艾索倫電力 (EXC) 2010 Q3 法說會逐字稿

Good morning. And welcome to the Constellation Energy Group's third quarter earnings conference call. At this time all participants are in a listen-only mode. Today's conference is being recorded. If you have any objections, you may disconnect at this time. I will now turn the meeting over to the Executive Director of Investor Relations for Constellation, Mr. Carim Khouzami. Sir, you may begin.

Thank you, and welcome to Constellation Energy's third quarter earnings call. We appreciate you being with us this morning. On slide 2, before we begin our presentation, let me remind you our comments today will include forward-looking statements that are subject to certain risks and uncertainties. For a complete discussion of these risks, we encourage you to read our documents on file with the SEC. Our presentation is being webcast, and the slides are available on our website, which you can access at www.constellation.com under Investor Relations.

On slide 3, you will notice that we will use non-GAAP financial measures in this presentation to help you understand our operating performance. We have attached an appendix to the charts on the website reconciling non-GAAP measures to GAAP measures. With that, I would like to turn the time over to Mayo Shattuck, Chairman, President and CEO of Constellation Energy.

Thank you, Carim. Good morning everyone, and thank you for joining us today. This morning we reported third quarter adjusted earnings of $0.48 per share. Including one time items, Constellation reported a third quarter GAAP loss of $6.99 per share, primarily driven by an impairment charge related to our investment in CENG. As you will recall, when we closed the joint venture with EDF in November of 2009, we were required to write up the value of our investment to reflect the estimated fair value at that time. Since then, a marked decline in the outlook for forward power prices, particularly in the third quarter, has led us to reassess the fair value of our investment in CENG.

After completing this valuation, we determined that our investment had declined by approximately $2.3 billion to a fair value of approximately $2.9 billion, as of September 30, 2010. We recorded this decrease as an impairment charge in our third quarter GAAP results. We are reaffirming our guidance range of $3.05 to $3.45 per share for 2010, and $3.25 to $3.65 per share for 2011. Jack will discuss our impairment charges and earnings guidance in more detail, during the financial during the financial section of the presentation.

As you likely heard earlier this week, we are pleased to announce a favorable agreement with EDF, which fundamentally realigns the relationship between our two companies. In the agreement, we addressed outstanding issues related to our Unistar joint venture and the contractual put option. We did so on terms that provide current and future benefits that were roughly economically the same as under the put option.

We have been, and will continue to be, an advocate for new nuclear. However, as I emphasized many times, new nuclear in America faces multiple challenges that it does not face in other countries where it enjoys strong sovereign support. Challenges include low demand and gas prices, increasing costs to build, the lack of adequate federal energy security and carbon policy, and a flawed federal loan guarantee process, that ultimately proved unworkable for Constellation. Notwithstanding our exit from Unistar, it is important to recognize that hundreds of people at Constellation, EDF and Unistar, have spent considerable time and effort, and made sacrifices, to lay a foundation for new nuclear in America. That is why we're pleased that one important outcome of our agreement, is that this foundation will remain in place, though now solely in EDF's hands. For EDF and the French government, new nuclear in the United States and other countries represents both an international and industrial imperative, and we wish them well in their pursuit.

Turning our attention to our businesses, let's now talk about some highlights that occurred during the quarter. Advancing our strategy to purchase new generation assets, earlier this month, a judge officially approved Constellation as the stalking horse bidder for the Boston generating fleet in New England. This fleet will support our retail and wholesale load serving businesses. This, in addition to the Navasota plants we acquired earlier this year, would complete the Company's previous stated plans, to use approximately $1 billion of cash on hands, to acquire generation plants. If our bid is successful, we will have added approximately 4,800 megawatts of gas fired generation to our portfolio during 2010.

In September, we announced the acquisition of CPower, adding 850 megawatts of demand response capacity to our portfolio, which more than doubles the size of our load response business. This makes us the second largest provider in the commercial and industrial competitive markets. This acquisition provides us with a proven platform, which includes many new customers and partner networks, located in electric choice markets. We expect to sell power and other products to these new customers.

During the quarter, we signed a number of agreements to deploy new solar installations. At the start of 2010, we announced that we had established a $90 million fund to develop solar projects, which we expect to fully commit by year-end. Recently, we announced an agreement to develop a new 5.2 megawatt system, to serve the Johnson Matthey facility in New Jersey. This is expected to produce approximately 20% of the facility's total electrical requirements.

A few weeks earlier, we announced an agreement with the Denver International Airport, for a new 4.4 megawatt solar installation. Constellation will own and operate this solar installation, selling the power produced to the airport under long-term PPA. Overall, our new energy platform performed well in this quarter, despite heightened competition. Our power and gas customer facing businesses, exceeded many of our planned metrics, including volumes, gross margin originated and renewal rates. We were successful in the most recent wholesale load auctions, winning new business at attractive profitability levels.

