艾索倫電力 (EXC) 2014 Q3 法說會逐字稿

Good morning. My name is Rashira and I will be your conference operator today. At this time I would like to welcome everyone to the Q3 2014 earnings conference call. All lines have been placed on mute to prevent any background noise. (Operator Instructions). Thank you.

Mr. Idehen, you may begin your conference.

Thank you, Rashira. Good morning, everyone and thank you for joining our third-quarter 2014 earnings conference call. Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer; Jack Thayer, Exelon's Chief Financial Officer; and Ken Cornew, President and CEO of Exelon Generation. They are 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 each of which can be found in the investor relations section of Exelon's website.

The earnings release and other matters that 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. Please refer to today's 8-K and Exelon's other filings for a discussion of factors that may cause the results to differ from management's projections, forecasts and expectations.

Today's presentation also includes references to adjusted operating earnings which is a non-GAAP measure. 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 GAAP earnings. We have scheduled 60 minutes for today's call.

I will now turn the call over to Chris Crane, Exelon CEO.

Good morning, everybody, and thanks for joining the call. We had another strong quarter from an operational perspective as well as a financial perspective. As we announced this morning, our operating earnings of $0.78 per share beat expectations and we remain on track to deliver on our financial goals for the year.

Jack is going to discuss the financial performance in more detail in a minute. I'm going to just focus on the broader strategy and operational issues.

Our strategy continues to leverage the integrated business model that creates value using our strong balance sheet to invest in both regulated and competitive businesses to drive growth. Our investment in Pepco Holdings, Integrys and most recently the two Texas gas plants confirm our commitment to grow on both our regulated and our unregulated side of the business.

Through this model our utilities contribute to earnings stability and provide dividend support while our competitive business provides exposure to market power upside. We are not just resting on the market power to turn around, we are continuing to invest in our core markets and competencies while pursuing opportunities to innovate in adjacent areas and Ken will elaborate on that when I finish and how we think about these markets.

When we own assets that are more valuable to others, then we will take a look at selling them as we continue to focus on our recycling of capital into stronger investments. You have seen evidence of that with our announcements on our asset sales this year and we will continue to optimize our portfolio going forward.

What drives our success is our focus on operational excellence. Our nuclear fleet continues to run at high-capacity factors, 96.5 percent for the third quarter. Our power fleet had a 98.8 percent dispatch match and our renewable energy capture rate was 94.9 percent. We also achieved very strong operational metrics in our utilities.

Many of our growth areas we are pursuing, such as Pepco Holdings and the Texas gas projects are directly tied to our ability to operate across our business at consistently high levels.

Switching gears, I want to quickly discuss the capacity market design proposals. There has been a lot of progress at PJM in developing a new capacity performance product and making other design changes. We are encouraged by PJM's acknowledgment of the value of reliability that comes from firm fuel, particularly giving our nuclear units performance and their minimal additional cost of compliance for us for this proposed product. We are keeping a close watch on how the proposal evolves over the next several months and we will continue to remain engaged.

On the Pepco Holding front, we continue to work through various regulatory approval processes. We received approval from Virginia earlier this month and we are working collaboratively with the other jurisdictions. We remain on track to close the transaction in the second or third quarter of 2015.

On the nuclear front in Illinois particularly, we continue to engage with the stakeholders as with the process goes forward on recognizing the value and the environmental benefit and the economic benefit of these plants to the state. That process as we have said before will continue to work through 2015.

In closing, we are pleased with the results of the quarter. Exelon is operationally strong and positioned to deliver earnings expectations for the full year. We remain committed to deliver sustainable income and provide access to growth opportunities across the energy value chain.

With that I will turn it over to Ken to discuss in more detail what we are doing with our competitive generation business.

Thanks, Chris, and good morning, everyone. We had a very productive quarter at Exelon Generation announcing several development projects and an acquisition. Each of these initiatives leverages our operating and commercial expertise. We are investing in our core business and markets as well as adjacent markets to increase value. We are positioning Exelon to be at the forefront of and capitalize on the evolving energy landscape. We are pursuing investments that meet customer demands across both the electric, and gas value chains.

Along those lines, last month we announced plans to build two CCGTs in Texas using a new GE technology that will make them among the cleanest, most efficient CCGTs in the state and in the nation. The units will be located at existing Exelon sites and will have a combined capacity of over 2000 MW allowing us to build them for more attractive price relative to other new builds in the region.

