Good morning. My name is Brandi, and I will be your conference operator today. At this time, I would like to welcome everyone to the Exelon Corporation Third Quarter 2016 Earnings Conference Call. [Operator Instructions] I would now like to turn the conference to Dan Eggers, Senior Vice President of Investor Relations. Please go ahead.

Thank you, Brandi. Good morning, everyone, and thank you for joining our third quarter 2016 earnings call. Leading today's call are Chris Crane, Exelon's President and Chief Executive Officer; and Jack Thayer, Exelon's Chief Financial Officer. They're joined by the 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, comments made during this call and in the Risk Factors section of the earnings release and 10-Q, which we expect to file later today. Please refer to today's 8-K or the 10-Q and Exelon's other filings for a discussion of 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 a reconciliation between the non-GAAP measures to the nearest equivalent GAAP measures. We've scheduled 45 minutes for today's call. I'll now turn the call over to Chris Crane, Exelon's CEO.

Thanks, Dan, and good morning to all of you. We appreciate your time and interest in Exelon and joining the call today. We hosted our Analyst Day in August, and you have a lot of information that we passed on to understand the business and our value proposition. With that fresh in your mind, today's call will focus on the third quarter results, some business updates, including actions we are taking with recent power weaknesses. We had a great third quarter across our utilities Constellation and our generating fleet. Our GAAP basis -- on a GAAP basis, we earned $0.53 versus $0.69 last year quarter-over-quarter. On the operating basis, we earned $0.91 a share, up from last year's $0.83 per share and well above our guidance range of $0.65 to $0.75 per share. Jack is going to cover the details on earnings drivers, but let me make a few observations. At the utilities, the hot summer weather was a big help, with revenues up on higher volumes of electricity sold and lower cost with less storm activity across the system. The excellent reliability we provided to our customers over a hot summer reinforces the benefits of our capital investment programs. ExGen had a great operational quarter, with the nuclear fleet producing more power ever in a quarter. Finally, Constellation really hit a sweet spot in the third quarter. The sustained hot weather enabled us to sell high volumes of electricity to customers while limited price volatility brought the cost to serve the customers down, allowing us to profit on both volumes and margins. The continued success at Constellation in the third quarter reinforces the value of our gen to load matching strategy. So if you look at Slide 6, as we talk about best-in-class operation, at the Analyst Day, we emphasized best-in-class operation across all our businesses, which we see as the ticket of entry at the utilities and economic imperative at the Generation business. And I'm happy to report that the third quarter was operationally strong. On our color block charts highlighted operating performance and customer satisfaction for the utilities, legacy Exelon utilities remain almost entirely first quartile. I'm proud of our customer satisfaction results, but am disappointed with our OSHA results, and we are taking corrective actions and should get these numbers back to first quartile shortly. At PHI, we are encouraged by the process we're making. Although some of this success has been helped by good weather and limited storm activity, we still have a long way to go to meet the reliability commitments we've made, but we are working hard to provide the service our customers deserve. I mentioned already but the nuclear team had a very good quarter, with a capacity factor of 96.3% and no unplanned outage days even with the summer's sustained heat. For the year-to-date, the nuclear capacity factor is at 94.8%. Constellation also had a great quarter, completing the acquisition of ConEd Solutions and beginning that integration. We continue to see a robust renewable rate, with margins in contract durations holding at levels we discussed at the Analyst Day. So I want to thank all of our employees for excellent operations over the quarter and professionalism in what was a very hot summer with fantastic results. On the regulatory team side, at the utilities are very busy as we work through a full load of rate cases at PHI, in particular. We've completed one rate case at PHI. The New Jersey BPU unanimously approved the ACE rate case settlement in August, yielding a good outcome. It brought needed benefits to the New Jersey customers months earlier than we would have litigated the case. We appreciate the efforts of all the parties in New Jersey in making this happen. We are encouraged by the progress that we are making so far, but we're also aware that improving operations and returns at PHI will take time. These are the first sets of rate cases. We plan to refile at each PHI utility again in 2017. We -- it will take 2 cycles to, what we believe, align our revenues with the significant capital being deployed to benefit our customers, improve reliability and help the environment overall. Talking about our key priorities, for us, is finding economically sustainable paths for our financially challenged nuclear plants. We're currently on very different paths but expect clarity this quarter in New York and also Illinois. In New York, we're making progress on finalizing the contracts with NYSERDA and expect to have them signed for all 3 plants in November. This aligns with the expected approval from New York PSC on the acquisition from the FitzPatrick plant. We expect the CES from GINNA Nine Mile I and II to add approximately $0.08 to $0.10 of EPS and expect FitzPatrick to add another $0.02 to $0.08 per share a year, depending on the refuel outage schedules. As expected, a group of independent power producers filed a challenge in federal court. The lawsuit does not request a stay or an expedited trial, and we continue to believe that the CES design is sound, and that it will withstand any legal challenge. In Illinois, we continue to work with a wide group of parties on a comprehensive energy package that would preserve the Clinton and Quad Cities stations operating rights. It will advance the utility investment aimed at energy efficiency and reliability and will support further growth in renewable energy production in Illinois. The time line is short for the resolution, with 2 windows during a 6-day veto session in November and the beginning of December. We remain hopeful that we can reach a constructive solution that truly is of best interest for our state and our fellow Illinois citizens. But absent of the action during the upcoming veto session, both facilities will close. We are moving forward with the retirement of the plants. We have already notified PJM of our intent to retire Quad Cities and will inform MISO in the beginning of December if the legislation does not pass. A few years ago, we asked you to wait a while we worked through the process in Illinois, and we have appreciated your patience. We are now very close to the ultimate resolution in both Illinois and New York. So with that, I'll turn the call over to Jack, and he will walk you through the numbers.