During the quarter, we continued to increase sales of non-commodity products to new and existing customers. This is an important element of our long term strategy, to broaden our business and relationships, away from pure commodity sales. Finally, during the quarter, BGE received a approval for its smart grid project, and is now able to apply the $200 million federal stimulus grant from the Department of Energy, to this transformational project. As we have said before, this project should improve service, billing and general reliability, while providing significant energy and peak demand savings. Longer term, the system will provide greater insight into BGE's operations, better informing capital investments, and other operational decisions.

Let me end by saying that I'm very proud of the accomplishments that we were able to achieve during the quarter. We remain focused on running the business, and invested in organic and acquisition opportunities, that we believe will drive increased shareholder value now, and into the future. With that, I would like to turn the presentation over to Jack Thayer for the financial overview. Jack?

Thank you, Mayo. As Mayo mentioned, for the third quarter of 2010, we recorded a GAAP loss of $6.99 per share. The GAAP loss was driven by asset impairments, primarily related to CENG. These impairments and other special items totaled $7.47 per share. Backing out these special items, our second quarter (Sic-see Press Release) adjusted earnings were $0.48 per share. You may recall that our adjusted earnings include non-cash, mark-to-market gains, and losses recorded during the quarter. This past quarter, we recorded a mark-to-market loss of approximately $0.14 per share, due in part to steep changes in commodity prices. In particular, natural gas. Excluding these mark-to-market losses, our adjusted earnings would have been $0.62 per share, in line with our business plan.

Looking at our quarterly results by segment, BGE reported adjusted earnings of $0.14 per share, in line with the results for the third quarter of 2009. Our generation segment reported adjusted earnings of $0.27 per share, down $0.67 per share, as compared to the third quarter of 2009. This decline is primarily the result of the sale of 50% of our nuclear assets, and the roll off of higher in the money hedges. Our new energy segment reported an adjusted loss of $0.07 per share in 2010, as compared to a gain of $0.16 per share, in the third quarter of 2009. This year-over-year variance is primarily the result of the negative impact of contract innovations related to our legacy UK coal and freight business. These innovations resulted in a loss of approximately $0.20 per share during the quarter. As you may recall, this offsets the innovations completed in the first quarter of 2010, which resulted in a gain of $0.20 per share. We do not expect any further material innovations to occur.

Turning to slide 6. During the quarter, we recorded impairment charges of approximately $2.5 billion related to our equity investments in the CENG and Unistar joint ventures, as well as our qualifying facilities fleet. These impairments result in non-cash accounting charges, that impact our GAAP earnings and equity balance.

As you will recall, when we closed the CENG joint venture last November, we recorded our investment at its fair value of $5.2 billion, in compliance with US GAAP. Fair value is an estimate, and most significantly impacted by forward power prices. As the decline in power prices accelerated during the third quarter of 2010, we reevaluated the fair value of our investment in CENG. Aside from the near-term commodity price activity, there have been substantial increases in natural gas supply, which depressed prices, and the projected fleet economics out the curve. Additionally, there have been no advancements made to provide any certainty around carbon legislation. Based on our current analysis, we determined that the fair value declined substantiallily, and is more than a temporary phenomenon. Therefore, we have written down the investment by $2.9 billion as of September 30, reflecting a pre-tax impairment charge of $2.3 billion.

Regarding the Unistar joint venture, you are no doubt aware that a few weeks ago, we informed the DOE, that we could not move forward with the loan guarantee process. Additionally, the economics of nuclear base-load generation, have deteriorated substantially from the time this investment began in 2006. Based on these circumstances and the information available to us as of September 30, we recorded a pre-tax impairment charge of $143 million, representing the full amount of our investment. Because we are not permitted to consider our late October agreement with EDF in determining fair value as of September 30, we expect to realize the economic benefit of this agreement in the fourth quarter.

Please turn to slide 7 to review the earnings outlook for our generation segment. Our generation fleet has been hedged for 2010 since the beginning of the year, and is 91% hedged for 2011, thereby insulating these years from changes in commodity prices. During the third quarter, forward power prices fell by approximately $3 to $5 per megawatt hour, in regions where we own plants. Moreover, the fall in power prices, was not accompanied by a similar fall in coal prices. Resulting in narrower dark spreads, and a reduction in earnings projected to come from open generation positions.

In 2012, we're about 50% hedged, a ratio that is lower than some of our peers. We're comfortable with this profile, based on our view, that current forecasted dark spreads are close to, or below breakeven levels, suggesting much more upside than downside. We expect dark spreads to widen as coal prices decrease, due to faulty gas switching and the retirement of smaller, less efficient unscrubbed coal plants. Given these views, we have positioned our portfolio to benefit from an expected widening of dark spreads in 2012.

