Exelon Corporation (EXC) Q2 2012 Earnings Report, Transcript and Summary

JaCee Burns Christopher M. Crane - Chief Executive Officer, President, Member of The Board of Directors and Member of Generation Oversight Committee Jonathan W. Thayer - Chief Financial Officer and Executive Vice President Kenneth W. Cornew - Executive Vice President, Chief Commercial Officer, Chief Executive Officer of Constellation and President of Constellation Stacie M. Frank - Vice President of Investor Relations Anne R. Pramaggiore - President of ComEd and Chief Operating Officer of ComEd Joseph Dominguez - Senior Vice President of Federal Regulatory Affairs, Public Policy, State Governmental Affairs & Communications Duane M. DesParte - Principal Accounting Officer, Vice President and Corporate Controller William A. Von Hoene - Executive Vice President of Finance & Legal Denis P. O'Brien - Executive Vice President, Chief Executive Officer of PECO Energy, President of PECO Energy and Director of PECO

Greg Gordon - ISI Group Inc., Research Division Stephen Byrd - Morgan Stanley, Research Division Steven I. Fleishman - BofA Merrill Lynch, Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division James L. Dobson - Wunderlich Securities Inc., Research Division Brian Chin - Citigroup Inc, Research Division Paul B. Fremont - Jefferies & Company, Inc., Research Division Michael J. Lapides - Goldman Sachs Group Inc., Research Division Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division Nathan Judge - Atlantic Equities LLP Angie Storozynski - Macquarie Research Paul Patterson - Glenrock Associates LLC

Good morning. My name is Stephanie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Second Quarter Earnings Call. [Operator Instructions] It is now my pleasure to turn the call over to Ms. JaCee Burns, Vice President of Investor Relations. You may begin your conference.

Thank you, Stephanie, and good morning, everyone. Welcome to Exelon's second quarter 2012 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 on factors that may cause results to differ from management's projections, forecasts and expectations and for reconciliation of operating to GAAP earnings. Leading the call today are Chris Crane, Exelon's President and CEO; and Jack Thayer, Exelon's Executive Vice President and Chief Financial Officer. They are joined by many other members of Exelon's executive management team who will be available to answer your questions. We have scheduled 60 minutes for this call. I will now turn the call over to Chris Crane, Exelon's CEO.