Thank you, Chris, and good morning, everyone. My remarks today will cover our third quarter and year-to-date results, our updated 2016 guidance range, progress on our current rate cases and our gross margin disclosures. Starting on Slide 9. As Chris stated, we had a very strong quarter financially and operationally across the company. For the third quarter, we delivered adjusted non-GAAP operating earnings of $0.91 per share, exceeding our guidance range of $0.65 to $0.75 per share. Exelon utilities delivered a great quarter, with a combined $0.53 per share of operating earnings. This was driven by favorable weather at ComEd and PECO where cooling degree days were 39% and 37% above normal, respectively, as well as lower O&M expense versus planned across all our utilities primarily due to lower-than-normal storm activity. Generation delivered $0.41 per share of operating earnings in the quarter. We have strong performance at our Constellation business, where our Generation to Load matching strategy continued to provide value and we benefited from a lower cost to serve our customers. On Slide 10, the $0.91 per share in the third quarter of this year was $0.08 per share better than the third quarter of 2015. Upside came from favorable weather across our service territories, the inclusion of PHI and higher distribution revenues at both ComEd and PECO due to increased capital investment and increased rates, respectively. This was partially offset by a decrease in earnings at ExGen, driven primarily by increased taxes due to the inability to use the domestic production activities deduction and lower capacity prices. On Slide 11, our year-to-date earnings of $2.24 per share are $0.11 per share higher relative to the same period last year, driven by performance at the utilities. The primary drivers are favorable weather, increased distribution revenues across all of our utilities due to higher rates and increased capital investment and the addition of PHI. ExGen is down $0.16 per share from this time last year due to increased decommissioning costs, increased taxes and share count differential. Turning to Slide 12, we are raising our full year guidance range from $2.40 per share to $2.70 per share to $2.55 per share to $2.75 per share, reflecting, in particular, the strong results that we've seen at ComEd and PECO year-to-date. Turning to Slide 13, we've laid out the schedule for the next 6 months of activity in all our current rate case proceedings across Exelon utilities. As you know, we filed distribution cases in all of PHI's jurisdictions and expect decisions spread throughout the third quarter of next year, providing needed revenue relief as we continue to make significant investments on behalf of our customers. Our investments in our utilities are needed to improve the customer experience and create value for customers. As Chris mentioned, in August, the New Jersey Board of Public Utilities approved the settlement authorizing Atlantic City Electric to increase its electric distribution rate by $45 million. The new rates went into effect immediately, which was 7 months earlier than expected. This really recognizes Atlantic City Electric's commitment to enhancing its energy infrastructure. Over the past 5 years, Atlantic City Electric has spent approximately $716 million in energy system upgrades to benefit its customers. The settlement is a good start, but there's more work to be done in the other jurisdictions. We still have rate cases outstanding at the other PHI utilities. In these cases, we're asking for $326 million in revenue requirement increases. These increases reflect recovery on multiple years of smart meter and other capital investments meant to improve the reliability of the grid across all the PHI jurisdictions. We're expecting the Pepco Maryland decision in mid-November, followed by Delmarva Maryland in February. In addition, ComEd made its annual formula rate filing with the Illinois Commerce Commission in the second quarter of this year, with the decision expected in December. ComEd requested a revenue requirement increase of $132 million related to approximately $2.4 billion in capital investments made in 2015. These investments, which include $663 million for smart grid-related work, have strengthened and modernized the electric system. More details in the rate cases can be found on Slides 28 through 33 in the appendix. Slide 14 provides our third quarter gross margin update, including our 2019 disclosures. We're including the 2019 numbers a couple of weeks earlier than our normal course of EDI as we wanted to package together some interrelated updates for you today. Our total gross margin uses September 30 curves and does not include the impacts of the CES program in New York or the purchase of FitzPatrick. But we have included these impacts below the lines to provide a full picture for 2017 through 2019, and we anticipate formally including both of them at our fourth quarter call. 2016 total gross margin increased $50 million during the third quarter, lifted by strong performance primarily at Constellation. We're highly hedged for the rest of this year and remain well balanced on our Generation to Load matching strategy. Total gross margin decreased from the second quarter to the third quarter by $100 million in 2017 and $250 million in 2018. The decline is driven by lower power prices on the unhedged portion of our output. We have seen power prices at NiHub and West Hub for these years move higher since the end of September, with 2017 increasing approximately $0.50 to $0.75 per megawatt hour, respectively. 2018 prices have increased approximately $0.20 to $0.50 per megawatt hour, respectively, and as a result, total gross margin on our unhedged generation has recovered since 9/30 by $50 million. At the end of the quarter, our hedge position was approximately 7% to 10% behind ratable in 2017 and 4% to 6% behind ratable in 2018 when considering cross-commodity hedges and reflecting our more positive fundamental view on the power markets. The majority of our link remains concentrated in the Midwest to align with our view of power market upside at NiHub. Total gross margins for 2019 is $6.8 billion, which is $450 million less than in 2018. The majority of the decline from 2018 is due to $175 million in lower capacity revenues, which we provided at Analyst Day, $125 million from a full year of retirement for Quad Cities and $200 million from a roll-off of in-the-money hedges versus 2018. We see multiple reasons why we'd expect a better realized power price environment than what's captured in these numbers. First, forwards beyond 2017 and especially beyond 2018 reflect a highly illiquid market with limited real price discovery. Liquidity will improve as we get closer to the delivery year, and that will help prices. In addition, our work on power market shows too many plants continuing to operate even though they're not economically viable. These plants will need to close, and like we've done with certain of our fossil plants and our planned nuclear retirements. Second, our Generation to Load matching strategy and our portfolio management team at Constellation have a proven ability to extract value out of various market conditions. Our Constellation business is set up to profit in periods of extremes. This summer, we captured better margins since our contracts are priced using forward summer market volatility. And when we don't see that volatility, such as this summer, we capture additional value. We saw the same thing during the polar vortex, a period with extremes but in the opposite direction. Our gross margin projections on this page do not anticipate these events repeating and assume normal weather, leaving the -- an opportunity for additional upside. And finally, the CES program in New York and the acquisition of FitzPatrick will add $500 million in gross margin in 2019 and annual EPS contributions of $0.10 to $0.18 per year starting -- annually starting next year. Turning to Slide 15. Even though we don't believe this market will be a reality, we are acting as if it will. We're reducing expected O&M expenditures by $100 million in 2018 and $125 million in 2019 at ExGen relative to what we showed you at Analyst Day, adding to the $400 million of savings we've already taken out of the business. We are finding additional savings as we focus our operations and reduce development efforts at Generation as we close out the growth CapEx program in 2017. We run an efficient organization, but we need to look for ways to reduce cost beyond these reductions. Our focus on -- our focus at ExGen remains on maximizing our cash generation to meet our commitments of funding utility equity needs and debt reduction. These efforts will help keep us on track. Finally, turning to Slide 16, our sources and uses slide. We expect adjusted cash flow from operations of $6.85 billion in 2016. In September, the U.S. Tax Court ruled against us on a like-kind exchange issue related to our sale of fossil generation in 1999. The outcome on numerics was not unexpected. We were fully reserved for the underlying claim. However, we do not agree with the decision and particularly disagree with the decision to issue penalties, which we did not think was likely or warranted. The law is very clear that we were entitled to rely upon the opinion of legal counsel. We believe the court came to an erroneous conclusion, and we expect to appeal the decision early next year. We plan to issue approximately $1 billion of long-term debt to support the payment to the IRS. I'll now turn the call back to Chris for his closing remarks.