An important element of our generation earnings outlook in 2013 and beyond, is capacity revenues. Given the most recent capacity auction outcome, we view our PGM fleet and their associated capacity revenues, as an important foundation of stability, to our earnings and cash flows. In 2012 and 2013, approximately 80% of our total unhedged gross margin is driven by these payments, which we will realize in the earnings, regardless of how commodity prices fluctuate. Let me also point out that this slide does not include the Boston generating assets. We anticipate the sale process to end in December of 2010. We remain hopeful that our bid will prevail, and look forward to providing you with additional details during our next earnings call.

Turning to slide 8, and a review of our new energy segment. This is the outlook that we showed in September, that highlights the earnings power and growth of our new energy segment. We will update you with changes, if any, at our year-end presentation in February, when our long-term planning process is completed.

Let me now take a moment to outline some of the key line items on the slide. Power and gas volumes correspond to the load we plan to serve, through our core customer facing businesses. These are characterized by high retention rates in our retail business, and predictable opportunities for wholesale utility auctions. With an average contract duration of approximately 18 months, we have contracted for approximately 65% of 2011, and approximately 35% of 2012's volume estimates.

We're also providing estimates for total gross margin realized, from the three key businesses in our new energy segment. Approximately 80% of the customer power and gas margin realized in each period, comes from our core retail and wholesale load serving activities. The remaining balance includes standard power and gas transactions. These activities include physical entitlements from power plants, contract and portfolio acquisitions and the purchase or sale of our lots of power capacity, and ancillaries for customers. We have a long history in this business, and a track record of consistent financial performance in these product areas.

Our upstream gas business owns properties that produce gas, oil and other distillates. The proven gas reserves from these fields, provide collateral efficient fuel hedges for our natural gas generation fleet. Our asset portfolio is supported by our reserve base loan, and currently produces an amount of natural gas equal to approximately 30% of our needs. If we are successful in closing the Boston generating acquisition, this percentage declines, and we would seek opportunities to expand our portfolio. The gross margin growth we are forecasting from our upstream gas business, is driven more by an expected increase in production, than a bullish outlook for gas prices. Similar to our generation outlook, this business is influenced by changes in commodity prices.

As we've discussed in the past, our sales force has been focused on providing our customers with other energy-related products and services, beyond just the commodities sale. These activities are comprised of solar projects, energy efficiency activities, and demand response management. We remain committed to expanding these operations, as we continue to leverage our existing customer relationships, providing a broad range of offerings, and pursuing new customers in targeted markets. Aside from these growth efforts, it is important to note the scalability of this platform. Over the next three years, our gross margin is expected to increase by approximately $200 million, as compared to about a $35 million increase in operating expenses.

Turning to slide 9. As Mayo discussed, we're holding our 2010 guidance range of $3.05 to $3.45 per share, and our 2011 range of $3.25 to $3.65 per share. At BGE, we are expecting to earn between $0.55 and $0.70 per share in 2010. In 2011, we forecast this segment to earn $0.75 to $0.90 per share. Forces that may impact our earnings include higher than planned pension costs, and the outcome of our pending rate case. And we expect to have a better understanding of these impacts by year-end.

Our generation earnings guidance remains unchanged with 2010 expected to be $1.05 to $1.20 per share, and 2011 to be $0.60 to $0.80 per share. Our highly hedged profile allows us to maintain our guidance levels, even with falling commodity prices during the quarter. Consistent with what we showed you last quarter, we expect our new energy segment to earn between $0.80 and $0.95 per share in 2010. In 2011, we continue to expect our results to be at the lower end of our stated range of $1.20 to $1.40 per share.

Many investors are focused on earnings further out, primarily 2012 and 2013. In 2012, a year that is a trough for many generation companies, we expect a loss from our generations segment, based on the current forward commodity curves. Back on slide 7, we show that the segment is expected to earn $80 million of EBIT. Most of the Company's non-regulated debt is attributed to the generation segment and therefore, it includes most of the associated interest expense, or roughly $130 million. If current forwards were to realize at today's level, this segment would lose approximately $0.10 to $0.20 per share in 2012.

Importantly, looking ahead in 2013, forward commodity prices remain challenged for all companies. However, our generating assets do benefit from being located in attractive regions, such as MAC. The recent 2013, 2014 capacity auction, cleared at well above expected levels. And as you saw in slide 7, capacity revenues for our fleet, and the segment's overall earnings, significantly improved beginning in 2013. At our new energy segment, we expect earnings to improve in 2012, as compared to 2011 levels, as we realize increased gross margin totals from each of our three key businesses, and leverage our scalable platform. As we have discussed in the past, our new energy segment offsets in part, the impact of economic downturns and declines in commodity prices. With that, let me now turn the call over to the operator for questions. Operator?

(Operator Instructions) Your first question comes from Jon Cohen with Morgan Stanley. Sir, you may ask your question.