These first of a kind GE gas turbines will provide the highest efficiency and best operational flexibility in the market. The units are designed to ramp faster than any other CCTG turbines allowing us to better capture market volatility and price movements. Importantly, being mindful of increased water efficiency in drought prone Texas, these units will be cooled with air instead of water. We expect construction to begin next year and commercial operation in 2017.

Earlier this month we also announced an investment in NetPower, a first of a kind demonstration power plant in Texas that uses carbon dioxide as part of the combustion cycle and produces zero atmospheric emissions. The technology will ultimately produce pipeline quality CO2 that can be sequestered or used in various industrial processes including enhanced oil recovery.

This technology is a potential game changer in reducing carbon emissions from power generation and is another step toward Exelon's vision of a clean innovative energy future.

Finally, as you know, we announced the acquisition of Integrys Energy Services at the beginning of the quarter and expect to close that transaction in November. The combination creates a stronger, more diverse business that is well-positioned to compete for customers in retail electricity and gas markets across the country. It vastly expands our gas portfolio increasing our load by 150 BCF annually and it enhances our generation to load strategy because many of the power customers currently served by Integrys are in regions where Exelon owns significant generation.

Shifting to the power markets and hedging on slide three, mild summer weather defined the markets during the third quarter. In July, spot markets cleared at relatively low prices on the back of low demand and strong natural gas supply. Forward market prices followed and bottomed out at the end of July. Since then, forward prices have recovered and they are still well above where they were at the beginning of the year. Prices are up approximately $5 a megawatt hour at West Hub, and $2.50 a megawatt hour at NI-Hub for calendar year 2015, and the move in 2016 heat rates and prices are similar.

We believe the price increases are due to the impact of coal retirements as a result of mass implementation next year and we expect this trend to continue. NI-Hub should be particularly sensitive to the coal retirements and our hedging strategy reflects that view.

During the third quarter, our portfolio management team performed very well. They executed on $150 million of power new business which allowed us to raise our full-year gross margin outlook by $50 million. In addition, we achieve $50 million of non-power new business.

For 2015 and 2016, total gross margin is down $200 million and $250 million respectively. Divestitures during the quarter account for $150 million of the decrease in each year and in 2016 lower market prices accounted for the remaining $100 million.

You all know that Exelon Generation stands to benefit significantly from changes in power prices whether in energy or capacity markets and we will continue to see improvements in both. In the meantime, we will continue to make investments in market-leading technology and expand our footprint in attractive markets through acquisitions.

I will now turn it over to Jack to review the full financial information for the quarter.

Thank you, Ken, and good morning, everyone. I will cover Exelon's financial results for the quarter, our full-year guidance range and update our cash outlook for 2014.

Starting with our financial results on slide four, we had a strong third quarter and Exelon delivered earnings of $0.78 per share exceeding our guidance and in line with our results for the third quarter of 2013.

At Constellation both wholesale and retail performed well this quarter driving the overall performance at Exelon Generation. During the year, we have seen dramatically different market conditions play out and our balanced generation to load strategy has benefited us in each circumstance.

During the first quarter, our reliable firmly fueled nuclear base load generation supplemented by our dispatchable fleet allowed us to take advantage of the volatility created by the Polar Vortex while successfully managing our load obligations. Our portfolio benefits from our load serving business in periods of low volatility like we saw this summer. We experienced lower costs associated with ancillary services, load following cost, specifically hourly LMP shaping in variable load risks and power basis. Post Polar Vortex and with the expectation of greater volatility in the future due to coal plant retirements and market rule changes, we are charging appropriate load following costs. We have seen the success of this strategy throughout the market cycle.

For the full-year, we are narrowing our guidance range to $2.30 to $2.50 per share from our previous guidance of $2.25 to $2.55 per share. We expect to deliver 2014 results comfortably within the revised full-year guidance range. One of our key assumptions is that bonus depreciation expires as scheduled. If extended by Congress, we will benefit economically with a positive cash flow impact from approximately $80 million in 2014 and in the ballpark of $1 billion in 2015. However, we would expect to see a $0.05 per share drag on our full-year earnings which is not factored into our current guidance for 2014 or 2015.

Turning to utilities on slide five, they delivered combined earnings of $0.29 for the quarter. For the third quarter, ComEd earned $0.15 per share. We are on track to have a decision in our most recent formula rate case in December.

On October 22, the Illinois Commerce Commission approved the Grand Perry Gateway 345 KV transmission line project. The nearly $260 million project will connect ComEd's Byron and Wayne substations alleviating identified congestion and providing that savings to Northern Illinois customers of more than $250 million within the first 15 years of operation.

