Good morning, and welcome to the Constellation Energy Group’s Q3 Earnings Conference Call. (Operator Instructions). 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 Q3 earnings call. We appreciate you being with us this morning. On slide 2: before I begin my presentation let me remind you that our comments today will include forward-looking statements, which 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, President, Chairman, and CEO of Constellation Energy.

Thank you, Carim. Good morning, everyone, and thank you for joining us today. This morning we reported Q3 adjusted earnings of $0.48 per share. Including one-time items, Constellation reported a Q3 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 Q3, 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 30th, 2010. We recorded this decrease as an impairment charge in our Q3 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 section of the presentation. As you likely heard earlier this week, we are pleased to announce the 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 a contractual put option. We do 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 are not faced in other countries where it enjoys strong, sovereign…

Thank you, Mayo. As Mayo mentioned, for the Q3 of 2010 we reported 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 Q2 adjusted earnings were $0.48 per share. You may recall that our adjusted earnings include non-cash, marked to market gains and losses recorded during the quarter. This past quarter we recorded a market to market loss of approximately $0.14 per share due in part to steep changes in commodity prices, in particular natural gas. Excluding these marked 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 Q3 of 2009. Our generation segment reported adjusted earnings of $0.27 per share, down $0.67 per share as compared to the Q3 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 Q3 of 2009. This year over year variance is primarily the result of the negative impact of contract novations related to our legacy UK coal and freight business. These novations resulted in a loss of approximately $0.20 per share during the quarter. As you may recall, this offsets the novations completed in the Q1 of 2010, which resulted in a gain of $0.20 per share. We do not expect any further material novations to occur. Turning to slide 6, during the…

(Operator Instructions) Your first question comes from Jon Cohen with Morgan Stanley. Sir, you may ask your question. Jon Cohen – Morgan Stanley: Hi, good morning, thanks.

Good morning, Jon. Jon Cohen – Morgan Stanley: The question 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 ‘13, it looks like your EBIDTA from the generation business is lower than your EBIDTA from your half of the CENG JV, implying you’re still losing money on your coal plants

Jon, let me take that. Starting specifically with the external tolls, that’s really the impact. As you may recall, some of those assets are located in the MAC region and particularly the Delta plant that’s now owned by Calpine. And with the recent clearing auctions we’ve seen the value of those assets go up as well as a widening of dark spreads in the market further out the curve. And can you remind me of the second part of your question? Jon Cohen – Morgan Stanley: Yeah. 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 EBIDTA guidance from the generation business, it is in fact lower than your 50% equity earnings contribution from CENG, implying that you’re still losing money even though you have half of your higher capacity pricing. So at some point would you think about shutting down some of your more marginal plants in Maryland?

As I mentioned on the call we’ve 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’re located in capacity regions that still make them economic, and continuing their operations is important for the reliability of the Southwest MAC 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 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’ll be a positive for the revenue side of the equation further out the curve. Jon Cohen – Morgan Stanley: Thanks.

Your next question comes from Angie Storozynski of Macquarie Capital. Angie Storozynski – Macquarie Capital: Thank you. I have two questions. One is with your new EDF agreement and you clearly have a benefit of the nuclear service agreement, and then a benefit of pricing your nuclear PPA with CENG, where should we see it recognized?

Angie, good morning, this is Jack. I’ll take that one. So 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 revenue generation segment although CENG shows up as equity in earnings. And you will see costs of goods sold effectively or gross margin go up at our New Energy segment. Cost of goods sold down. Angie Storozynski – Macquarie Capital: Yeah, that’s good. Now how about, there’s a bit of a change in your volumes mix for the retail business, right? I mean it seems like there’s more, well on the New Energy side it seems like more on the retail side and less of the wholesale volumes. Can you talk about that?

I’m going to ask Kathy 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 the 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 retail 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. On the wholesale side it’s much more of a counter-party business, and that’s a business that we can dial up or dial down much more easily as we think about our collateral, our liquidity, usage, etc. So you may see some shifts between the businesses but the good news with the segment reporting is that you’ll see that as our thoughts change. Angie Storozynski – Macquarie Capital: But is it already reflected in your- And for the slide that you’re showing on New Energy, it’s already reflected in the mix?

It’s what our thoughts are currently. Angie Storozynski – Macquarie Capital: Okay, thank you.

Angie, I think it’s 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 a variety of sales channels, to dial up or dial down that 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’ll see the full P&L effect, not the constituent sales channel data. Angie Storozynski – Macquarie Capital: Okay, I really appreciate that. Thank you.

