艾索倫電力 (EXC) 2010 Q1 法說會逐字稿

Good morning. And welcome to the Constellation Energy Group's first quarter earnings conference call. At this time, all participants are in a listen-only mode. (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 first quarter earnings call. We appreciate you being with us this morning. On slide two, before we begin our presentation, let me remind that you our comments today will include forward-looking statements which are subject to certain risks and uncertainties. For a complete discussion of these risks woe encourage you to read our documents on file with the SEC. Our presentation is being web cast and the slides are available on our Web site which you can access at www.Constellation.com under Investor Relations. On slide three, you will notice 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 Web site reconciling non-GAAP measures to GAAP measures.

With that I would like to turn the time over to shot Mayo Shattuck, Chairman, President and CEO of Constellation Energy.

Thank you, Carim. Good morning, and thank you for joining us today. This morning we reported first quarter adjusted earnings of $1.43 per share. Including one time items, Constellation reported first quarter GAAP earnings of $0.95 a share. We are reaffirming our 2010 guidance range of $3.05 to $3.45 per share.

We are lowering our 2011 guidance range by $0.20 to $3.25 to $3.65 per share. This reflects the impact of significantly lower forward commodity prices on our generation fleet, which contributes to a reduction in our 2011 earnings outlook of approximately $0.40. We expect this decline to be offset in part by improving earnings from our New Energy segment. Jack will discuss this in more detail during the financial section of the presentation.

During the quarter, our New Energy segment continued to generate strong new business, with retail margins averaging at the upper end of our targeted range of $5 to $7 per megawatt hour. The cash flows and earnings associated with these new contracts will be recorded over their duration, which average about 18 months. We recently finalized our agreement with the DOE, for a $200 million smart bridge stimulus grant. We are excited about this project, which represents the best of breed in the new generation of utility operations.

Our Smart Grid system will transform BGE's relationship with its customers, improving service, billing and general reliability, while providing significant energy and peak demand savings. Additionally, the system will provide greater insight into BGE's operations, better informing capital investments and other operational decisions. We await a Maryland PSC order regarding our proposed initiative, which we expect during the second quarter.

This month, we announced the close of Criterion, a 70-megawatt wind project located in western Maryland. The project is expected to cost $140 million and will be constructed and owned by Constellation. This project includes a power purchase agreement with the Old Dominion Cooperative for energy and renewable energy credits produced by the wind facility. This facility adds to Constellation's clean energy portfolio which includes now about 1,000-megawatts of renewable power generation owned or under contract from sources including solar, hydro, geothermal and biomass, in addition to the 3800-megawatts of clean nuclear energy that we operate.

Also this month, we announced an agreement with Navasota holdings to combine two cycle gas plants in Texas for $365 million, the equivalent of $332 per kilowatt, roughly one-third the price of new construction. We view this acquisition as an important first step in our strategy of acquiring attractively priced generating assets in regions where New Energy's load obligations exceed our physical generation capacity.

Let us turn to slide five where I will speak more about the details of of this transaction. The Navasota transaction includes the purchase of two efficient clean natural gas asset, Colorado Bend and Quail Run. Taking advantage of a very favorable entry point in the asset economic cycle, this transaction provides an opportunity to re-establish a physical generation footprint in an attractive market. The transaction includes two 550-megawatt facilities that commenced operation in 2007 and 2008.

The Colorado Bend plant is located in the Houston zone, ERCOT's premium price zone. The Quail Run zone is located in the west zone, near Odessa, Texas in an area where substantial ancillary services are needed to manage reliability given the region's significant wind buildout. On a stand alone basis, we expect this transaction to yield an attractive unlevered rate of return that is based on today's curves within our 8 to 10% target range. Jack will speak to the details of the assumptions that are factored into the calculating of these returns.

This acquisition will also support our retail and wholesale load servicing activities in ERCOT, reducing our net load position by approximately 21% in 2011. These dispatchable units will provide a risk management benefit to our New Energy business in Texas, helping us manage and mitigate risks associated with energy price spikes and providing valuable ancillary services for our load business. Each plant has a 275-megawatt expansion in the advanced development stage. while currently noneconomic, this option provides us with a long-term capability to develop additional capacity in ERCOT and further balance Constellation's generation capacity, and New Energy load obligations in that region.

