艾索倫電力 (EXC) 2017 Q3 法說會逐字稿

Good morning, and thank you for standing by, and welcome to the Exelon Corporation 2017 Q3 Earnings Conference Call. (Operator Instructions) Thank you.

Mr. Dan Eggers, Senior Vice President of Investor Relations for Exelon, you may begin your conference.

Thank you, Toni. 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. We're joined by other members of Exelon's senior management team and 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 today 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, and operationally, we're performing in quarter 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 are deploying to our customers' benefit.

The FERC is making strides to address pressing resiliency needs for the power system, and we see that in a 2-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's Section 403 filing noted the flaws in the current price formation are part of the reason that nuclear units, the most resilient and cost-effective 0 emission resources in PJM, are being lost to premature retirements. Given our 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 are 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 cost by $250 million on a run-rate basis in 2020, primarily at the Genco, including today's announcement we're in a cost -- our O&M cost, versus planned by over $700 million annually from initiatives identified since 2015.

We continue to challenge our businesses to evaluate cost, and today's announcement savings are part of that ongoing effort.

We're confident in our previous 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 price -- 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 businesses 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'll 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 1 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 at the utilities -- 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, and particularly want to call out the tremendous improvements at PHI compared to last year. With the 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 benefit going to our customers with the integration of PHI into Exelon. And finally, as in prior quarters, our best-in-class nuclear 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 market and ensure that our customers continue to benefit from a 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 a 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 step in preserving resilient baseload generation as well as delivering economic and environmental benefits that nuclear power uniquely provides. We expect 135 terawatt hours of our generation output in PJM to benefit from price uplift that will layer in over the coming years as the existing hedges roll off.

Second, we think FERC can take on -- take the time to fully evaluate market reforms that will ensure power supply resiliency. This is a multifaceted exercise that should take into account the cost and impact to our customers and economy of the long-term interruption of a natural gas fuel supply -- interruption of the natural gas and 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 process being made at FERC and PJM, 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 have 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 with 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, tightening the top and bottom of the range by $0.05. So we're now at $2.55 to $2.75 per share. The strong performance of utilities is allowing us to still target the midpoint of our original guidance range 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 off 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 rate cases resolved over the past year are driving a better-earned ROEs at PHI. For the legacy Exelon utilities, our earned ROEs remained over 10% but abated a bit from the last quarter with the less favorable year-over-year weather impacts at ComEd and PECO that you can see on Slide 9's waterfall.

Overall, Exelon utilities ROEs are still nearly 10%, including PHI. We're proud of the performance of our overall utility business, and we still see 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. This settlement provides a 4% rate increase, with new rates implemented earlier than what would have occurred if the case was fully litigated. The timing 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 approved 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 for 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 through 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 2 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 the planned growth in the Capitol Riverfront and Southwest Waterfront areas for 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 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 the shifts in revenue recognition for the Illinois ZECs from 2017 to 2018, which we also show in the waterfalls on Slide 21 in the Appendix.

The capacity in 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 helped 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, largely reflecting the effect of the mild summer and reduced optimization opportunities. We are highly hedged for the rest of this year and are well balanced on 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 2 categories. The first relates (inaudible) business in our unhedged power position. We're lowering our assumptions from MISO and New York capacity prices based on recent spot year options and bilateral deals in the market. This lower the capacity in 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 ZECs, while the $15 million decline in 2019 just reflects the lower outlook for the past 2 revenues. During the third quarter, we also saw declines in energy prices, including some adverse news and basis differentials in the PJM East's sum, which costs another $50 million in 2018 and '19. 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 powered new business to go line. 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 risk 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 suppliers since the polar vortex has led to better margin discipline with our unit margins holding consistent with prior years. We are, however, seeing lower renewal rates compared to last couple of years, moving from something closer to 80% to the low 70s. At 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 to Constellation from 2018 and 2019. Notably, even against a 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 '19 incorporate C&I renewal rates in the low 70s and wholesale margins hovering around the bottom end of what we've realized over time. We've been through these periods of low load pricing -- lower load pricing in the past and has previously 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 who misprice 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 are $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 to power market reforms that represent real value uplift for us. We're maintaining 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 2 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 have been many puts and takes this year at ExGen that have both benefited and weighed on 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 the EGTP plants and changes to base CapEx and 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 3x debt-to-EBITDA target for ExGen's balance sheet, which we will meet over our 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 -- by hurricanes Harvey, Irma and Maria. Exelon utilities sent more than 2,200 employees and contractors and support personnel from our 6 utilities to help with the recovery efforts after Hurricane Irma. Our crews traveled to Florida and Georgia where they, for more than 2 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 utility's 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 4 years at ExGen and the holding company. We are focused on optimizing the value of our ExGen business by seeking fair compensation for our carbon-free generation fleet, closing uneconomic plant, 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 rate metrics and grow our dividend in a stable consistent manner. And as many of you are aware, our dividend growth program is 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 we're 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 the 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.