Thank you, JaCee, and good morning to everybody. We'll start off on Slide 2. As you saw on our release this morning, Exelon has delivered solid performance for the quarter. Our operating earnings per share were $0.61 for the second quarter, in line with our expectations. Our nuclear organization continued to run the fleet well, turning in a capacity factor of 93.4% for the second quarter, a period that included 51 planned refueling outage days at 2 units. The first 6 months of the year, the capacity factor was 93.5%. The performance of the entire generation fleet was very good. Our commercial operations also performed well in actively managing the portfolio. In the Midwest and Mid-Atlantic regions, our decision to be ahead of ratable in prior quarters allowed us the opportunity to slow down our hedging volume in this quarter. In Texas, as prices moved up during the second quarter, we accelerated our hedging activity to lock in the upside of 2012 and 2013. In addition, our retail sales channels are meeting expectations for added margins and volumes. As you can see in the hedge disclosure, the second quarter had a dip in the market, but we believe in July, we've made up over half of that on the open gross margin, and Ken and Jack can address those questions as we get to the Q&A. At our utilities, this summer has brought extreme heat along with some violent storms. Our utilities system weathered the heat extremely well when we experienced 8 to 12 consecutive days of temperatures above 90 degrees across the 3 service territories. The storm brought more of a challenge, particularly in the BGE service territory, which experienced one of the most damaging storms in BGE's nearly 200-year history. Both Maryland and Illinois were hit by significant storms. In total, the utilities restored power to approximately 1.2 million customers during the first week of July. I would really like to thank our utility crews at BGE, ComEd and PECO for their tireless efforts to restore the service to our customers, also -- or often through intense heat periods. We spoke to you at length at our Analyst Day in June and provided you with a significant amount of information. We remain on track with what we told you. Not much has changed. Therefore, our presentation -- prepared remarks and presentation today are short, leaving additional time for questions. Additionally, in the spirit of continued transparency, we have provided additional information in our Appendix, which assists you in financial modeling efforts. I do continue to be extremely pleased with our merger. The operations has been seamless due to a large part to a very effective integration planning and how well we are working together. We remain on track to achieve $100 million -- $170 million of merger-related O&M synergies for 2012. Based on our performance to date, we are reaffirming our 2012 full year earnings guidance range of $2.55 to $2.85 per share, and we expect to be comfortably within that range. Jack will cover our financial performance in greater detail in a few moments, but let me first give you an update on regulatory developments at ComEd and BGE and our expectations for growth capital at Exelon Generation over the next 3 years. Turning to Slide 3. On June 22, the Illinois Commerce Commission agreed to rehear key elements of the ComEd's 2011 formula rate filing, including the treatment of the pension asset. We view the ICC's decision as a step in the right direction. ComEd's goal is to provide customers with better service, more choices and greater control over their electric bills. We are committed to working with the regulators to make sure we can make the investments necessary to fulfill these promises to our customers. We also believe our positions are soundly supported by the existing legislation. The ICC's timeline for rehearing calls are on order by September 19 of this year with hearings beginning later this week. Reversal of the original ICC decision on the rehearing items could improve ComEd earnings by as much as $0.10 per share in 2012. Turning to BGE. On July 27, BGE filed a combined electric and gas rate case with the Maryland Public Service Commission. The rate case reflects a $204 million increase in revenue requirements for both electric and gas, with the requested ROE of 10.5%. BGE needs to make investments in assets and systems to maintain and improve electric reliability, ensure gas safety and meet increasing compliance obligations. In order for BGE to continue to make these needed investments to serve the customers, it requires the opportunity to earn a fair return. We expect an order from the Maryland PSC by February of 2013, with hearings to be set for later in the fourth quarter. Now I want to spend a few moments on our growth capital expectations for Exelon Generation for the next 3 years. At our Analyst Day in June, we presented our CapEx expectations through 2014. In those numbers, we included $800 million of undesignated spend in our renewable business for 2013 and 2014. This is a conservative planning view, which affords us flexibility if we find the right opportunities. We continue to assess the viability of the spend. Our decision to move forward with projects will be driven by value creation for our shareholders, which will largely be determined by the extension of the federal investment tax credits and balance sheet flexibility. Antelope Valley Solar Ranch One in California is an example of this type of renewable project we find attractive. The 230-megawatt solar facility, progressing according to plan, the first portion of the project is expected to be online in October of 2012, and we expect commercial operations in late in 2013. Antelope Valley will be free cash flow accretive in 2013 and due to the project financing, we have minimal impact on our credit metrics as calculated by S&P. We expect to fully recover our investment by 2015. If we find similar growth opportunities, we will pursue them. We have created flexibility in our balance sheet by incorporating this undesignated spend. Before I turn over to Jack to review our financial results, there are a few things I want to reiterate. First, this quarter, we demonstrated our commitment to operational and financial results. I remain extremely pleased with the merger, it is working. We are already seeing benefits. As I said at our Analyst Day, we have the right strategy, the right platform, the right set of assets and the right leadership to manage through the market downturn and deliver unparalleled upside when the markets recover. In the meantime, we remain committed to our investment-grade balance sheet and our dividend. Exelon is the best-positioned company in the industry. With that, I'll turn it over to Jack to cover more details on the finances.

