Good morning. My name is Reshira and I’ll 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. After the speakers’ remarks there will be a question-and-answer session. (Operator Instructions) Thank you. Mr. Idehen, you may begin your conference.

Thank you, Reshira. 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 earning release this morning along with a presentation, each of which can be found in the Investor Relations section of Exelon’s Web site. 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 defer 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 fillings 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 opening 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’ll now turn the call over to Chris Crane, Exelon's 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's going to discuss the financial performance in more detail in a minute. I am 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, in how we think about these markets. We own our assets that are more valuable to others -- 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 for the quarter. Our power…

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 electricity 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 on existing Exelon sites and will have a combined capacity of over 2000 megawatts, 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 see CCGT 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 NET Power. 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…

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 4. 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 cost associated with ancillary services, load following costs, specifically hourly LMP shaping and 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 of approximately $80 million in 2014 and in the ballpark of $1…

Before I turn it over 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're looking for in Illinois so I want to be clear. We are not looking for a bailout. We have a strong record of opposing non-market-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 carbon regime like a 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) Your first question comes from Greg Gordon with ISI Group. I am sorry, your first question comes from Steve Fleishman with Wolfe Research.

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's simplest. We have had significant storm expense this year, particularly at PECO and BGE. And then as you think about the formula rate at ComEd, interest rates, it's based of the 30-year treasury. As that's declined our allowed return has declined with that. So that's been a headwind for the year. And when you aggregate those, that's on the utilities side really kind of bringing down the expected contribution relative to plan from the utilities. That said, both the formula rate and increased rates of BGE have been an offset to that and been a positive for the year. On the Exelon Generation side, clearly you are seeing the benefit 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 increase outages this year. We have had higher costs associated with purchasing power during the polar vortex. So, again, speaking to the benefit of the balance load gen strategy, the opportunity to participate in the polar vortex and that volatility was a benefit at Constellation during the winter. The opportunity to have lower cost 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.

Okay. Great. And 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 we are not, you won't have the numbers for Pepco in your guidance yet? So where is all that, yes?

No, 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 that 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 billion. We will have, including Key/Con, roughly $1.4 billon 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's at the two combined-cycle plants in Texas, whether it's 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.

Your next question comes from Greg Gordon with 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've 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?

That’s correct.

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

And is the Integrys acquisition factored in yet?

No.

It is not.

It is not.

Okay. So neither is factored in?

That’s 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 '17, middle of '17, end of 2017?

Yes. When we roll out '17 and EEI you will see the assumptions of the new Texas power plants in the open gross margin calculation.

And, 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 would serve in the quarter in terms of the load in the retail business. So 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 got 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 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, and I am talking, 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 location of cost or basis cost 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's 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 have purchased prior to the quarter and got the benefit of. 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, it's truly a story of generation and load.

Your next question comes from Dan Eggers with 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 some policy changes there? Just kind of how you guys are seeing these kind of two major power markets evolve that's maybe leading to some capital allocation decisions?

Dan, what don’t I speak to the assets sales side and then Ken can speak to the investment side within ERCOT. There's no question that the discussion and commentary around the proposed capacity performance market factored into the pricing. We started our process in advanced of that but the commentary was well understood by the buyers. It was factored into the pricing. And while we didn’t have absolute clarity on how that market will develop, certainly it played in the element in the investment decision for the buyer. Clearly we have an internal view on how that market will evolve and what it's near term and more importantly longer term impacts will be on asset values. And we have factored that into our decision to sell Key/Con as well. As you will know, we were 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 viewed as an opportunity to recycle that capital and invest in Texas opportunity and others. Ken?

Yes, 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 was very leveraging in terms of putting the best technology forward that we could and doing 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 location advantage that obviously we have been working on and we are implementing that strategy as such. So for us this is a deployment to better technology. It's a 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 use issues in Texas as 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 environmental regulation space. That’s 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 their own because of that. And I think what you mentioned is potentially even more upside.

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 they, 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’s 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 nuclear 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 the -- 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 offices, he has been opposed to carbon trading regimes historically. So that’s a big toggle there. In terms of Illinois, there hasn’t been a lot of focus on who the different candidates would deal with carbon going forward. Not an 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 claims standpoint. So we don’t think the game changes materially depending on the gubernatorial election and what's going on.

Your next question comes from Stephen Byrd with Morgan Stanley.

I wanted to talk about the forward power market versus fundamental view that you have. Since March we have seen the PJM East on peak heat rates for 2016, rise about 3500 from about 12,000 to 15,500. 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?

Yes. Stephen, it's Joe Nigro. If I start in PJM East, I would say that in the '15-'16 timeframe we think that the PJM West hub prices are generally fairly priced. There is a small big of upside in '16. When you go out to '17--'18, we do see increasing upside. I think on the NI Hub side, it's safe to say that there is quite a bit of upside both in the '15-'16 timeframe and more so in '17-'18. And some of that is related to the facts 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 mentioned in the last few months in '15 related to the back end. 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 in the course of the year, would be incremental upside to what I'm talking about and it's not factored into our fundamental focused. From a fundamental forecasting perspective, we spend a lot of time scrubbing the stack as to what we expect to be added into the stack and what changes we would expect. I think it's safe to say, when you look at the new build economics for CCGTs in the Midwest, they are pretty challenged given the fact where energy prices are and the associated capacity prices. You are much closer to breakeven economics in the mid-Atlantic. And that gets into where the market 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's (indiscernible) that I understood the first part ?