Thanks, Jack. We do appreciate the time. And we've had a lot to be proud about at the company, but we're not happy with the outlook that we see at ExGen. As Jack talked, we're taking actions. The limited liquidity in the forwards beyond 2017 and the true lack of discipline by uneconomic generators are distorting the market. That said, we're not just going to sit around and wait on the power markets to recover. As we said, we're taking further actions to control our future at ExGen, aggressively managing our cost across -- or even against these forwards, cutting $100 million in cost from 2018 and $125 million from 2019 on top of the $400 million we've already cut across the business. And we're pursuing the compensation for the 0-carbon attributes of our plants, as we've done in New York. We are optimizing the fleet. All of this brings us back to the value proposition. We're targeting the best-in-class utility EPS growth of 7% to 9% through 2020. The strong free cash flow at ExGen will provide the incremental equity needs at the utilities as we focus on debt reduction at the ExGen. We're focused on optimizing the value of our ExGen business by seeking the fair compensation for the carbon pre-generation fleet and closing uneconomic plants. We will be opportunistically -- that's a good word, to selling assets where it makes sense to accelerate our debt reduction plans and maximize value through the gen-to-load matching strategy, which had another big quarter. We'll continue to focus on sustaining strong investment-grade credit metrics, growing our dividend in a consistent visible manner. And I want to thank you for your interest, and now we're ready to take questions.