Thank you, Chris, and good morning, everyone. My commentary will supplement the earnings press release issued this morning, which includes a substantial level of detail about Exelon's financial results. Let's begin with the summary of this quarter's financial results by operating company on Slide 4. Due to the merger, the composition of current quarter earnings for ExGen, BGE and Exelon are not comparable to last year. Thus, I'll highlight a few key results for the quarter in lieu of stepping through a comparison to last year. We are pleased to have delivered non-GAAP operating results of $0.61 per share this quarter. Our earnings are tracking well within our full year guidance range as a result of Exelon's operational performance. ExGen's $0.47 non-GAAP earnings per share contribution is in line with what we expected for the quarter. At the utilities, ComEd recorded $0.05 non-GAAP operating earnings per share this quarter, about $0.10 lower than it would've been if not for the impacts of the ICC order in their formula rate case. Given that the Commission agreed to revisit their ruling in ComEd's formula rate case, we're hopeful for a favorable outcome. The final decision will not be known until September 19. Thus, ComEd's financial results reflect the year-to-date impacts of the May order. PECO and BGE rounded out earnings this quarter with contributions of $0.10 and $0.02 per share, respectively. With respect to weather, ComEd's quarter results include a $0.01 benefit due to June's above average heat, while the financial impact from weather at PECO and BGE is negligible this quarter. At PECO, the above average heat experienced in the quarter was offset by fewer than normal heating degree days, and BGE's decoupling mechanism largely offsets the net impact of load variances. Updated load trend slides for ComEd and PECO are in the Appendix of today's presentation for you to review at your convenience. You'll notice that PECO's load outlook has improved since our Analyst Day presentation. As a result of positive development surrounding the acquisition of the ConocoPhillips and Sunoco's Pennsylvania oil refineries, PECO now expects a year-over-year, weather-normal decline of 2% versus the 3.3% decline in load previously projected. Turning to Slide 5. The commercial team continued to execute on the portfolio management and load serving strategies outlined by Ken at Analyst Day. We've made progress on our growth objectives in the brief time since disclosing our targets and have locked in an additional $150 million of gross margin towards our new business targets for the year. In our Midwest to Mid-Atlantic base load regions, we were able to slow the pace of our hedging activity this quarter in a flatter market price environment. In 2013 and 2014, our hedge percentages increased 3% to 5% this quarter versus a typically ratable 8%. This opportunity was created due to our efforts to be ahead of ratable in the previous several quarters when market conditions were more favorable. In the ERCOT region, we captured value from the link we carried into the quarter and timed our sales to capture the higher pricing prevalent earlier in the quarter. This execution led to a $1 per megawatt hour increase in the effective ERCOT realized energy prices for 2013 and 2014. We remain well positioned to meet our load serving sales targets. Our sales teams remain active in all competitive markets, renewing existing customers and attracting new customers from all customer classes. We'll provide a more comprehensive status check and update of our load serving business growth at EEI. An update of Exelon's sources and uses of cash is on Slide 6. We've had some movement in our planned CapEx spend for the year. However, the changes are primarily minor timing-related shifts, and all 2012 projects are still on track, including the $2 billion we're investing in attractive NPV positive growth projects. The more significant changes in our cash flow projections relate to tax settlements and debt financings. Regarding tax settlements, the majority of the $550 million decline in cash from operations is associated with a shift in the timing of refunds associated with settlements of our 2002 to 2006 tax filings with the IRS. The refunds, which have been agreed to by the IRS appeals, are now expected to be delayed until sometime in 2013 or 2014 due to a procedural change in the handling of partial settlements. Given the anticipated timing of the back settlement, ComEd is pulling forward a previously planned 2013 issuance to fund needs in the interim. At PECO, given the attractive interest rate environment, we are refinancing an incremental $100 million of the planned debt retirements, bringing total issuance to $350 million. This will also help reduce expected future financing needs. In June, ExGen completed its planned $775 million debt issuance with solid pricing that compared well to its 2010 debt offering. The 10-year and 30-year priced at 4.25% and 5.6%, respectively, compared to the 4.0% and 5.75% coupon achieved for the 10-year and 30-year offerings in September of 2010. These funds will be used for general purposes of the company, including investment growth. ExGen also announced they completed a private exchange offer for all the outstanding 7.6% senior notes due in 2032. Of the $700 million principal outstanding, more than 63% were tendered in exchange for cash and notes that will expire in 2022 and 2042. Going forward, this debt exchange will lower our annual pretax cash interest expense by approximately $7 million. And I'm pleased to announce that we are executing on an amended expense strategy for $7 billion in credit facilities, which will enable 3 key benefits. First, we'll extend the tender by 1 year on Exelon Corp.'s, Exelon Generation's and PECO's facility, and by 2 years on BGE's credit facility, resulting in a 2017 maturity for all our facilities. Second, we'll be able to realign the bank group with the combined company, bringing in new banks and ensuring all banks lend to each operating company within the Exelon family. Third, we'll capture current market pricing consistent with what we pay on ComEd's $1 billion credit facility refinanced earlier this year. We expect to close on the amended facilities in August. Before I open up the call for questions, I want to look ahead to next quarter's earnings. We expect Q3 non-GAAP operating earnings in the range of $0.65 to $0.75 per share, and we remain confident that we will achieve our full year earnings target of $2.55 to $2.85 per share. Our earnings guidance range adequately accounts for the impact of weather and incremental storms incurred in July. Most notably, it reflects $0.03 of incremental storm cost at BGE for the derecho storm. We are confident about achieving our financial targets this year, and there are several factors that give us line of sight on this goal, including our ability to hit synergy targets. To date, we've initiated and completed several milestones that will position us to achieve our $500 million run rate O&M savings starting in 2014. Staffing and selection was finalized at the end of June. Contract negotiations are in progress to incorporate our increased scale and scope and vendor contract pricing, and we eliminated an additional portion of our surplus credit facility. And with that, we're ready to take questions.