If you turn to slide six, as we've discussed, throughout 2009, lower total energy demand, idle industrial capacity, and reduced commercial activity contributed to overall economic weakness and in turn lower power prices. Over the first quarter of 2010, forward natural gas prices continued to decline, despite some strength in prompt gas, owing to the potential for increased supply from expanding shale gas production in LNG imports.

Forward power prices dropped during the quarter by a greater rate than natural gas, as forward heat rates contracted due to forecasts for continued low energy demand, weak industrial recovery, and market transformation programs such as demand side management and Smart Grid technology. Forward dark spreads for typical contracts also fell during this period to levels below break-even economics. As the price of coal was supported by increased overseas demand for different types of coal.

We view this to be a temporary phenomenon that will not be sustained over the longer term. Constellation's fully hedged profile in 2010 helps reduce the impact of the lower commodity price environment on our earnings and cash flows. As we look ahead to 2012, Constellation is approximately 46% hedged, with many of these hedges struck significantly above current market prices.

Let's now turn to slide seven to discuss some of the market fundamentals that we're seeing that could spur such a recovery in commodity prices. Within our five-year planning horizon, we see forces that may help return energy demand and reserve margins to 2006 and 2007 levels. Increasing estimates for GDP and industrial production suggests that load growth will resume. On a regional basis, we have seen the most improvements in load in highly industrial regions such as the midwest and ERCOT. In these region, the industrial recovery has helped overall consumption higher.

On the supply side, the downturn in power demand and prices will likely forestall new investment in generation and transmission. For example, projects like path, and lead to a tightening of reserve margins as load demand increases. Also, the volume of new renewable energy being added to the grid is depressing forward prices, but also spurring greater intermittency in spot market volatility. This is driving our focus on gas-fired generation with cycling capabilities becoming increasingly valuable. Offsetting these supply increases is the probability of more coal-fired plant retirements due to age and negative economic returns, and over the longer term, pollution control requirements and regulatory and other legislative mandates. Some forecasts contemplate more than 22 gigawatts of retirements over the next decade.

Although the current commodity price environment is challenging, looking forward, our industry is on the cusp of great change and for those companies with the right strategy, we believe there is robust financial potential. Policy, economics, technology, and the potential for tougher environmental standards are combining to shift the long-term supply and demand fundamentals of our industry. These are changes we welcome, and are prepared to meet through our near-term generation acquisition strategy, and our longer term pursuit of new nuclear.

Before I turn it over to Jack, let's turn to slide eight to review our investment thesis. Our New Energy segment is a leading supplier of electricity and gas to more than 30,000 customers across the country. We are leveraging our existing customer relationships to cross-sell energy products and solutions to further meet their energy management needs, providing us with new sources of revenues. We are also piloting residential retail offerings in markets where the existing head room supports customer switching.

The current low commodity price environment has reduced the New Energy segments contingent and other capital requirements, which means that we are able to grow new business volumes without a significant impact on our current balance sheet and liquidity profile. This segment will help offset the negative impact of lower commodity prices on our generation segments earnings. Additionally, since New Energy is the segment with a higher return on equity, the associated earnings and cash flow growth will also play an important role in sustains our FFO levels and insulating our credit metrics.

Over the longer term, as power prices rebound, we expect the contingent and other capital requirements of New Energy to increase. Maintaining and growing volume levels in a higher priced environment is dependent upon more efficient capital means to hedge the business. In a higher-priced environment, physical generation provides a collateral efficient hedge due to load business and the long time world generation plays in sustaining our New Energy business is one reason why acquiring additional generating assets in the current environment is a high priority.

To this end, we still have a sizable excess cash balance earmarked for asset acquisitions at attractive values, even after announcing plans to develop a solar facility at Mount St. Mary's University, and establish an incremental $90 million fund to develop other solar projects, construct our Criterion wind project in western Maryland, and acquire the Navasota plants in Texas. Near term, these investments strengthen the company from a standpoint, and longer term, these investments position Constellation to benefit from any commodity price recovery.

At our regulated utility, we remain focused on meeting our customer's needs for better reliability, efficiency in managing their energy bills. We have increased our capital spend programs at the utility in order to meet these needs. These plan investments will grow the utilities rate base and should provide a reasonable rate of return to drive additional BGE earnings. Finally, through our UniStar partnership we continue to advance the development of a new nuclear unit at Calvert Cliffs. Another key milestone lies ahead as we await DOE's decision on who will be provided with the federal loan guarantee. Being able to lever the project with a DOE loan guarantee and limiting our exposure to cost overruns and delays should result in attractive risk-adjusted returns for our shareholders. These factors among others are essential to future decisions to build the plant.

