Exelon Corp (EXC) — Q3 2017 Earnings Call Transcript

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 the 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 technology 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 due to premature retirements. Given the size of our PJM fleet, each dollar or megawatt hour of distortion caused by a flawed 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 to a successful process at FERC that will eliminate these distortions by the summer of 2018. We have not reflected the value of these reforms in our forecast that we’re showing you today, but we do believe they could be a significant positive for us starting in 2018. Finally, we are executing on our management plan, focused on strengthening our operation and continuing to find efficiencies. To that end, we lowered our costs by $250 million on a run-rate basis in 2020, primarily at the Genco, including today’s announcement we’re in our costs, our O&M cost versus planned by over $700 million annually from initiatives identified since 2015. We continue to challenge our businesses to evaluate costs and today’s announcements savings are part of that ongoing effort. We’re confident in our previously announced plan to generate $6.8 billion of free cash flow at the Genco through 2020. That will fund our utility growth, grow the dividend and meet our debt reduction commitments. It is this deliberate work that positions us well to face some headwinds. After a series of mild summers and winters, we have seen decline in power market volatility, which is weighing on the forward power prices, impacting the Constellation business. Just as we experienced during periods of low volatility, we’re again seeing less discipline by some of the wholesale and retail competitors in the market as they become more aggressive with their pricing. We have been through low discipline, low volatility periods before, and they end up in the same way. Those without discipline fail; that is when we can grow our market share by winning business at good margins or acquiring low business offered for sale. We expect volatility to return to the markets with normal weather conditions, which will benefit our Constellation and Generation business. In the meantime, we remain disciplined in our bidding strategy and remain behind our ratable hedging in our generation. Last week, the Illinois Power Authority shifted its schedule for finalizing the procurement of the Illinois ZEC contracts by one month from late December 2017 to late January of 2018. Based on our assumptions, this delay will shift $0.09 of EPS from 2017 to 2018. Even with the unanticipated EPS shift, we’re narrowing our 2017 guidance to $2.55 to $2.75 per share, keeping us on path to the midpoint of our original guidance as the utilities outperformed our plan. Moving on to Slide 6, I want to highlight our excellent operational performance for the quarter. The color block chart continues to show strong quartile – top quartile performance across all of the utilities in most categories. I particularly want to call out the tremendous improvements at PHI compared to last year, with a 22% improvement in reliability, with PHI on track for their best year ever in reliability and a 17% improvement in speed of restoration of outages. Performance improvements like these really highlight the benefits going to our customers with the integration of PHI into Exelon. And finally, as in prior quarters, our best-in-class nuclear and power fleets performed with very high reliability in the quarter. Moving to Slide 7. Now let me turn to the proposed rule issued by Secretary Perry in September. The order is aimed at protecting our customers from outages, resulting from man-made and natural interruptions on the gas system by preserving resilient generation sources, including nuclear. We commend the Secretary for focusing attention on the need to reform the energy markets and ensure that our customers continue to benefit from the resilient system. FERC is currently considering the DOE’s proposal, with the first round of comments filed on October 21, reply comments due on November 7, and the final order scheduled for December 11. We have shared our perspective on this important policy initiative. First, we think the FERC should direct PJM to evaluate and correct any deficiencies they see in energy price formation, which have put baseload generation assets at a disadvantage. We believe timely action on price formation could be implemented by as early as mid-2018. These reforms will be valuable first steps in preserving resilient baseload generation and delivering economic and environmental benefits, the nuclear power uniquely provides. We expect 135 terawatt hours of our generation output in PJM to benefit from price uplift that will occur in the coming years as the existing hedges roll off. Second, we think FERC can take the time to fully evaluate market reforms that ensure power supply resiliency. This is a multi-phase exercise that should take into account the cost and impact to our customers and the economy of the long-term interruption of a natural gas fuel supply. We believe these are important issues that need to be addressed for our country’s future, but they require more analysis to ensure the right reforms are implemented. We are encouraged by the progress being made at FERC and PJM, and support for price formation changes. Between these efforts and state initiatives, we’re optimistic about the path to preserve nuclear power plants and their critical economic, environmental and reliability roles that they play in the communities that we serve. I’ll now turn the call over to Jack to take us through the numbers.

