Exelon Corporation (EXC) Q1 2011 Earnings Report, Transcript and Summary

Denis O'Brien - Executive Vice President, Chief Executive Officer of PECO Energy, President of PECO Energy and Director of PECO Stacie Frank - Vice President of Investor Relations Christopher Crane - President, Chief Operating Officer and President of Exelon Generation Joseph Dominguez - Senior Vice President of Communications, Federal Regulatory Affairs & Public Policy and Senior Vice President of State Governmental Affairs for Exelon Generation Kenneth Cornew - Senior Vice President and President of Power Team John Rowe - Chairman, Chief Executive Officer, Chairman of PECO, Chairman of Exelon Enterprises, Chairman of Exelon Energy Delivery and President of Exelon Generation Matthew Hilzinger - Chief Financial Officer and Senior Vice President

Michael Lapides - Goldman Sachs Group Inc. Dan Eggers - Crédit Suisse AG Paul Fremont - Jefferies & Company, Inc. Angie Storozynski - Macquarie Research Jonathan Arnold - Deutsche Bank AG Julien Dumoulin-Smith - UBS Investment Bank Ali Agha - SunTrust Robinson Humphrey, Inc. Brian Chin - Citigroup Inc Hugh Wynne - Sanford C. Bernstein & Co., Inc.

Good morning. My name is Teresa, and I will be your conference operator today. At this time, I would like to welcome everyone to the Exelon First Quarter Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to Ms. Stacie Frank, Vice President of Investor Relations. Please go ahead.

Thank you, Teresa, and good morning, everyone. Welcome to Exelon's First Quarter 2011 Earnings Conference Call. 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. The earnings release and other materials we will discuss in today's call contains 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 Exelon's other SEC 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 several other members of Exelon's senior management team, who will be available to answer your questions. We've scheduled 60 minutes for this call, and I'd now like to turn the call over to John Rowe, Exelon's CEO.

