Good Morning. My name is Cynthia, and I will be your conference operator today. At this time, we would like to welcome everyone to the Exelon Corp. Second Quarter Earnings Conference Call. [Operator Instructions] I would now like to turn today's call over to Stacie Frank, Senior Vice President of Investor Relations. Please go ahead, ma'am.

Good morning. Welcome to Exelon's Second Quarter 2010 Earnings Review and Conference Call Update. Thank you for joining us today. We issued our earnings release this morning. If you haven't received it, the release is available on the Exelon website at www.exeloncorp.com. Before we begin today's discussion, let me remind you that the earnings release and other matters we will discuss in today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties, as well as adjusted non-GAAP operating earnings. Please refer to today's 8-K and our other filings for a discussion of factors that may cause results to differ from management's projections, forecasts and expectations, and for a reconciliation of operating to GAAP earnings. Leading the call today are John Rowe, Exelon's Chairman and Chief Executive Officer; and Matthew Hilzinger, Exelon's Senior Vice President and Chief Financial Officer. They are joined by other members of Exelon's senior management team who will be available to answer your questions. I will now turn the call over to John Rowe, Exelon's CEO.

Thank you, Stacie. Good morning, everyone. As you all know from our press release, our second quarter performance exceeded both our own earlier expectations and your estimates. Exelon turned in operating earnings of $0.99 per share compared to our earlier estimates at $0.80 to $0.90 per share. Matt will explain how we were able to do this in more detail, but constant attention to operating performance across all of our business units were a big part of the story, and so we're improving power market conditions. The weather also helped. We've had so much heat in Philadelphia, almost twice the normal level, Denis O'Brien, who is a bit of a skeptic looked at me the other day and said, "John, if this stays up, I'm going to believe that climate problem you've been working on is real." It is, and we might be even be seeing it. As a result of our strong first half, we are raising our operating earnings estimate for the year to $3.80 to $4.10 per share. Now normally, on these calls, I spend most of my time talking about the highlights of the quarter. I'm going to leave that to Matt Hilzinger today and talk about the subject that most of you are asking us to address. That is our longer-term earnings potential. Most of you tell us that you respect our operating performance. We appreciate that, I think we deserve it. Most of you described our assets as a solid foundation for future earnings growth. That's true too. Most of you recognized that we have some upside next year, as the full requirements contract expires between Exelon Generation and PECO. But you'll likely question how two, three, four years from now, we will be able to prosper in a world of low gas prices…

Thank you, John, and good morning, everyone. As John mentioned, that I will provide an overview of the results for the quarter and highlight a few key drivers compared to our earnings guidance, and how we expect the results will affect us for the rest of the year. I will also give a brief update on our hedging activity and load forecast. The key messages for today's call can be found on Slide 6. I echo John's sentiment on this quarter's performance. It was exceptional. We recorded operating earnings of $0.99 per share, well above our guidance for the quarter, primarily due to two drivers. First, higher rev net fuel at ExGen, mainly attributable to increase nuclear volumes and improved market conditions, and second, favorable weather at PECO and ComEd. Our second quarter results were achieved despite incurring $0.03 per share of cost for severe storms that hit the ComEd and PECO service territories. With respect to the storms, thousands of dedicated employees under the leadership of Denis O'Brien, Frank Clark and Anne Pramaggiore, worked tirelessly to repair damage resulting from severe storm activity in late June. ComEd restored 90% of the 800,000-plus customer outages, resulting from two waves of storms within 24 hours. PECO mobilized its emergency response organization to restore service to the 330,000 customers affected by one storm that lasted 30 minutes. Both ComEd and PECO continue to raise the bar for rapid storm response and delivering on our commitment to keep the lights on. Our quarter-over-quarter drivers for the operating companies can be found on Slide 8, 9 and 10. In lieu of walking through the quarter-over-quarter results, I'll spend my time providing additional insight into the two drivers that led to the second quarter earnings being above our guidance. Starting with PECO on Slide 11.…

[Operator Instructions] Your first question comes from Hugh Wynne with Sanford Bernstein.