Hi, good morning, thanks.

Good morning, Jon.

My question's on the generation earnings outlook slide. It looks like the external tolls line in 2013 changed quite a bit. And my other question is now that you're going to be the owner of these Maryland coal facilities, have you started to think about whether you might like to shut some of them down? Even with a higher capacity in 2013, it looks like your EBIT from the generation business is lower than your EBIT from your half of the CENG JV. Implying you're still losing money on their coal plans.

Jon, let me take that. Starting specifically with the external tolls, that is really the impact. As you may recall, some of those assets are located in the MAC regions and particularly the delta plant that is now owned by Calpine. And with the recent clearing auctions we have seen the value of those assets go up, as well as a widening of spark spreads with the -- in the market further out the curve. With respect to -- can you remind me the second part of your question?

The second part of the question is it looks like now you're clearly going to be owning the coal facilities in Maryland. And if I look at your 2013 EBIT guidance from the generation (inaudible) it is, in fact, lower than your 50% earnings -- equity earnings contribution from CENG, implying you're still losing money even though you have half your higher capacity pricing. So, at some point, would you think about maybe shutting down some of your more marginal plants in Maryland?

As I mentioned on our -- on the call, we have retained a 50% hedge ratio, which is definitely lower than some of our peers in 2012 for exactly the issue that you point out. The economics for some of these more marginal plants is becoming challenged. Now, fortunately for our assets, they are located in capacity regions that still make them economic. And continuing their operations is important for the reliability of the southwest MAAC zone. But we are anticipating that other generators who are facing similar issues who do not have that capacity benefit will start to -- given the view that the EPA is going to be more aggressive in their standards as well as the current economics, that firms are going to start to think hard about shutting down some of their smaller, older coal units, and we think that will be a positive for the revenue side of the equation further out the curve.

Thanks.

Your next question comes from Angie Storozynski, Macquarie Capital.

Thank you. I have two questions. One is, with your new EDF agreement, and you clearly have the benefit of the nuclear service agreement and then a benefit of pricing of your nuclear PPA with CNG, where should we see it recognized?

Angie, good morning, this is Jack. I will take that one. So, if you think about the -- if you think about our segment accounting, we have CENG, with the shift in the PPA from a firm to a unit contingent contract, and I believe as part of the 13D EDF reported that that's at a 4% discount, we will see revenues go down at CENG. So, effectively, revenues go down on the generation segment, although, CENG shows up as equity in earnings. And you will see cost of goods sold effectively, or gross margin go up at our NewEnergy segment.

Cost -- okay.

I said that. Costs of goods sold down.

Yes, down. Yes, okay. That's good. Now, how about -- there is a bit of a change in your volumes mix for the retail business, right? Seems like there is more -- well, on NewEnergy side, seems like more on the retail side and less of the wholesale volumes, could you talk about that?

I'm going to actually ask Kathi Hyle to speak to that.

Good morning. So, the volume mix and the good thing about the new reporting package is that you see the P&L and you see the volumes or how we're thinking about volumes for retail and wholesale, and, we consciously spend time thinking about where the switch market is going, what our win rates are, what our market share will be. And you may recall, on the rail side, we really -- these are customers that are very, very sticky and we have a retention rate that approaches 80%, and we work very hard to maintain that for the repeatable earnings. Well, on the wholesale side, it is much more of a counter party business, and that is a business that we can dial up or dial down much more easily as we think about our collateral, our liquidity usage, et cetera,. So, you may see some shifts between the businesses. But the good news that with the segment reporting is that you will see that as our thoughts change.

But is it already reflected in your -- so, the slide that you were showing on NewEnergy is already reflective of the change in the mix?

It is what our thoughts are currently.

Okay, thank you.

Angie, I think it is important to note, and this is why we believe the segmented disclosure is important. We look at this as a business with many sales channels, and we have the flexibility, depending on margins that we see in the variety of sales channels, to dial up or dial down activity across the platform. So, I do believe that over time, you're going to see consistent growth and performance out of that business. But you will see the full P&L effect, not the constituent sales channel data.

Okay, I really appreciate it, thank you.

Your next question comes from Greg Orrill, Barclays Capital.

Yes, thanks a lot, good morning. I was hoping to get an update on just the margins you're seeing on new business at NewEnergy on the power side.

Good morning, Greg, this is Kathi Hyle. So, as you can see, I think in back of the additional modeling for the retail business, our margins -- or the margins that we originated in business for the quarter were in that 5 to 7 range that we came in at 534 for the quarter, and we feel pretty good about that. But, again, I would point us to the P&L that we're providing you. So, I would like us to start looking at -- I think that it is really good to be able to look at the fullness of the P&L and see how as we're growing this business, we're able to leverage our cost structure and drive earnings.

Thank you.