Thank you, Stacie. It's a shame to waste such a talented woman on the Safe Harbor notice. That seems to be your loss at life. In the first quarter, we again turned in very strong operating and financial performance. Our operating earnings were $1.17 per share, which meet both our expectations and those we have read on The Street. It won't always happen but it sure is nice when it does. Our earnings at Generation were helped by the performance of our units in Texas during a February cold snap there. They were helped, as you expected, by the roll off of the PPA between Exelon Generation and PECO. They were also helped by the positive effects of bonus depreciation, which lowered Pennsylvania income taxes. On the operating side, our nuclear fleet turned in a 94.8% capacity factor during the quarter. Congratulations to Chip Pardee and Mike Pacilio. Our first quarter performance gives us confidence that we will be well within our guidance range for the full year of $3.90 to $4.20 per share. Matt will discuss the financial results in more detail shortly. I want to talk about a couple of other issues that concern you and concern us. The EPA proposed these rules last month on air toxics and on the 316(b). Both were proposed on time and in ways that were generally consistent with what we expected. We remain confident that EPA will issue the final toxics rule and expect that rule to go into effect as planned with compliance in late 2014 or early 2015. There has been a lot of noise about these rules, and there will continue to be noise as people fight them. I don't think the noise will go away, but I don't expect Congress to do anything to change the rules. The EPA is simply enforcing the requirements of the existing Clean Air Act, as that act has been interpreted by the courts including the Supreme Court of the United States. The last major amendments to that act are now over 20 years old. Neither the rules nor their implementation should be a surprise to anyone. My confidence is bolstered by the fact that the Senate failed to pass legislation that would stop EPA from regulating greenhouse gases. That legislation only got 50 votes, so it seems highly unlikely that the Senate could find the required 60 votes it would need to block EPA's health rules on mercury, arsenic or other toxins. If the Senate didn't choose to block carbon regulation, it is not going to pass legislation that most people believe will negatively impact the health of babies, children and pregnant women. According to the EPA's estimates, the health benefits from controlling mercury could be as high $140 billion, while the cost of compliance would only be around $11 billion. While one should take these numbers with a little skepticism on both sides, it's hard to argue that the cost benefit differential is not huge. On the reliability front, the impact is manageable. Each NERC region has excess generating capacity. 2/3 of the coal fleet has already installed or is in the process of installing the controls necessary for compliance, and much of the capacity from coal plants that do retire can be replaced by underutilized existing gas plants. For Exelon's fossil units, the proposed rules have minimal impact. We have already made the decision to retire our Eddystone Units 1 and 2, and Cromby Station, with the first 2 of these units set to retire at the end of next month. We are evaluating compliance options at Eddystone 3 and 4 and Schuco oil peak. Our share of the expected compliance costs at Kanuma Station, where we own 21% is expected to be small. Coupled with the Transport Rule, which will be finalized in June, we believe that our plant owners will evaluate compliance with the Toxic Rule on a holistic basis. Turning to 316(b). We are pleased with EPA's decision to avoid the "one size fits all" rulemaking. They have allowed flexibility in compliance methods and time lines. Their rules enable cost-benefit analysis and give discretions to state permitting authorities. Cooling towers are not mandated as the best technology available for all plants. It appears to us that screen technology can be employed to comply with the impingement requirements at a small fraction of the cost of cooling towers. We expect the final rule on the 316(b) sometime in July next year. Turning to the RPM capacity markets. You all know that May will be an important date for us. As we have discussed in the past, the environmental regulations will have an impact much earlier than their compliance dates particularly in PJM, where the capacity market looks forward, 3 years. EPA's proposed regulations, along with our market fundamentals, will be key input into the capacity auction, the results of which will be known on the 13th of May. Coal prices continue to face upwards, which help; natural gas prices remain low, which does not. Milling behavior for coal generators and also for demand response will be key. These are the big open questions that will impact -- affect capacity auction results. Demand response may also be impacted by PJM's filing at FERC this month to clarify the rules for how demand response is measured and eliminate double counting issues. It now appears that the legislation passed earlier in this year to incent new gas generation will not have an impact on this year's PJM auction. We are also pleased that FERC, in its recent discussion involving PJM's minimum offer price, rule called the MOPR [Minimum Offer Price Rule], acted decisively in defending competitive markets and the value they bring to customers. FERC rejected exemptions from them, MOPR for state action, like that at New Jersey, which were designed to incent new capacity with out-of-market mechanisms. When we take all of this together, our view remains that the results of the auction for Exelon's feet -- fleet will be similar or slightly better than last year, but we simply won't know until we see them. On the nuclear front, we are of course following the events in Japan everyday, as are you. They will be a focus for us and for our regulators, as they should for the next several years. It is clear that the situation in Japan will have implications for the industry here, but it is still too early to define or quantify those implications. The NRC is taking an active role to continue its strong record of ensuring the safety of the U.S. nuclear fleet. We know that certain areas will get more attention, probably the maintenance with spent fuel pools, the adequacy of containment structures to withstand extreme events and emergency planning procedures to deal with the sustained loss of power. At this point, we don't see significant near-term implications for the license renewal process. We are fully engaged and will work with regulators, industry groups and elected officials to satisfy everyone with the operation of our fleet. We have completed the four recommended actions from [indiscernible], performed walk-downs at each of our plants and verified their capabilities to mitigate extreme events that we have designed into the process. Nothing in that review raised new doubts about the safety of our plants. Chip Pardee has testified before the Senate Environment and Public Works Committee and in the Senate forum in Illinois hosted by Senators Durbin and Kirk. He has briefed members of Congress and their staff on Exelon's response procedures specifically. We expect some increased fees from the state of Illinois. Currently, we are working with the Illinois Emergency Management Association in that regard. Exactly what the U.S. nuclear industry will be required to do is still an open question, and putting an estimate on any cost is premature. But we do expect there could be incremental oversight or process changes, and we will deal with those issues squarely. Until we have a better picture of how things may change, we have not modified our [indiscernible] plans. So far in 2011, we have spent $65 million of the $450 million capital expenditure program planned for this year. A large part of that is associated with turbine replacements at Dresden, Quad Cities, and Peach Bottom. We received NRC approval earlier this month for 32 megawatts of uprates at Limerick, which we will bring online this year. We will continue to evaluate the power uprate program as we go, but at this point, it is too early to make any changes. It continues to appear to be a net benefit for shareholders. On other fronts, we continue to pursue ways to increase our value. Exelon Generation is trying successfully to reduce congestion around our units in the Midwest. We have discussed in the past the transformer replacement at the rising substation near Clinton, which is on schedule to be completed later this year. In addition, Generation will invest approximately $5 million in reconductering the 345 kV line to reduce congestion around our Quad Cities plant. In our wind business, we are moving forward with 230 megawatts of wind in advanced development in Michigan. We will look for opportunities to develop our Wind portfolio further but are insistent that they be based on long-term contracts. So the last quarter was filled with a number of significant events. Life is never boring for Exelon or its analysts or for its shareholders, but we have turned in a very good quarter, and I am very proud of what the Exelon team delivered for you this quarter.