Your next question comes from Greg Gregg Orrill, Barclays Capital. Gregg Orrill – Barclays Capital: Yes, thanks a lot. Good morning. I was hoping to get an update on just the margins you’re seeing in new business at New Energy on the power side.

Good morning, Greg, it’s Kathy Hyle. Gregg Orrill – Barclays Capital: Good morning.

So as you can see, in back of the additional modeling for the retail business, our margins or the margins we originated in business for the quarter were in that 5 to 7 range, so we came in at 534 for the quarter. And we feel pretty good about that. I would point you to the P&L that we’re providing you, so I’d like us to start looking at- I think it’s 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. Gregg Orrill – Barclays Capital: Thank you.

Your next question comes from Ameet Thakkar, Bank of America/Merrill Lynch. Your line is open. Ameet Thakkar – Bank of America/Merrill Lynch: Good morning, guys.

Good morning. Ameet Thakkar – Bank of America/Merrill Lynch: Just wanted to follow up on the question that was asked earlier on the change in the CENG PPA to more of a unit contingent arrangement. Jack, you mentioned that I guess the revenues at CENG will decline and cost of goods sold at New Energy would presumably decline as well since they’re paying less for the power. Now the unit contingency, 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 to reset, when we entered into the sale of half of our interests of CENG to EDF, we entered into a PPA. There was an inception trade which captured approximately $700 million in 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 the unit-contingent shift in the contract addresses is the open position or unhedged position of CENG in ‘12, ‘13, and ‘14. Ameet Thakkar – Bank of America/Merrill Lynch: Okay. And then as far as the order of magnitude impact on earnings in ‘12, ‘13, and ‘14 and New Energy, is that something you can discuss?

It’s not typically something we go into. I think the good news is that given our disclosure rates you can pull out a (inaudible) back into a number. Ameet Thakkar – Bank of America/Merrill Lynch: Okay, great. And just real quick on New Energy, it looks like you have a pretty substantial increase in retail, going from some 60 some terawatt hours to over 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 six months from now as far as what kind of percentage of the load you want to have contracted?

So six months from now, the percentage of load contracted would be somewhere in the 50% range. As far as the markets that we’re targeting, we’re targeting all of 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 built in our market share expectations and that’s the growth that you’re seeing. Ameet Thakkar – Bank of America/Merrill Lynch: Okay, and sorry, one last question. And Jack, your EBIDTA for generation looked like it declined a little over $30 million. I just was wondering how the EPS segments from generation for the ‘11 guidance wasn’t lowered.

I’m sorry, for 2011? Ameet Thakkar – Bank of America/Merrill Lynch: Yes.

I think it’s, given the range that we provide that incorporates the potential for prices to move and it’s still within the range. Ameet Thakkar – Bank of America/Merrill Lynch: Thank you, sir.

Your next question comes from Raza Hadasi, Decade Capital. Your line is open. Raza Hadasi – Decade Capital: 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 $596 million – it’s down about $130 million. Yet it seems on slide 22 that your assumed PJM/Wesson New York power prices only went down $2 to $3 and your total generation is up 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.

Raza, 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 in our outlook on 7, it’s really based on the average hedge price that we’re seeing. We can go into more detail offline if you’d like to run through the numbers. Raza Hadasi – Decade Capital: Okay, great. Yeah, that’d be helpful. And then just a second question on slide 22, I noticed 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’m just wondering why the percentage hedged went down.

Similar to the, I guess driven by the earlier comments that I had – what you see is we’re less hedged than some of our peers, and what I’d 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 buyback or de-designate hedges against our fleet to make it more open to the extent that a recovery is in the outlook. Raza Hadasi – Decade Capital: 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 over quarter?

I think that certainly we consider basis but it’s 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 more economically and will bid their plans economically, and will make decisions that drive those dark spreads to widen.

And 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’ve seen in heat rate expansion, and as we unwind we use gas sometimes from a liquidity standpoint and then we’ll replace with power, and sometimes that can have an impact to those actual hedge prices as heat rates expand. Raza Hadasi – Decade Capital: 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’s 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? Raza Hadasi – Decade Capital: Yeah, monetizations.

No. Raza Hadasi – Decade Capital: No, okay. Okay, great. Thank you very much.

Sure.

Your next question comes from Neel Mitra, Simmons and Company International. Your line is open Neel Mitra – Simmons & Company International: Hey, good morning.

Good morning. Neel Mitra – Simmons & Company International: I just had a question on slide 7, the generations earning outlook. The capacity revenue in 2013 looks like it’s $344 million, and in your September 29th presentation it 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. Neel Mitra – Simmons & Company International: Okay, so the New York capacity payments have come down for…?

