Good morning, and welcome to Constellation Energy Group's Fourth Quarter and Full-Year 2010 Earnings Conference Call. [Operator Instructions] I will now turn the meeting over to the Director of Investor Relations for Constellation, Sandra Brummitt. Sandra, you may begin.

Thank you. Welcome to Constellation Energy's 2010 Year End Earnings Call. We appreciate you being with us this morning. With me here in Baltimore today are Mayo Shattuck, Chairman, President and CEO; and Jack Thayer, Senior Vice President and CFO. Mayo and Jack will provide you their perspective on our performance for the quarter and the year, as well as our expectations for the future. Following their remarks, we'll take your questions. Please turn your attention to Slide 2, a reminder 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 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.

Thank you, Sandra, and welcome to your new role. Good morning, everyone, and thank you for joining us today. This morning, we reported full-year adjusted earnings of $3.06 per share, which includes a non-cash mark-to-market timing loss of $0.23 per share. Including one-time items, Constellation reported a full-year GAAP loss of $4.90 per share, primarily driven by impairment charges on our CENG and UniStar investments. Importantly, the one-time items resulted in a positive cash inflow of approximately $240 million. Looking forward, our guidance ranges remained at the previously disclosed $3.10 to $3.40 per share for 2011, and $2.40 to $2.70 per share for 2012. Our 2013 earnings estimate continues to be north of $3 per share. Jack will discuss our 2010 results and earnings outlook in more detail later in the presentation. In 2010, Constellation performed very well, completing all of the strategic initiatives we announced at the end of 2009. We strengthened and grew customer relationships, invested in physical generation assets at attractive prices and improved system reliability and corporate-wide efficiency. We believe the successful completion of these initiatives lays a solid foundation for perspective growth of our customer-centric business. In February of last year, we spoke with you about our plan to deploy more than $1 billion to acquire Generation. In less than 12 months, we completed our goal by purchasing combined cycle facilities in ERCOT and NEPOOL at attractive prices. We also completed construction and are now operating our Hillabee combined cycle plant in Alabama and the Criterion wind project in Western Maryland. Collectively, through acquisitions and investments, we have added more than 4,300 megawatts of physical generation capacity to our portfolio, bringing the total installed capacity of our generation fleet to approximately 12,000 megawatts. We are expanding the bundle of products and solutions we offer customers…

Thank you, Mayo, and I'm on Slide 10. As Mayo mentioned, full-year 2010 adjusted earnings were $3.06 per share. As you may recall, our adjusted earnings include non-cash mark-to-market gains and losses that service hedges in customer and generation positions. This past year, we recorded a mark-to-market loss of approximately $0.23 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've been $3.29 per share in the upper end of our guidance range. Looking at our results by segment, BGE reported adjusted earnings of $0.69 per share, down from $0.80 per share in 2009. This decrease was due to the impact of higher storm-related expenses and inflation, partially offset by lower bad debt expense and higher transmission revenues. Our Generation segment reported adjusted earnings of $1.25 per share, down from $2.11 per share in 2009. This decline was primarily the result of the sale of approximately 50% of our nuclear assets at the end of 2009. Our NewEnergy segment reported adjusted earnings of $0.54 per share in 2010, improving $0.08 per share as compared to 2009. This improvement is primarily the result of improved profitability in our Power business and greater upstream gas production. Turning to Slide 11. Similar to other utilities, BGE is currently in a growth phase, investing considerable capital in technology, infrastructure and efficiency projects. Over the next three years, BGE's average rate base is projected to grow to approximately $4.8 billion, representing a 28% increase over our current rate base. We are investing capital to improve system reliability and quality of service for BGE's customers. We expect to file rate cases in a more frequent manner, reducing regulatory lag and driving improved earnings. With regards to the implementation of our smart meters and…