Thank you, John, and good morning, everyone. My key messages for today are on Slide 5. I'll begin by discussing our first quarter results, and then I'll give an update on our latest market views and load results. In the first quarter of 2011, Exelon's operating earnings were $1.17 per share compared to $1 per share in the first quarter of 2010. Our earnings improved over last year as a result of higher realized energy prices mainly in the mid-Atlantic region due to the end of the PECO power purchase agreement, higher capacity revenue and higher nuclear volumes due to fewer refueling outages this year compared to the prior year. Exelon's first quarter results were better than our guidance range because of three principle reasons: first, favorable revenue net of fuel and taxes due to an extreme weather event in February; second, a position change in Pennsylvania's state bonus depreciation policy; and third, favorable O&M that is primarily timing in nature. The weather event in Texas occurred in early February, when cold weather and unit outages caused ERCOT to implement emergency procedures. Our ERCOT generation assets performed well, which contributed approximately $0.02 per share to our bottom line. Exelon's first quarter results also reflect a $0.03 benefit related to bonus depreciation in Pennsylvania. Historically, Pennsylvania disallowed the recognition of bonus depreciation in the same year it's allowed for federal purposes. However, in February the Pennsylvania Department of Revenue issued a bulletin permitting the recognition of 100% bonus depreciation in the same year as recognized for federal purposes. As a result, PECO and ExGen will recognize a lower-than-expected state tax expense for 2011. In addition the $0.03 recognized in the first quarter, we expect to recognize an additional $0.03 of favorability for this item during the course of the year. The key drivers for ExGen's quarter-over-quarter earnings are on Slide 6. You may recall on our fourth quarter 2010 call in January, we highlighted our expected increase in revenue at ExGen due to the expiration of its power purchase agreement with PECO. This contributed $0.19 per share to Generation's earnings in the first quarter. On Slide 7, you can see a snapshot of our hedge position as of March 31. You will notice from the chart on the left and from our updated hedge disclosures, that our hedge percentage for 2012 is closer to a ratable level. Based on our commodity views, we completed the majority of our sales during the higher-priced periods during the quarter. In addition, the amount of put options has remained relatively unchanged since the end of last year. You can see from the chart on the right the 2012 and 2013 PJM West Hub prices started and ended the quarter around the same level, while NiHub prices have not fully returned to the levels of year-end despite the recovery of gas to year-end levels. We continue to leave a reasonable open position in the Midwest in 2013 in order to allow more time for price recovery. Looking at the back end of 2014 and '15 forward curves in the chart in the bottom right, you can see that the rebound in price recovery was more pronounced in the last half of March compared to earlier in the quarter. In addition to increases in gas and coal prices and the events in Japan, we believe a portion of this reflects the impact of the recently proposed Air Toxic Rule. We recently updated our analysis of the Air Toxic Rule and our revised estimate for the projected impact on energy prices is in the range of $4 to $6 per megawatt-hour. We believe that the 2014 and 2015 PJM West Hub forward prices shown in the chart reflect most of this uplift. However, based on our analysis, it appears that only a limited amount of the potential uplift is reflected in NiHub's 2014 and 2015 prices. As a reminder, our portfolio is essentially open in 2014 and '15, which allows us to capture that upside when it's priced into the forward markets. ComEd's year-over-year earnings are on Slide 8 and additional details are available in the earnings release attachments issued earlier today. Approximately $0.06 of the quarter-over-quarter reduction in EPS was due to last year's catch-up benefit for the uncollectible rider that we booked in the first quarter of last year. Turning to Slide 9 for ComEd's load results, ComEd's quarter-over-quarter weather-normal total load decreased by 0.1% compared to last year as a result of lower usage in the residential class. The quarter results are in line with our expectations, and we anticipate the Chicago area housing market conditions will continue to challenge year-over-year growth in the residential class. We expect to see positive growth in the residential sector in the third quarter of this year, assuming Chicago area home prices have bottomed out by then. As predicted, large C&I continue to deliver year-over-year growth and small C&I had a modest increase over the prior year. We continue to anticipate flat load growth for the year compared to the prior year, and as such, our prior forecast remains unchanged. Earlier this month, we received the ALJ's [Administrative Law Judges] proposed order in the ComEd's distribution rate case filed last June. The ALJ proposed $166 million revenue increase, which had a $14 million calculation error, bringing the actual amount of $152 million. This compares to the ICC staff reply brief amount of $113 million. We expect the commission's final order by the end of May, which will become effective in June 2011. At the end of May, the commission will also issue their final order for ComEd's alternative regulation proposal, which is designed to establish a recovery mechanism for proposals such as Smart Grid. In legislative news, the Public Utilities Committee of the Illinois House held several hearings over the last few weeks for Illinois House Bill 14. As a reminder, this is legislation that would enable ComEd to make major investments in the electrical grid to modernize the system and would also provide a formula rate mechanism for more timely recovery of ComEd's costs. We are working to build broad stakeholder support for the bill, and we expect to know more before the spring session of the Illinois General Assembly ends in late May. PECO's quarter-over-quarter key drivers are on Slide 10. PECO's earnings now reflect the new distribution rates from the gas distribution rate cases approved last year. Turning to Slide 11, PECO's weather-normal total load growth for the quarter decreased by 1.1% compared to the prior year but was slightly better than our projections. The quarter-over-quarter 1.1% decrease was principally driven by large and small C&I, partially offset by modest growth in residential. The growth in the residential class was due to better-than-expected improvements in key economic factors, mainly, increases in real disposable income. Large C&I load growth was negative this quarter compared to the first quarter of 2010, primarily due to inventory restocking that took place in the first quarter 2010 and lower usage in the pharmaceutical sector. Our outlook for load growth for the full year has not changed, as we continue to expect total load to be flat for the year. Turning to our cash sources and uses on Slide 12. We are expecting to generate cash from operations of $4.3 billion this year. Our end-of-the-year cash forecast remains the same at approximately $400 million, which factors in the dividend and investment in our growth projects such as uprates and wind development projects that are currently underway. We are generating strong cash flows and have also taken concrete steps to further strengthen our short-term and long-term liquidity positions. In January, we reduced our 2012 through 2014 cash requirements by contributing $2.1 billion to our pension funds and increased the funded status from approximately 70% to nearly 90%. In February, we refinanced $6.4 billion of credit facilities at Exelon, GenCo and PECO with favorable rates and turns, and the agreements are in place for 5 years with an option to extend them for two 1-year periods. This gives us flexibility to manage future refinancings. These steps, along with a continued focus on financial discipline and cost management, positions us well to meet our funding requirements, including dividends and growth capital and maintain strong credit metrics. As an additional note, we have provided in the appendix to today's slide on Page 40, more details on the specific calculation of Exelon's consolidated credit metrics. Before I close, I just want to reiterate John's earlier statement about 2011 guidance. I continue to believe that we will deliver full year operating guidance comfortably within the range of $3.90 to $4.20 per share especially considering our better-than-expected earnings in the first quarter and the additional $0.03 we expect to recognize from Pennsylvania bonus depreciation during the rest of the year. For the next quarter, we expect operating results in the range of $0.90 to $1 per share. That concludes my remarks, and we can now take questions.