So just to summarize here. You gave us a negative adjustment on several things at ExGen that totaled $200 million, but since that mark, you've seen $50 million come back, and so '19 is negative $150 million and if you achieve your cost-cutting goals, you'll essentially have eliminated that. And so we're at a push in '19 with those offsets. Is that correct?

Yes, Greg. And I think as you think about it and if you listened 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 -- the decline in Constellation business could prove temporary. Obviously, the $250 million are permanent cost savings and capitalized all in terms of value creation.

Okay. So as per usual protocol, you're using the current forward curves for power, but 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 curve for power. I think the big thing to note in 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 '13, 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 '12 and '13, we saw power -- C&I power margins dip 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 on what we think value is and that will serve us well historically and quite frankly, has allowed us to acquire companies a few times as well. So we'll continue to remain disciplined.

Sorry, go ahead.

No, I'm just going to say -- so the beginning of the question, all the numbers in here 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. 1 -- 2 more questions. One, looking at Slide 20, your cash flow profile. Looks slightly better and it 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 an earnings growth profile that looks more comparable to the regulated peer group. They trade at 18x earnings, you're trading at 14x 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, Greg. 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 in 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 4 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 in -- 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 wanted to be.

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

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

Yes. For $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 when you translate it into the ATC basis that we would rather view?

Jonathan, this is Joe. We're still waiting to see some additional details from PJM. But -- and so we're not going to be putting out a number until we get all of those details. But I have seen the reports that a number of you have compiled on the subject with the range that is somewhere between $2 and $5 ATC movement as a result of the elimination and the 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. And then, Chris, you've said I think earlier in the year that this dividend revisit and the longer-range growth outlook would be Q1. And I believe what you just said is pretty consistent with that, if you do it as 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 multiyear plan. We gave you '16 through '18. That would be the time in the first quarter to be updating, in my belief. It's at the board's discretion on where we'd go with that. But that would be our timing in my mind in our current plans in communicating with all of you.

What should we be expecting you to give us next week the EEI. No, no, not the EEI, what items?

Yes. The 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 million, and we can do the deep dive on that, but it will be detail on what you're seeing today and an opportunity to have some one-on-one dialogue about it.

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

Well, it's 11:15 and 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 hate to speculate, but we work together in a sector at EEI, and I'm sure Tom Kuhn will be getting us all together and we'll figure out our next steps as the rewrites, as they discuss, are finalized in 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 at EEI as we work through the weekend and see the effect on the proposed, and still we got to go back to this as 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.

Sorry to put you on the spot on that on a real-time issue.

No, that's okay.

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

So just -- 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.

Steve, 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 to retail, there's 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's 2 elements. One is, obviously, we have contracts on 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 (inaudible) and what the components of that are 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 a 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 in 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 terms of making that change, is your -- 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 our load business. About 60% of it is on our retail C&I business and about 40% is associated with our wholesale polar business and there's really 2 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 had these challenges 5 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 I'm just curious, given that fact, just have your thoughts on the Texas kind of market and potential they're changed for you? How you're thinking about that?

It's Joe again. I should go in. 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 growth that they expected. And in our own modeling, we have sensitivities. We ran some sensitivities looking at the possibility of retirement. 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 some, obviously, with the problems with the hurricane in August and, quite frankly, the biggest thing down there is 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.