Thanks, Jack. So in 2010, we took advantage of growth opportunities, both organically and through acquisitions. As we look forward in 2011 and beyond, we expect to grow in each of our business segments. As we've discussed in 2010, we acquired generating assets and funded these acquisitions with excess cash on hand. Looking forward, we continue to pursue attractive opportunities to further expand our physical generation fleet in regions such as ERCOT, where the load we serve is greater than the amount of physical generation we own or contract. This approach to our generation in load-serving businesses and competitive market should drive greater efficiency in terms of capital requirements and realized earnings and cash flow, sustaining a balanced earnings model. We believe that we'll be able to fund these acquisitions by accessing the equity and debt markets. We will continue to be a leading supplier of power and gas to retail and wholesale customers. We're expanding our offerings to include more innovative products and services that help meet customers' financial objectives, energy efficiency targets and carbon footprint reduction goals. We believe that these additional offerings will strengthen and deepen our customer relationships and provide us with additional sources of non-commodity-based earnings. We are increasing our capital spending program at BGE, investing in liability and energy efficiency. Our Smart Grid program is just one example of this increased spending commitment. Respectively, this increase in capital spending should grow the utilities rate base and its earnings. Finally, Constellation is committed to further streamlining its businesses, making Constellation a leaner, focused company poised for growth. Aggressive pursuit of cost savings and capital efficiency, as well as a balanced asset-backed investment strategy is key to our continued competitiveness. With that, I'll turn the presentation over for questions and ask the operator to open it up. Operator?

[Operator Instructions] And our first question comes from Angie Storozynski with Macquarie Capital.

The growth in the NewEnergy business. You're not providing any more the split between retail and wholesale. Should we assume that the growth since the third quarter is everything in retail?

Kathy Hyle is here and I'll have her address that.

So the growth in the fourth quarter was primarily retail and across the Power business in the fourth quarter.

But I am asking about the forward-looking volume.

For forward-looking, there's a half a dozen things that are driving that group. One is the markets are growing, so we talked about Pennsylvania, Ohio, Illinois, Michigan, Caps, and maybe Arizona. KEMA, put out a retail energy outlook published in late January and they state that they expect the '10 to '11 period to be one of the largest growth periods for competitive power sales and we certainly have seen that where we've seen volume growth of over 30% year-over-year in 2010, and we kind of expect to see 2011 levels to be very good. Second issue is we've got this national platform that is different than anyone else and we can really drive growth through that national platform. As Jack mentioned, for the first time, we truly have a unified sales force. We've got -- we're selling commodities with one sales force. We've got products specialists, We've got quotas and our compensation is aligned to those expectations. With a scalable model, we've completed in 2010, our systems integration. We've got one system and we really are on the brink of being able to realize true scalability. We've got the breadth of our product offerings, so with Solar, Energy Efficiency, Demand response, Information Management, that allows us to deepen our customer relationships and that drives renewal rates and profitability. And lastly, we are supporting all of this with investment dollars for greater training, education and marketing support. So that's really the fundamental reasons why we're seeing the growth in the business, Angie.

Yes, but I was actually asking if this is retail volumes or is it wholesale volumes?

Primarily retail volumes.

And similar drivers for the pickup in gas volumes?

Yes.

I understand that we're having a lot of uncertainty as to what happens with PJM capacity prices. But you are providing a disclosure of your capacity revenues for 2014. Could you tell us what kind of assumptions do you have behind those numbers?

Sure, Angie, this is Jack. We do anticipate and we include in here our fundamental view that capacity prices will decline in the '14, '15 auctions in Southwest MAAC relative to the '13, '14 planning years capacity price clearing. And just as you think about a sensitivity to that, if prices were to go down by $10 million, that results in about $7 million gross margin hit in 2014 and about $11 million in '15. So as you recall, its back-end weighted to the '15 planning period. Obviously, if prices were to go up, then we would see the inverse of that happen.

Jack, just for clarification. The predicate was that if prices went down by $10.

That's correct. I was just trying to give the six delay.

But what's already embedded in this assumption is a much lower number than last year's auction. Is that correct?

What's embedded is a lower number, but you'll recall that the impact of that is roughly five months of the year.

I know, I mean, our calculations imply a significantly lower number embedded than your estimates, and that's why I was asking, But I'll follow-up offline.

Gregg Orrill with Barclays Capital.