[Operator Instructions] Your first question comes from Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG: I guess first question just as it relates to kind of the RPM outlook with the EPA rules draft that is out there, some decisions on demand response. Have you guys gotten more or less enthusiastic about the outlook for this auction from what guys thought you were seeing at the fourth quarter hump?

Well Ken is always enthusiastic, so I'll let him answer the question.

Yes. I think we are where we've been talking about being for the last few months. We see the 2 big drivers in RPM being -- have the supply side into this auction, and that is -- the coal plants and how they bid their costs given the environmental regulations John talked about and how much demand response shows up at the auction. So right now, we see -- our modeling shows a result that is very similar to last year. If less demand response shows up and generators bid their costs, we could see some upside. Dan Eggers - Crédit Suisse AG: Okay. And I guess maybe, Ken, just kind of an ancillary question. When you look at the NiHub pricing and you're not seeing any sort of response for the toxics rules or much of a margin for the coal generators, who are you seeing out transact in the curve to kind of bid away what seems like kind of obvious changes in the market? And are you guys managing your hedging strategy? Is there even a greater temptation to kind of lay off hedging, given kind of the mismatch between the market today and the underlying fundamentals.

As Matt indicated, we do see upside in NiHub prices. I continue to look at spot heat rates and historical heat rates for the last couple of years and see heat rates in the 7.5 to 8 range. And in the forwards, we're still seeing the low 6s for heat rate. So I believe there is upside in NiHub prices, and that continues to rationalize itself in the spot market. As Matt said, we are adjusting our hedging strategy in accordance to that belief and keeping some more position in the NiHub, relatively speaking, and in '14 and '15, in particular, were largely open as we indicated. So we see that our portfolio is well positioned to take advantage of that upside. That market is not overly liquid, particularly when you talk about trading in the '14, '15 time frame, so we expect to see more rational pricing as that market starts to develop more trading activity as time goes on. Dan Eggers - Crédit Suisse AG: And Ken, just on the last question, just kind of on market liquidity. Are you guys seeing much liquidity selling '13 and '14 power today in any market? And or is it too fragmented to get a real read on what ultimate market conditions are going to be?

Again, we're seeing really good liquidity at West Hub, and that market has a lot of participants. And NiHub it's -- it tends to be more in lumps. When the Illinois Power Authority comes out to procure more power going forward for a couple -- on behalf of our and ComEd customers, we will likely see liquidity at that time in the NiHub market. But the NiHub market is relatively thin in that '14, '15 time frame in particular.

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

I'd just like to follow up on Dan's question a bit. You say you're largely open in '14 and '15, but which implies that you have got some positions on in those years, and you also said the market is very liquid. So you know, is this a change -- have you done some hedging that might have been contributing to pressuring the curve? Or -- and are you sort of backing off doing that? Or is it -- have you really just done nothing?

