Matthew Hilzinger - Chief Financial Officer, Senior Vice President and Treasurer Anne Pramaggiore - President of ComEd and Chief Operating Officer of ComEd Stacie Frank - Vice President of Investor Relations Ronald DeGregorio - Chief Operating Officer of Exelon Transmission Company and Senior Vice President of Exelon Transmission Company William Von Hoene - Executive Vice President of Finance & Legal 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 Kathleen Barron - Vice President of Federal Regulatory Affairs & Policy

Greg Gordon - Morgan Stanley Paul Fremont - Jefferies & Company, Inc. Jonathan Arnold - Deutsche Bank AG James Dobson - Wunderlich Securities Inc.

Brian Chin - Citigroup Inc Hugh Wynne - Sanford C. Bernstein & Co., Inc.

Steven Fleishman - BofA Merrill Lynch

Thank you, and good morning, everyone. Welcome to Exelon's Second 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 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 Exelon's 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. In addition, during the call, we will be discussing the proposed merger of Exelon Corporation and Constellation Energy Group, Inc.

Today's discussion does not constitute an offer to sell or the solicitation of an offer to buy any securities, or a solicitation of any vote or approval. Furthermore, today's discussion is not a substitute for the registration statement on Form S-4 that Exelon filed with the SEC on June 27, 2011, that included a preliminary joint proxy statement prospectus or for the definitive joint proxy statement prospectus and other relevant documents that Exelon will send to a security holder in connection with the proposed merger.

For important additional information regarding the proposed merger, including the risks and uncertainties associated with it, please refer to the earnings release and today's 8-K, as well as the joint proxy statement prospectus. Leading today's call are John Rowe, Exelon's Chairman and Chief Executive Officer; and Matt 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. We've scheduled 60 minutes for the call, and I'd like to now turn the call over to John Rowe, Exelon's CEO.

Thank you, Stacie, and good morning, everyone. As you know from our earnings release we had another fine quarter.

Our operating earnings were $1.05 per share, which I think significantly exceeded your consensus expectations. We have had a very busy summer at both ComEd and PECO with extreme heat and violent thunderstorms.

One in July, on ComEd, knocked out over 850,000 customers, and it took us nearly a week to get them all back. But the ComEd system is performing better than ever before, and handled without major trouble, a new all-time peak of 23,753 megawatts on the 20th of July.

ComEd got a reasonable result in class rate case considering the appellate court decision that you had all heard about 6 or 9 months ago. And it's continuing its work to get Illinois Senate Bill 1652 enacted.

This legislation would support a broad infrastructure improvement program and finally bring some real regulatory stability to Illinois. We simply don't know what the odds are of the governor signing it.

He hasn't been sounding promising to date, and we don't know whether the legislature would overturn the veto. It is certainly possible that they would because they want these jobs very badly.

In Philadelphia, PECO continues to produce genuinely exceptional financial results. And it has handled its extreme heat superbly.

PECO also hit an all-time peak last Thursday and again topped it on Friday. During the second quarter, Exelon Generation's capacity factor in its nuclear fleet was 89.6%, largely as a result of 103 refueling outage days at 4 units.

For the first 6 months of the year, the capacity factor was 92.2%. And in spite of a year of -- with an extraordinary number of refueling outages, our nuclear group continues to strive to achieve its usual 93% this year.

Our performance this quarter was distinguished by some positive tax items, which are not simply accidents, but the result of very hard work by Tom Terry and his tax guidance. We are on or slightly ahead of plan just with basic operating use, but the tax benefits allow us to increase our earnings guidance for 2011, up from $4.05 to $4.25 per share.

This range already includes about $0.04 per share of incremental storm costs from the major July 11 storm, which we will book in the third quarter. Now we've had continued storms in ComEd.

I don't have a good number yet on the expense of the whole, but that was the big one, and we've already got that pretty well boxed. Needless to say, I am personally very pleased at being able to increase the earnings guidance.

Our merger work in Maryland is marching along right on schedule, and one of these days, I'll wake up retired, hopefully as early as January, so I would really like 2011 to be a good year. And right now, it looks like it's going to be a very good year, indeed.