[Operator Instructions] Your first question comes from the line of Greg Gordon from ISI Group.

So I noticed that the open gross margin numbers and the hedged gross margin numbers are down from the Analyst Day because you used a June 30 deck. But can you give us a sense of what pricing has done since then?

Yes. Ken, you want to...

Yes. Greg, June 30 was a relative low point from a pricing perspective, and prices were largely down from $1.50 to $2. As of the end of July here, we've -- the prices have rebounded about halfway, so $1 of that price is back in energy prices. So commensurate with that, as Chris commented on, we would expect to see our open gross margin calculation make its way halfway back up to where it was on April 30.

Great. And can you comment on whether there's been any sort of a public discussion about the pension issue as it pertains to your rehearing in front of the ICC amongst the commissioners or any other relevant parties?

There hasn't -- make sure I understand the question. You're asking, has there been any public statement by the Commission on the rehearing?

Or any other relevant interveners.

No. The rehearing process will start, I guess, the end of this weekend.

Yes. We've got hearings start at the end of this week. The date for the Commission's order is September 19. That's the drop-dead date for it. The one thing that is sort of a recent vintage that you may not be aware of is there was a hearing held before the House Public Utilities Committee on July 10. And we basically passed the resolution that we had filed on June 18, passed it through the House Public Utilities Committee, 22, yes, 1 no, on that date. So that was -- basically, what that resolution does is point out the 3 big issues that the Commission has taken up on rehearing and expresses the General Assembly's view that the 3 issues were not decided in accordance with the legislation of the account.

Your next question comes from the line of Stephen Byrd from Morgan Stanley.

Just wanted to focus -- just building on Greg's question on the power price dynamics and the change. We saw some interesting dynamics in the sense of the power price falling at the same time that gas -- for gas rose. Could you maybe talk a little bit about the dynamics that you saw underlying sort of the disconnect between the movement in gas and power?

It's going to be driven off of load, but, Ken, do you want to...

Yes. Stephen, you did see a decline in heat rates in the last couple of months. Obviously, some of that is driven by increases in natural gas prices. We've noticed the tendency for power prices to be sluggish and how they move relative to gas. And really, as we got into the summer period and you started to see summer heat rates, the spot heat rates increased, that has created a rebound somewhat in the power price dynamic and you see power prices come back up. Again, it's a market that has a lot of different dynamics to it that are driven by future expectations or price, but as you see, reality in the spot market, it tends to have influence on longer-term prices as well. And I think higher spot heat rates have driven power prices up.

That's very helpful. And then just shifting over to Illinois briefly, if the rehearing goes well in Illinois, do you expect next year you'd be in the range of your allowed ROEs? Or would you expect a modest lag at that time, if the rehearing goes well, sort of on the positive end of the range of outcomes?

Yes. If the hearing goes well, it resolves the issues that are causing us to under-earn. The -- if you remember the rate, the formula rate is based off of 580 basis points above the composite treasury. So we would get back to what we think the legislative package that had allowed us to earn what Anne [ph] is earning.

Yes, so the 3 issues really takes care of the bulk of it. There's a few issues that the Commission did not take up on rehearing that will carry over, we'll take them up on appeal. So there's a little bit of cleanup on that, but we get very close.

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

A couple of questions. First, just there's been some commentary by other PJM generators that there's more maybe openness by PJM to review the MOPR rule in time for next year's auction. Could you comment at all on what you're hearing on that topic?

Yes. We're engaged in a dialogue with the generators and PJM. I'll ask Joe Dominguez to cover where we're at in the process now.

