here. But with respect to the dividend, how do you think do you think about the stability of cash in the various businesses the various businesses? Obviously, there’s a certain legacy here, but how do you think about the stability from ZEC’s and the retail business? And how do you think about that, at least into the conversation around dividend policy? i.e., can you bank on cash flows out of businesses that are not utilities and/or think about of a higher payout on the core utilities?

Sure. So – as we’ve talked about 4 years ago, 4.5 years ago now, as we restructure the dividend and put our strategy and our focus on really growing the utility business through the acquisition of BGE and then the acquisition of PHI. And it was to theoretically watch the growth in those businesses and have a 70% – 65% to 70% dividend policy, theoretically, at the utilities. Now you know that’s going to cycle during different growth periods. But that was the way we had the dividend set to grow. In the first couple of years, we were starting to get closer to that, giving that accomplished in the early 20s. And so that’s when we came up with the growth policy at 2.5%. As you can see, the utilities are continuing to grow, although right now, it’s taking cash infusion – equity infusion from the Holdco through the Genco. But they’re continuing to grow. So our stability of the dividend is very well anchored. Our growth – potential growth for the dividend is well anchored. As we come through the last couple of years and started to see more reliable or consistent cash flows from the Genco on programs that compensate for the other benefits besides just the energy, you’re seeing a potential that, that can be a dependable cash flow, that can be used for potential return of value to the shareholders. So that’s the way we’re looking at it and we’re presenting it to the board, but the cyclical nature of the commodity market will not leave us, but the certainty of that certain elements on those revenue streams give us the opportunity to look at the world a little bit differently. So that’s how we’ll continue to model it, and we’ve gained greater flexibility with programs like the ZEC.

Excellent. And then, let me ask you this. With respect to the utilities, right? I know we’ve had a lot of conversation on the other side of the business. But obviously, you’ve had some reasonable success of late in ComEd around – how do you say, scaling some of the smart grid efforts? How do you see the ability scale that further? And obviously, this might be getting ahead of the annual process and the CapEx budget, et cetera. But maybe this is more to Anne and thinking about the ComEd prospects beyond 2020 here.

So let me start off and I’ll let Denis jump in here or Anne on the call. The advent of digitalization of the distribution system and the transmission system is offered us an opportunity for capital investments that directly benefit the customers and drive reliability. We have now put in communications backbones to reach smart meters to help us with fault isolators, fast reclosers, that’s the kind of spend, along with replacing antiquated cable and updating the system with new components. Now, as we go into the 2020 and beyond, there is a significant amount of work being done on what else can be done to develop into the smart city that we can better serve the communities while investing and driving efficiency into the systems. And the work that’s being done on microgrids, the experimental work there, to see what the societal benefit in certain microgrids in certain locations. What we can do to integrate with more of the community is there an assistance within the street light programs or assistance that we can provide with our infrastructure on the meter reading of water or gas or other types of systems is where we’ll be going. And I think, this technology is morphing faster than it ever has in our sector. And with our design teams, data scientists, the work that we’re doing on big data, digitization is going to provide us many opportunities for continuing to optimize the system for the customers’ benefit. Denis, I don’t know if I covered it or... Denis O’Brien: This is Dennis. Chris, I think you covered it pretty well. We’re spending about $5 billion year-end capital. We still see opportunities to continue to invest in convergence relative to our systems to build the systems of the future, whether that’s billing systems, transmissions data systems or others. We see opportunities to continue invest in resiliency and security. We’re seeing opportunities relative to the transmission system as we look at resiliency and security and to build the transmission system of the future. Chris hit on smart cities and other things like that. And the last thing as you look at the grid of the future and we think about distributed generation, in order to get our system ready for that, that really means about converting some of our lower-voltage circuits into higher-voltage circuits. And so that’s an opportunity for further capital deployment. So we’re deploying about $5 billion of capital a year. We see that continuing and see lots of opportunities to continue to invest in utilities as usual.

But does that enable kind of accelerating CapEx spend overall? And perhaps, that the core of the question.

I don’t see – it’s accelerating the plan. I think we’re at a point that we’re managing efficiently the spent that we have. We also have to balance the impact to the consumer. Spending capital for the sake as spending capital without finding the efficiencies in the delivery into the benefit of the customer, it wouldn’t be prudent. Right now, the projects that we have on schedule, the cash flow that supports that are managed well and they do support what our bottom line. It needs to be as to the benefit of the customer.

And one thing I’ll add to that. Our focus on we’re 18 months into PHI acquisition. Our focus now is to get the performance to the right level. We had our best year ever in reliability at PHI last year, which we only had the company since March. We’re going to blow it through that level of reliability this year in a good way. So the first couple of years, how do we get the performance to a good place? How do we write the image and reputation, and improve our regulatory outcomes at PHI.

Excellent. Thank you all.

Thanks.

Your next question comes from the line of Stephen Byrd from Morgan Stanley.

Good morning and congratulations on the – announcements and the utility performance.

Thank, Steve.