Turning to the merger. We made all of our regulatory filings within a month of announcing the transaction.

We filed our S-4 proxy statement with the SEC at the end of June. The FERC and DOJ processes are proceeding on course.

The Texas and New York processes are on track. We hope to get a decision in Texas next month and New York before the end of the year.

The NRC is likely to complete its review by January. In Maryland, the schedule has been set to have a Public Service Commission decision on January 5, 2012.

If you look at those dates, you see the basis for my hope that we actually can get these all done in January, or perhaps in February. We continue to work with the stakeholders in Maryland, including the governor's staff.

We have several Exelon officers based in Baltimore to ensure that dialogue remains constructive throughout the process. This is one of the lessons we've learned from all of our work in New Jersey 5 years ago.

It is: get your own people on the ground, get direct information and have people get to know you firsthand. So far, everything is on pace and on schedule.

I believe we do remain on track to close the merger early next year. Chris Crane and Mayo Shattuck are in the process of defining the new leadership structure.

They will make the announcements of the first layer of executive management announcements late this summer. Over the last 3 months, we have visited with many of you, I'm sure with all of our larger shareholders.

And I'm pleased to say the reaction from you has been generally very positive, indeed. Nearly everyone I have talked to and my reports from Bill Von Hoene and Stacie and Chris are similar, recognize that this deal works.

It makes financial sense from earnings position, from a cash flow perspective and from a credit perspective. The combination of our Generation fleet with Constellations' customer-facing business provides a strong platform for growth.

And the transaction allows us to diversify our fleet across various forms of clean energy, and enables us to execute our Exelon 2020 vision for a clean energy future. Being clean is a competitive hallmark for Exelon.

It will become even more advantageous as we move into this new era of EPA regulations. More and more, through a combination of economics, gas prices and pending environmental regulations, we expect to see the market bias towards cleaner forms of energy.

Earlier this month, EPA issued its final Cross-State Air Pollution Rule, what we used to call the transport rule. The final rule contains many of the provisions that the Clean Energy Group, to which Exelon belongs, suggested and provides more regulatory certainty for lowering NOx and sulphur dioxide emissions beginning as early as next year.

We applaud EPA's use of a market-based solution with interstate trading where it could. Overall, we think the rule will have a positive impact on wholesale prices, albeit with some regional differences.

We're still evaluating the rule, and we'll learn more as we see allowance trading in advance of the January 2012 start date. On the Air Toxics Rule, EPA extended its comment period until early August, but has maintained a strong commitment to finalizing that rule in November.

This is of the utmost importance to EPA, and I expect them to hold to that timeline. The administration has made it increasingly clear the EPA has its full support.

As we expected, the capacity markets were the first to reflect the environmental regulations. Current prices in the most recent PJM auction suggests that generators are taking a long-run economic approach to bidding, and companies continue to announce coal retirements and new plans for complying with the regulations.

In PJM alone, plant operators have announced plans to retire more than 8,000 megawatts of operating coal capacity. We continue to believe that there will not be repeal or multiyear delay of the EPA regulations, despite some congressional attempts to do so.

As you can all can tell from that current budget stalemate, doing nothing is a congressional strength, and we are glad to be at the position where that's good enough for our purposes. Opportunities to get one-year extensions when needed for compliance will be evaluated by EPA, maybe justifiable in a number of cases and indeed, Exelon would not oppose that.

What we care about is when they are going to shut down a plant, they do it promptly and on time. We do not support and do not expect delays in the closing of plants that are not going to be upgraded.

I want now to turn to the nuclear industry's response to the events at Fukushima and its implications for the U.S. nuclear industry.

We are very pleased that from the very first days, the Nuclear Regulatory Commission has taken a fact-based, balanced and objective approach to assessing U.S. nuclear plants and that the administration has backed the NRC in this regard.

Our own Chip Pardee has worked daily in coordinating with regulators, policymakers, the Nuclear Energy Institute, INPO and our peer companies. He is chairing the industry's Fukushima Response Steering Committee.