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 the 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 are updating our 2017 EPS guidance range, heightening the top and bottom of the range by a nickel. So we’re now at $2.55 to $2.75 per share. Strong performance of utilities is allowing us to still target the midpoint of our original guidance range despite absorbing the $0.09 of ZEC timing impact. Moving to Slide 11. Our utilities continue to execute delivering strong earned returns in the quarter, in addition to the robust operational performance Chris already discussed. Looking at the trailing 12-month book ROEs, we saw improvement at PHI compared to last quarter across all jurisdictions except ACE, where they rolled out favorable weather in the third quarter of 2016 for the less beneficial summer weather this year. Our efforts to improve operations and the contributions from the rate cases resolved over the past year are driving better earned ROEs at PHI. For the legacy Exelon utilities, our earned ROEs remained over 10%, but abated a bit from last quarter with less favorable year-over-year weather impacts at ComEd and PECO that you can see on Slide 9 of the quarter call. Overall, Exelon’s utilities ROEs are still nearly 10%, including PHI. We’re proud of the performance of our overall utility business and we still see an opportunity to improve our returns at the PHI utilities as we bring their performance to levels more consistent with the rest of our utilities. On Slide 12, we update the status of our rate cases. At Atlantic City Electric, we reached a settlement for the second case in a row. The settlement provides a 4% rate increase, with new rates implemented earlier than what would have occurred if the case was fully litigated. The timing of rate making in New Jersey is helping us make beneficial investments for our customers. While still a work in progress, the investments are having an impact with outages down 33% and average customer outage time down 35% compared to 2011. We also received an order for Pepco Maryland that granted an electric distribution base rate increase of $32.4 million based on an allowed ROE of 9.5%. The improved electric delivery rates became effective on October 20, 2017. We filed rate cases in the third quarter for Delmarva Delaware electric and gas and expect orders by the third quarter of 2018. We’re proud of the hard work from our utilities and regulatory teams. These efforts are helping to bring PHI’s earned ROEs to allowed levels while we simultaneously improve performance for our customers. More details on the rate cases and their schedules can be found on Slides 34 to 42 in the Appendix. Turning to Slide 13. We regularly update you on our progress on the regulatory front, but another essential aspect of the business is effectively deploying capital on behalf of our customers. We’re currently on course to deploy our targeted $5.3 billion of capital in 2017. We’ve highlighted on this slide, two of the many notable projects we’re developing to benefit our communities and customers. The first is Pepco’s Waterfront Substation. This substation is part of the larger capital grid project and is currently under construction with expected completion in 2017. Once complete, it will improve reliability to existing customers and support planned growth in the Capitol Riverfront and Southwest Waterfront areas in the next 20 to 30 years. The other project I’d like to highlight is ComEd’s Grand Prairie Gateway transmission line that was energized earlier this year. It’s a $200 million, 60-mile-long transmission line in Northern Illinois that provides structural benefits to the market, resulting in lower energy and congestion charges to customers, and an increased import capability of approximately 1,000 megawatts. Over the next 15 years, customers collectively will save over $120 million and carbon emissions will be reduced by nearly 500,000 tons. These are just a couple of examples of how we continue to invest prudently across all our utilities and look forward to sharing more as we go forward. Slide 14 provides our gross margin update for ExGen. Before I get into the market developments impacting gross margins, let me first discuss the impacts from a shift in revenue recognition for the Illinois ZEC from 2017 to 2018, which we also show in the Waterfalls in Slide 21 in the appendix. The capacity and ZEC line declines by $150 million in 2017 and increases by $150 million in 2018, offset by $50 million in other capacity declines, which I’ll discuss in a moment. The rest of the bars help to then isolate movements in underlying gross margin not related to ZEC timing. In 2017, gross margin is down $50 million compared to last quarter, partially reflecting the effect of mild summer and reduced optimization opportunities. We are highly hedged for the rest of this year and are well balanced for our generation to load matching strategy. Turning to 2018 and 2019, separate from the Illinois ZEC timing, our gross margin is down $200 million for each year and can be bucketed into two categories. The first relates to business and our unhedged power position. We are lowering our assumptions for MISO and New York capacity prices based on recent spot year options and bilateral fields in the market. This lowers the capacity and ZEC line by $50 million on a rounded basis from last quarter. For 2018, the line shows up as a