Construction on the transmission line is scheduled to begin in the second quarter of 2015 and the line is expected to be in service by the second quarter of 2017. Including this project, ComEd is on track to invest more than $1.7 billion in 2014 which is approximately $300 million more than last year. This includes over $400 million related to EIMA and is consistent with our investment strategy to continue improving reliability and system performance in the ComEd service territory.

PECO's earnings were $0.09 per share for the third quarter. Through the end of September, PECO has substantially completed the installation of advanced meters and grids for electric customers, nearly 1.5 million meters with an overall investment of approximately $700 million with $200 million of that funded by the DOE. We are well into the deployment of upgraded natural gas meter modules installing more than 120,000 modules. We expect the installation will be complete in the second quarter of 2015.

This technology brings significant benefits to PECO and its customers. In addition to helping the Company further improve storm restoration and improve operational efficiencies, the technology also helps customers better understand and manage their energy use and costs.

BGE delivered $0.05 per share this quarter. On October 17, BGE reached a unanimous settlement agreement on its rate case which was filed with the Maryland Public Service Commission. The settlement includes a total revenue requirement increase of $60 million between electric and gas. In addition, the settlement allows for a $20 million reduction in depreciation and amortization expense. This is the first BGE rate case settlement since 1999 and is the result of an improving regulatory environment in Maryland. It still must be approved by the Maryland PSC before it becomes effective. The earliest new rates would go into effect would be mid-December.

Slide six provides an update of our cash flow expectations for this year. We project cash from operations of nearly $7.5 billion. This compares to $6.975 billion last quarter. The variance is primarily driven by additional proceeds from asset divestitures.

Turning to our asset sale program, we announced agreements to sell our Fore River, Quail Run, and West Valley units during the third quarter. Our total gross proceeds from these plants and Safe Harbor will be $1.3 billion. On an after-tax basis, net proceeds from these sales will be more than $975 million.

Further, on October 24, we entered into a definitive agreement for the sale of our interest in Keystone and Conemaugh to an affiliate of ArcLight Capital Partners for $470 million of gross proceeds inclusive of approximately $60 million of working capital or $418 million on an after-tax basis. We expect to close this transaction late this year or early next year.

Please note that the sale of Keystone/Conemaugh is not included in our cash forecast or reflected in our commercial disclosures. We will update these disclosures on the fourth-quarter call. However, we expect to take an impairment loss of $350 million to $450 million which will be reflected in the fourth quarter. This is non-operating and will not impact the full-year EPS guidance.

We anticipate closing the Integrys transaction in the fourth quarter. The purchase price and working capital of approximately $325 million is reflected in the cash from operations.

On the financing side, we completed the $695 million financing of ExGen Texas Power, a diverse portfolio of CCGTs and peakers in ERCOT North and Houston zones. Since the third quarter of last year, we have project financed approximately $1.75 billion providing capital to allow us to explore growth opportunities for Exelon Generation. As a reminder, the appendix includes several schedules that will help you in your modeling efforts.

Now I will turn the call over to Chris for his concluding remarks before we open the line for Q&A.

Before I turn it over for Q&A, I want to close with some more remarks on Illinois. There has been a fair amount of speculation and some misreporting on what we are looking for in Illinois so I want to be clear. We are not looking for a bailout. We have a strong record of opposing nonmarket based solutions not only in Illinois but in other states as well. What we are seeking to keep the plants operating is a solution that recognizes the clean attributes of nuclear as done with other sources that we compete against within this market. Examples of such a solution would be a clean energy standard or a carbon regime like RGGI, Regional Greenhouse Gas Initiative.

So there has been recent publications of reports that clearly articulate the significant contribution to the state and local economy as well as the environmental benefits from our nuclear plants and we agree with those totally. Various state agencies including the state EPA and the ICC continue to work on the issue in a coordinated fashion and we hope that a positive conclusion will be reached by the end of the legislative session next May.

So thank you and we look forward to seeing all of you at EEI and with that, we will open it up for questions.

(Operator Instructions). Steve Fleishman, Wolfe Research.

Thank you. Sorry, Greg. So just a couple of quick questions. First, on the 2014 guidance update, the overall number is the same midpoint but it seems like there is $0.10 to $0.15 more at ExGen and $0.10 to $0.15 less at the utilities. Could you just kind of give a quick snippet of explanation for the changes in each?