Jonathan, we have done some hedging in 2014 commensurate with our ratable hedging program. We did see, at the beginning of the quarter, some pressure on NiHub prices likely driven by entities doing some hedging. We did most of our hedging early in the quarter, and we think the market's rebounded somewhat because that pressure has backed off.

Okay, so your lesser -- you were more active and now you're less active in those out years, basically?

That's correct. And obviously, we look for all the different channels. We talked about the hedge, not just underlying OTC [over-the-counter] transactions, it's the retail business, it's potential put option strategy, it's different locations like Ad Hub [ph], it's different locations in the East relative to load auctions and the retail business. So there are wide variety of channels for us to perform our hedges in 2014.

And Ken, have you sort of tried to gauge the timing for when the market sort of will reflect, you know, your view of fundamentals and then the kind of where we're headed on environmental? Do the rules have to go final? What's the catalyst? Is it just a time issue, how far away we are...

Jonathan, I think a lot of it is how far away we are, and I think it's going to be time. Clearly, if the rules become final and more knowledge is out there as to what the plants are actually doing, that will end up being reflected in power markets, so that will help. But I think time is the biggest issue right now and it's just going to take some time for the markets to rationalize what we think they will.

Okay. And if I may, just on -- I noticed that the nuclear uprate CapEx that you referenced in the slide ticked down from $475 million to $450 million for this year was when, intuitively with -- I guess, you'd think the cost of doing things like this might be on the rise. Has the scope changed or is the cost that's changed? Or what drove that?

Ken will get that.

No, Jonathan, it's just timing. The project's scope hasn't changed. Execution and building, things like that have some flexibility as we work through the projects, but they're still on budget, and we'll adjust the timing over the next quarters and you're still on schedule.

Your next question is from Hugh Wynne with Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., Inc.: I'd like to get your updated views on what impact we might expect on kind of maintenance CapEx for the nuclear fleet from Fukushima Daiichi and the cooling tower regulation. I know that we don't have the NRC recommendations on hand, so it's impossible to give a detailed response to what they're going to say. But on the other hand, I think you mentioned that the adequacy of containment structures is obviously an issue that's going to arise from there now or so. If we had to begin to think about the implications of Fukushima Daiichi and the cooling tower regulations on your fleet, could you perhaps talk to the units that might be affected and how we might scale potential capital expenditure implications?

I'll let Chris start, because he knows the detail much better than I, to kind of give you a little frosting that I can't. Go ahead Chris.

Just breaking down. The way the 316(b) was issued for review, we feel there's a lot more flexibility and it's not "one size fits all," which would drive us into more expensive remediation methodologies to cooling towers. So we have -- and we'll continue to evaluate our fleet. But we do not see a material increase in capital expenditure required for the cooling towers. Now that said, it's a state-by-state interpretation and we'll continue to monitor over the next couple of years as permits come up, how we work within the states. Our biggest issue in that area has been in -- is reflected in our decision at Oyster Creek based off of the state's decision there for the Barnegat Bay. On Fukushima, we think that the analysis that is under way will continue to support the design -- the structural design of our various reactor types, and it will reaffirm our operating strategies to ensure that we do not challenge the structural integrity as a potential event happens. We see the expense and the focus coming more in operating strategies in preparations for beyond-design basis accidents, things you just can't anticipate, and we'll work with the regulator and the industry on those. We have differentiated ourselves significantly in operating strategy. And everybody's read the articles over the last couple of weeks that have been in most of the papers and they've heard from the U.S. regulators and the administration, many politicians about those differences. So we're not anticipating large capital expenditures, maintenance CapEx or installation of any major upgrades and we'll just continue to work. Trying to quantify the expense where we think more of it will come in, it's too early now. Again, I don't see it as significantly material at this point. But Chip Pardee is leading the industry group, working with NEI and INPO to make sure that we're closely in communication with the regulators and the administration -- the politicians so we can resolve the concerns and continue with the high safety records in preparation standards that we have.

I can't do the detail as well as Chris does, and you all know that we can't preclude the possibility of some material CapEx requirements. But I really think you ought to focus on the fact that from everything I know, and I think I'm speaking for my colleagues too, the fundamental problems here were not with the Mark 1 containments themselves. The fundamental problems here were with getting fuel to the diesel generators and responding to a situation that they lost outside power. And that is something we've already gone a lot to address at our plants. And as Chris started to say, in fact, did say, we've already been doing things to deal with that and expect to be asked to do some more. Chris, did I overstate that?

No, no, that's right. Hugh Wynne - Sanford C. Bernstein & Co., Inc.: If I could just ask one quick follow-up to that, your plants are located near two large metropolitan centers. And I think one of the more remarkable things about the Fukushima Daiichi disaster is that the scale of the evacuation that was required from the vicinity of the plant. Have state officials indicated that there is any concern on their part regarding evacuation plans or the feasibility of evacuation in the event of a problem?