[Operator Instructions] And our first question is from Greg Gordon with Evercore ISI.

So looking at the disclosures on the utilities, you raised your guidance range by $0.05 at each of the 2 utilities, but ExGen also had a -- is $50 million better on a gross-margin basis. I know you usually think about this in sort of rounding terms, and that's less than $0.05, but as you think about Q4, where are you -- where do you think you are inside the ExGen guidance range, assuming normal operations for the rest of the year?

Greg, I'd say we're feeling very good on the back of a very strong performance within the Constellation business year-to-date. There are some timing elements that keep us in that same guidance range. Obviously, the fourth quarter is an important one for that business, and we'll be tracking it closely. But I'd say we feel good about how we're trending, and that's reflected in our comfort in taking the guidance up across the company.

When I look at the delta from '18 to '19 in terms of the headwind from capacity -- and a lot of this, you talked about at Analyst Day. Capacity, mark-to-market on power curves, but then the offsetting benefits of lower O&M, lower depreciation, lower taxes, it looks to me, based on the fully diluted share count, like that's about a $0.15 delta today based on current forward curves. Am I missing something or is that in the right ballpark?

I mean, relatively speaking, I think that's -- you're in the right direction. I don't want to give 2019 guidance at this point, but that feels right.

Okay. And then can you give us some sense of timing on the process for the Mystic plants and when we might get some visibility on price and timing to close?

I don't think that there's been any statement on that.

We acknowledged we're selling the plants. Beyond that, Greg, I don't think it's probably right for us to comment on the process.

Our next question is from Jonathan Arnold with Deutsche Bank.

Can I just ask about the -- you made comments about feeling good around how you're executing in Constellation. Any comments on trends in margins and renewals? And one thing we noticed was that the new business to go for 2019, $950 million, is down a little from what you had for 2018 this time last year, yet you've got ConEd Solutions in there, I would guess. So is that some pressure in what you've seen around margins or more conservatism? Or how should we think about those numbers?

Jonathan, it's Joe. We feel pretty -- we feel very strong we're going to be able to deliver on 2019. Part of the reason that number is down is because we've already executed more in that year than we would have at this point last year for 2018. So that's why you see a lower number. Our new business to go -- our new business in total -- or the business we're going to create in total between 2018 and 2019 is roughly the same amount, and we're comfortable that we're going to be able to meet these targets as we've done in the last 4 years. At your comment about margins and the renewal rates in retail, as I mentioned at Analyst Day, that market has remained stable. Our margins are right in line with what I talked about at Analyst Day. Our renewal rates remain strong. The acquisition of ComEd, although we've only had them for a brief period, is going well. We're very impressed with the way they run their operation, and we're integrating that into the Constellation business. So the retail business remains very stable, and we're happy where things are at this point and continue to monitor it.