Sure, Steve. This is Jack. So I will start with the utilities where I think it is simplest. We have had significant storm expense this year particularly at PECO and at BGE. Then as you think about the formula rate at ComEd, interest rates it is based off the 30-year Treasury. As that has declined, our allowed return has declined with that so that has been a headwind for the year. And when you aggregate those, that is on the utility side really kind of bringing down the expected contribution relative to plan from the utilities.

That said, both the formula rate and increased rates at BG&E have been an offset to that and been a positive for the year.

On the Exelon Generation side, clearly you are seeing the benefits of a number of positive outcomes, strong performance from Constellation. You are seeing the elimination benefit of the DOE fee but we have had some increased outages this year. We have had higher costs associated with purchasing power during the Polar Vortex.

So again speaking to the benefits of the balanced load gen strategy, the opportunity to participate in the Polar Vortex and that volatility was a benefit to Constellation during the winter. The opportunity to have lower costs to serve during the summer was also a benefit at Constellation which I think you are seeing in the very strong improvement in the hedge disclosures as those positives have benefited our overall outlook.

Great. I guess one other question is just in thinking about all the asset sales and your forecast, I guess when you give like 17 at EEI, will this money have been reinvested in something or is it all going into Pepco which you won't have the numbers for Pepco in your guidance yet? Where is all of that?

I understand the question. You will recall when we announced the Pepco transaction we had highlighted that we would use $1 billion of those proceeds from asset sales to fund that investment and at the time we disclosed that we expected the impact of the asset sales -- the lost contribution from those assets, the addition of Pepco to be $0.15 to $0.20 accretive in 2017.

The proceeds to date as you know are in excess of that $1 billion. We will have including Key/Con roughly $1.4 billion of after-tax proceeds and we will incorporate that into our disclosures as we move forward.

I would say that we believe that the very attractive prices that we have received are helping us to fund the growth whether it is at the two combined cycle plants in Texas, whether it is at the acquisition of Integrys, cash is somewhat fungible but we are doing a lot that we think is very positive on the Exelon Generation side of our business to invest and grow.

Okay. Thank you.

Greg Gordon, ISI Group.

So Steve thankfully did not ask my question. When we are looking at the gross margin update just want to be clear on what is baked in and what isn't baked in. So you just announced the sale of Key/Con, so the lower volumes and the lower gross margin associated with the sale of Key/Con are not yet factored in, is that correct?

Steve, it is Joe Nigro. They are not factored into the disclosure.

And is the Integrys acquisition factored in yet?

No, it is not.

Okay, so neither is factored in?

That is correct.

And when you give us the 2017, when you roll it, are you going to include an assumption for the contribution from the new Texas power plants or will they be up and running beginning of 2017, middle of 2017, end of 2017?

When we roll out 2017 at EEI, you will see the assumptions of the new Texas power plants in the open gross margin calculation.

Greg, we plan on having those units up and running prior to the summer of 2017.

Great. Can you maybe spend a little bit more time explaining how you were able to reduce the cost of serving your load so much that you were able to put up a really strong quarter despite the fact that I presume you actually delivered variable load risk probably came in on the downside of your expectation of what you'd serve in the quarter in terms of the load in the retail business? Can you explain a little bit more how you were able to more than offset that on the cost side?

Yes, Greg, there were really four elements to the success in the quarter and three of them are directly related to load. I think Jack said this and I will reiterate it. I think if you look at the first quarter, we got a huge benefit on the Generation side because us, like everybody else, incurred substantial charges on our load book in Q1, but we get the benefit of the Generation in the first quarter.

In the third quarter, it was directly related to the fact that we had estimates of what cost to serve would be in the three big buckets. One you just mentioned, the variable load shape. The second is there is ancillary service cost estimates and then the third piece is -- let's stay in PJM for a second because we have quite a bit of load in PJM. We have estimates as to what specific locational costs or basis costs would be.

In all three of those buckets, the cost came in substantially lower than what we were expecting them to be and so we got the benefit of that by serving load at contracted prices.

The fourth element which really isn't tied to load directly but it is more of a general portfolio management comment is we benefited from our spot optimization as well shaping of our generation to match our load and running short schedules, price protection to the downside that we purchased prior to the quarter and got the benefit as well as when we did see some volatility, we had some opportunity with our excess generation to capitalize on that as well. So really and truly a story of generation and load.

Thank you very much.

Dan Eggers, Credit Suisse.