With that, I will turn the presentation over to Jack Thayer to review the financial results.

Thank you, Mayo. And good morning, everyone. Turning to slide ten, I will review our financials for the first quarter of 2010. Backing out one-time special items, our first quarter adjusted earnings were $1.43 per share. Strong performances by each of our core business operations contributed to these positive results.

As Mayo mentioned, our GAAP earnings for the first quarter of 2010 were $0.95 per share. During the quarter, we recognized special items of $0.48 per share. Details of these items can be found on slide 16 in the additional modeling section. BGE recorded adjusted earnings of $0.32 per share for the first quarter of 2010. As compared to $0.41 per share for the first quarter of 2009.

As you may know, BGE records approximately half of its annual earnings in the first quarter of any given year on account of the seasonal demand for natural gas and electricity. The decrease in earnings per share as compared to the first quarter of 2009 is largely attributable to the effects of the winter storms in dirt in the mid Atlantic region as record snowstorms blanketed this area, causing outages and line damage which BGE employees worked around the clock to restore. Costs related to storms in the first quarter of 2010 were approximately $0.06 higher than for the same period in 2009.

Our generation segment reported adjusted earnings of $0.44 per share, down $0.04 as compared to adjusted earnings of $0.48 in the first quarter of 2009. Given that we are fully hedged in 2010, the quarter's decline in spot prices did not have a material impact on our first quarter earnings. Rather, the decrease in earnings per share as compared to the first quarter of 2009 is related to the sale of 50% of our nuclear assets to EDF, partially offset by lower interest expenses due to the retirement of the EDF preferred stock, in conjunction with the close of the sale.

Our New Energy segment operations reported adjusted earnings of $0.54 per share in 2010, as compared to the adjusted loss of $0.15 for the first quarter of 2009. This favorable year on year quarterly variance is primarily driven by costs related to derisking our business in 2009 and improved retail power margins during 2010. Also captured in our New Energy segment is the positive impact of the novation of contracts related to or legacy, UK, coal and freight business. These novations resulted in bringing forward into the first quarter approximately $0.19 of noncash earnings. This is expected to be offset later in 2010 by noncash losses associated with other contract novations. We do not expect any further material novation or contributions to our legacy UK coal and freight business to occur. Finally, our in the money PPA with our CEMG joint venture contributed $0.13 to our first quarter 2010 adjusted earnings.

Turning to slide 11, as Mayo discussed earlier, during the quarter we announced our acquisition of two combined cycle plants in Texas from Navasota holdings. This acquisition provides us with a strong physical generation foundation in Texas that will complement our New Energy activities in the state. The price paid for the project was attractive. With an IRR well within our targeted range of 8 to 10%, unlevered returns for generation acquisitions, and with an implied multiple of approximately seven times mid cycle EBITDA before considering the benefits these plants offer our New Energy business. These projected returns consider our modeling of the Pacific plants and our long term assumptions about the ERCOT market.

Let me take a moment to describe these assumptions. Increasing wind generation in ERCOT will have a beneficial impact on combined cycle plants like Colorado Bend and Quail Run. As wind contributes to additional system variability going forward, given the intermittency of the resource. This should require us to procure more ancillary services and to cycle plants more often during the high-priced periods caused by wind fluctuation. Colorado Bend and Quail Run are both highly flexible plants, and will benefit from both additional ancillary revenues and greater run time.

Furthermore, by adding these plants, Constellation is reducing its exposure to costly super peak pricing in Texas, which exceeded $1,000 per megawatt hour during seven days in 2009, and 15 days in 2008. ERCOT is one of the most price volatile and dynamic power markets. Texas is also one of the fastest growing states in the US, where higher-than-average load growth is projected. However, the current commodity market and the lack of a capacity product means that new build economics will be challenging in Texas in the near future.

At the same time, Texas has one of the lowest reserve margins in the country, currently 22%. And it is expected to decline to 10% by 2015 according to ERCOT's estimates. Typically, reserve margins falling below 15% is viewed as a new build signal. Accordingly, we would expect to see longer term spark spread expansion required to support new build economics. Overall, we're excited about the transaction in Texas, and it is one that we hope to replicate during this low commodity and asset price environment.