Your next question comes from Ameet Thakkar, Bank of America Merrill Lynch. Your line is open.

Good morning, guys.

Good morning.

I just wanted to follow up on the question that was asked earlier on the change in the CENG, PPA doing more of a unit contingent arrangement. Jack, you mentioned that the revenues at CNG will decline and cost of goods sold at NewEnergy would presume the kind of the decline as well, since they are paying less for the power. Now, the unit -- I guess the change in price would really only apply to the volumes that aren't part of a legacy PPA that you had at Nine Mile Point or GNA, is that correct?

That's correct, so just for -- to reset, we -- when we entered into the sale of half of our interest in CENG to EDF, we entered into a PPA. There was an inception trade which captured approximately $700 million of value, 50% of which was ours. That remains intact as part of this. There were further firm power sales that were contracted for over the course of that, and so really, what we're -- what the unit contingent part of the -- or shift in the contract addresses is the open position, or unhedged position for CENG in 2012, 2013 and 2014.

Okay, and then as far as kind of an order of magnitude impact on earnings in '2012, 2013 and 2014 and NewEnergy, do you have that -- is that something you can discuss?

It's not typically something we go into. I think the good news is that given our disclosure is, you can pull out a 12C and back into a number.

Okay, great. And then just real quick on NewEnergy, it looks like you have a pretty substantial increase in retail, going from some terawatt hours, 90 terawatt hours by 2012. What particular markets are you targeting, and you mentioned that 35% of the load is kind of already contracted. What should we look for in six months from now as far as what kind of percentage of the load you want to have contracted?

Six months from now, the percentage of loads contracted would be somewhere in the 50% range. As far as the markets that we're targeting, we're targeting all the open markets. We are widely balanced, geographically balanced in this business. And as we look at switching rates that are improving, and as we look at other markets that are providing a level of opening, we think -- we build in our market share, expectations, and that's the growth that you're seeing.

Alright. And just, sorry, one last question. And Jack, your EBIT for generational looked like it declined a little bit over $30 million. I was just wondering how the EPS segment from generation for the 2011 guidance wasn't lowered.

I'm sorry, for 2011?

Yes.

I think it is -- we've -- given the range that we provide, that incorporates the potential for prices to move and it's still within the range.

Thank you, sir.

Your next question comes from Reza Hatefi, Decade Capital. Your line is open.

Thank you very much. If I look at slide 7, your non-nuclear gross margin, $119 million plus the capacity piece of $344 million is $463 million, and that compares to last quarter of $5.96, but down about $130 million. Yet it seems on slide 22 that you assumed PJM West and New York power prices only went down $2 to $3, and your total generation is about 15 terawatt hours. I would have thought the decline there would have been more like $40 million or $50 million, but it went down $130 million. So,I'm just trying to figure out why it went down as much as it did.

Reza, with respect to hedges and other things, I think, as you know, we do hedge far out the curve and we do lock in some of these activities. And what you're seeing on slide 22 is current forward market curves. And with respect to what you see on the -- in our outlook on 7, it is really based on the average hedge price that we're seeing. We can go into more detail offline, if you would like to run through the numbers.

Okay, great, yes, that will be helpful. And then just second question, on slide 22, I notice that the non-nuclear plants hedge percentage went to 19%, and it was 24% last quarter. But the average hedge price went up a couple bucks. I am just wondering the percentage hedge went down.

Similar to the -- I guess driven by the earlier comments that I had, what you saw in the -- what you see is we're less hedged than some of our peers. And what I would say is we are active in the hedge market, and we actively manage via portfolio management, and we leverage some of the -- what we perceive to be quite low dark spreads in power prices during the quarter, to effectively buy back or dedesignate hedges against our fleet to make it more open to the extent that a recovery is in the outlook.

And just quickly on the last question, the PJM, or the coal plants, was basis any part of that? Did basis go down? Were your expectations of basis in the out years versus your current expectations quarter versus quarter?

I think it is -- certainly, we consider basis, but it is more an issue of the relative dark spreads, either approaching zero or going south of zero and our expectations that as we move closer to realization, that the more consistent phenomenon that we see is that people behave economically and will bid their plants can economically and will make decisions that drive those dark spreads to widen.

And just if I could just add quickly, we do use gas to hedge in some cases and so sometimes, and as we think about what we have seen in heat rate expansion and as we unwind, we use gas sometimes from a liquidity standpoint and then we will replace with power, and sometimes that can have an impact to those actual hedge prices as heat rates expand.

Okay. And were there any -- just lastly, were there any gains booked during the quarter in terms of hedge management or anything of that nature? I think there is a lot of disclosure in the press release. Sorry, I couldn't go through all of it .

No, not that -- you mean in terms of monetizations?

Yes, monetizations.

No.

No, okay. Okay, great, thank you very much.