I wanted to ask a question about the estimated impact of the Clean Air Transport Rule that you outlined in your first slide. And I guess my question is this, how do you expect the impact to capacity prices to materialize, particularly in Western PJM, where we see some coal-fired power plants owned by Edison and Ameren and Dynegy to be particularly vulnerable to closure. And the reason I asked is because it seems to me that the scale of potential retirements in Western PJM is sufficiently large that they probably can't be permitted by PJM and maintain desired levels of reliability, and measures will have to be taken therefore to augment capacity. It might include some of the transmission upgrades that you've mentioned, also RMR contracts such as you've mentioned and maybe demand-side management initiatives, as well. And I guess my question is, could you please walk us through how the capacity impact would play out given that some of these measures may not, in and of themselves, actually lead to the withdrawal of this capacity from the auctions?

We see it about like you do. The short answer to your three questions are yes, yes and yes. The way we look at it is, there will be very substantial impacts in the Illinois, Indiana, Missouri area that you described in your comments, that those impacts will be mitigated by combinations of transmission, RMR and demand-management activities. We still see very substantial benefit here for the values of Exelon Generation. And I want to ask both Ken Cornew and Joe Dominguez to supplement my answer because we worked very hard when we developed our Eddystone and Cromby RMR proposals to make certain that we weren't asking for things that were anti-market or anti-green. There are ways to do this that helped in both regards. So let me first ask Joe to comment with his insights on your questions, and then I'll ask Ken to back cleanup here.

Thanks, John. Hugh, let me break this into pieces. First, talking about the Transport Rule, we don't see the Transport Rule as a driver for retirements, not in its present version. I think what John referenced to in his earlier remarks is that the combination of two provisions in the Transport Rule: One, that it begins in 2012; and two, that it eliminates the value of historical SO2 and NOx allowances in the banks that exist will create a new allowance market in 2012, which, based on pricing we have seen in EPA's power price modeling, we would anticipate will have an effect of $2 to $3 on market prices beginning in 2012. That does not occur as that's in the energy market. That's not capacity market. Turning to the capacity market, we have looked at a number of the analyses of retirements that we'd expect and are not anymore getting worse, as well as pirates and many others that exist. Across the country, if we look at all of the RTOs, there is about 100 gigawatts of excess capacity above and beyond the NERC reliability requirements. So that if we see all of the retirements that are predicted even in some of the more severe scenarios, we would not see a shortage of capacity that would put the system in jeopardy from an overall capacity reserve margin basis. We will see, and John alluded to this, some hotspots where transmission upgrades will have to be made before units are allowed to retire, but the timing is important here. Because the capacity auction looks three years forward, unless the RMR lasts for three years or more, you would not affect the next capacity pricing cycle. So, for example, in the case of our Cromby and Eddystone RMR, we will have…

Hugh, Joe and John I think it address pretty well the retirement situation, also associated with continuing to operate coal plants and those costs ending up in the bidding structure in the capacity market for plants that actually exist. Finally, we also have to consider declining energy benefits from these plants as historical energy benefits decline that results in higher cost to bid in the capacity construct, both driven by gas prices being lower and incremental and variable cost of dispatching these coal plants. So it's not only retirement, it's also the cost structure that defines the cost-base bids for existing capacity that are likely to be pushed higher.

Our next question comes from the line of Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG: John, I appreciate the dialogue and I guess if we were to take the conversation a little further when you think about mercury and any other impacts, what it would do to plant closures and necessary rises in capacity revenues, energy revenues, that sort of thing. How do you deal with the regulators by way of managing through the magnitude of rate increases that would presumably come with the sort of earnings transfer you see out the horizon and in particular, as you look at Illinois with the power authority and their ability to contract outside of traditional auction mechanisms. Is there a risk that some of these value transferred never ends up to you because the regulators get in the way?