Or at least other regions where you think about where we own generation. It’s really the outlook. Neel Mitra – Simmons & Company International: Okay, sure. And then just to follow up on New Energy, 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’s going into new regions like Ohio and Pennsylvania, whether it’s going into the retail markets or residential retail markets like in New Jersey? And how much of it is just driven by customers in existing markets?

It’s 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 are 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 we’re generally able to renew or retain customers in the 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. Neel Mitra – Simmons & Company International: Great. And just to 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 just the retail landscape is very competitive, and low pricing markets and maybe more importantly low volatility markets, which we’ve been seeing for the past year; and I think we’ve told you historically that when there is low volatility that does put some pressure on margins, and I think we are certainly seeing that. It’s a very competitive landscape. We have some very strong competitors. We’ve 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 to what we’ve seen historically. Our win rates are consistent and holding, and we feel very good about the competitiveness of the marketplace.

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’s a pretty interesting phenomenon that Maryland is now close to being 15%, 16% switched up from very much single digits probably even 18 months ago. Pennsylvania is 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 is there, the switching rate is moving quite quickly and the rate really seems influenced mostly by how much education there’s 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’s definitely a word-of-mouth type of phenomenon, we see the acceleration. So now is a very interesting time given low volatility, headroom, and there almost being a policy education response that these markets are opening up quite quickly. Neel Mitra – Simmons & Company International: That’s very helpful, thank you.

Your next question comes from Paul Freemont, Jefferies. Your line is open. Paul Fremont – Jefferies: Thank you very much.

Good morning, Paul. Paul Fremont – Jefferies: I guess my first question is you had talked about the unit contingent discount resulting in lower numbers at CENG and higher gross margin at New Energy. Is any of that reflected in your outlook for either CENG or for New Energy? Is that benefit included in the numbers you provide us with?

Paul, I think as I mentioned earlier in the call, the unit contingent aspect of that contract really starts hitting in ‘12, but more significantly in ‘13 and ‘14. As you know we give guidance out through ‘11 at this point. It certainly is factored into our guidance or at least our generation statistics for 2012, but its impact is almost negligible. Paul Fremont – Jefferies: And the ‘13 CENG number, is that included in that or not?

The impact, I don’t believe that it’s included in that. It’s just not that meaningful as to be outside the range that we’ve given New Energy in ‘12. We’ll update as we roll into the new year and roll forward; the New Energy guidance into ‘13 will reflect that outlook. Paul Fremont – Jefferies: If I start with the CENG on hedge gross margin of $1.4 billion and add back let’s say another $150 million to $200 million for fuel, should I take that 4% sort of discount off of a $1.6 billion number? Is that a fair way to start here?

Well, we’re obviously happy to work through this offline, but I think 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 ‘14 we’re on a glide path to getting 85% of that 95%. And EDF gets the remaining 15%, so there’s roughly 5% that’s sold at the spot market 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 2 RSA then you can get to a number that pencils out to what the impact is. Paul Fremont – Jefferies: Okay. You had talked about avoided costs associated with either winding down UniStar and also the potential costs of a lawsuit. 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’ve captured value 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 the $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 New Energy 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. Paul Fremont – Jefferies: In looking at the power plants under the put option, I guess our own numbers, we were coming up with maybe $40 million or $50 million of EBIDTA in ‘11 and ‘12, but that rose to $100 million and above in ‘13 and ‘14 because of capacity payments. Is that a reasonable way to characterize the expected EBIDTAs of those power plants?

I’d say your near-term number’s light. Our number’s more, it’s closer to $70 million. Your longer term number of $100 million is in the ballpark. Paul Fremont – Jefferies: Thank you.

Your next question comes from Ali Agha, SunTrust Robinson Humphrey. Your line is open. Ali Agha – SunTrust Robinson Humphrey: Thank you, good morning.

Good morning. Ali Agha – SunTrust Robinson Humphrey: Jack, as you look at the Boston Gen. acquisition, if it does get completed and you end up buying those facilities, should we think of the volume or output coming from those assets as being incremental volume for New Energy to go out and market? Or would it serve some of the existing load that New Energy has under contract?

I think the way I characterized that is if you think about Generation underpinning our activities, we’re roughly at about a 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’s 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 New Energy volumes to the extent we see attractive margins that we can earn in the variety of markets that we’re active, not just New England. Ali Agha – SunTrust Robinson Humphrey: Okay. So to be clear, 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’s 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 that 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 that 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. Ali Agha – SunTrust Robinson Humphrey: And Mayo, you had mentioned that assuming Boston Gen. happens you basically fill in the holes that you 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?