Let's now turn to slide 12 to review our generation fleet's economics. This is a slide that is likely familiar to most of you. It represents our generation earnings outlook, providing an update on how changes in forward prices and hedging activity affects our generation segments earnings. In 2010, our generation fleet has been fully hedged since the beginning of the year, thereby insulating it from the recent fall in spot and forward commodity prices during the first quarter.

As you are all aware during the first quarter, forward power prices across the country fell by a significant amount. In the regions where we own plant, around the clock forward prices declined by approximately $7 to $9 per megawatt hour. Moreover, the fall in power prices was not accompanied by a similar fall in coal prices. Resulting in tighter dark spreads, and reductions in earnings projected to come from our open generation positions.

As we look forward to 2011 and 2012, although less hedged than in 2010, we still maintain high annual hedge percentages relative to our peers. Our hedge ratios are 74%, and 46% in 2011 and 2012 respectively. Given the magnitude of the decline in commodity prices, and the tightening of dark spreads, the move during the quarter had a material impact on our generation earnings outlook. Since the start of the year, for example, our forecasted 2011 generation EBIT has fallen by approximately $110 million.

The impact of falling forward commodity prices is being felt by every company in our industry. However, our competitive business model with a strong New Energy business outlook is reducing the impact of declining prices on our overall earnings. As we've said in the past, our retail load serving business typically originates higher margins during troughs in the commodity cycle. Expanded margins and prospectively growing load volumes during periods of low power prices increases earnings at New Energy. Helping insulate Constellation from trough periods in the power cycle.

Let's now turn to slide 13 where I will discuss the business mix of our New Energy segment. As we discussed with you during our analyst day, our New Energy segment is a leading provider of load to retail and wholesale customers. However, in addition to selling more power and gas to customers, we are also focused on leveraging our customer relationships to cross-sell our energy products and solutions, increasing our share of our customers' total energy spend. Within our New Energy segment, we have different activities, some of whose margins typically move with our counter with commodity price improvements and some that are largely independent of moves in prices.

Customer power and gas includes our retail and wholesale power and retail gas operations. These operations are counter-cyclical to the broader commodity marks and currently represent the largest portion of our New Energy segment. Accounting for approximately 70% to 80% of the total business mix. Our upstream gas business consists of six fields with proven reserves that are approximately 280BCF, primarily located in the Woodford Basin.

These assets provide an effective hedge to approximately 30% of our overall gas needs in 2010. These assets are levered to a recovering commodity prices, primarily gas, although these fields do also produce some natural gas liquids and crude oil. This also provides collaterally efficient means to offset the impact of changing gas prices on our generation fleet. Currently, these assets represent approximately 10 to 15% of New Energy's total business mix.

Customer services and solutions provides large commercial, industrial, and governmental customers with solutions such as energy efficiency, automated demand response, and behind the meter solar. We also provide products such as energy audits and service contracts tailored to meet the needs of residential and small commercial customers. These activities offer services and provide benefits to customers through every stage in the commodity cycle and t are therefore independent of commodity price movements. While we have plans to grow this segment as we increase our cross-selling efforts to our customers, currently these activities represent total of approximately 10 to 15% of New Energy's total business mix.

Turning to slide 14, to review our earnings guidance. Let me conclude by reviewing our earnings guidance for 2010 and 2011. Our 2010 guidance range remains unchanged at $3.05 to $3.45 per share. We have, as Mayo mentioned at the start, lowered our 2011 guidance by $0.20 to $3.25 to $3.65 per share. Reflecting the $0.40 impact of lower commodity prices on our generation fleet, offset in part by $0.20 higher expected New Energy earnings.

As you can see on this slide, using our new reporting framework, we're able to provide you with our 2010 and 2011 guidance on a segment level basis. Thereby allowing to you better understand the merits of our competitive business model, where increasing New Energy earnings helps to offset declining generation earnings. Let me now take a moment and walk you through the 2010 and 2011 guidance by segment. After earning $0.80 on an adjusted basis in 2009, we're forecasting BGE to earn between $0.55 and $0.70 in 2010. The decrease is driven by higher O & M expenses as well as higher depreciation, due to increased investment.