I was wondering if you could comment on the cash balance at the end of the year and how much you think you have potentially? Cash balance at the end of the year and how much you think you have available for acquisitions and outside the load region, specifically where you might look to deploy that?

Well, obviously with the close of the Boston Generating assets, we used a significant portion of that cash balance in the opening week of 2011. With respect to the cash on hand, as we've guided you before across the businesses, we'd like to keep roughly $600 million of cash on hand at any given time. As we do expect, the Quail Run facilities sale to close in generally the end of the first quarter, maybe early in the second quarter. But that would increase the cash balance by $180 million or so and we would look to use those cash proceeds to grow our business and that could be in the form of generating acquisitions or it could be growing the NewEnergy business.

And maybe I missed it, but how much of the $0.23 mark-to-market was in the fourth quarter?

$0.10 of that mark-to-market was in the fourth quarter and will realize the offsetting position, primarily in 2011, but some '12 and '13.

Brian Chin with Citigroup.

Question on the collateral chart that you guys put in your presentation. Is that intended to include Boston GenCo or no?

Yes, it does.

If I compare the collateral chart versus the prior quarter's collateral chart, it doesn't look like there's a whole lot of movement in necessary collateral positions. Should we have expected some change given the acquisition of Boston GenCo there? Or is that not right?

I would say, Brian, you have sort of two offsetting moves. One, obviously we do add the Boston Generating facilities, but prices have gone down. Therefore, as we calculate in that lower-priced environment, the benefit from generating capacity and offsetting collateral postings or the potential need to post in extreme events goes down.

And then just following up on the capacity price commentary. Is it the view that capacity prices should be lower for your portfolio because of transmission line capacity and convergence of prices between Southwest MAAC and RTO? Or is there some other issue that you guys are expecting?

I think it's more fundamentally the demand statistics that have come out from PJM and their recent guidance are lower. That's offset in part by a higher cost of new entry charge, but that clearly doesn't make up for the difference.

So then do you expect Southwest MAAC to clear separately from the MAAC and RTO regions, or no?

We do expect more impact in MAAC than we do in Southwest MAAC.

I might just add to that, that the modesty bearish signals were obviously the load forecasts went down and there was also increased transfer limits into MAAC. And on the other hand, sort of the question marks that will sort itself out through the auction would be unknown, coal retirements, what the DR bids will be and then the bidding strategies from the other companies. So I think on balance, this is like a little bit of a forecasting game that we don't play out publicly, but those are probably the most important variables that will realize themselves when we get the answer.

Ameet Thakkar with Bank of America Merrill Lynch.

I don't want to belabor, I guess, the capacity discussion, but I was looking at Slide 32, and you guys have a footnote there that says -- I guess it says, reflects clearing prices 2013, '14 only. Just so I'm clear, the '14 generation EBITDA or gross margin you provided, does that assume that capacity prices are flat? Or as Jack mentioned, you guys are assuming a lower price reflecting your fundamental view?

I'd say, Ameet, on 32, it's really -- this is just for presentation sake. This is not the number that is included in our generation hedged disclosure.

And then just real quick on, I guess, the retail gas growth. I think you guys kind of highlighted some of the states where you're seeing increases in switching et cetera on the power side. Is it similar on the gas side, or are there other areas that we should kind of focus on for describing that growth?

This is Kathy Hyle. It is similar on the gas side, but really one of the more important things really is the unified sales force and we're getting one sales force that's truly selling both. Larger power sales force now has the ability to sell gas.

I noticed that you guys didn't provide, I guess, the gross margin on $1 dollar per megawatt hour basis on retail. But you did discuss some of the drivers; higher volume, higher retention rates. I guess should we assume that, I guess, gross margins have kind of -- on a per unit basis are kind of flat and you're just really driving this by higher retention and higher volume?

Yes, we have given you ranges, 5% to 7% for retail, 2% to 4% for wholesale. We certainly expect to be within those ranges over our planning period.

Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG: As you guys look at kind of the 2012 open position hedging and then kind of your point of view in the market, how should we think about ratably heading into '12 and '13 over the course of this year? And are there metrics we should be paying attention to as far as free cash flow or coverage metrics that will affect how you guys put on positions?