positive $100 million after the timing uplift from $150 million of Illinois ZEC, while the $50 million decline in 2019 just reflects the lower outlook for past revenues. During the third quarter, we also saw declines in energy prices, including some adverse news and basis differentials in the PJM east, which caused another $50 million in 2018 and 2019. However, with the recent rally in power prices, we have already recovered about half of the $100 million of 2019 gross margin declines for Generation. We also see a $100 million decline in gross margins in 2018 and 2019 from the Constellation business, reflected in the lower power new business to go live. A series of mild summers and winters have contributed to reduced power market volatility, which in turn is impacting the competitiveness of our load business. As we’ve witnessed in prior periods of low price volatility, some of our competitors are mispricing risk in an effort to win business. In the wholesale load business, we’re seeing other players mispricing risks as we consider the market risk from weather volatility, basis variability and the likely impact of energy market reforms that Chris talked about earlier. Against this backdrop, we are clearing at margins near the low end of historical realizations. In the C&I business, the consolidation of the suppliers since the polar vortex has led to better margin discipline, with unit margins holding consistent with prior years. We are, however, seeing revenue renewal rates compared to the last couple of years moving from something closer to 80% to low 70%. These lower renewal rates, we still expect our volumes to be flat year-over-year, whereas our previous guidance assumed higher renewal rates that will drive volume growth for Constellation in 2018 and 2019. Notably, even against the challenged market backdrop, we’re holding volumes and margins flat, which is a testament to the strength of our retail platform and our disciplined approach to bidding business. The updated gross margins for 2018 and 2019 incorporate C&I renewal rates from the low 70s and the wholesale margins hovering around the bottom end of what we’ve realized over time. We’ve been through these periods of low load pricing in the past, and as previously said, it has created opportunities for us. A return to normal weather will inject some power market volatility, which will positively impact forward power prices for Generation. Retailers and wholesalers in mis-priced risk have consistently been driven from the business when we go from a period of low volatility to a volatility event. When the market corrects, we’ll be there to win business at good margins and grow volumes and market share, just as we had in the past. Even against the current market backdrop, Constellation continues to generate strong earnings and free cash flow. Our gen-to-load matching strategy remains a competitive advantage relative to our peers, contributing positive margin and providing a vehicle to bring our generation output to market in a disciplined manner. From a hedging perspective, we ended the quarter approximately 11% to 14% behind our ratable hedging program in 2018 and 10% to 13% behind ratable in 2019 when considering cross-commodity hedges. We remain comfortable being more open when we look at market fundamentals. Spot natural gas prices this year at $3 per Mcf, which is $0.50 higher than last year in spite of mild weather this past winter and summer. However, these higher prices have provided only modest uplift to spot power prices this summer, while the forward prices have decreased slightly. We think that a return to more normal weather and volatility in the market will help reverse this. And as Chris discussed, we see a path for power market reforms that represent real value uplift for us. We’re maintaining an additional link to be able to monetize these reforms. Turning to Slide 15. We continually challenge our organization to find operating efficiencies and focus on managing our cost. To that end, we’re announcing another wave of O&M cost reductions, building on previous years’ efforts. We will ramp these new initiatives over the next two years, as shown on the lower-right table, reaching a $250 million annual run rate in 2020. The savings will come primarily from ExGen and the corporate center. If you look at this initiative together with the programs we’ve announced since 2015, we’ll strip out over $700 million of annual run rate cost, providing significant earnings and free cash flow benefits. Turning to Slide 16. We appreciate that there are many puts and takes this year in ExGen, but we have both benefited from our free cash flow outlook through 2020. When we take into account the movement in power price forwards through the end of October, updated gross margin outlook for Constellation, the benefit of further cost cuts, the early closure of TMI and exit of EGTP plants, and changes to base CapEx in working capital associated with all these business updates, we remain confident in the free cash flow outlook and capital allocation commitments we made at the beginning of the year. We’re also committed to meeting or beating our 3 times debt-to-EBITDA target for ExGen’s balance sheet, which we will meet over the planning horizon. On the fourth quarter call, we will roll forward the free cash flow outlook for the next planning period. And with that, I’ll turn the call back to Chris.