In 2011, we expect to earn adequate risk-adjusted returns on increasing investments on BGE infrastructure and smart energy programs. Our generation segment earned $2.11 on an adjusted basis in 2009. In 2010, we expect the earnings contribution from this segment to decrease to a range of $1.05 to $1.20 per share. Largely driven by the loss of earnings related to the sale of 50% of our nuclear assets. The lost earnings, however, are partially offset by the $0.56 of benefit we received from our below market PPA with the nuclear joint venture. In 2011, as we discussed, declining power prices have negatively impacted this segment causing the segment's earnings forecast to decline approximately $0.40 per share.

During 2009 our New Energy segment contributed $0.46 on an adjusted per share basis, driven by lower volumes that were offset by higher margins on new business. In 2010 we expect this segment to contribute $0.80 to $0.95 of earnings, with the continued rolloff of lower margin contracts, and increased cross-selling opportunities. In 2011, the retail and wholesale businesses are expected to continue their increasing earnings trend, with the roll-off of lower margin contracts, higher origination volume, and the realization of new retail business at the higher end of our margin expectation of $5 to $7 per megawatt hour. For 2011, we expect New Energy to be between $1.20 and $1.40 per share, up $0.20 from the range we showed you as of year end 2009.

As currently hedged in 2012 and beyond, Constellation's earnings are increasingly leveraged to dark spreads and outright power prices. We show our exposures on the right side of the slide. In 2012, as PPAs roll off, we like many of our industry peers are increasingly sensitive to power prices.

Let me now turn the time back to Mayo for some concluding comments.

Before turning the call over to questions, let me conclude with just a few thoughts. The uncertainty of the current commodity environment weighs heavily on everyone in this call. We however see opportunity. We have built a company and a strategy with the flexibility to deal with all phases of the commodity cycle, whether in the troughs and harvesting value at the peaks. We are using our excess cash balances and financial stability to further transform Constellation into the leading customer-focused, merchant generation company. Our first quarter is an important step on the road to realizing this strategic vision. And with that, operator, I will turn it over for questions.

Thank you. (Operator Instructions). Your first question comes from Dan Eggers Credit Suisse. Your line is open.

Good morning. Jack, I was wondering if you could elaborate a little bit more on the New Energy expansion, from what we saw at the analyst day, am I hearing that the volumes you guys expect to sell out of New Energy are going to go higher than kind of the stable number you talked about before?

Sure, Dan, good morning. Let me answer your question and then I'm going to ask Kathi Hyle to comment on the business outlook. With respect to margins, we continue to see them coming in at the high end of the $5 to $7 range tier. To your volumes comment, as you recall, in the declining price environment, we have to reserve less collateral against prospective market stresses. And so in the current environment, we see the opportunity to expand the volumes prospectively of the business. We're doing without any impact to the balance sheet or our use of our available -- or nonavailable liquidity. Kathi do you want to comment on the business?

Sure. We're very pleased with the business opportunities that we've seen this past quarter in particular, the margins. Volumes, I believe we have in one of the modeling pages, and you can see that we're forecasting I believe 134 terawatt hours of volume, pretty equally split between the retail and the wholesale business for 2010, and that's pretty consistent with what we shared with you on analyst day.

So I guess we're then assuming that -- okay. How much volume increase do you have based on the lower collateral obligations? Does that mean that 134 is 150, 160? Or is it more small increments of increased volumes?

So for 2010, the 134 is what we think we're going to do this year. As you look out, you know, maybe start thinking about 10 to 12 terawatt hour increase as a range for 2011.

Okay. I guess the other question, and maybe it might be a little early yet but what are you guys seeing with kind of the financial reform package coming through right now, how it is going to affect kind of the trading and positioning around the New Energy business broadly and then within the specific cost of the business.

Well, you probably prefaced that correctly or it might be a little bit too early. It has been a very, very dynamic week on that front. But I think that the industry is still very much focused on the end user evening exemption language and the definition of the swap, and we believe -- and this is probably the most important issue, the we believe that the intent is actually to have an end user exemption. So we continue to be very much involved in that debate, with all constituencies and I think that the industry representatives, EEI, and others involved in this debate, have really spent an enormous amount of productive effort, making sure people understand what is obviously a complicated issue. And we will not let up on that with the prospect obviously that there are amendments to come, and there is a regulatory process and rule-making process to come, and I think that it is going to be important that all of us continue to focus on the intent, and I think that we feel that the work done to date is going to end up in a place where the industry falls largely under this end user exemption issue.