On July 12, an NRC task force issued its 90-day report, which states clearly that U.S. nuclear plants are safe and also describes areas for regulatory improvement.

We expect the NRC staff and the commission to work very diligently in both effectively learning how to improve the regulatory structure but also making certain that it stays fact-based. The industry will work through both INPO and NEI to make certain that all this happens.

The issues identified in the task force report are largely those we expected. Very importantly to us, the task force report appears to find that current standards for the storage of spent fuel and the license renewal process are sound and appropriate.

Since these were areas that defined the high-end of the potential cost to us, we are pleased to see that they have achieved this level of stability. How the NRC implements the remaining task force recommendations will take time to know.

The cost to Exelon is still impossible to determine in any degree of detail, but we expect when we know that it will be spread over a number of years. Nonetheless, with the challenges ahead for the country's oldest and dirtiest coal plants, I would rather have the challenges of Exelon's nuclear fleet any day.

The fundamental competitive strengths that we have remain intact. The value of our fleet will improve as power markets improve and EPA regulations are applied.

Our uprates program continues to provide us with a low risk, low-cost growth vehicle. We have added 194 megawatts since we began the program in 2009.

We have the ability to reassess market conditions as we go. Thus, we have decided to remove the Three Mile Island and Clinton EPUs from the plan due to economics.

But we are moving forward with our other uprates and plan to bring another 185 megawatts online between now and the end of 2013. So let me end with the following.

This quarter's results represents the 11th straight quarter in which we have met and generally beaten your expectations. We've beaten our own internal forecast.

The reason for this is not always the same. Constant attention to operations is part of it every quarter, including this last one.

In this quarter, some tax benefits were a big part of the change. But the key message I would like to leave you with is that we keep finding things to improve the system.

We are absolutely, totally, rigorously and pathologically dedicated to doing that. We can't guarantee that we'll be successful in doing that every quarter as we go forward, but I believe this company is placed, positioned and hung out to dry on the proposition that we can keep things better than the models.

With that, I'll turn the call to Matt Hilzinger.

Thank you, John. Good morning, everyone.

I'll start my remarks this morning on Slide 10, and follow with some additional commentary on our second quarter results and update on hedging and recent regulatory activity. Earnings release issued this morning provide significant detail about our second quarter results.

We are pleased to deliver another quarter of financial results that met or exceeded your expectations. Exelon's second quarter operating earnings were $1.05 per share, compared to $0.99 per share in the second quarter of 2010.

The earnings drivers for all 3 operating companies are highlighted on Slides 11, 12 and 13. Our second quarter results include the recognition of a onetime tax benefit of $0.07 per share at Exelon, resulting from a provision under the Energy Policy Act of 2005 that allows transfers of cash or investments from our nonqualified nuclear decommissioning trust funds to our qualified nuclear decommissioning trust funds, generating a tax deduction at the time of transfer.

Exelon originally exercised this provision in March of 2008 and recognized a significant cash benefit based on the proposed regulations back in 2008. However, since that time, the IRS issued final regulations with provisions that allow us to carry back the deduction for 2 additional years from 2008 to 2006, resulting in earnings of $0.07 per share from the accumulation of interest and lower tax expense.

We also expect to recognize about $0.01 per share benefit in the second half of the year for this item as well. Moving on to Slide 14 for an update on power markets and hedging status.

Power prices in both the Mid-Atlantic and Midwest have recovered steadily since hitting their lows in late February. As you can see from the chart on the lower left, Midwest heat rates improved quite significantly as power prices increased despite the decrease in gas price, indicating in part the recognition of environmental compliance requirements by market participants.

With this improvement in Midwest power prices, we increased our hedging activity, including participation in the Illinois Power Authority solicitations conducted on behalf of ComEd and Ameren. As highlighted in our hedge disclosure section of this presentation, we are slightly above a purely ratable hedge for 2012 and 2013.

With further improvement in forward prices in July, we continue to leverage our market views for executing sales within the quarter by selecting the product mix and using various channels to market to add value to the portfolio. Turning to Slide 15.