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 of 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 after Hurricane Irma. Our crews traveled 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 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 and 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 growing our dividend in a stable consistent manner. As many of you are aware, our dividend growth as of the end of October gets for 2.5% annually from 2016 through 2018. We are working with our board and expect to provide an update on a multi-year outlook for the dividend growth plan as part of our planning and budgeting process that we are currently undertaking. 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 costs 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.

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 offsets, is that correct?

Yes, Greg. And I think as you think about it and you listen to 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 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, it’s 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 in 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 the 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 are 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 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 an 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 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 had 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 allows us 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.

Good morning.

I wanted to just make sure, at the beginning, Chris, I believe you just gave $1 of market price improvement sensitivity based on 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 of 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, to 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 expect you to provide next week at the EEI?

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, it's 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, not only as a company, but as a sector.

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

No, that’s okay.

Thank you, guys.

Sure.

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 you’re backing up your retail and the like? I mean just curious how you’re thinking about that?

Hey Steve, good morning. It’s Joe. We are thinking about that and I think the first thing is, 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 are a couple of elements to that. The first one is, we’ve done some preliminary modeling 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 buy back this. We have a view of the things we need to do. I think as it specifically relates to our retail contracts, there are 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 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 are lots 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% on our wholesale polar business, and there’s really two elements that are different 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 expected. And that’s very different than when we had these challenges five years ago, where our margins and our renewal rates both dropped pretty appreciably. 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 hindsight, congratulations on adding your Texas gas plants months before all the coal plants shut. But – I’m sure you planned that out. But I’m just curious given that fact just how your thoughts on the Texas kind of market and potential there changed for you? How are you 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’ve run some sensitivities looking at the possibility of 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 new build 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 from that.

Thank you.

Hey, good morning.

Good morning, Julien.

Hey, so a 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 about the stability of cash in the various businesses? Obviously, there’s a certain legacy here, but how do you think about the stability from ZECs 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 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 start 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 to 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 communication 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 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...

This is Denis. Chris, I think you covered it pretty well. We’re spending about $5 billion of 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, transmission data systems or others. We see opportunities to continue to 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’s 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 spend that we have. We also have to balance the impact to the consumer. Spending capital for the sake of 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 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 the 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.

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

Thanks, 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 there 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 the 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 makes sense. So I want to just shift over to 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 tells us we would ends up in a volatility of event. And then go back for a number of years. We’ve seen players whether they are 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 priced 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 in 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 amount; 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 an opportunity to capture some of that back when we see the volatility of events.

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

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 bolster the dividend or where do you think that capital allocation will 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 costs; 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 capital are coming our way, and we’ll make sure that we 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 are 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.

And this is Joe. We’re pleased to see the upcoming in Connecticut the other day, where all the different structures, 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 the 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 a result of price formation, the cost of the ZECs or the cost of the support payments will go down. That’s anticipated.

Got it. That’s very helpful. And secondly, in terms of the ZECs, if you could just touch on how you think of ZECs playing 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 do 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. That’s super helpful, guys. Thanks so much.

Thank you.