And if I can just ask one last one, mayo, any thoughts on when you expect to hear from the DOE on the loan guarantee.

I'm going to have Mike Wallace who is deeply involved in that speak to that issue.

Good morning, Dan. Our application with the DOE is complete now, after months of interaction and complying with their requests for additional data and reviews. And further, our negotiations with DOE are now finished. The key step that we now await is approval by the DOE credit review board. That is the final step that DOE that is required, so that they can issue their commitment letter. We understand there is also a White House review process under way as well. But in summary, given all of that, we anticipate getting a DOE loan guarantee commitment letter in the next several weeks.

Okay. Thank you.

Your next question comes from Andrew Weisel, Macquarie Capital. Your line is open.

Hi, good morning, guys. The first question has to do with the volumes at New Energy. It looks like they actually -- the projected volumes of this year have actually come down by about 5 terawatt hours from the last update. Given the counter-cyclical nature and the low power prices, why is that directionally going down and is that conservative?

So the volumes that we have in the 134, it is just our current forecast, and update and it contemplates whatever activities we're seeing from the economic cycle. And the mix of the business between our wholesale and our retail business. We feel very strong about what we've seen in the quarter, with respect to new originated business from both the volume and more particularly from a margin standpoint, and we feel pretty comfortable with what we're presenting here today.

Okay. Great. The next question is about future asset acquisitions. Obviously, you can't get too specific. But should we think about the regional priorities based on where your most short load or is it more a matter of which regions are most appealing kind of in absolute terms?

Well, our objectives continue to be the same, that we have expressed obviously an interest in the northeast and Texas as being the places where we have the largest load obligations, and the least amount of generation capacity. In the case of NEPOOL, none. So we will continue to focus on both regions. Those are the highest priorities. And we think that during the course of the year, there are going to be some opportunities that arise in those regions.

Okay. Thanks. Then the last one, sort of just a nitpicky one. 2010, you're basically fully hedged, but for some reason, it looks like the average hedge prices have actually come down by a couple percent. How does that work there just mathematically?

I think it is -- the answer to that question is quite simple. This is the amount for the remainder of the year. Whereas the prior estimate was for a full year. So it is really just the nature of hedges rolling off, and impacting the averages.

Got it. That makes sense. Okay, great, thanks a lot, guys.

Thank you.

Your next question comes from Greg Gordon, Morgan Stanley. Your line is open.

Thanks. Good morning.

Good morning, Greg.

I jumped on a little bit late, I just heard the tail end of what you said, your economic assumptions were for the acquisition of the Navasota plant. Can you just review that again?

In terms of unlevered returns, we would expect to earn, within our targeted range, of 8 to 10%. On a mid cycle EBITDA, we believe we paid seven times EBITDA for the plant. And that's before you consider any of the insurance benefits or business support benefits of the plant for our ERCOT retail activities and wholesale activities.

So you're basically assuming then that spark spreads rise from where they are now by around $5, $6 per megawatt hour, right? Because right now, it looks to me based on that math like you're assuming a spark spread closer to $20 a megawatt hour.

I think in looking at those plants it is important not just to focus on actual spark spreads but also the ancillary services that t these plants provide. They do offer the ability to respond quickly to the intermittency associated with wind. I think on a longer-term perspective, and the fundamentals certainly support an increase in heat rates in ERCOT, you're seeing demand there. That state is growing faster and participating in the economic recovery to a greater degree than many of the other states in the union, and we do see reserve margins there getting below that 15% threshold that does tend to signal new build responses and in ERCOT it is going to have to show up in power prices as opposed to capacity that you would see in a market like PJM.

So there is some combination of increases in heat rates and/or ancillary services that gets -- that adds several dollars a megawatt hour to revenue versus where the current forward curve currently is? Is that a fair --

No, that's correct. Plus the capacity factor of the plant, we would expect it to increase as reserve margins --

So there is sort of a dynamic impact to reserve margins tighten, capacity utilization goes up, at the same time that your realized revenue per megawatt hour goes up. But clearly you can't justify buying the plants at the price that you paid if you assumed that current forward curves were accurate and to ask the question in another way, what is your multiple as you pay on 2011 cash flow, with the current curve were to continue to be -- continue to be in place?

I think, Greg, your earlier comment about our anticipation of a recovery that exceeds the current forwards, plus the impact on the expected capacity factors of the assets is what makes the acquisition economic, these assets are uniquely leveraged to a recovery, particularly given the price we paid for the assets, the transaction is modestly dilutive, in 2010 and 2011, and we would expect it to be break even and accretive in 2012 and beyond.