Okay. And then can I ask around the ExGen O&M guidance? Could you give us a little more insight into what's driving the incremental savings? And then, perhaps -- I mean, is this -- obviously, one of your nuclear competitors is seeing some cost pressures in that business. Can you talk about how -- what your sort of underlying expense profile might be, and how much you're having to cut in order to get to these net lower numbers?

I'll let Jack fill in the details. On our nuclear fleet, overall, in the past 7 to 10 years, we have made significant capital investment to prepare the plants for their extended life. You can see our reliability numbers reflect the investment that's been made, so we do not see any significant increase in capital. Actually, we're seeing the decrease in capital, in maintenance capital, because of the massive improvements that we've made. On the O&M side, there's been significant focus, not only at Exelon but across the industry, with industry initiatives to try to find ways to take what were old processes that were put in place that may be much more efficiently executed with the same results on a much lower cost basis, and that's the initiative that the Nuclear Energy Institute is performing. I can't speak to other fleets, but I can tell you that we have a very strong focus on capital, a very strong focus on efficiency. And the last thing we would do is cut into safety or reliability, and that's been a clear focus of mine throughout my whole career, and it will continue to be. Run the plant safely, reliably and very efficiently.

So Jonathan, just building on what Chris said, starting with that focus on safety and reliability. As you might imagine, when you contemplate a program that, say, is $400 million across the company and you're turning over many stones, you identify additional opportunities. And so among -- we've got almost more than 100 initiatives that we've been looking at, and each will contribute approximately from $1 million to several million dollars. But whether it's corporate efficiencies in organizational design, nuclear fuel savings, contractor costs, in-sourcing rates, nuclear site security, automation, NRC fees reductions, property taxes, organizational design and centralization such as within our engineering group, outage costs, automation, I mean it's just a long list of activities. And we do have good line of sight on these opportunities. And I think building on the processes that we've put in place to target cost and seek efficiencies, I think our hope is that we may, in fact, even find more than what we're sharing with you today.

Our next question is from Steven Fleishman with Wolfe.

Yes, a couple of things. First, just on the new -- the New York ZECs. Could you just clarify kind of the thoughts on ZECs versus RECs? Because the IPPs that filed the appeal seem to kind of say there is a difference. So could you kind of clarify maybe where they're getting that wrong?

Joe.

Yes, it's Joe Dominguez, Steve. We don't think there is really a difference. The program was fashioned after the REC programs. The distinction is that plaintiffs who are trying to create New York are not real. But they face the political problem, of course, that if they describe the lawsuit as also challenging the renewable programs, they're going to have a good deal more opposition. But the programs function essentially identically. The ZEC program is based on the cost of keeping resources in the market just as the renewables credits are the cost of keeping resources in the market, paying for the environmental attributes, recognizing that these assets get both wholesale and market revenues as well as attribute payments. But from our perspective, they function pretty much the same way.

Okay. And then moving to Illinois, could -- just any more color. Are you feeling more optimistic about being able to get a legislative bill this veto session than, let's say, a month or 2 ago?

I'll let Anne.

Okay. This is Anne Pramaggiore. We are -- I think what we're seeing right now is that there's a bit of an opening of a door. The legislature has a temporary budget in place, and Chicago public school funding is behind them. And so I think we see an opportunity in the veto session. We also think there's a lot of work to be done to get there. We've got to pull together a coalition to come in with an agree [ph] bill as much as possible, and we're in the process of putting that together now. But we do think that there's the potential that this would be entertained in the veto session.

Okay. And then, just lastly, in the context of what you said about the kind of power views and long-term liquidity. To the degree that, let's say, Illinois bill passes and it includes benefits for all types of generation, just -- doesn't that kind of continue on the kind of -- the potential inefficiencies of the markets and kind of keep some of the issues that are causing prices to be lower? So I guess, just how are you thinking about hedging and managing your portfolio against the fact that if -- the more of these you get done, the more Generation stays around?