Sure.

Your next questions from comes from Neel Mitra, Simmons and Company International, your line is open.

Hey, good morning.

Good morning.

Just had a question on slide 7, the generation earnings outlook. The capacity revenues in 2013, it looks like it is $344 million, and your September 29 presentation looked like that number was $366 million. The numbers haven't materially changed for 2010 through 2012, and I was just wondering what was driving that change for 2013. I would say that any variance you see there is primarily related to New York capacity where we own assets. Okay, so the New York capacity payments have come down for --

Or at least other regions where if you think about where we own generation.

Okay.

It is really the outlook.

Sure. And then, the -- just to follow-up on NewEnergy, the big increase in 2012. I was wondering if you could directionally kind of just break out where you see the growth in retail margins, whether it is going into new regions like Ohio and Pennsylvania, whether it is going into the retail market -- or residential retail markets like in (inaudible) and how much of it is just driven by customers in existing markets.

It is kind of all of the above. So, we have entered the residential market. We've entered the residential market in Maryland and just recently, in New Jersey. We would look to expand our participation in the residential markets by 2012. We -- as I said, we are geographically diverse and we're in all the markets. So, as you see, Pennsylvania open more, we will be there. As you see Ohio, we will be there as well. And really, what you're seeing is our assessment of market switching rates growing, our market share staying the same, or slightly increasing. Our view of where rates are and looking at our renewal percentages, which is a -- generally are able to renew or retain customers in a 75% to 80% range. And with the markets opening, what we expect to win, which -- generally, our win rates are somewhere in the 25% to 30% range.

Great, and just a follow-up on that question. How are you seeing other integrated utilities in terms of competition to kind of hedge generation retail impacting growth rates in terms of volumes and retail margins at this point?

Well, the retail landscape is very competitive in low price in market and maybe more importantly, low volatility markets which we have been seeing or the past year ,and I think we have told you, historically, that when there is low volatility, that does put some pressure on margins. And we certainly are seeing that. It is a very competitive landscape. We have some very strong competitors that we have seen the top five shift around a little bit with First Energy moving up into that top five realm. But we feel very good about our offerings, and our renewal rates are consistent and holding as to what we have seen historically. Our win rates are consistent and holding, and we feel very good about the competitiveness in the market place.

I might just add to that that what we're seeing on the east coast is really just the nascent development of the residential markets that just comes from all of the utilities coming off of their long time rate freezes. Education from a policy standpoint really beginning to take hold and most prominently, there actually being headroom. So, between the states, it is a pretty interesting phenomenon that Maryland is now close to 15%, 16% switched up from very much single digits, probably even 18 months ago. Pennsylvania switching quite fast, New Jersey is really at the front end, so we're in single digits in New Jersey. But in all of these cases, the headroom there is.

The switching rate is moving quite quickly, and that the rate really seems influenced mostly by how much education there has been in the market with respect to what this is all about. It's still a complicated sale. People are still learning what it means to switch off of their local utility, but once that education is in place and there is a -- definitely a word of mouth type of phenomenon and we see the acceleration. So, now is a very interesting time given low volatility, headroom and there really being a -- almost a policy and education response that these markets will be opening up quite quickly.

That is very helpful, thank you.

Next question comes from Paul Fremont, Jefferies, your line is open.

Thank you very much. I guess my first question is, you had talked about the unit contingent discount resulting in lower numbers as CENG and higher growth margin at NewEnergy. Is any of that reflected in your outlook for either CENG or for NewEnergy? So, is that benefit included in the numbers that you provide us with?

So Paul, I think as I mentioned earlier in the call, the unit contingent aspect of that contract really starts hitting in 2012, but more importantly -- more significantly in 2013 and 2014. As you know, we give guidance out through 2011 at this point. It certainly is factored into our guidance, or at least our generation statistics for 2012. But its impact is almost negligible.

And the 2013 CENG number, does that -- is that included in that or not?

The impact, I don't believe that it is included in that, and it is just not that meaningful as to be outside the range, certainly, that we have given at NewEnergy in 2012. And we will update as we roll into the new year and roll forward. The NewEnergy guidance into 2013 will -- it will reflect that outlook.

If I start with the CENG on hedge gross margin of $1.4 billion and add back, let's say another 150 to 200 for fuel, should I take that 4% sort of discount off of like $1.6 billion type number? Is that is a fair way to start here?

Paul, we're obviously happy to work through this off line, but the right way to think about it is the nature of the contract with CENG is that they sold roughly 95% of their output to their two respective partners. We get, in 2013 and 2014, we're on a glide path to getting 85% of that 95% and EDF gets the remaining 15%. So, there is roughly 5% that is sold at the spot markets, and then we get 85% of the remainder. If you think about the megawatt hours that are open that aren't covered by the GNA PPA as well as the Nine Mile 2RSA, then you can get to a number that pencils out to what the impact is.