Just kind of following up on these asset sales, can you help put in context the idea of selling down some PJM capacity ahead of RPM rule changes, the idea of investing in ERCOT before there is any demonstrative move and maybe policy changes there? Just kind of how you guys are seeing these kind of two major power markets evolve that is maybe leading to capital allocation decisions?

Why don't I speak to the asset sales side and then Ken can speak to the investment side within ERCOT.

There is no question that the discussion and commentary around the proposed capacity performance market factored into the pricing. We started our process in advance of that but the commentary was well understood by the buyers. It was factored into the pricing and so while we didn't have absolute clarity on how that market will develop, certainly it played an element in the investment decision for the buyer. Clearly we have an internal view on how that market will evolve and what its near-term and more importantly longer-term impacts will be on asset values and we factored that into our decision to sell Key/Con as well.

As you know, we were very close to $1 billion of net proceeds. We didn't need to sell this asset. We viewed it as a very attractive price and one that we viewed as an opportunity to recycle that capital and invest in Texas opportunity and others. Ken?

Dan, I am sure you realize at this point we have been working on this Texas opportunity for a while now. We had sites that were set up very well to construct bringing GE and Exelon together. It was very leveraging in terms of putting the best technology forward that we could and doing it at a very, very low cost and we are excited about the ERCOT market and its fundamentals going forward. We think that these plants will show up right about at the right time when ERCOT needs power and we think we have a technology and a location advantage that obviously we have been working on and we are implementing that strategy as such.

So this is for us, this is a deployment to better technology. It is deployment to lower cost and a deployment to more upside for ExGen.

Ken, when you think about the ERCOT market, you highlight the air cooled nature of these plants and with the CSAPR rules kind of evolving or coming back again, are those having bearing or is there a way to think about the economic value of both CSAPR coming back and maybe water usage in Texas to help put this in a better cost position?

Clearly our strategy to go air cooled is a good one for Texas given the water constraints that are there and our strategy to put efficient clean, lowest in the stack combined cycle is going to be constructive in the environmental regulations space. That is all upside for us. We looked at the economics of these plants, where they sit on the stack and how they can respond to price movements and they will stand on our own because of that and I think what you mentioned is potentially even more upside here.

Let me just elaborate on the water side. When you go to build a new asset and you try to secure water in the ERCOT market, you are building a 20- to 30-year asset with a contract that can only extend for three years. The air cooled nature of these assets guarantee their availability and their capability of returning value for many years to come. While as Ken pointed out, they have the best mechanical heat rate and the best ramping speed to capture and to operate in a market that is heavily saturated with renewables.

Okay, got it. I guess one last question just on the CO2 front, there is kind of two big gubernatorial elections in Illinois and Pennsylvania this year. In Illinois, what has been the comments I guess between the two candidates or is there any difference in willingness to consider supporting if somebody puts the value on the new clear assets?

And then in Pennsylvania, I believe Candidate Wolf has come out in favor of some carbon policy. Where do you guys see that potentially playing through?

This is Joe Dominguez. I think you have captured it well in Illinois I think -- or excuse me, in Pennsylvania. I think Candidate Wolf has talked about joining RGGI if he becomes the governor and I think that would be their compliance mechanism at least based on what he said. Obviously if Corbett remains in office, he has been opposed to carbon trading regimes historically so that is the big toggle there.

In terms of Illinois, there hasn't been a lot of focus on how the different candidates would deal with carbon going forward, not in opposition certainly to carbon trading from either candidate at this point. We think both will recognize the inherent value of nuclear both from a reliability and clean standpoint so we don't think the game changes materially depending upon the gubernatorial election in Illinois.

Okay. Thank you, guys.

Stephen Byrd, Morgan Stanley.

Wanted to talk about the forward power market versus fundamental view that you have. And since March, we have seen the PJM East on peak heat rates for 2016 rise about 3500 from about 12,000 to 15,500. And when you look at your fundamental view of heat rates and then also sort of new build economics when you combine capacity prices plus spark spreads which were 16 or up about 40% at PJM East. Can you give us your view on your fundamental power view relative to the forwards?

Stephen, it is Joe Nigro. If I start in PJM East, I would say that in the 2015, 2016 timeframe we think that the PJM West Hub prices are generally fairly priced. There is a small bit of upside in 2016. When you go out to 2017, 2018, we do see increasing upside. I think on the NI-Hub side, it is safe to say that there is quite a bit of upside, both in the 2015, 2016 timeframe and more so in 2017, 2018.

And some of that is related to the fact that you just have better liquidity in the front end of the curve, 2015 in particular, and we have seen quite a bit of heat rate expansion as you have mentioned in the last few months in 2015, relative to the backend.