Steve, this is Joe Dominguez, and I'll turn it back it over to Joe Nigro in terms of managing the portfolio. Look. We've -- the market is what it is. Today, we have over 30 states with renewable portfolio standards that recognize the environmental contributions of virtually every resource in the market that does what our nuclear plants do. So we're seeking to get fair treatment. At the same time, from a policy perspective, we've been clear for many years now that we think the right move is to put a cost occlusion in the market. That is, in the case of climate, establish a price on requirement. And we're going to continue to pursue those things. But obviously, there have been a number of headwinds that have prevented those policies from being fully realized and fully recognizing the impact that carbon has on climate, as measured by the federal government. So we haven't seen programs that trade [ph] carbon up to the social cost of carbon. We're going to continue to work on those things. But the plans we have in New York and Illinois, we think of as preserving those units for the day where we have that best design in place. And we think that day is going to come eventually, but we need a bridge solution to keep the units that are important to our customers in place so that they're available once we do have a carbon signal in the market. And that's how we reconcile it. But we have to take this world as it comes to us, and the world currently isn't our most favorite design of putting a price on carbon in the market. We have these separate state programs, and it's important for our customers that these nuclear plants be preserved, and that's what's driving our initiatives. Joe?

Yes. And I would add, just from a market perspective, portfolio perspective, a couple of things. One is, on the market side, I think the illiquidity of the market is somewhat independent of what Joe is saying. I think it gets into the nature of market participants. As you're well aware, when you think about the financial institutions to start with that added liquidity in this marketplace in years past, we don't see nearly the depth of that. But what's interesting is the power markets have been illiquid for quite some time. But when you look at open interest just on the gas market, for example, we've seen a change there where it's very front-end loaded versus kind of the outer years. And I think what's important with that is -- and let me give you an example. When you look at the price change in the quarter in PJM, in particular, versus -- the end of June versus the end of September, you saw that the prices -- the price of gas in each of those years, when you include the basis prices weren't great, fell equally. Yet we dropped power prices more materially on the back end of the forward curve than we did in the nearby 2017, and that gets into some of the illiquidity in the market. As it relates to our portfolio, we take all these factors into account, both the things that we're doing internally with our other assets, we have an estimate of what other folks are going to do with their own assets. We've been very clear that we've been aggressively managing our portfolio as it relates to our ratable plan, and we'll continue down that path. The last thing I would add is that we talk a lot about the benefits of our Generation to Load Strategy, and we do it with both [ph] in the dollars. It also has a huge benefit from a market perspective because it doesn't force us to go to that illiquid over-the-counter market. We have a strong customer base and a very, very strong load serving business now that matches output of generation to quantity of load very well. And we're going to continue to grow that, and we've done it both organically very well and through acquisition with like Integrys and ComEd, and that's been a big benefit also.

Your next question is from Stephen Byrd with Morgan Stanley.

Congratulations on a great quarter and on further cost reductions. I wanted to hit on what you mentioned in terms of some of your peers who would appear to need to shut down further plants. And we do see some of those same dynamics, but I was curious, from your point of view, what kind of catalysts or drivers should we be thinking about in terms of seeing more sort of rational decisions and further shutdowns? What do you see as some of the key catalysts?

So Stephen, I think the example I would give you is like when you look at coal-fired generations. When you look in the Eastern Interconnect between, call it, 2016 and over the next few years, we see almost 30 gigawatts of coal expected to retire, with almost 2/3 of that being done by the end of next year. The obvious examples are some of the plants that have been announced in Illinois and also in Ohio and the rationalization of that. Obviously, we've taken our own actions with our own power plants. We've seen others do the same thing beyond coal, and we expect more of that will continue if these low prices continue. Because when we look at it fundamentally, there are plants that are challenged economically that are still running that, really, the economic rationale isn't there for those to continue to operate.

And Stephen, just to build on that. I think you've heard us make strong comments about a focus on reducing leverage at the Genco to 3x debt-to-EBITDA. I think the reality is, in this current pricing environment, you're going to start to see others look at their outlooks and look at their leverage statistics and focus their efforts on generating cash. In order to do that, they're going to need to retire money-losing assets. So I think it'll force greater discipline on their part. We're already seeing some of that. I think there's a potential for consolidation and asset optimization around that and portfolio optimization. So I think we see a pathway for others to be disciplined as we have. But obviously, we need to see execution on that -- in that regard.