You can see the diversity in our Generation and sales mix. While our nuclear assets are the core of our Generation portfolio, a sizable ownership or control of other assets complements our nuclear base and allows Power Team to serve more structured products, including retail.

Following the roll off of the power purchase agreement with PECO, we continue to utilize several channels to market to minimize liquidity and congestions. Exelon Energy, our competitive retail business, has experienced significant growth, primarily in Pennsylvania.

Their delivered electric sales volume for the period January to June 2011 increased by over 50% to 9.6 million megawatt per hours compared to the same period in 2010. Turning to ComEd.

The Illinois Commerce Commission issued its final order in ComEd's 2010 distribution rate case at the end of May. ComEd received a revenue increase of $143 million versus its revised request of $343 million, with the new rates starting in June.

The ICC order aligned with many of the recommendations in the ALJ's proposed order, approving a 10.5% ROE and a capital structure with equity slightly above 47%. We view this as a reasonable outcome considering the commission's order reflected the impacts of the Illinois appellate courts decision and the depreciation reserve, which represents $85 million of the reduced revenue request.

ComEd targets an earned return on equity of 10% or better. However, due to the final outcome of the ComEd rate case and the recent impact of the 2 very severe storms that hit the Chicago area in June and July, ComEd will struggle to earn its target ROE this year.

As a result, we have adjusted our full year earnings range down for ComEd. Going forward, absent the effectiveness of the Illinois Senate Bill 1652, ComEd is looking at alternatives such as formula rate legislation or more regular rate case filings using a future test year in order to achieve more consistent 10% or better earned ROEs.

Turning to load. Our expectations for both ComEd and PECO for the balance of the year are very similar to what we indicated last quarter.

In the Chicago area, we aren't seeing any major changes in load or the economy that suggest we need to be more or less optimistic. In Philadelphia, despite a lower gross metro product growth estimates since the last quarter, we anticipate no material changes to our 2011 load forecast.

You can refer to the appendix for the slides on load trends and key economic indicators. Moving on to Slide 16.

Last year, we announced our intention to pursue the RITE line, a high-voltage 765-kV transmission project in the Midwest through a partnership with the Electronic Transmission America, referred to as ETA, a joint venture of AEP and Mid-American holdings. The updated project timeline reflects the execution of the partnership agreement between Exelon and ETA that was formalized on July 13.

The agreements establish operational, financial and management terms to the construction of a line that will extend from Illinois through Indiana to the Ohio border. We expect this line to improve reliability and reduce congestion to this territory once it is fully operational later in the decade, subject to a number of variables including approvals at PJM and FERC.

The execution of the partnership agreement cleared the path for the FERC rate and incentives filing, which was submitted on July 18. The filing reflects a total of 12.7 return on equity, which includes a base return and incentives.

The filing also requests other incentives such as our ability to recover abandonment costs and construction work in progress. We have asked the FERC to issue an order on this binding by October and are beginning to work to include the line in the PJM regional transmission expansion planning process.

Our latest cash flow update is on Slide 17. Our business continues to generate strong cash flows from operations of $4.3 billion, and we expect to end the year with $350 million in cash.

Cash benefits associated with the nuclear decommissioning trust funds special transfer tax that I described earlier will be realized in 2012. Capitalizing on the financial health of the business, we're able to deploy capital for value enhancing investments when such opportunities present themselves.

This was the case with our $305 million acquisition of Wolf Hollow, a 720-megawatt combined central plant. This acquisition aligns well with our existing footprint at ERCOT.

It works from a financial and credit standpoint given our existing PPA for 50% of the output of the plant, and it will further complement our combined portfolio once we merge with Constellation. We purchased Wolf Hollow at a very attractive price compared to other recent transactions, and it will be funded upon closing with cash and available liquidity resources.

The acquisition is pending approval from the Texas PUC, which we expect to receive in the third quarter. Before we open the call for questions, I'd like to provide you with our business outlook for the rest of the year.

As John said, we are raising and tightening our full year guidance range because of our strong year-to-date performance, tax related items in the first 6 months of the year and our view for the balance of the year. For those of you who track storms, we have included in our guidance about $0.04 per share of incremental storm costs related to a severe storm that hit the Chicago area on July 11.