Okay. You had talked about avoided costs associated with either winding down UniStar and also the potential cost of a lawsuit. Have you -- are you able to quantify what the expected savings from both of those items would be?

I think the important part is when we characterize the settlement, that in our view, we have captured value that that's roughly economically equivalent to had we exercised the put asset. As you point out, avoiding the cost of the wind down at UniStar is a non-trivial component of that. And then with respect to the other elements, the contractual relationships, the other financial terms, that plus this $250 million of tangible value we think gets to that equivalency. You do point out an important element, which is in agreeing to the settlement we did avoid litigation with EDF. Hard to quantify the distraction that that would have been in diverging our focus from our core efforts to grow the NewEnergy business and expand our generation fleet. We don't consider that in the equivalency concept, so I think we would view that as incremental benefit or avoided detriment. And we think it was the right thing to do.

In looking at the FM power plants under the put option, our own numbers, we were coming up with may $40 million or $50 million of EBITDA in 2011 and 2012, but that rose to $100 million and above in 2013 and 2014 because of capacity payments. Is that is a reasonable way to characterize the expected EBITDAs of those power plants?

I with say your near term number's light. Our number is more -- is closer to $70 million. Your longer term number is -- of $100 million is in the ballpark.

Thank you.

Next question comes from Ali Agha of SunTrust Robinson Humphrey Your line is open.

Thank you, good morning.

Good morning.

Jack, assuming that the Boston Gen acquisition does get completed and you end up buying those facilities, could we think of the volume or output coming from those assets as being incremental volume for NewEnergy to go out and market? Or would it serve some of the existing load that NewEnergy has under contract?

Ali, I think the way I characterized that is if you think about generation underpinning our activities, we're roughly at about 50% to 60% match at the moment. We think in this low-price environment, with low-unit bar and more upside than downside exposure as being an area where sustaining that is probably the right way to think about that. So, to the extent that we're able to add the incremental megawatt hours from Boston Gen, we do believe that that would facilitate the potential to go and grow the NewEnergy volumes to the extent we see attractive margins that we can earn in the variety of markets that were active, not just New England.

Okay. So to be clear, so if you want to keep that 50% to 60% mix, that would be sort of the rough run rate in terms of what incremental value or volume should be, assuming that acquisition happens.

So, I think there is an important element in that obviously, we determine whether we enter into business or not as to whether we can earn appropriate economic returns for that risk. To the extent we're able to see those gross margins and P&L, profit and loss, that supports taking on incremental volumes, we will do so. I would say the important element is, if we are successful in New England, our large liquidity pool is fungible. So, to the extent that we have physical generation in one market right now in the pool we're supporting our activities with a variety of both bilateral tolls and counterparty agreements, but also using the financial markets and using our cash and liquidity instruments. To the extent we have physical generation in the region, we can redeploy that in other regions to grow our business, should we see attractive risk adjusted margins and returns.

And Mayo, you had mentioned that assuming Boston Gen happens you basically filled in the holes that you had originally identified in Texas and the New England market. Assuming that is the case, how should we think about use of any excess cash that you may have beyond Boston Gen actually closing?

Yes, I think that we will continue the strategy of looking at assets to match our customer load serving business. So, to the extent that there is something in the market that is attractive to us, we will finance that in a balance sheet neutral manner. So, I don't expect that will be out of the game in that respect.

Okay. And last question, just given the profile that you have laid out for 2012 and essentially, perhaps 2013, is it fair to say from a financial (inaudible) point of view that share buybacks, if any, would be on your radar screen perhaps beyond 2012, or would that not be accurate?

I think it is really just a function of what the opportunity is going to be. And obviously, we have got a business that we feel we can grow. It is growing nicely now. We have a solid strategic path in developing channels, developing products. So, to the extent that that strategy is complimented by reinvestment, obviously, we will go in that direction. But recognizing your point, to the extent that that heads in a different direction which we don't expect, obviously, we will look for returning value when we can to shareholders.

Understood, thank you.

Operator, I think we have maybe time for maybe two more callers.

Your next question comes from Julien Dumoulin-Smith, UBS. Your line is open.

Hi, Good morning.

Good morning.

I was wondering if you could briefly discuss, following up on Ali's question, how you would like to anticipate growing the volumes at the NewEnergy business. It seems as if headroom with the latest slide in power prices would likely provide a continued slate of opportunities into next year. Does that mean there -- further asset acquisitions seems in the cards? Or how would you kind of contextualize the opportunity in terms of the growth at NewEnergy?