We've had several discussions with PJM and other stakeholders. We remain cautiously optimistic that we're going to get revisions to the MOPR process in advance of next year's auction. Obviously, our discussions are confidential. But I think there is widespread understanding of our concerns regarding the MOPR exemption process. And I think as time goes on, there's going to be an effort to change that process. That's about as much as I can say about those discussions.

We definitely want to do this in a cohesive manner and go under the filing to FERC on the, I think it's the 205s. More of an uncontested unified voice from PJM but don't plan on stopping. We'll continue to push the issue.

Okay. Secondly, just should we still assume your asset sale related to the mergers closing will be announced sometime in August?

Yes, we expect everything wrapped up within the timeframe allowed. I think we have a 30-day extension that allows everything to be cleaned up by September 9. But it's well underway and don't expect bumps in the road.

Okay. And one last question, just on the tax cash flow item that you mentioned and the like, I hadn't recalled that being kind of delineated out as a special cash flow item. I just want to make sure that the kind of, let's say, the fixed income/rating agency community knew that there was a kind of a onetime tax cash flow item in this year?

Steve, this is Jack. We hadn't delineated out within the cash from operations, the tax item. But certainly, in our conversations with and our updates to the rating agencies, we're updating them on the expected timing of when those cash flows recover.

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

My questions are mostly answered, but I just -- on this cash flow question, I just wanted to clarify the difference between the $1.4 billion to 5 common OCF in the Analyst Day, and the $975 million, is that pretty much all this tax item?

It's taxes as well as the recovery on the pension and other items related to the ICC order.

So those were not sort of x'd out when you did the Analyst Meeting deck then?

The ICC rate order would have been x'd out, but some of the assumptions around working capital and timing, we did not build into our operating cash flow assumptions that time given the timing of the announcement relative to our Analyst Day. So that's an incremental, roughly $75 million hit to working capital and cash flow relative to what we showed at Analyst Day. So the significant portion of it is the timing of the tax that adds in.

That was the best part of $400 million and then the ICC stuff is $75 million or so?

The working capital element related to the ICC order is $75 million.

Your next question comes from the line of Julien Dumoulin from UBS.

So first with regards to BGE, I noticed you guys filed this rate case late last week. I'd be curious, to what extent do you expect kind of status quo your ability to earn your ROE next year under these new rates just kind of from a rate lag perspective? And then secondly, is there any chance given some of the reliability standards in the state to pursue any kind of quasi-trackers? Is there any outlook for that at all?

We -- the filing is based off of our desire for the ROE. And I think we've done a good job on stating the basis for that in the filing. So we'll proceed on that front. BGE has some room to make up, to catch up on earnings. As you know, when we announced the intention for our merger, we had to hold BGE out of their rate case. So that's caused some damage. And then there's with the timing and the recovery. But we fully expect to state our case and obtain those numbers. Ken, you want to talk about the Commission's philosophy on riders in Maryland and the potential of that?

Sure, and there's no question that Maryland Commission has not been particularly amenable to forward-looking adjustments. They didn't support any of those in the recent cases. However, we do think we have a compelling reason for proposing some of those. And then in parallel with that, we are still looking at opportunities to work with the Maryland legislature. We had some success in a, what was called the STRIDE Bill, looking at gas safety-related investments, which we almost got across the finish line, and we're going to be reintroducing that again. So we're going to be working both sides, both the legislative and the regulatory process.

Great. And then on the ExGen side, just to be curious, we've seen some shifts in power basis, 80 Hub, NiHub and perhaps, more interestingly, towards the East. How structural are some of these changes as we are thinking about it? Or are they due to more temporary type item?

Yes, Julien. And clearly, spot-basis figures have dropped significantly and it really is explained, in my mind, by coal and gas competition. So a significant amount of basis in the past has been driven by cheaper power prices in the Midwest, cheaper plants and higher costs and a higher heat rate used in the East. Now as gas and coal competition occur, those basis numbers drop. I think that's the main reason we've seen a squeeze in basis. I don't think there are major structural changes that are driving spot basis and forward basis right now. Obviously, with coal retirements coming in 2015 and some reinforcement of the grid, there are going to be some changes.

Your next question comes from the line of Jay Dobson.

Chris, I wanted to follow up on your CapEx comments in your prepared remarks, particularly around renewables. If the PTC is not extended, how much of that $800 million in 2013, 2014 would go away?