This storm ranks as one of the worst to hit the ComEd region, impacting in excess of 850,000 customers. These storm costs have been included in our consolidated third quarter guidance range where we expect to earn between $1 and $1.10 per share.

Our confidence and our higher full year guidance range is based on the impact of weather so far this year, including storms, new distribution rates at ComEd beginning in June, consistent operational performance and continued effective management of our own up costs[ph]. We delivered strong financial results in the first half of the year even before the tax items that came through, and we are on track to maintain our earnings commitments to you over the remainder of the year.

I will now open the call for questions.

My question relates to the nuclear task force report and then the suggestions in there that it might be to put hardened vents on the Mark 2 containments. And I think we're right, some of those are Exelon plants.

You have any indications you can give us on whether -- what the cost of that might be if that was the way they head with this?

Chris or Chip, we've done some of that altogether. Would you flesh that out for me?

Sure. This is Chip speaking.

We have started our technical reviews if, in fact, those vents are deemed to be required. And we don't yet have any firm price numbers, but they're not extraordinary costs.

These are not significant engineering or construction tasks, so I can just answer qualitatively that those should not be numbers that you would be able to discern.

Chip, you've done some of those already, haven't you?

Yes. Not on Mark 2s, on Mark 1s.

But there are sufficient parallels that we can start from a pretty sound basis.

Could you give us a sense of what it might have cost on the Mark 1s and what the date of those costs were, roughly?

They were early enough, decades ago, starting through the 90s and such that I wouldn't care to extrapolate those costs up forward. But again, they were not large numbers, Jonathan, in the big scheme of things.

So could we be -- are we talking tens of millions or single-digit millions?

I don't know yet, but neither -- again, neither will be big movers for us.

Okay. And then my second question, if I may, on -- in the event that the legislation in Illinois was -- doesn't sort of get over the finish line, what would the likely timing of another rate filing be?

Ann, would you pick that up?

Sure. We are looking at probably early 2012 for that, but we're still in the process of making decisions.

Obviously, we're working hard on the legislation, and that's our first choice at this point, John. That's roughly the timing, Jonathan.

So the -- your -- on Page 22, your estimated open gross margin is based on forward curves from June 30. But I think we all know since the CSPA (sic) [CSAP] Rule came out, power prices have moved up several dollars since then.

So are you seeing the same thing that I'm seeing in that prices are up a few dollars, therefore, all things equal, your open gross margin will be modestly higher? And then second, the real big question is, do you think that really truly reflects the fundamental impact of CSPAR?

Do you think that just reflects the fact that we have a heatwave? How much more, if any, do you think sort of fundamental pricing needs to move as a reflection of what you see in these rules?

Greg, Ken Cornew is good at telling you whether the hot food wants a ham or bacon, so he will answer that.

Greg, we have seen the days immediately following the announcement of the Cross-State Air Pollution Rule, we saw the PJM markets move up about $1 and the ERCOT move up a little more strongly, about $2. Since then, we continue to see some movement.

And now, the markets are more like $2 to $3 up, particularly in the out years, in '14, '15. I think the majority of that move does relate to the announcement of that rule.

There has been, also, in the market, a realization that the fundamentals that make their way into the spot are real, and they're likely to continue in the forward market. So we'll be seeing some heat rate move up and corresponding price move up in the markets because of that.

And that wasn't just the heatwave. That started in the middle of the second quarter, backed off a bit with the drop in gas, but has recovered again.

So is there more? Potentially.

We need to see exactly how emission allowances start trading [indiscernible] start figuring out what kinds of allowances they're going to need to dispatch their plants, but we haven't seen that yet in the market.

Great. And on the flip side of that, we're starting to hear a lot about the amount of productive gas capacity coming online in the Marcellus Shale and that, to some degree, that is not getting to market because of liquids and transmission capacity being constrained.

But I know there's a lot of money flooding that zone to try to fix that. Are you concerned about gas basis being a headwind as we get into '12 and '13 that could mitigate the positive impacts of the things that you just discussed?