Dan, as you know, we sell the power from our generating fleet to our NewEnergy business, who in turn hedges externally. Typically in any given year, as we roll into a new year, so let's move forward to stay were at this time, next year in 2012. We would anticipate being anywhere from 80% to 100% hedged depending on our bullishness or bearishness on pricing. What we've seen certainly in the 2011 period as you get closer to the delivery year, the more fundamental physical elements of plants actually needing to make money to run have caused dark spreads to increase, as we've gotten closer to delivery, we'd anticipate similar occurrences in 2012 as we get closer. Dan Eggers - Crédit Suisse AG: You talked about the idea of expressing a view with where you're hedged right now. How far off of what you’d be at normal run rate hedge are you guys, in the expression of your view? Or is the hedge percentage now is just kind of a natural hedging, so there is not a significant view being expressed in where you're hedged today?

I would say we are at the lower end of the range, which we'd be hedged for 2012. I generally like to about 60% to 80% hedged in the current year plus one, and we’re just right at the lower end of that range. Dan Eggers - Crédit Suisse AG: Then I guess, Kathy, maybe you could talk to this a little bit. But extending a year on NewEnergy we see customer services and solutions with about 24% CAGR over the next three years from a growth perspective. Can you share a little bit of where you're seeing some of that scaling? And how much of it is the ability to grow into it with some of the new acquisitions, and how much of it is just deeper customer penetration?

It's primarily deeper customer penetration, although certainly the CPower acquisition gives us a formidable position with the demand response. But as we are seeing and you saw great results in the Solar business, where we sold 36 megawatts to customers this year; we expect that to continue. The Energy Efficiency has been a little bit slower in 2010 than we would like, but we're starting to feel very good about that ramping up and it really is just this breadth of product offerings that we're seeing in our customers and being able to penetrate those customers more deeply. Dan Eggers - Crédit Suisse AG: When I look at the fact that O&M isn't moving in that process, should we be thinking that these businesses are kind of infinitely scalable from a profitability perspective? Or where are you getting the release on O&M on a multi-year basis?

We really are on the brink of scalability right now. I can't say enough about what it means to have us all, all the retail platform being on one system and the ability for us to really drive and leverage this business and you're going to start to see that over the next couple of years.

John Cohen with Morgan Stanley.

Just PJM power prices had been rising kind of through the end of last year, which we think to some degree is due to strong eastern coal prices. Can you just talk a little bit about to what extent do you think the NYMEX quoted prices for cap reflect your true underlying economics for coal purchases? And also for your open gross margin in '12 and '13, when you're a little bit less hedged, what assumptions are you making in terms of coal pricing out there and also the coal composition, the coal mix, for the fleet?

Sure, John, as you know, we've seen both because of the Australian flooding, but also global demand for, as you mentioned, CAP coal coming out of China, India and other markets. We have seen Central App coal move higher roughly to $80 a ton. I think our expectation is that you will continue to see a healthy bid for coal in the market and that will elevate overall from a fundamental point of view overall power prices as coals on the margin and good portions of the day here in Southwest MAAC. With respect to our hedging statistics. If you look at our coal hedging, you can see that we're really trying to sustain more of the dark spread exposure as opposed to power price exposure. We're only 9% hedged in 2013, in this current environment where you do have higher prices and if there is the risk of potentially locking in higher-priced coal and exposing yourself to declining prices should that happen. Then obviously that increases the risk we're trying to manage that by appropriately aligning our fossil hedges and our coal hedges.

But is your exposure on the coal side CAP pricing or can you blend in some higher sulfur Illinois Basin or PRB coals to kind of reduce your fuel costs?

It depends on the assets. Certainly, at our Brandon Shores and Keystone and Conemaugh facilities, those are the largest baseloads. We're primarily earning the Central App coal. We do have the ability to blend in at certain other facilities, PRB and other, and we can burn some Illinois Basin.