No, we haven't had any dialogue with the states on any level of concern about that. It will be a subject that will come up. We believe our current evacuation plans are at the right level. They don't just stop at 10 miles. I mean, we've talk about a 10-mile EPZ. We actually do have monitoring out further than 10 miles where protective actions could be stated if warranted. I think the reality is our operating practices would prevent us from getting beyond those -- that limit. You'll hear a lot from anti groups using that as a major issue, and they'll be trying to use that to attack specific plants that they've been after for years. But we just -- we don't see that as being a valid issue, and we think that the debate will take place and the regulator, we'll be looking at it. But we don't see any changes or anticipate changes.

Your next question comes from Michael Lapides with Goldman Sachs

I've got a question for you. In the EPA analysis of the HAP [hazardous air pollutant] MACT [maximum achievable control technology] rule, they outlined that the anticipated amount of wet scrubbing was going to be minimal, and that it was going to be mostly dry sorbent injection and maybe a little bit of dry scrubbing. Just curious, do you think that's viable both on Appalachian coal and PRB [powder river basin] coal? And how do you think about what the potential different uplift in power prices would be under one set of solutions, meaning maybe wet scrubbing versus under another dry scrubbing and sorbent injections?

Well, since I thought all this stuff was coming, I sold the coal, so I'm not the expert on that. And I'm going to let Joe Dominguez, who is, respond to that one.

Thanks, John. I think it is going to be different for PRB units, where we have predicted for some time that DSI [dry sorbent injection] is an option. I think you're probably going to see more scrubbing, more wet scrubbing and dry scrubbing on Appalachian units, and perhaps a little bit more than EPA has predicted in its models. Where DSI applies, there is obviously going to be a variable-cost impact, and we're going to look very carefully at what happens with SO2 emissions. And it's -- there's a potential there that you could see on a megawatt-hour basis, an increase in variable costs of somewhere between $4 to $8, depending on how much SO2 has to come out if you use a dry scrubber. In that instance, the impact isn't necessarily felt in the capacity market, but on the energy side of the equation where units remain, they don't retire, but they have higher variable costs and higher dispatch costs.

Got it. John, just curious, different topic. Your kind of latest thoughts on industry consolidation on M&A and on your broader portfolio of assets and companies.

My latest thoughts are just what my thoughts have been for several years. I keep saying that consolidation makes sense in this industry, that it's essential in this industry. We always look and we're as cold-blooded as it can be when it comes down to the economics. We won't overpay for a deal and we won't enter transactions that give away all of our upside to a power market recovery. It's really important to us. We've talked to enough of you about it to know that you don't want us to do that. We won't give up our financial discipline and we're committed to protecting our investment-grade rating. I mean we know that we would have a prettier, more balanced company if we had a larger share of regulated operations along with our generating business. But simple, plain old shareholder value trumps that sort of strategy every time, so we are where we have been. I'm reminded, my troops didn't tell me to say this, So I'm probably out on a limb, but the Pope was asked to comment on Mel Gibson's movie about the crucifixion, and he had said, "it was as it was." We are as we were.

Your next question is from Brian Chin with Citigroup

Following up on a key wins question on gigawatts for coal retirements. Can you give a little bit more color on how you thought about the site-wide averaging rule? And how many units may not be shut down because they happen to share a site with another unit that has to clean their scrub? Can you just give a little bit more color and how you thought about that?

Yes. Joe, you want to cover that?

Sure. Presently, Brian, we don't see the site-wide averaging as being an option that's going to be available to a lot of units. It doesn't necessarily affect our retirement analysis at all materially.

Your next question is from Paul Fremont of Jefferies & Company. Paul Fremont - Jefferies & Company, Inc.: I guess, John, you've mentioned in past conference calls, you've talked about possible combinations I guess, with Nicor, with Progress. I was just wondering if we could get a comment out of you on maybe advantages or disadvantages of combining with a company like Constellation?

We don't comment on anything specific that hasn't already gone by. And we won't -- this lady is not for commenting on rumors. Paul Fremont - Jefferies & Company, Inc.: Second question would be with respect to your prediction of, I think it was -- I think, $4 to $6 of higher energy prices based on what's coming down from the EPA. Can you give us a sense of what gigawatt retirement assumptions you come to for PJM?

We still expect to see a retirement of somewhere between 9 and 11 gigawatts in the PJM territory, Paul. Paul Fremont - Jefferies & Company, Inc.: And is that mostly -- is that sort of biased towards the eastern part of PJM because of the Appalachian coal versus being able to comply with DSI for PRB?