Well, as you know, Greg, the basis numbers had decreased substantially since the onslaught of eastern gas development. To the extent Marcellus Shale continues to replace shale from Haynesville or other more standard production from the Gulf, you might see a little more decline in the basis, but that gas market, for the last 9 months or so, has been relatively stable.

Supply and demand seem to be well in balance. Storage figures are a little lighter than they were a year ago.

We feel like the gas market likely will stay in this current range for a good amount of time.

John, I think you mentioned on the Air Toxics Rule that the -- you expect the EPA to hold to their schedule and that -- and then you said they had the -- you feel they have the full support of the administration. Any sense of kind of data points that further indicate that?

Well, I think that there was a quote from either the President himself or his staff recently. Kathleen, do you remember exactly what they said?

Well, there was -- I think you're probably recalling the statement from the Chief of Staff, and that was a few weeks back, indicating that the White House was supporting EPA. And then more recently, in the context of the appropriation discussion, again a reflection that they would veto a big pull back from EPA and its ability to finalize the rules.

Okay. And then I guess one other question, just on this RITE transmission line.

Could this basically allow NiHub Power to potentially get into SinHub or ADHub [ph]? And how many megawatts could potentially go across this line?

Chris, will you pick that up?

John, this is Ron DeGregorio. I'll take that.

This line will allow for a greater flow of energy and power from the various points that you mentioned. The ultimate size and power flow of that will happen as it relates to the specific design, but we're talking nominally, 3,000 to 4,000 megawatts.

3,000 to 4,000 megawatts. Okay.

A question for you, going back to the nuclear task force, you indicated that both the diligent process but perhaps more importantly a fact-based process was your hope. And I was just wondering if you could square that with at least the Chairman's desire of the NRC to get this sort of rules out in 90 days similar to the task force report.

It would seem to almost make that fact-based approach maybe a little more challenging, if you had thoughts there.

Well, I can try. The Chairman clearly wishes to look decisive.

None of us wish to stand in the way of being decisive about these things as long as they got the facts in. The full regulatory staff was not included in the preparation of the 90-day report.

It is almost inconceivable that the Chairman and the other members of the commission won't want to hear from their own in-house experts. In addition, they have to give the industry some opportunity to comment on specific proposals.

I can assure you, we won't do that just for the point of delay. We would like early clarity as much as the public would like early clarity.

But these are very complicated things, and it's my guesstimate that the commission is going to need more than 90 days in at least more complex areas. Chip, what would you like to add to that?

I think that pretty much covers it. We're watching the other commissioners weigh in at this point in time.

And I think from what we can tell, we'll see more clarity around the response to the question in relatively short order is my belief, but until such time the commission finishes weighing in, I don't think we'll know more about timelines or the degree to which the public will participate in the process.

No, that's very helpful. And I guess for clarity, your cost estimates of compliance with whatever new rules, you won't be willing to make that available to folks like us that are interested, probably about the time the rules are made.

So to the extent it takes longer than 90 days, we should anticipate that it'll take you that long to come up with the cost estimates.

When we can give you a number that is with -- at a breadbox level of accuracy, we'll give it to all of you. I mean right now, all we know is that some of our worst fears, particularly about the fuel pools, do not appear to be happening.

And so that's very good thing, indeed. But we just can't give you a number yet because we don't know what we have -- what they have in mind.

The vent hardening is not a very big issue, but some of these other things could cost significantly more. And you won't have to ask.

When we know, we'll get it to all of you as fast as we can.

And then, Matt, just a couple of clarifications. What was the storm cost in the second quarter?

I think you were saying the $0.04 you would incur for the July storms in the third quarter. But I know you had $0.03 in the year ago second quarter, and I wasn't clear what the second quarter of '11 had for storm costs?

I think it's around $0.01 to $0.02 of storm costs in the second quarter. So we had some storms in June and probably estimated to be around $0.02, June.

Okay, got you. So we got $0.01 or so benefit from -- relative to a year ago.