We don't have an exact number. There are some projects that are still under construction right now. We have Antelope Valley that will go into 2013. We'll still look at other opportunities. I would say that the wind growth would be significantly reduced with the PTC going away. There probably will be some solar opportunities left, and we'll continue to focus on those.

And could you put a sort of number around what the wind going away would, just as we all sort of stare at CapEx and the like?

If you look at the numbers we have slated for 2014 in that rounded up CapEx spend of about $425 million, we would look at other uses of that if they created value. We just don't see the wind being there to use that to -- the market being there to need that expenditure. But we'll continue to look at others.

Okay. So we shouldn't assume the $425 million goes away, it might just be reallocated. So if we're sort of stay out of the bottom line of CapEx, don't assume PTCs go away, CapEx goes down, but maybe it gets reallocated. Is that the right way to think about it?

It has the potential to be reallocated based off of the value of the investments that we can find at the time. What we're trying to do in this period and we've talked about a sustainable growth, is really focus on the flexibility that we have on the balance sheet, look at what our potential investment opportunities could be. They meet the hurdle rates, they help drive the outyear earnings. So it's not that we would -- if wind's not there, we're not investing anymore. We go to different areas and see if there's a good value proposition. And if not, we don't spend the money.

Perfect. And Chris, do you all, as a corporation, have a view on PTCs?

We are -- we do have a very strong view on PTCs. We're -- and publicly, we're asking them to be stopped. We do have a wind business. We think wind should be in the portfolio, but what's happening, I think there's unintended consequences with all the fundamental shifts in the generating stack right now between coal retirements, natural gas coming down, trying to subsidize a single source can create some market distortions. And we're asking for a break period, let's let the market stabilize. That PTC has been in place since 1992, I believe. And I think that's enough time to jumpstart an industry, 20 years. So we've made it known even as a wind company that it should be stopped and let's stabilize the fundamentals so we all know where we can make our investments.

Okay, perfect. Just 2 more questions then. A quick one for Joe, I think. On the PJM MOPR, understanding it's all confidential of discussions, but assuming you got to something that was somewhat unanimous and uncontested, would it be your view that, that's something FERC is willing to consider and approve?

It is my view. I think if the stakeholders come together with proposed revisions that address some of the defects in the exemption process and their sufficient support of that, I think it would get through FERC fairly easily. Obviously, the process being that we get to that solution, and we have some work to do to get there. Again, we're cautiously optimistic we will.

Awesome. And then last question, I guess, to Ken. Just give a little granularity on sort of what you're seeing on retail margins in the Northeast.

Yes. As I've stated in the -- on Analyst Day, we expect margins in the $2 to $4 area, and we don't see any reason to change that perspective.

Your next question comes from the line of Brian Chin from Citigroup.

Just a quick clarification on Slide 15, which has been a helpful slide. In the footnotes, you guys talk about how the CENG O&M and D&A is not included in the stub estimate. Should that mean that it is included in the full year estimate? Or should we think of it that the accounting treatment for both the sub and the full year are comparable so we can really compare those?

Duane, do you want to...

Yes. No, the -- you can think of that as comparable. The full year earnings estimate only reflects BGE's contribution.

CENG's.

CENG, I'm sorry. I misunderstood the question.

So the -- we're only recognizing the net profits from the JV, not trying to fold in the operating expense. So from an accounting perspective, it's comparable, yes.

Understood. And just to clarify...

And, Brian, just the rationale for giving you this is in our Generation statistics, we show the megawatt-hours under purchased power for CENG, and we wanted comparability to the extent that you wanted to model this on a P x Q basis so you could model in the full impact of CENG's P&L.

Understood, understood. And then also, the reason why the stub estimate, the full year estimate price for taxes other than income, why they're similar, that's just due to rounding. Really, there's probably the full year estimate's probably a little bit higher than the sub estimate just prorating [ph] up, right?

That's right. It's rounded to the nearest $50 million, and it just -- it's the nature of the numbers that the spread is really within that $50 million advance.

Your next question comes from the line of Paul Fremont from Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: I guess yesterday, we heard for the first time that MidwestGen may find its way into bankruptcy at some point. If they were to reject contracts, including, I guess, their obligation to deliver capacity under RPM, what would happen to -- will they have to rerun the auctions basically? Or what would happen with respect to sort of filling in that capacity that's already been sold in auctions?