Those are all great points. I wanted to shift over to the New York ZEC legal challenge, and I think you've laid out your points of view in terms of the legal position. In the event that, in court, the ZECs were either sort of overturned or remanded for substantial modification, can you speak to the impacts to the acquisition with Entergy in terms of the transaction impacts?

Sure. Stephen, this is Joe Dominguez again. So the way you ought to look at that transaction is the legal risk will shift to us, really, around the time we do the outage in January. So post January, you ought to think about us as effectively being the economic owner of that legal risk, subject, of course, to the approvals. But we're not going to be able to walk away from the transaction if something occurs post January that changes the ZEC program. And the logic there is, after the outage, we effectively have our fueling machine, and we've paid for the outage cost, so we're going to be the economic owner at that point, again, subject to regulatory approvals of the transaction.

Understood. And I guess, the worst case always is that you do still have plant closure as an option, so that your worst case is captain, and you still do have the potential for, obviously, a good outcome?

That's right. And we feel very strongly in the merits of the case. Otherwise, we would not have done this.

Our next question is from Shar Pourreza with Guggenheim Partners.

Chris and Jack, the $0.02 to $0.08 of synergies from FitzPatrick, can you just remind us if that includes any additional synergies of owning FitzPatrick next to Nine Mile?

It doesn't, and we'll evaluate that as we get into the integration. There's conversations now in the nuclear integration team on what is the best way to optimize. The security fences are next to each other. It's a very big site. So amalgamation of the complete site might be more expensive than it's worth, but there are other elements in and on the site that we can look for synergies around the support services and the executive management.

Okay, got it. And I don't know if you could mention the actual -- is it enough to be a couple of pennies or anything directionally? Or not yet, too early?

Too early. We've got to get in and see and make sure that we maintain our design basis but look at everything possible we can to be more efficient.

Okay, got it. And then just lastly, with the strong results year-to-date, is this sort of any opportunities to pull forward some O&M? And maybe how we should think about it for the fourth quarter?

I'd say, with respect to O&M, we're going to manage our plan tightly. And generally, there's not that much opportunity to move things quarter-to-quarter. The planning required for the bulk of our O&M takes months, if not years, and so I think you'll see us try and land pretty darn close to what we've shown you in the slides today.

And we have time for one last question. That is from the line of Chris Turnure with JPMorgan.

I had some questions on Pepco, and I wanted to just get an update on your latest dialogue with interveners in Maryland and D.C. and just kind of how things are progressing there on their understanding of you guys underearning by so much and having stayed out of cases for so long there predeal. Denis O'Brien: This is Denis. Great question. We -- as we're going through the integration, I think things are going very, very well. As we mentioned before, it's going to be a long haul in terms of rate cases being filed every 12 to 15 months for the next 5 years. We've had some good progress in New Jersey. We're in the throes of the case in Maryland at this point, and I guess, we'll know about November 15 the outcome of that. So a little hard to predict. Maryland's somewhat challenging. We are continuing to work on improving reliability, improving all of our performance levels as well as working to improve our image reputation and brand in Maryland. But I think this is going be one of those things where it's going to take us a few cases to get through to a better level of performance. So we're seeing November 14 or 15 where we are, and we're going to make this happen. It just may take us a few cases into it.

And in D.C., we're early in the process. We've made our filing. We're in data request now. Over 400, I believe, data requests are coming in. So there's going to be a lot of dialogue there, a lot of questions that we'll need to provide the sound answers for the basis of our request.

Okay. And then, excluding weather, were there other drivers behind the outperformance -- or pardon me, the guidance increase for the Pepco utilities for 2016?

Primarily weather-related. So hotter-than-normal temperatures as well as storms, relative to what we budgeted, came in lighter. So beyond that, I think those were the major drivers.

And that does conclude the question-and-answer portion. At this time, I would like to turn the conference back to Mr. Eggers for closing remarks.

Thank you all for joining us and your time today. I know it's a busy earnings day. We appreciate your interest in Exelon, and we look forward to seeing a number of you at EEI the week after next. Have a great day.

Thank you. Ladies and gentlemen, this does conclude today's conference call. You may now disconnect your lines.