And then on the tax issue, Matt, you said there'd be another $0.01 in the second half. Is there a reason to believe that wouldn't be in the third quarter or -- just to understand your characterization of the second half versus the first.

Yes, the $0.01 is connected to the first $0.07. And it's just -- it's waiting for some final clarification from the IRS.

So it's going to largely be dependent upon that. We like to see it in the third quarter, but it could move to the fourth.

But it's dependent upon the IRS.

I had a question for Chip. You gave us a point of reference for thinking about the cost of the vent hardening on the Mark 2s.

The NRC's report had 3 principal recommendations, and I was hoping that you might be able to give us a way to think about the capital or O&M costs associated with those that they're looking for you to ensure that you've got adequate protection against seismic and flooding throughout your plants, they're looking for you to enhance station blackout mitigation capability and finally, they're looking for you to strengthen the emergency preparedness to address prolonged station blackout. And just if I reference back, say, to what occurred after 9-11, is there some way that you could give us parameters to think about the O&M or capital costs associated with those?

I don't know how much clarity, additional clarity, I will able to provide. But I don't know if you were able to listen to the call that NEI had yesterday on largely the same subject.

And one significant differentiator that we do see thus far with the 90-day report versus actions that were required post-9-11 is that unlike the events of a decade ago when our principal corrective actions involved adding significant security staff and -- significant additions to security staff, which, as you know, are ongoing O&M expenses versus highly concentrated on once-and-done capital improvements. From what we can see this time around, the task force largely concentrates on the physical attributes of the power plants, which tend to lend themselves to capital versus O&M improvements.

I do know that we have completed our first round of seismic and flooding walk downs at our power plants. We did that several months ago as an immediate action post-Fukushima.

And we have not found significant deficiencies with our current design basis features, so I am not anticipating at all any large expenditures around the minor deficiencies that we did find. But until such time NRC is more specific about whether or not further strengthening of our seismic or flooding defenses will be required, I can't really speculate the costs.

I do know that again, though, those would lend themselves to onetime capital costs instead of ongoing O&M commitments that we'll have to make year-over-year.

That's helpful, actually. On the enhancing the statement -- station blackout mitigation capability, it seems to me that the types of steps that NRC is got in mind are not dissimilar to those that you probably had to take when they looked at the potential for an airplane impact on your nuclear power plants after 9-11, although this time, they're also contemplating, I guess, a 2-station blackout, 2-unit black out.

When I went back and looked at your CapEx numbers at ExGen in the years following 9-11, I really couldn't see a major upward move in capital expenditures. Is that a fair read across the likely implications of these new guidelines?

I think that is a fair read across. Now -- and as you can tell, both John and I are both hedging our answers with there is little definition to what the specific actions that we'll undertake actually are.

But I think you have that directionally correct. It appears thus far that we'll end up doing, generally speaking, more of the same in improving the robustness of our layers of protection.

And certainly, not starting from a redesign of significant safety systems or anything like that.

Hugh, I don't know if this is helpful or not, but it's the best I can do. After TMI, there were major structural changes in plant design requirements.

It seems to me that the tone of the post-Fukushima review is not that we'll go back and redesign all the old plants, it's that we'll have to have more consistent measures in place to respond to things that might exceed the design basis. I think Chip and his colleagues call those SAMGs.

But they tend to be much lower in expense than major rebuilds, and you might take a look at it that way.

I guess that was exactly my final question. The third recommendation, strengthening emergency preparedness at the plants is what possibly could give rise to higher O&M costs.

And I noticed going back again to ExGen's experience in the years following 9-11 that the major increase in costs that was seen there was really associated with O&M. And I know at the time, you guys had to go out and hire mercenaries like a renaissance prince to protect your plants.

But is there a concern that you may face a significant uptick in O&M costs due to the need to strengthen the emergency...

From all we can see right now, Hugh, the answer to that question would be no. And if, for some reason, the complexion changes, as John said, we'll get back to you in prompt order.

But I just am not seeing it at all. The defenses that we're talking about with regard to robustness against natural disasters and such are aren't the same as adding security officers as the history around 9-11 dictated.