Okay. Great. I guess I just have one other question. I hate to beat a dead horse on this, but my understanding was these assets were on the market for some time. And lots of different potential acquirers had an opportunity to look at them. It seems that your rationale for acquiring them makes sense to me but it doesn't seem like there is any secret sauce to this. Where do you see something different? Or where do you have a different edge from the dozen or other other entities that had an opportunity to look at these assets.

Greg, I might recharacterize, there was an auction process with these assets so if that's what you mean by being on the market for some period of time, I think it is clearly, we won an auction process. I would suggest the secret sauce is the relationship that these assets are forward, from a risk management perspective our New Energy business, to allowing us to hedge the exposures with gas which is far less volatile than the $1,000 per megawatt hour prices that we tend to see with some frequency in Texas during low wind, high temperature periods.

Okay. So you basically bought yourself a heat rate cap, on top of the assets working based on your economic assumption, you also bought yourself a heat rate cape for your retail businesses?

It certainly insulates or clips the super peak exposure that is uniquely sized in the ERCOT market given their willingness to let power prices send new build signals because they don't have the capacity market.

Thanks, Jack. That is all very clear.

Your next question comes from David Frank, Catapult. Your line is open.

Hi, good morning.

Good morning.

Jack, you have an estimate or could you provide us in percentage terms an estimate of New Energy's, your expected earnings total contributions beyond 2011?

No. I think at this point, given the time span between now and 2012, I don't think that would be prudent, given the open position we maintain in our expectations for power price recovery. for power price recovery.

Okay. And a follow-up actually for Mayo, when I look to slide eight, you have a bullet you talk about participating in the development of new nuclear in your partnership with EDF, and you have a little segment that talks about attractive, assuming among other things, you I guess minimize your exposure to cost overruns and delays. Is this kind of maybe where the value, the hidden value in that put could come into play?

Well, as we talked about on analyst day, there are a number of issues that we have been addressing for close to four years now, with respect to knocking off the risk profile of building a new nuclear plant, and certainly one of the big hurdles, right in front of us, is the loan guarantee process. And in fact, there is a little bit of good news, sort of in the week, in the sense that there seems to be growing support for expanding the volumes underneath the loan guarantee program. So hopefully that will manifest itself, and we have -- you know, within the last month or so, since analyst day, just continued in the same path of developing processes to mitigate the other risks that we have associated with the project. Obviously, cost overrun is an issue that naturally we, and our investors would be concerned about. We have a significant partner in all of this, you know, looking at the same economic issues, and they have other broader aspirations and interests around the world, with respect to the development of particularly the French nuclear industry, and so all of these things are in very active discussion at this point, as you might imagine. This is a big year for new nuclear. And so as we suggested last time, we take all of these variables into account, in very active discussions with our partner, and as those unfold during the course of the year, we will be as disclosive about that as we can be. But I definitely would represent that this is sort of the big year, as most of these major risks get consummated and mitigated, if we're to proceed.

Great. Well, thanks a lot. Congratulations on a great quarter.

Great. Thanks very much.

Your next question comes from Paul Fremont, Jefferies. Your line is open.

Thank you. I guess I'm confused on a number of fronts. You guys had an analyst meeting at the end of March in a commodity price environment that is virtually identical to today's, but you chose to take down your guidance on the generation side today, rather than a month ago. Were you anticipating some improvement in the commodity prices between the analyst meeting and today? Or what was the logic there?

This is Jack. Clearly, as we spoke to you, and other analysts going into that meeting, we acknowledged that the prices had come down markedly during the quarter. As you know, we maintain an active investor calendar, and so it was no secret that we -- that there was going to be some impact on prospectives, 2011 and beyond earnings if we marked to current market. With respect to the focus of that analyst day, it was very much on the new segment outlook and we didn't want to distract from the focus on the segment reporting and the fundamentals of the business by marking our earnings to market.

With respect to what we've seen in power prices, we certainly gave you the detail and transparency to make your own assumptions in your models with respect to what the impact could be if you mark those earnings to market. And I think we've been probably somewhat progressive relative to peers in the industry in acknowledging what the impact of the current forward markets will be on our 2011 earnings relative to peers and beyond. And the final point I would make is while we knew where prices were going to be, given that the forwards you see are March 23, since that point, if you were to market the end -- at the end of April here, we've seen a modest recovery from that period of somewhere between 4 and 8% in 2011. If you look at PGM and New York pricing. So I don't know that I would characterize our analyst day and the decision to reduce guidance here today, as being addressed in a way that you perhaps described.