Julien, I think, we think about assets supporting that activity, but we also think about liquidity instruments. So, in the quarter we redid our lines of credit with the new three year facility for $2.5 billion. As you seen us with other products, whether it is the gas links credit facility, actually tha we have with your firm, with a sizing of $500 million as well as other instruments, we're quite adept at structuring both physical products as well as financial products that allow us to support and sustain the business. So, what I would say is, with generation acquisitions or not, we're going to be looking at the economics associated with, as well as the market opportunity of, growing the business and looking to sustain that. I think an important window in which we're looking that, and really, guardrails is the context of -- if you think about the average life of a customer is 18 months. What we have to be able to do is should power prices increase, which, as you know, increases unit bar and increases the potential for collateral that we might have to pay -- have to post on new business, that we're keeping a very watchful eye on what that exposure might be in sizing the business appropriately.

So, I guess the good news for us in this environment, is, given declining power prices, this is not a market where you want to be 100% matched. You actually -- our advantage with our model, which is substantially larger volumes of sales relative to the generation we produced, to the extent that that leads us -- or provides us the opportunity to go buy generation assets cheap at what we believe to be the trough of the cycle to better match that business, then I think we would just view that as having the right strategy and having the right structure and balance and the flexibility to go leverage the trough in the cycle while others are either shedding assets or doing other things to season their balance sheets.

Excellent. And maybe -- I imagine it doesn't seem as if you phrased it this way, but are there any growth targets with regards to growing volumes at NewEnergy? Is that something that you would characterize as such?

No, I think you find us to be economic in our decision making and our forecasts. And to the extent that there is good economic business to be done at the right level of risk, we will do it. To the extent that we're not being appropriately compensated, then we're not going to do it. And we have given you a three year volume outlook. I think that is -- I think fair to say, best in class disclosure. To the extent that others want to go out further, we will consider it.

Great, thank you.

One more question.

Thank you, your last question comes from Paul Patterson, Glenrock. Your line is open.

Good morning, Paul.

Good morning. Just a few quick things. The tax impact of the write down and the -- on slide 16, the $730 million of non-cash -- benefit for non-cash adjustment to net income, how should we think about the tax impact going forward? Does it impact earnings at all in the next few years, or just, is it all in the quarter?

I would say that can with respect to the write down, it was purely a write down for GAAP purposes. So, it really doesn't impact -- we didn't pay incremental taxes when we wrote up the value of CENG. We're not realizing tax benefits by writing down, it is merely a GAAP -- as you recall, we don't consolidate CENG.

Right.

So, it is purely a -- a book tax, or -- sorry, a GAAP element, not a tax element.

And is the $730 million just the tax adjustment that we're looking at here in the slide 16 that non-cash adjustment to net income?

Yes.

Okay. And on the DNA, it looks like it goes down $20 million. Is that all that we are going to have on a GAAP basis? Is that sort of the going-forward impact of this write down?

With respect to the going forward, given the life of the assets, let me get back to you on that. I want to make certain that I am capturing the right DNA impact. But we will follow-up with you offline on that.

Okay, and then on Reza's question about the dehedging. There is no financial impact associated with that? There's no benefit from getting out of those contracts? It would seem to me you the would probably get some sort of gain somehow, right?

It is really -- to the extent you dedesignate hedges, it shows up in the accrual books. So, it will realize that benefit in 2012 and beyond as we -- as it shows up as effectively a lower cost to serve.

I got you. Okay. And then also, I wasn't really clear, in the quarter, taking out that $0.20 issue associated with the -- in NewEnergy ventures, the contract mark-to-market loss, it still seemed like it went down. I'm sorry if I missed this. What caused it to go down quarter-over-quarter.

I think you may be confusing two issues. The $0.20 issue was related to the contract novation we had for our Colin Freight business in the UK.

Right.

As you recall, in the first quarter we can had a $0.20 gain. We said it would be offset by a $0.20 loss. This is that and effectively, it is a net breakeven and that ends our impact with respect to --

In the quarter, it seems like it is a negative $0.07. If we add back $0.20, we're about $0.13 versus last year's of $0.16 quarter over -- Q3 to Q3, do you follow me?

Yes, I do. I think, with respect -- it is really corporate allocations, so some of the different way in which we're handling credit facility fees that are drying that shift.

Okay, and then just finally, demand response FERC NOPR, I know you guys have bought CPower and you're obviously very familiar with what is going on with demand response. I was wondering if this NOPR is approved, have you guys done any modeling that you could share with us, the potential impact if the FERC demand response NOPR is implemented as conteplated in the NOPR? In other words, if it comes to fruition as it is currently in the NOPR, what the impact on the markets could be? Is there -- do you guys have anything you can share with us on that?

Paul, really not at this time. Obviously, we're aware of the issue and thinking through the impact on our business, but as far as quantifying it, we're not in a position to do so.

Okay, thanks a lot, guys.

Alright, thanks.

Alright, thank you all. We look forward to seeing you next quarter.

Thank you. This does conclude today's conference. Thank you for attending. You may disconnect at this time.