I think it's more balanced. We continue to look at smaller units being economically challenged to the extent that DSI opportunity makes it a little easier to comply. Natural gas prices and power prices aren't making it easier economically for these units. So when you look at the whole picture of value for smaller coal units, very, very challenged right now, and particularly challenged at least, if we see lower capacity results in the next off. Paul Fremont - Jefferies & Company, Inc.: And sort of my last question is, I guess, Calpine in one of its -- during its Analyst Day sort of talked about the impact of trona on variable cost as being in the $5 to $15 range. Is that sort of consistent with what you would project as an increase in variable costs using DSI?

Joe, you want to cover that?

Yes, I just gave a number, a range of $4 to $8, and I've seen estimates that are $10 or more. I think to get to those numbers, you're really using DSI to capture a lot of SO2. To just capture mercury and capture hydrochloric acid, the numbers are going to be significantly lower. But it's going to depend on how those particular owners decide to use DSI to capture SO2 for Transport Rule purposes. So it could be as high as that. We see the range being $4 to $8. Paul Fremont - Jefferies & Company, Inc.: And your $4 to $8 also includes the various waste disposal costs that are associated with it or not?

No, that just is the variable costs of it. If you're talking waste disposal, you're talking about the residue and the ash treatment. We're going to see how the coal ash rules come out. That's going to be incremental to the numbers that we talked about.

The next question comes from Ali Agha from SunTrust

John, when I hear your message on the fact that the fundamentals, obviously, the forward curves, are not being reflected in the forward curves, is there anything that Exelon can do proactively in anticipation of that return to fundamentals i.e. would a share buyback be something you could consider, given your confidence in how the markets will ultimately move? Is that something that you would consider?

We could consider it, but we aren't going to do it. We've gotten a lot of anxiety with credit rating agencies over having -- one was done what they thought was one too many before, and it would be very unlikely that we would do a share buyback. We do believe these fundamentals will turn out for our benefit. We want to keep our balance sheet strong as we work through the trough. And the best places we can react to this are places you've already asked about, which are things we can do with Ken's hedging strategy, his efforts to find longer-term contracts that reflect these realities and our efforts to reach the market more effectively so we're less dependent on pure spot prices.

Okay. Second question, and you addressed that early as well, assuming that the right value is out there and can be obtained by Exelon -- I mean, conceptually when you look at your portfolio, you mentioned the fact that perhaps having a slightly more regulated balance maybe good. But at the end of the day, are there any sort of holes, if you will, in the portfolio that do you think need to be filled? For example, do you think that you will need a bigger marketing organization to go with your large generation fleet?

That's asking the lady the question she already refused to answer. Our virtue will remain intact, at least in so far as I can protect it. Look, we've talked about the things that interest us many, many times. We're not coy about that. We'd like more regulated assets if the price is right. We like more generation assets, especially nuclear and gas, if the price is right. We like more renewables if the price is right, we get enough contracts. We like safer channels to market, and we won't say anything about any specifics.

I understood. Last question, could you remind us in your '11 guidance, what is the implied ROEs assumed for ComEd and PECO versus what the actuals were in '10?

Matt, will you do that breakdown?

Yes, I will. So on PECO, I announced -- and I'll start with '11 in PECO because it's really, I think, it's most relevant now that they've got their new rates in. But their -- the guidance was around 12%. And the bonus depreciation would probably push them a little bit higher on that, maybe up close to 13%, but that's partly what we're seeing at -- mostly what we're seeing at PECO. At ComEd, we target an ROE of 10%, and that's what we would expect out of ComEd over the long term. I think in 2011, we might see something closer to 9% to 9.5%. But we're going to largely see how the ComEd rate case comes out, but we're going to eventually as we go into '12, see somewhere around 10%-plus.

Your next question comes from Julien Dumoulin-Smith with UBS

I wanted to follow up a little bit on the prepared remarks. You spoke about an uplift from the Toxics Rule of about $4 to $6 a megawatt-hour. I was wondering if you could provide more granular view as to what the constituents were? I don't know if you were trying to get it that from, call it a DSI or trona perspective? Or if that was more of a comment relating to retirements?

Right. It's a combination. It's for -- when we run our models and particularly in the Midwest, we don't see that the Midwest prices are reflecting an uplift from these rules. And our models are indicating a $4 to $6 uplift from retirements and from increased cost of dispatch. That combination of elements are both reflected in the $4 to $6. As we said before, we think we are seeing that in West Hub prices eastern part of PJM, we don't see those uplift reflected in the NiHub prices at this time.

Great and just to be clear about it, $4 to $6 applies to both PJM West -- or PJM East, rather, for your portfolio and NiHub?

It does. It does, and it's hard to decompose what's actually driving market prices. But we think largely that $4 to $6 should show up in the future in the NiHub price, and right now, at least a lot of it is showing up in the West Hub price, in the '14, '15 or under.