There is always risk but I would point out that we have a lot of room for upside in '12 and '13 and '14 before power prices get back to the levels in total and in absolute levels or the levels of increases that we were talking about in the 2006 and '07 period. But yes, of course, there is risk and Joe and Darryl Bradford and Bill Von Hoene, Paul Bonney and a whole lot of other people will both be working on managing that risk and also working on ways of handling contractual negotiations so that these increases are feathered in an orderly way. We've been fairly good in finding ways to come up with long-term agreements that soften this volatility on a year-to-year basis, and we'll continue to hunt for those ends. Dan Eggers - Crédit Suisse AG: And I guess one other question, John. You've had a more outspoken view on where the markets are going to go because of these policy events. Are you seeing any assets out in the market that seem underpriced ahead of what could be a significant recovery as you see the market going?

It's funny, we always see assets overpriced compared to companies. And I don't think we're seeing a lot of underpriced assets out there. We keep looking but the people who have the assets that we think will flourish best in this environment continue to carry pretty good prices for those assets. So we find that chopping is -- still work for parsimonious people.

Your next question comes from the line of Jonathan Arnold with Deutsche Bank.

My question has to do with just trying to reconcile some of the comments you've made about your optimism in terms of seeing signs of recovery in the market and then just how much additional hedging you put on during the quarter? Looked like you added the best part of 10% and when I do the math on what ratable would mean in terms of getting to 90% type range for 2012, you wouldn't have had to add anything like that much. So can you help us to reconcile the amount of hedging you did and your comments on the market outlook, which seemed, in my view, to imply optimism around the near term as well as the longer term?

I will do my best. We have lots of reasons to hedge, and of course, I'll ask Ken to supplement this. One of which is to protect the dividend and the credit ratings in downside scenarios. Another is that the further you go out, the less liquid markets are, and we don't want to be in a position where we have issues over liquid markets. But as I said in my opening comments, we try to soften the effect of the hedging by using -- put options where we can. So we kind of hedge the downside on the basic commodities, but keep a chance to get the spreads that we think will be there. It's a constant conundrum for us and if we ever abandon the basic ratable approach, we'll let you all know. But right now, we think we should, more or less, stick with ratable. We do think the upside is real, and as we become more confident of that, can take it into account when it does. Ken, can you pick that up from there because the tension you described is clear and it's just that we want to have some absolute protection on the downside.

Sure, Jonathan. John highlighted the reasons we hedged and how we align our hedging with our financial policies, and you've heard that before. And he also highlighted the size of our Merchant Generation portfolio and held us three-year ratable hedging program had tend to allow us to orderly, in an orderly fashion, sell our portfolio in orderly, strategic way. Two or three years out, the portfolio is still had substantial upside from the open position as he has indicated. Another comment we haven't talked about as much in advance is our customers, wanting to buy power in that type of work-time range also. The competitive Retail business is typically a two- to three-year business. Polar options are typically two to five years, but full requirements products being in the two- to three-year range and then Block products going out five years, in which we have an opportunity to get some upside from environmental regulation. And finally, there are plenty of wholesale customers out there that are much interested in having generation in a forward sense than in a spot sense. Don't forget the price uncertainties that still exist in this marketplace. Economic recovery, obviously, spot gas prices still tend to be weaker than forwards and we have to watch that and be sensible about that. And you know the generation supply effect doesn't react that quickly. And John talked a lot about what's going to happen to the generation spot back in the future. But it is slow to react and likely not in this three-year timeframe significantly, and we have weather uncertainty. That being said, we've stayed ratable and we've gotten ahead -- we stayed ahead of ratable with our options as we did last quarter. If you look at that hedge disclosure, we're probably slightly behind the ratable pace in the second quarter in '11, slightly ahead in '12, and we did a lot of hedging in '12 in the Eastern part of our portfolio and very little in the Midwest part of our portfolio. So we try to balance that to keep some upside. So we continue to look at different products and locations and timing, just trying to keep as much upside as we can for you.

I would particularly note Ken's comments that some of his longer-term contracts include some premium for the environmental issues that we see.