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

A couple of quick questions, maybe 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 a dividend policy? I.e., can you bank on cash flows out of businesses that are not the utilities and/or think about of a higher payout on the core utility?

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 75% 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, that the cyclical nature of the commodity market will not leave us, but the certainty of certain elements on those revenue streams give us the opportunity to look at the world a little bit differently. So -- but 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 conversations 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 an ability to scale that further? And obviously, this might be getting ahead of the annual process and the CapEx budget, et cetera. But can -- 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 has 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's 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...

I think -- this is Denis. Chris, I think you covered it pretty well. We're spending about $5 billion of 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 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? Maybe perhaps, that's the core of the question.

I don't see us 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 flows that supports that are managed well and they do support what our bottom line. It needs to be as to benefit the customer.

And one thing I'd add to that. Our focus is -- 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 through that level of reliability this year in a good way. So the first couple of years, you're -- how do we get the performance to a good place. How do we right the image and reputation and improve our regulatory outcomes at PHI.

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

I wanted to drill into the idea of resiliency laid out by the Department of Energy. Is there a way for us to conceptually think about the value of 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 makes sense just sort of, how to go about trying to value that. Any suggestions you have in thinking about that?

Joe?

Steve, it's Joe Dominguez. If you've seen our pleading, you know that we have a multiphase process where, in the first instance, we need to get analytics from the RTOs. Can they run without pipelines? What's the impact to the consumers? We can move from there to design basis for the system that we think is going to iterate between NERC, FERC and the Department of Energy for some time after we get the data. In terms of how we ultimately implement that into the system, I think once we have the design basis, what we're trying to avoid, we will start looking at mitigation solutions, maybe the retention of additional fuel secured resources to avoid this outage risk. But I think it's premature to get there. One way you can think about, though, if you 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 the market solution to get dual fuel resources to 90 days of fuel would be. That would probably the $8 or $10 of megawatt hour in terms of doing that, based on the cost we saw on 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 could come back to market solutions or other solutions that will ensure we have the resources to mitigate that risk and provide the security we need to provide for our customers and 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. I wanted to shift over to the retail business. There's been a lot of discussion on this call around 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 who don't -- were not backed up by physical generation who may mispriced the upside risk to power prices? How would you -- assuming again that we do see the kind of formation changes we expect, would you see a shakeout there?

Yes. I think history tells us we would. Anytime would see volatility event, and then we could go back for a number of years, we've seen players, whether they're big or small, whether they are on the C&I side, in the residential side and quite frankly, the polar loads on the wholesale side, we've seen folks who've aggressively price the risk or the ultimate price to the customer have been hurt. And as I said earlier, we've had opportunities to acquire companies in that type of environment. We've had 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 #1 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 polar options. So the underlying business is strong. The growth we expected we're not achieving, and I think the discipline will serve us well and we have opportunity to capture some of that back when we see the volatility event.

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

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 in 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 goes?

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, the opportunities for us to deploy the capital are coming our way, and we'll make sure that we'll look at it in a disciplined fashion. If there are more accretive ways to spend the capital in the utilities, in a low-risk area, that would be something we'd 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 multiyear plan as we work through the LRP planning process. And we work with our board heading into 2018.

Got you. That's very helpful. And secondly, in terms of the ZECs. If you could just touch on how you think ZECs play out in different states. In other states, obviously, very happy there. And secondly, how does that fit in with the price formation in the DOE reform? Do you see them impacting or do you see that as completely independent?

This is Joe again. We were pleased to see the upcoming in Connecticut the other day, where all the different structures, the central premise is the same. Nuclear units are critical for our customers, and we need to preserve them. So definitely a step forward on the policy front there. We're having very productive discussions both in Pennsylvania and New Jersey. We'll continue to do that. In terms of the interaction I see between the programs, if we get an upside in price formation, I think that will ultimately be taken into account in the process. So there will not be a double dip here. If prices increase as result on price formation, the cost of the ZECs or the cost of the support payments will go down. That's anticipated.

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.

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