Yeah, I think that we’ll continue the strategy of looking at assets to match our customer load serving business. So to the extent that there’s something in the market that’s attractive to us we will finance that in a balance sheet neutral manner. So I don’t expect that we’ll be out of the game in that respect. Ali Agha – SunTrust Robinson Humphrey: And last question, just given the profile that you’ve laid out for ‘12 and essentially perhaps ‘13, is it fair to say from a financial prudency point of view that share buybacks if any would be on your radar screen perhaps beyond 2012? Or would that not be accurate?

You know, I think it’s really just a function of what the opportunity is going to be. And obviously we’ve got a business that we feel we can grow. It is growing nicely now, we have a solid strategic path and developing channels, developing products. So to the extent that that strategy is complemented by reinvestment obviously we’ll 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’ll look for returning value when we can to shareholders. Ali Agha – SunTrust Robinson Humphrey: Understood, thank you.

Thank you.

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

Your next question comes from Julien Domoulin-Smith, UBS. Your line is open. Julien Domoulin-Smith – UBS: Hi, 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 New Energy 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 that further asset acquisition seems in the cards or how would you contextualize the opportunity in terms of the growth at New Energy?

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 a new three-year facility for $2.5 billion. As you’ve seen us with other products, whether it’s the gas-linked credit facility actually that we have with your firm, with the 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’d 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 at and really guardrails I 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 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. Actually our advantage with our model, which is substantially larger volumes of sales relative to the generation we produce, 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. Julien Domoulin-Smith – UBS: 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 New Energy? I mean is that something you would characterize as such?

No, I think you’d find us to be economic in our decision making and our forecasts, and the extent that there’s good economic business to be done at the right level of risk we’ll do it. To the extent that we’re not being appropriately compensated then we’re not going to do it. And we’ve given you a three year volume outlook; I think that’s fair to say best in class disclosure. To the extent that others want to go out further we’ll consider it. Julien Domoulin-Smith – UBS: Great, thank you.

I guess one more question.

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

Good morning, Paul. Paul Patterson – Glenrock Associates: Good morning. Just a few quick things. The tax impact of the write down, and 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 is it just all in the quarter?

I would say that 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’s merely a GAAP- As you recall we don’t consolidate CENG, so it’s purely a GAAP element, not a tax element. Paul Patterson – Glenrock Associates: And is the $730 million just the tax adjustment that we’re looking at here in slide 16, that non-cash adjustment to net income?

Ye. Paul Patterson – Glenrock Associates: Okay. And in the D&A, it looks like it goes down $20 million. Is that all we’re 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’m capturing the right D&A impact. But we’ll follow up with you offline on that. Paul Patterson – Glenrock Associates: Okay. And then on Raza’s question about the dehedging, there’s no financial impact associated with that? There’s no benefit from getting out of those contracts? It would seem to me that you probably get some gains somehow, right? No?

It’s really, to the extent that you designate hedges it shows up in the accrual books, so we’ll realize that benefit in ‘12 and beyond as it shows up as effectively a lower cost to serve. Paul Patterson – Glenrock Associates: I gotcha. And then also it wasn’t really clear – in the quarter, I mean picking up that $0.20 issue associated with the New Energy ventures, the contract marked to market loss, it still seems 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 coal and freight business in the UK. As you recall in the Q1 we had a $0.20 gain; we said it would be offset by a $0.20 loss. This is that, and effectively it’s a net break even and that ends our impact with respect to– Paul Patterson – Glenrock Associates: I mean in the quarter it seems like it’s a negative $0.07. If we add back $0.20 we’re about $0.13 versus last year it was $0.16 Q3 to Q3. Do you follow me?

Yeah, I do. I think with respect, it’s really corporate allocations, so some of the different ways in which we’re handling credit facility fees that are driving that shift. Paul Patterson – Glenrock Associates: Okay, and then just finally, demand response FERC NOPER, I know you guys have bought CPower and you’re obviously very familiar with what’s going on with demand response. I was wondering, if this NOPER is approved, have you guys done any modeling that you could share with us the potential impact if the FERC demand response NOPER is implemented as contemplated in the NOPER- In other words, if it comes to fruition as it is currently in the NOPER, what the impact on the markets could be? Do you guys have anything you could share with us on that?

Well 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. Paul Patterson – Glenrock Associates: Okay, thanks a lot guys.

Okay, thanks.

Okay, thank you all. We’ll 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.