Could I ask a related follow-up? When you look at the forward curve for power out through PJM and NiHub and you see the kind of uptick there is in the 2014 curve, I mean, what do you attribute that to and then to what -- when you're kind of trying to deconstruct the curve, is there -- how much of that is the upside that you're describing and how much of it is just liquidity or whatever else in the curve?

Jonathan, it's obviously challenging to deconstruct, but my opinion is the majority of the movement in heat rates and power prices has been driven by spot prices and what we've actually seen this year relative to last year, we see much improvement in spot prices year-over-year. Congestion is significantly less year-over-year. We see some demand recovery, particularly off peak in industrial sectors in the Midwest. And we've actually gotten some normal weather and a little better weather. So I believe most of what you've seen so far is related to the spot market kind of rationalizing the forward prices.

Your next question comes from the line of Michael Lapides with Goldman Sachs.

Two questions, not necessarily related to each other. First, demand. You're not-weather-adjusted demand trends during the quarter were pretty different, meaning, ComEd pretty strong, PECO, not so strong. Can you just talk about drivers of that and what you expect, not just kind of going forward in near term, but next few years, meaning, what are going to be the biggest drivers of demand differences across the two different regions?

I'll let Denis O'Brien from PECO and Anne Pramaggiore from ComEd pickup in this. But let me say that you accurately described the second quarter. But in the first quarter, PECO had a better pickup and on the whole, we're looking at demand growth between 0% and 1% this year, probably a little better in PECO going into the out years. ComEd, continuing in that vein unless, of course, the Air Quality Enrichment program that's going on around the country leads to consistently higher weather. But we see very soft recovery. We tend to see our very large customers coming back. A little improvement in our residential load, but what we would call the small commercial and industrial sectors remain very depressed. And with that, defers status on that end?

Philadelphia has had rather unique weather here with the first quarter having 70 inches of snow, the snowiest winter in history. A three snowstorms that stormed the region in, interesting enough. And June is the hottest month in Philadelphia in 137 years of record-keeping. So when you try to do your weather correction, you're dealing in some pretty unique space. If you put the first quarter and the second quarter together for us, residential growth is at 0% for us for the first half of the year. We see just a moderate grow from there, about 0.5% growth for the second half of the year. And a small C&I -- the second quarter did not look good when you put the two quarters together. It's about just under negative 3% growth. We saw the small C&I drop last year in the third quarter. So as we profile it from here on out, it's about a negative 0.5% from here. We see small C&I very slow in coming back. I think we're near the bottom there, but it's going to be a long way in terms of coming back. And then in the large C&I, the first half has had 1.4% growth. As Matt said, driven by the manufacturing sector. We've seen steel and petroleum, in particular, are being strong. That's been about rebuilding inventory and some benefit we've seen from consolidation of planned activities and more of those coming in to our region. The load that's coming to the region like consolidation of plants, we see that continuing on. Building of inventory, we do not really see that trailing off unless we see in the economy turn significantly. And when you add them together with some known information we have from the pharmaceutical sector, we see the large C&I pretty flat for the second half of the year in terms of -- comparison to '09. So all-in-all, we stand with our estimates, pretty flat for the rest of the year.

Unrelated question -- lots of the PJM assets are either going to incur significantly more cost aka the unscrubbed coal units or shutdown. When you look outside of PJM, meaning the states to your north, to your west, and even some to your south, lots of -- have you looked at how many of those coal plant are actually being scrubbed and whether those coal plants can wheel power into Northern Illinois?

Joe Dominguez will take that.

Obviously, because of the imports into PJM, we look at retirements not just within PJM, but in MISO and to a lesser extent within SERC. So we have taken all of that into consideration. I think those are the three areas you can put your finger on that you're going to see the greatest impact in terms of coal retirements. This is certainly not a situation that's unique to PJM. I'd say, there are three NERC-reliability regions that are going to be most affected, and that's going to be PJM or RFC has called in NERC space, MISO and SERC are going to see similar numbers of retirements as a result of these new regulations, and we have considered that in our modeling space.

But are you likely to of see a fundamental difference in the number of plants across scaler side that gets scrubbed in the states where, honestly, those plants are under traditional rate-making processes versus those that are in competitive markets. And how would that impact kind of the NiHub market?