Great. And then, maybe a follow-up on hedging policy and all that. I'm looking at -- or contrasting your first quarter disclosures against your 4Q for the Midwest, just looking at the 2013, it looks as if hedge prices implied were fairly low, if you kind of do the back-end available math, if you will. But then, conversely, there was a very high implied price for the last quarter versus EEI. So could you perhaps in aggregate comment, are the '13 hedges, you spoke abut liquidity previously, are they biased towards peak or off-peak? Or is there some way to think about that at all? Just as we look, future call it as you roll forward into new hedges?

And I think you are asking about the effective realized energy price in '13 at NiHub, is that correct?

Yes, precisely.

Yes, but the large majority of that reduction in that effective realized energy price is merely a fact that we put on more hedges at lower prices and our previous hedges were at higher prices, so we're going to see the effective realized energy price come down. Coupled with that in this quarter, we looked at '13 NiHub prices and saw that the drop was primarily driven by summer and fall months. And our hedging position in the Midwest has a significant amount of energy sold in the Jan through May period because of the 3,000-megawatt ComEd swap. So we didn't see as much mark-to-market uplift on the swap commensurate with the price drop that we really modeled later on in the year, so that's helping drive down the effective realized energy price. But again, the majority of that change is merely the fact that we're putting on more hedges in a lower market.

Your next question comes from Angie Storozynski with Macquarie

Two questions. One, could you quantify the uplift to first quarter results from the timing of O&M expenses?

I think it was $0.03, Matt?

Yes, it was $0.03, and it was primarily related to generation and O&M spend in the nuclear operation. And it was just -- it's simply some work that we had expected to get done and has been pushed off to the balance of the year. So it was clearly a benefit that we had in the first quarter but we would expect to spend to that through the balance of the year.

Great. And now about PECO. You mentioned the better-than-expected residential load growth, but your assumptions for 2011 went up pretty significantly from 0.1% on a weather-normalized basis to 2.1% within one quarter. Could you explain in more detail how is that possible?

This is Denis O'Brien with PECO. Your question is about the residential numbers? And the growth...

Weather-normalized load growth, expectations went up from 0.1% to 2.1%?

That's just, I believe, economic growth that we project through the years, through the rest of the year as we have modeled with all of our economic data for the region. I'll ask Phil to add anything else to that.

Yes. I'll just add to that, as we look at the forecasted GNP for the Philadelphia metropolitan area, it's forecasted to be 3% for 2011. That's up from 2.3% of what we were expecting at the time we did the budget. We've also seen a pickup in the employment levels. Unemployment rate is projected to be down to 8.3% for 2011 versus 8.9% in 2010. We're also seeing a big pickup in real disposable income of 2.9%. We've also seen steady growth in the number of customers and an increase in the confidence level of consumers as well. So it's very -- just very positive signs on the macroeconomic conditions.

Okay and how is it reconciled with energy efficiency initiatives in Pennsylvania and the fact that C&I load is actually weaker than what you expected.

Yes, we are seeing an impact in the energy efficiency programs overall. The deemed savings is about 1.2% reduction in load for 2011 versus 2010. On the large industrials, what's happening there is, we see in 2010, we saw some restocking on the inventory in the first half of the year, which we don't expect to repeat as much in 2011. We've also seen a couple large industrials have some onetime load reductions in 2011. They had a large pharmaceutical company who was a little slow to transition to market, and they ended up using their own gas generation supply load in the first quarter. We don't anticipate that to happen in the balance of the year. We also saw another large customer who had a substation that was out for over a month and basically had to import power from a different supplier, that too, it was a onetime item, which we don't expect to happen again.

Ladies and gentlemen, we have reached the allotted time for questions. I would now like to turn the call back to Mr. John Rowe for closing remarks.

Thank you everybody, and I appreciate the compliments on the quarter. We were very happy with it. I just like to finish with this little wrap-up. As we all know, the world that we were in love with came to an end back in 2008. Since that time, we have delivered operating earnings of $4.20, $4.12 and $4.06. As you can tell from our results in the first quarter and our reconfirmed estimate range, we are in a very good position to give you numbers like that again this year. When next year and 2013 come, we cannot fully overcome the downward pressure that has existed on electricity prices. You know that, and have been pricing that into our shares for at least a year, probably 2 years now. But I urge you to look at how well this machine is operating. We continue to produce results that are better than the models indicate. I think we can keep doing that as we go forward, and you can't be sure until you see it, which is why we don't always put it in a forecast. But there are a lot of good things going on within this company, and there are good opportunities that Kevin and his team keep finding in the power markets that you can't put just in a linear extrapolation. So I feel very good about this quarter. I feel very good about last year, and I think we will continue to deliver you results that are just a little better than you might by playing with your models. Meanwhile, thanks for your patience and I appreciate the compliments on the quarter.

Thank you. This concludes Exelon's First Quarter 2011 Earnings Conference Call. You may now disconnect.