Yes, I don't think we're prepared to address the MidwestGen and I hadn't heard about that. But the commitments in the auction, I don't -- they would not rerun the auction. Joe or Ken, you want to jump in? The fall for provisions are...

Yes, there are obviously the fall provisions and the incremental auctions for people to buy replacement capacity if capacity drops out for any reason. We're not going to comment on, as Chris said, MidwestGen's particular situation. Paul B. Fremont - Jefferies & Company, Inc., Research Division: And you if you were to take MidwestGen out of the equation, I mean can you give us a sense of what reserve margins might be sort of in Chicago because as I understand, that, that is a bottleneck?

I don't think we know what MidwestGen units clear in any particular auction. We can't know that. So we definitely can't do that calculation. Paul B. Fremont - Jefferies & Company, Inc., Research Division: And then the last question for me is, it looks as if gas prices, since the ones that you're using as reference prices are up like $0.10, so how much of the July improvement is due to higher gas? And how much of the July improvement in absolute price of power is due to market heat rate?

I would say, Paul, it's due almost entirely to higher gas prices. There has been higher spot heat rates in the middle and the Midwest region, lower spot heat rates in the ERCOT region, so it depends on what we're talking about here. But mostly, the increase in gas has driven a commensurate increase in power prices. And it's not really a fundamental shift from a forward sense in heat rates at all. Heat rates are very flat from a 13 to 16x rate. Paul B. Fremont - Jefferies & Company, Inc., Research Division: So I guess -- so what would've caused the deterioration in the forward market heat rates?

Heat rates are typically inversely correlated to natural gas, so they will fall. Heat rates are higher relatively than the year's historical heat rates have been. They reached a high point with the low point in natural gas a couple of months ago and have fallen. As we've indicated before, we believe that from a forward sense, these heat rates should be increasing fundamentally as coal plants retire. They're not doing so. Again, it's a sluggish and liquid market where in the '15, '16 timeframe, we don't see a lot of buying interest and buying activity.

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

Just talk a little bit about some of the feedback you've gotten from the rating agencies, maybe even the fixed-income community more broadly, and post the Analyst Day in terms of kind of not having plans for either doing equity or convertible securities in the next year or so in your base case.

Yes, we typically don't go into a lot of detail about the discussions of the agencies, but we haven't had any conversations around it. We continue to look at our models. We continue to look at our growth opportunities. We are very comfortable with cash from operations covering our operations requirements, including the dividend. And so if there is an equity, it would be off of a growth opportunity that we want to pursue, and to uncover the upside of that would cover the dilution of the equity issuance. But there hasn't been any real dialogue beyond what we had with you at the Analyst Day.

Okay. And a question on the New York power market, there's obviously a very important docket still open at the FERC regarding, really regarding Zone J capacity pricing, but it will have a ripple effect throughout all of New York. Can you just give your kind of point of view about the regulatory structure of the New York market, whether you have any concerns about the regulatory viability of kind of how that capacity market is working and just insights into the ongoing FERC docket?

We think the New York ISO is looking outward to try to find ways to improve that forward capacity market, and we do want to support that dialogue to how to stimulate the right kind of investment into the market. I think they've had that discussion looking forward, too. As far as the FERC filing issue...

Yes, Chris, I think I'd just echo your comments. What we see in New York is really no different than what we've seen in New England and PJM. There are MOPR issues in New York. There are issues regarding questions about state subsidizing, generation, and I think we're working through those in the FERC cases that have been ongoing, we saw the Astoria [ph] case that we were involved in getting decided last month. And I think there are continuing stakeholder discussions about how to handle capacity needs. The Governor obviously has a plan and that is a combination of transmission and new generation and we're taking a look at that. I don't see any imminent problems there. I think they're the same issues that we confront in other RTOs, and I think we're going to work through them.

Your next question comes from the line of Ali Agha from SunTrust.

Just clarifying on the ComEd, assuming you do get the reversal and the rehearing, as I recall, that $0.10 pickup that you talked about, that would be an annual impact, right? That would also flow into '13, '14 looking forward as well? Is that the way to think about that?

There's a catch-up period that's annual to recover that.