That all takes into account normal weather and normal operations. Some of the changes that PJM is talking about related to things like dynamic reserves that they are looking at implementing the first of the year would be incremental upside to what I am talking about, and it is not factored into our fundamental forecast.

From a fundamental forecasting perspective, we spend a lot of time scrubbing stack as to what we expect to be added into the stack and what changes we would expect. I think it is safe to say when you look at the new build economics for CTGG in the Midwest, they are pretty challenged given the fact where energy prices are and the associated capacity prices.

You're much closer to breakeven economics in the mid-Atlantic, and that gets into where the markets spark spreads are and where the capacity prices are, but they are generally close to breakeven economics.

Okay, thank you. The first part of what you said, Joe, you were talking about PJM West. Was that also designed to cover PJM East or what is the (multiple speakers) first part ?

They are generally pretty close. There is probably slightly more upside. It is called PJM West Hub then there is East Hub and there would be increasing upside as you move further West to PJM to Ni-Hub for example.

Okay, understood. So PJM East in your view is more closer to fair value but not overstated?

Yes.

Okay. Then shifting over to the utilities, we just talked a little bit about PECO and low growth expectations. Longer-term beyond, it just looks like for this quarter and next quarter the low growth numbers are a bit lower than before. Can you talk a little bit more fundamentally about the PECO territory and your thoughts on load growth longer-term?

The longer-term load growth in all three areas is really pretty flat. I think we may see load growth anywhere between zero and 1% over the next few years but we are not seeing anything really significant.

Okay, great. Thank you very much.

Jonathan Arnold, Deutsche Bank.

Good morning, guys. Could I ask a question about how you see demand response playing out particularly in PJM? You are obviously a large owner of utilities and PJM seems to have the strategy that DR is going to reorganize itself under the umbrella of states and utilities. So sitting on both sides of that equation, do you have a view on how this can work and what the impact on sort of the amount of that product in the market might be under different scenarios? Anything you could say there?

Sure. This is Joe Dominguez again. Obviously a very dynamic situation. We have court order delaying the mandate at FERC. We will see if FERC is able to move forward with an appeal to the Supreme Court. So the decision isn't final until at least that determination is made.

We think demand response is a very important tool in the market. It is important to offer customers, it helps to keep prices low and as long as it does exactly the same thing as generation, we think it needs to be a component of the market.

We have looked at the white paper that PJM circulated. I think it begins a good discussion. Obviously if the LSEs are going to be in the contracting role for DR, there has got to be a lot of work done between FERC, the states and industry ultimately to make sure the product is defined appropriately in a uniform manner and then is included in the load forecast. We think that makes a lot of sense.

As you know, First Energy has filed a complaint and they had some requested relief to strip DR out of the markets and rerun the last auction. We don't support that but we do support prompt action by FERC to define the new DR market to work with these states to implement it. But the close, we see it as a continuing and important tool and there is a good deal of work in our view to be done and how it gets defined and implemented.

Do you think that implementation can practically be achieved by next May's auction in the same type of scale that it is at today?

No, I don't think so. I think the timing is going to be very difficult particularly if FERC appeals the matter to the Supreme Court. We are not going to have a decision by the Supreme Court in all likelihood until March which is going to be a challenge for all these stakeholders to develop programs and have it implemented assuming the appeal isn't granted.

If it is granted, I think things will obviously stay and we will all await the decision from the Supreme Court. But even if the Supreme Court doesn't hear the matter, it is going to be hard to imagine that we will have all of the predicate work done to fully involve DR to the full extent that it is already participating which was your question. That is different than saying that there can be no DR participation. I think we will get some DR participation on the load side even if the timing is constrained, just probably not as much as we have seen.

Okay. Great thank you for that. Can I ask just on another topic on the Illinois process, Chris, I think at the outset you said you think that it will continue through 2015 but then you also said you are hoping that there will be some sort of determination by the time the Legislature wraps up. Could you just maybe elaborate a bit more on what you see the steps in this process to be and timing of them?

At the end of the last session, there was mandates given by the legislature to different state agencies to review the environmental and economic support of these units -- units that are in Illinois. That is ongoing. As I mentioned, it is a coordinated collaborative process and dialogue that is underway right now. I wouldn't speculate what the final outcome. We were suggesting is there a potential for a clean energy standard as we have discussed before? That has to be vetted through to see if that is the right avenue going forward.