I think there are two view points out there. One is, and I've read one view that regulated states will use this as an opportunity to retire plants and build new plants and the plants that are retired are generally older plants that don't have a lot of rate base value. So they will use this essentially as a tool to reshape the regulatory compact in those states. And obviously, there is another school of thought that don't hold on a little bit longer in the regulated states. The reality is that the cost associated with all of these environmental regulations, and I'm not just talking about air, here but layering on coal combustion waste and potential water regulations. It's going to be difficult for folks to pay for the plants that they want to keep open, the ones aren't really marginally economic or the ones that they really like and would like to retrofit to make them comply with all the environmental regulations. When you add on -- really putting on controls and doing that sort of thing on plants that are economically marginal, I don't think you're going to see behaviors that are radically different in monopoly markets as opposed to competitive markets.

I would just like to add to this and I'll let Ken sure will correct me if they think I'm wrong. But I guess, I see the picture in Wisconsin, Iowa, Missouri, Southern Illinois, the adjacent areas, a little bit more like some of the suppositions in Hugh Wynne's earlier question, the big new units that are most compliant, most valuable, tend to be in turf like Southern Duke, AEP, Dominion and I think if you look at Wisconsin, Iowa, Missouri, Southern Illinois, you tend to see a pretty large percentage of the older and unscrubbed units that would have the largest compliance for scrubbing. I say that based on both things I've seen in anecdotes but, Ken, did I overstate that?

No, John. You just said it perfectly and one more comment I would add is, regulated states and regulated entities don't typically build or maintain generation to export to other regions, they do it for their customers. So Michael, I would think that, that impact would be minimal from that perspective.

Cynthia, I think we have time for one more question, please.

Your next question comes from the line of Steve Fleishman with Bank of America.

I guess with a commentary you made about the positioning on the environmental rules, what does this mean, if anything for how you're looking at kind of M&A, and I guess, maybe, are you still the hyena or are you more of a gentle elephant right now?

Steve, you've known me for much of the last two decades, and you know I'm always careful. We've been calling Hilzinger here at El Toro because of his optimism. But I doubt if anybody is going to start calling me the elephant anytime soon. Well, we remain very value-driven. We always look, we stay oriented towards cleaner fleets, rather then less-clean fleets. But we believe that this is an industry where you need consolidation. But to make it make sense for investors, it has to be earnings accretive in relatively early time periods. And it has to be consistent with our need to maintain investment grade credit ratings. So no, you're not going to hear a lot more trumpeting, trunk-waving or roaring around here. We're constantly looking for how you add real value, and that just didn't get to change as long as I sit here.

But it also sound like your more focus still is on -- if at all, on value in the generation side as opposed to the regulated side?

Well, I wouldn't say that because we've liked some of the additional diversity that having more regulated business would give us. The problem is that the regulated integrators are, in my view, on an up cycle in their market valuation. And the commodity-driven companies are at the low end of this cycle. So you have to be very careful about using your own paper, which has more upside potential in the future to buy somebody who's more regulated and may already be higher. We'd like to have a little more balance. But it's very difficult to find one that meets our value equation criteria.

Cynthia, I'd like to turn the call back to John Rowe for a couple of closing remarks.

Just to wrap up, Exelon, as you all know, is just different from other folks. We're 2/3 to 3/4 of commodity business, and 1/3 to 1/4 of regulated set of T&D companies. And when you think about that, we kept our earnings well over $4 last year in the worst recession in decades. We're beating our expectations this year and if you look at our earnings range, you can see that we think we have a shot at something in the $3.90s or perhaps even over $4 this year. We should do a little better next year. As we've said, '12 is a little tougher. But I think you'd see growth again in '13 and '14. And I just leave you with this, there are very, very few commodity-driven companies that can hold earnings that well and give you the kind of upside that we can give you. And we're committed to making it happen. Thanks, everybody.

Ladies and gentlemen, that concludes today's conference. You may now disconnect.