Right. So in summary, you guys are not really that concerned about either investment cost increases or O&M cost increases as a result of these recommendations?

Hugh, we're not in any panic at all, but we take every round of this with pilgrim-like gravity. I mean, this was a massive nuclear accident.

While small compared to the tsunami and earthquake itself, it's still somewhere between TMI and Chernobyl on the bad things scale. And we will take everything the NRC is doing with the greatest seriousness.

We will work with them as closely as they will let us to get efficient and effective responses to this. But I think what we're saying is we don't, at the moment, see anything that has a major impact on the economics of these plants.

Recently -- on the merger developments, recently, there's been a few parties that have seemed to signal that further plant divestitures beyond what you guys have announced might be necessary. Can you just provide any comment or color on that?

Bill Von Hoene will pick that up.

We did, as we previously stated, a very careful analysis prior to the filing of our agreement and in our filings with FERC and our dealings with the Department of Justice as to what we believed would be the necessary divestitures with reference to the tests that are applied by those groups. We believe the divestitures that we proposed, which, as you know, is about 2,700 megawatts are sufficient to meet those tests.

And we're aware of the filings -- I think you're probably referencing in FERC, the recent interventions in FERC last week, but we do not believe that we will be required to do additional divestitures to meet the tests that those entities had historically used.

Just as a quick follow-up to Brian's question, based on what the PJM market monitor was recommending, how would that affect the proposed 2,700 megawatts? And would it potentially delay the timeline for approval at either DOJ or FERC?

Paul, as you know the intervention by the market monitor did not recommend any specific additional divestiture but did indicate that in the market monitor's view, that additional divestiture would be required without quantifying that. As we studied that, and we discussed this last week, the things we would note is that the analysis performed by the market monitor differs significantly from the type of analysis that has been typically performed by FERC.

And so the application of that analysis would be new and would be something that FERC had not done in prior mergers. So our expectation is that FERC will continue to apply the standards and analysis they have used and that we meet those tests and that the market monitor's depiction deploying different tests that FERC has not used will not control.

What FERC will determine is whether, based on the interventions, a hearing is necessary, and were there to be a hearing ordered by FERC, that would prolong the proceedings. But we don't expect that, that will happen, and we think we will be able to address all of the interveners in a way that -- which is consistent with other approval before FERC will obviate the need for any additionally hearing will keep us on schedule.

Also when you announced the merger, you had initially talk about announcing the first level of reports within a 90-day period. That looks like it's been delayed.

Is there something we should think about that sort of driving the delay in that announcement?

I think the only thing that's affecting the delay since we reviewed some of it with our board just yesterday is just when and how to communicate to certain people. We're trying very hard to keep this a happy merger at -- in both companies.

And right now it is, and I think we're going to try to keep a soft hand to make certain it stays that way.

And I guess my last question is, with respect to Commonwealth Edison, it looks like there's $0.03 that was stripped out as nonrecurring for the distribution rate order. But there also looks like there's another $0.03 onetime item that's included in your $0.15 operating number for the second quarter of 2011.

What's the difference between the 2?

Yes. Paul, it's Matt Hilzinger.

These are items that we've either included or not included in operating earnings in the past and are reversing. And we're just keeping symmetry to where they were originally included.

So that was for the money -- for the EPS that was included in ops, that has to do with underground cables and some working capital kind of a lead-lag amount that we basically had reserved through operating earnings in the past, meaning that we took the charge to operating earnings in the past. We're getting recovery of that so we're reversing that through operating earnings.

The items that have been excluded from operating earnings that you're saying had to do with severance back in '09 and Medicare Part D, those were originally excluded from operating earnings. And so we're excluding that now.

So we're just providing some symmetry as to how they went through the original P&L.

I'm going to turn the call back to John Rowe for closing remarks.

I was looking at a summary statement on my own investment portfolio this morning, and observed that the best thing in the last 60 days was gold. Well, I'll leave you with this thought: Exelon is safer than gold, it's got more upside than gold and it pays a 5% dividend, which is damn hard to get out of gold.

Thank you, everybody.