We are just holding that it needs to be a market-based reform in support of the assets as the state currently supports renewables, clean coal and other sources. So the sources we compete against are already recognized for the value that they provide and that is what we are looking for.

So we had made the agreement with the state since they were open to having discussions about compensating for the value that they provide that we would slow any decision on what the long-term viability of some of the plants would be. We hope that we see a path clear by the end of this session coming up in May and if not, we will have discussions on the other side looking at the economics of the plants.

My memory says that the state agencies were supposed to come out in November. Is that correct and are you expecting that to happen on time?

Actually they have a window between November 15 and January 15 to issue those reports so the earliest we will see them is November 15. Hard to say whether they are going to hit the earlier part of the target but very confident that they will get their work done within the 60-day period.

Thank you very much, guys.

Hugh Wynne, Sanford Bernstein

Thank you very much. You all are obviously intermittently involved in discussions around the reforms to the PJM capacity market architecture and I am sure you have modeled the potential impact of the various different changes that have been proposed.

I was wondering if similar to the detailed discussion that you provided of your expectations for energy prices you might provide more color on what you expect the impact of the proposed reforms to be over what period of time and perhaps also give us your assessment of the likelihood of these reforms being accepted by FERC in time for the next auction?

So we don't want to speculate. The process is very fluid right now on the design and how it would go forward so we don't want to speculate or start to put a stake in what we think the valve is to us. We first want to get the design right so we understand that the capacity will be there and that the system will be secure.

As the process moves forward we may be able to do that but it is some time off. We believe that the commitment that PJM has made and their Board has made two of dressing these revisions to the process will be done in a timely enough manner to allow to review and make judgment before the next auction. So we feel good about that part of it but too early to speculate on value proposition here.

Just a follow-up on that. You've in the past, you have obviously been quite bullish in your forecast about energy prices in PJM and to a certain degree that has played out yet the decision to invest when it was taken was taken in Texas.

Could you comment on the relative economics of the two markets, why you favor Texas over PJM and whether the prospective changes in the capacity market in PJM might allow you to make a similar new build decision in the future closer to your core markets?

Sure. There are a couple of ways to look at that, Hugh. One is we have still a significant upside to the energy and capacity market in PJM. The divestiture of our partial ownership in those assets will not be material depending on which way the market goes. We have talked in the past about continued geographic diversification of our generating portfolio. ERCOT is a core market, it is not an adjacent market, it is one that we work in now with our wholesale and retail portfolio, our generating assets. We have continued to maintain a very positive stance on ERCOT and stated previously that we will continue to look for opportunities to invest in it and that is what these units are, the technology, the brownfield location, the nature of their cooling will allow them to take a spot in the dispatch stack that will allow us to recover the value that we need for making such an investment.

We continue to monitor the PJM market, the needs for generating assets. In some areas, we are somewhat constrained based off of market power view of where we would want to build plants or could build plants but there may be potential opportunities coming forward as plants retire and the market tightens and the capacity market revisions come in that we might be able to deploy a technology that would give us the return on value that we are seeing in the ERCOT market.

Great. That is very helpful.

Ali Agha, SunTrust.

Thank you. Good morning. In the opening remarks you all had stated that in the gross margin numbers taking out Safe Harbor and the three gas-fired plants, I think took out about $150 million annually from the gross margins. Just to complete that picture on a pro forma basis, if you take out Keystone/Conemaugh, how much further reductions should we assume just from a pro forma basis?

It would be roughly $150 million in 2015 in gross margin and about $100 million in 2016.

Just from those two divestitures?

Correct.

Got it. And then second question, Jack, you alluded to Pepco and the net impact in 2017 from that acquisition. Can you remind me, the equity units, $1.15 billion. If I recall correctly they have to be converted into equity in mid-2017 at the (multiple speakers) equity price. Is that correct?

That is correct.

So in your vision, obviously (multiple speakers)

With obviously a floor of $35. We participate in the upside if the shares are higher at that point all the way up to a 25% premium.

Got it. Got it. So in your math obviously you have made that conversion when you were running that calculation (inaudible)?

Absolutely.

And my last question for you guys, obviously you have been fairly active on the divestiture front with your capacity, you are building a greenfield plant and a plant in Texas. As you look at the landscape right now, are you seeing more opportunities to buy or sell given the kind of prices that may be out there for existing assets?