The second area of confusion for me is you've talked about multiple of EBITDA, in mid cycle. I guess what you haven't said is what should we expect is the EBITDA of the Texas plants? I think we -- you know, our own calculations were coming out somewhere in the $10 million range. Is that a reasonable assumption to use for EBITDA contribution in 2011? Or is that -- or are you coming up with something materially different?

Well, I think it is fair to say that with respect to those assets, we've given you the heat rate, you know the capacity factors that they've been running, and you can make your own assumptions around what the contributions from those specific assets will be, in 2010 and 2011, and I did comment earlier that the acquisition is modestly dilutive to 2010 and 2011 EPS and becomes break-even to accretive in 2012 and beyond.

Are the Texas assets included in the non-nuclear generation earnings outlook statistics? Or are they excluded from that?

They are not in there as we have not closed on the acquisition yet.

Okay. And I guess back at the analyst day, the numbers that you provided, I think had a return on cash assumption of 1.75%. Pre-tax. Is that assumption still what we should assume is baked into your guidance numbers?

Basically, we use one year LIBOR strip to calculate the return from the cash. I don't think there's been any meaningful news in LIBOR in that one-year strip period.

Thank you very much.

Thank you.

We have time -- I think we have time for one more call.

Thank you. Your last question comes from Reza Hatefi, Decade Capital. Your line is open.

Thank you. A couple of questions. One, could you expand, talk a little bit more about the increase in guidance at New Energy in 2011. And I guess there was a $0.20 increase and what drove that?

I think the short answer is higher than anticipated margins on new originated business, and renewal business, as well as expectations to grow other aspects of our New Energy business.

Is the new guidance envisioning more volume in there than your prior guidance?

2011.

For 2011, it contemplated as Kathi Hyle mentioned on a approximately 10 to 12 terawatt hours of volume growth.

And you mean 10 to 12 terawatt hours of volume growth versus your prior guidance or just versus 2010?

Versus 2010.

And how about versus your prior 2011 guidance? Are you now seeing more volumes in that -- that was the main driver of the $0.20 increase in guidance? Or is it that you signed some great deals recently that are now -- you're now embedding in that guidance?

No, it is entirely related to -- with the decline in power prices, that we've seen the collateral, we have to reserve against stress scenarios, is smaller, on a per unit basis, which allows us to, with our current available liquidity and balance sheet to do a higher volume of business.

Okay. And I'm looking at slide 28. I noticed that for example in 2013, your non-nuclear plans are hedged 25%. And then on slide 14, the total coal volumes are 14.8 terra watt hour, and gas oil is 2.1 terra watt hours. Now, so it seems like the total generation volumes are lower in 2013 versus your analyst day slides. But yet, your hedge percentages are also lower. It is now 25%. It was 29% at the analyst day. And the analyst day also had higher volumes. So could you explain I guess what happened there? I would have thought the hedge percentage would have gone up with lower volumes.

The reality is once you get out to 2013, there is not a liquid market. So to the extent that we're taking actions to forward hedge our fossil generation, further out the curve, generally that is done in the PJM market through gas and as well as some longer term wholesale obligation, but given the time and duration between now and then, we would expect obviously these numbers to change meaningfully each quarter and every year, up through 2013, given the normal cadence of hedging in our business.

Okay. So it is like a mix -- are you sort of saying it is a mixed products of hedges and that's why that number kind of moves around or --

If you think about how we hedge the business, the bulk of it is through our New Energy business, with 18-month customer contracts. So if you think about a normal hedging profile, we're hedging our fleet roughly 2.5% each month, going through the year. In the forward year. That relationship decreases as you get further out the curve, given there's no liquid market really, and you have to use proxies to hedge the fleet, based on a macro outlook for power prices at the curve.

So none of the hedges were monetized or anything like that?

I think there's -- no, there is -- it is just normal course hedge management of the fleet on a current year plus three basis.

Okay. Appreciate that. Thank you very much.

Thank you.

All right. Well, thank you all very much for attending this morning. And we will see you next quarter. Thank you, operator.

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