They are generally pretty close. There's probably slightly more upside at, let's call PJM West hub then there is at East hub. And there would be increasing upside as you move further west in PJM to NI Hub for example.

Okay. Understood. So PJM East in your view is more closer to fair value...

Yes.

But not overstated. Okay. And then shifting over to the utility. 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?

Denis, you want to cover that? Denis O’Brien: The longer-term load growth in all three areas is really pretty flat. I mean I think we may see load growth anywhere between a zero and 1% over the next few years but we are not seeing anything now really significant.

Your next question comes from Jonathan Arnold with Deutsche Bank. Jonathan Arnold – Deutsche Bank: Could I ask a question about how you see demand response playing out, particularly in PJM? I mean 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. Jonathan. This is Joe Dominguez again. Obviously a very dynamic situation. We have a 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 and the response is a very important tool in the market. It's an important tool for 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 the 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, FirstEnergy has filed a complaint and they had some requested relief to strip out DR out of the markets and rerun the last option. We don't support that. What we do support, prompt action by FERC to define the new DR market to work with the states to implement it. But to close, we see it as a continuing and important tool and there is a good deal of work in our view to be done in 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's at today?

No, I don't think so. I think the timing is going to be very difficult. Particularly if FERC appears 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 the 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 wait the decision from the Supreme Court. But even if the Supreme Court doesn't hear the matter, it's going to be hard to imagine that we will have all the predicate work done to fully involve DR to the full extent that it's already participating, which was your question. That's 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?

Yes. 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 that are in Illinois. That is ongoing. And as I mentioned, it's a coordinated, collaborative process and dialogue that's underway right now. I wouldn't speculate what the final outcome look. We are suggesting, is their potential for a clean energy standard as we have discussed before. That has to be vetted through to see if that's 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 the provide and that's what we are looking for. So we had made the agreement with the states 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 aspects or the long-term viability of some of the plants would be. And so 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 do you still -- are you expecting that to happen on time?

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

Your next question comes from Hugh Wynne with Sanford Bernstein. Hugh Wynne – Sanford Bernstein: You 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 stick in what we think the value is to us. We first want to get the design right so we understand that the capacity will be there and the system will be secure. As the process moves forward we may be able to do that but it's some time off. We believe that the commitment that PJM has made and their board has made to addressing this process or to addressing these revisions to the process, will be done in a timely enough manner to allow FERC to review and make judgment before the next auction. So we feel good about that part of it but it's too early to speculate on value proposition here.

Just a follow-up on that. You've in the past, obviously have been quite bullish in your forecast about energy prices in PJM and to a certain degree that's 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 is a couple of ways to look at that. One is, we have is 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's not an adjacent market. It's 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's what these units are. The technology, the Brownfield location, the nature of their cooling will allow them to 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 the market power, a 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 the technology that would give us the return on value that we are seeing in ERCOT market.

Your next question comes from Ali Agha with SunTrust.

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 '17 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-'17...

That's right.

At the then prevailing equity price. Is that correct?

That's correct.

Okay. And so in your [revision] (ph) obviously you...

Ali, 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. Okay. And so in your math obviously you have made that conversion when you were running that math?

Absolutely.

Okay. And my last question for you guys. Chris, obviously you've been fairly active on the divestiture front with your capacity. You are building Greenfield plants 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?

Yes. 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 than we, in some cases higher than we can see that value ourselves. And we have participated, 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. They didn't have the earnings capability with their dispatchability 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's 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.

Your next question comes from Paul Fremont with Jefferies.

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 re-running 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 '16,'17, so not in the '15, '16 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.

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

And the retail component of it is only one side of it. As you transition into these things there is going to be a generation benefit on the other side. So you would have to look at the net effect of all 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 a price. What we see the reform is doing is, in the first instance, curing a real reliability problem that we have in PJM. The problem that we see growing worse over the next few years. And that's 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. And what we saw out of this past winter is a lot of units did not perform well and that's created a real problem that needs to be addressed. But it really, it doesn't relate, I don't think to anything that would provide a guarantee of a payment for the nuclear assets. It's 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 severe penalties for non-performance 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's going to be addressed by the PJM reforms. The reforms in terms of 111(d) and zero emission energy is the focus of our work at this day. And as Chris said, over the last six years Illinois has passed laws that essentially provide market-based credit opportunities for all types 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 come to roost. And so what we are trying to 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 in 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 KW?

Yes. We have said we are spending about $1.4 billion on these plants and they are going to be in excess of 1000 megawatt each. So you can do the math. It's going to be our around 700 a KW.

And your last question comes from Paul Ridzon with 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 or was it at the 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 the utilities. Then you also had elements of the decline in interest rates around treasuries factoring into our earned return at ComEd.

So 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.

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

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