I wanted to drill into the idea of resiliency laid out as part of energy. Is there a way for us to conceptually think about the valued resiliency or a framework for assessing – how to appropriately value resiliency? It’s been a tricky thing, I think, for all of us to really think through the high-level idea to make sense just sort of how to go about trying to value that. Is that any suggestions you have in thinking about that?

Steve, it’s Joe Dominguez. If you’ve seen our fleeting, you know that we have a multi-phase process where, in the first instance, we need to get analytics from new RTOs. Can they run without pipelines? What’s the impact for the consumers? We can move from there to design basis for the system that we think is going to iterate between NERC, FERC and kind of the Department of Energy sometime after we get the data. In terms of how we ultimately implement that into the system, I think once we’ve the design basis, is what we are trying to avoid, we will start looking at mitigation solutions, maybe the retention of additional fuel secure resources to avoid this outage risk. But I think it’s premature to get there. One way you can think about is, though, you can take a look at the capacity performance program. We were able to value the cost of incremental reliability associated with dual fuel. So if the design basis ultimately ends up being we need 90 days of fuel, we have a mathematical way of calculating what’s the market solution to get dual fuel resources to 90 days of fuel with it. That would probably be the $8 or $10 of megawatt hour in terms of doing that based on the cost we saw in CPAY. So that’s one approach. But from our perspective, we need to drop back here, take a look at the data, make sure we have the right definition of resiliency, the right design basis and then we come back with market solutions or other solutions that we would ensure resources to mitigate that risk and provide the security we need that we provide to our end customers in the nation.

And I think the key to that, what Joe said, is a market solution.

Understood. Within that market construct that we have that makes sense. So I want to just shift over the retail business. There’s been a lot of discussion on this call around. Just the competitive playing field, if we do see FERC performs on power price formation and if power prices do rise, would you expect to see a bit of a shakeout amongst smaller retail players? You are not backed up by physical generation. You may misprice the upside risk to power prices. How do you assuming again that we do see kind of formation we expect? Would you say a shakeout there?

Yes. I think history tell us we would ends up in a volatility of event. And then go back for a number of years. We’ve seen players whether the big or small, whether they are on the C&I side, the residential side or quite frankly, the power loads on the wholesale side. We’ve seen folks who aggressively price the risk or the ultimate price to the customer have been hurt. And as I said, earlier, we had opportunities to acquire companies in that type of environment. We’ve the opportunities to grow our business organically. And we think remaining disciplined to what we’re doing is the right thing to do. We still have almost 25% of the C&I market. We’re the number one C&I marketer by a huge amounts. We’re the third largest residential marketer in the United States and we compete in all the wholesale power options. So the underlying business is strong. The growth we expect we’re not achieving and I think what discipline will serve us well and we have opportunity to capture some of that back when we see the volatility of event.

That’s great, that’s all I have. Thank you.

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

Thanks. Good morning. So my question goes back a little bit to the dividend discussion. And what I was trying to connect the dots on was, you’re already kind hitting your leverage targets, your free cash flow targets, right now, with the current plan. If you do have price reform and if you do have further ZECs coming from other states, then you have that incremental free cash flow. How should we think about that capital allocation? Is that more to both of dividend or way do you think that capital allocation go?

First of all, we will look at it in a disciplined way on what is the best way to return value to the shareholders, while maintaining our commitment to the customers. So the plan, as I said, earlier that we started out on over 4.5 years ago is working. We’re reducing our debt. We’re strengthening our balance sheet. We’re reducing our cost. We’re able to make solid investments in our utilities, and we’ve been able to do a part of a dividend increase program as we were doing that. As you can see, as we get stronger and stronger, opportunities for us to deploy the capital are coming our way, and we’ll make sure that we will look at it in a disciplined fashion. If there are more accretive ways to spend the capital in the utilities, and in a low risk area, that will be something we look at. But as we’ve committed previously, and as we’ve signaled, it’s a conversation that’s ongoing right now. There is opportunities to revise the dividend policy and give you another multi-year plan as we work through the LRP planning process. And we work with our board heading into 2018.

Got it. That’s very helpful. And secondly, in terms of the ZEC’s, if you could just touch on how you think of ZEC’s plays out in different states – in other states obviously, very high in there. And secondly, how does that fit in with the price formation and the DOE reform. Do you see them interacting? Or if you see them as completely independent?

And this is Joe, again. We’re pleased to see the upcoming in the Connecticut the other day, where all the different structure, the type of premises the same nuclear units are critical for our customers. And we need to preserve them. So that means as set forth on policy front there. We have been very productive discussions both in Pennsylvania and New Jersey. We’ll continue to do that. In terms of the interaction, I see between programs, if we get an upside in price formation, I think that will ultimately be taken into account in the process. So it will not be a double dip here. If prices increase as result on price formation, the cost of the ZEC’s or the cost of the support payments will go down. That’s anticipated.

Got it. And you think that’s a dollar per dollar adjustment? Or do you think there’s some benefit that you do keep?

No. I think it’s a dollar per dollar adjustment.

Got it. That’s super helpful guys. Thanks so much.

And for closing remarks. I will now turn the call over to Chris Crane.