Just to clarify, the assets in Texas are on brownfield sites and that helps their cost basis significantly with the infrastructure to support the plants already being there. Right now the market has priced assets higher in some cases higher than we can see that value ourselves. We have participated and will continue to participate in the sales process looking at the potential purchase of assets as they come to the market but they have been trading at as we see a premium and that was what led us to the divestiture of some of the assets that we have that didn't have the earnings capability with their dispatch ability and their capacity factors or the nature of the agreement of ownership that we value them as well as others in the market are willing to pay.

So we don't see much more in the way of asset optimization beyond what we have discussed previously. We will continue to participate but we do see other markets as a potential investment on a new build if it is peakers in some areas or highly efficient units in others. But don't expect to see a lot of transactions either way just because of the market values on them right now.

Got it. Thank you very much.

Paul Fremont, Jefferies.

Thank you very much and I guess my first question is that PJM is talking about incremental auctions as part of their capacity performance transition plan. Can you speak to the effect of rerunning past auctions on retail contracts that you currently have outstanding and whether those contracts would somehow have the ability to reprice?

First of all we think the impact would begin in 2016, 2017 so not in the 2015, 2016 timeframe and as you know, most of our contracts are called within that 30-month tenure. Contracts that would be affected we believe on the fixed price side contracts that the change in law clause would be relevant in this instance and we would invoke that given the changes that we are talking about.

So you would have some ability to pass through the cost?

Correct, to our retail -- in most instances. There are instances on our retail customers where you can't but in most instances you can.

Paul, this is Ken. I would just add that we have been aware of this situation or what I would call exposure or risk and are treating it appropriately in our pricing of customers as we continue to compete for them.

The retail component of it is only one side of it. As you transition into these things a generation benefit on the other side so you would have to look at the net effect of all of that.

And then when we think of the capacity performance market and what you are asking for potentially either in New England or New York with your nuclear plants, what would the implementation of this type of a scheme by PJM do with respect to your desire to have some form of fixed price protection for the nuclear plants?

I think what Chris has been saying is we are not looking for fixed price protection in the way of a PPA or a guarantee of price. What we see the reform as doing is in the first instance curing a real reliability problem that we have in PJM, a problem that we see growing worse over the next few years and that is the first and most important focus of our work.

What it will do is it will provide potential additional compensation for firm fuel resources, resources that are reliable like nuclear units and it will punish resources that don't perform well. What we saw out of this past winter is a lot of units did not perform well and that has created a real problem that needs to be addressed.

But it really doesn't relate I don't think to anything that would provide a guarantee of a payment for the nuclear asset. It is not nuclear specific. Any unit that performs well and secures its fuel will have the opportunity to earn a little bit more. Those units that don't perform well and don't have firm fuel will be exposed to the severe penalties for nonperformance which is the way it should be.

I guess I'm still not understanding. So what additional support would the states potentially be providing under in terms of compensation for those units?

I think we are mixing two things. We are mixing a reliability need that is going to be addressed by the PJM reform. The reforms in terms of 111(d) and zero emission energy is the focus of our work at the state and as Chris said, over the last six years Illinois has passed laws that essentially provide market based credit opportunities for all forms of zero emission energy with the exception of nuclear. And the focus of our activities in Illinois will be to include nuclear and give it an opportunity to compete on a best price basis for those clean-air attributes.

We have made it clear over the last three years in a very pointed way the unintended consequences of subsidizing one clean source against another and the unintended consequences have come to roost and so what we are trying to do is fix what has happened between the subsidized PTCs and other forms of enablement for those more expensive sources to come to market. So we are looking at the market fix and what would be a fair treatment of all the renewable or clean generating assets within the market.

And then my last question is in Texas, what would you estimate is sort of the lower cost to build at your existing site per kilowatt?

Yes, we have said that we are spending about $1.4 billion on these plants and they are going to be in excess of 1000 MW each so you can do the math. It is going to be our around 700 a kilowatt.

Okay, thank you.

Paul Ridzon, KeyBanc.

You touched on this a little bit but could you just go back to kind of the upside that you saw in the third quarter, was it all ExGen for was it utilities as well?

The benefit in the third quarter was exclusively ExGen.

Did it make up for some shortfalls at the utilities?

You had some storm expense at utilities but you also had elements of the decline in interest rates around treasuries factoring into our earned return at ComEd.

Say relative to your guidance the utilities underperformed and that was more than offset by ExGen?

I would say they modestly underperformed and it was meaningfully offset by ExGen.

Great. Thank you very much.

You are welcome.

Thank you very much. That will conclude the third-quarter call.

This concludes today's conference call. You may now disconnect.