I just wanted to hit on your comment about the tolling arrangements. Can you just comment on the structure of the two biggest ones, which are to clean energy plant and Calpine's York facilities? How would you suggest that we model those from both an earnings perspective and also from a valuation perspective?

Interestingly enough, I think, on a valuation perspective, let me start there. Obviously, this is a negative drag on earnings and to extent you're applying a multiple to something that looks more akin to debt, or a hedge, an underwater hedge that rolls off. I think you're probably overstating the negative impact on the overall earnings capabilities of the enterprise. The tolls themselves largely five-year deals where we have tolls where we deliver gas when we get the power. We have seen an uptick and you'll see this in our Generation stats, an uptick in our expectations of how much in Q4 we expect in terms of output. From those facilities, but nevertheless, certainly not at the heat rates that we would have expected in a much higher gas environment in 2008 when we entered into the long-dated contracts for them.

Neel Mitra with Simmons and Company. Neel Mitra - Simmons & Company: On Slide 13, it looks like the 2012 gas load that you project to serve went up about 33 Bcf, and the customer power and gas gross margin went up about $71 million since the last update. And I was wondering what was driving the increase in gas load serve? Did you sign a contract, or is it a projection? And then second, if all of that $71 million is attributable to the new load or if power margins have come up since your last update?

Neel, I'd say on the gas side, as Kathy mentioned. As we sell -- as we increasingly sell gas and power through a unified sales force, our expectation is that we will pick up incremental sales. We also did enter into a new gas supply agreement that is more attractively priced. So we also believe that, that should also help us be more competitive in the markets. On the customer power and gas side, as we mentioned earlier in the presentation, we are investing significant dollars in growing our mass markets channels. And obviously those investment dollars in '11 really start to pull through in 2012, as we benefit from the growth of that business, as well as ideally market expansion as the Illinois Power Authority contract rolls off and that market opens up a as well as others. Neel Mitra - Simmons & Company: And then Jack, on the operating expenses, excluding upstream gas, they're going up in 2011 and 2012 when the volumes aren't going up that much. Should we view the rising O&M in '11 and '12 as an investment for new contracts in '13 or 14? Or is it a true reflection of your operating expenses in '11 and 12?

Really would bifurcate that into two things. One, as we mentioned, this now includes the CPower acquisition, which obviously wouldn't show up in volumes, assets, demand response. So there is increased expense associated with the inclusion of that business. As you did reference and as I previously did, the investment dollars associated with marketing Constellation Electric, as a mass markets provider are the other key driver in the '11 and '12 increase. In terms of the overall scalability, the platform that we previously discussed, we continue to believe that, that is the key competitive advantage that we're just beginning to realize. Neel Mitra - Simmons & Company: And then just really quickly on the way we should look at the NewEnergy business from a gross margin perspective of $5 to $7 a megawatt hour and ROE of 11% to 14%, do those metrics still apply? Or should we be looking at it differently in terms of profitability?

I tend to be an EBITDA person myself. I think as we talked previously, gross margin depending on the customer class, if you're earning $5 to $7 from a residential retail customer that’s obviously not that great. If you're earning it from someone like Verizon, that can be fantastic. So we don't believe the gross margin is really a good measure of the overall profitability of each customer relationship, which in part is why we went to this level of disclosure and re-segmented the business. So I think from our end, if you look at the analyst community, there's a range of values that's applied to the EBITDA in the business. I would say our hope is as we shift on more bundled non-commodity-driven sale right now, we're about 13%. Our goal would be to get about 20% of our overall sales being from non-commodity-related activities. I guess the high end of the street is probably 6x EBITDA multiple in that business. If we are contracting for 20-year solar arrangements with our customers and long-dated energy efficiency relationships and automated load control that makes it a very sticky relationship with our customer. We believe that as an annuity-like and a highly-recurring business, where we are providing our customers with very valuable services that can't get elsewhere on a bundled basis. And we think that should merit a higher multiple.

All right. Well, thank you all. We'll expect to have you all online in another quarter, but we'll see you up in the road during the course of the quarter. Thanks all very much.

Thank you for participating on today's conference call. You may disconnect at this time.