Yes. So the 3 issues that are on rehearing at the Commission, gains that $0.10 in 2012, they are $0.05 and $0.06 in 2013 and 2014, respectively. So that's basically how it works out. And then you just have a little bit of cleanup as we've got some issues that'll take to appeal that didn't get picked up on the rehearing to get us all the way back.

I see. Okay. And the second question, Chris, I mean looking a little longer-term, you -- obviously, the -- you are the babies of the commodity cycle, but your capacity prices are pretty much set through mid '16. And you look at the forward curves, your cost of production, et cetera, when do you think you're in a position to be close to the earnings base that you earned back in '11, the north of $4 earnings base? When will this company have that kind of earnings power in your mind, looking at this combined company?

There are so many variables in and around that. We have to see the effects in the market of how gas stabilizes out. We have to look at what the effects are with the [indiscernible]. It would be pretty premature to pick that date right now. We continue to really focus on high reliability, solid investments, keeping a discipline on the expense, working hard to build the right rate base within the utilities and get the right return, focusing on a higher contribution on the dividend in the earnings from the utilities. So there's a lot of things in play. I couldn't pick 2016 we're back there, but it's -- there's work that we can do, and we are doing it, and then there's the market fundamentals that will drive a significant portion of that.

Fair enough. But standing where we are today looking forward, it's not -- I mean the next 3 years most likely won't get you there. Is that a fair way to think about it?

I wouldn't go there. I wouldn't go one way or the other. We don't project earnings in the outyears and there's a lot of fundamentals around that. We do have a ratable hedging that secures us, slowly blends in while perturbations of market adjustments. But there's -- I don't know if I'd hit that point yet.

Your next question is from the line of Nathan Judge of Atlantic.

I just wanted to ask about Page 5, the kind of middle of the page, just Midwest, Mid-Atlantic wholesale was pared down in a low-price environment. Could you just elaborate on what you were going for in that bullet point?

Sorry, Nathan, I'm just -- I got it.

This is Ken. You're referring to the bullet point on slowing down our hedging, paring down our hedging in the Midwest and the Mid-Atlantic?

Yes. I guess more thematically, are you revisiting your overall decision on whether to ratably hedge or not?

No, we're remaining disciplined and we will stay within a relative band around ratable hedging. We got ahead of our ratable plans starting in the third and fourth quarter of last year, seeing the potential for gas price roll down. So we got ahead of our ratable plan and this statement just points to the fact that we slowed down our hedging in the second quarter. Hedged at a slower than ratable case but fall back to a ratable position at this point.

And could you just update us as to what kind of options are being deployed now as a percentage of the overall?

About 5% in 2013, 7% to 8% in 2014.

And are those electricity? Are those gas?

Mostly gas, but there are some electricity options there as well.

Your next question is from the line of Angie Storozynski.

My questions have been asked and answered.

Your next question is from the line of Kit Canote [ph].

Most of my questions have been answered also. Just one related to potentially to the discussion of the MOPR issues. There was a hearing in federal court on the LCAPP appeal that public service and others are conducting. A, do you guys have a view on how that might turn out? And B, in your view, does it matter how that turns out ultimately? I mean are there -- if say, LCAPP were to be overturned and seen as unconstitutional, would that have a retroactive effect in any sense or an immediate impact? Or would that potentially just be a kind of a signal to states in the future not to subsidize power plants?

I think I'll let Bill answer the details. I think it's clearly messaged to states what are the fundamental principles around the market design and the laws and the rules around the market design. We don't think -- if people had won, and we know people have won capacity bids within the specific year, and they can't comply, there's ways to get out. There wouldn't be a restructuring of the auction. But you want to talk about our view overall?

Yes. Kit, this is Bill Von Hoene. The -- Kit, you know the court, as you referenced, the court heard arguments yesterday for about 3 hours. The court did not render a decision, nor indicate when it would. The results that are possible are summary judgment one way or another or have the matter go to trial, and we don't have an opinion at this point, a projection as to what the court's going to do. But as Chris referenced, the results if they were favorable to us would be largely perspective. And we do think they would be material for what will happen in other states that may otherwise have an inclination to do the subsidized generation.

There's many participants in the market today that are willing to invest for new generation. We're doing so in our Nuclear operates. There's others that are doing so with new iron in the ground. We continue to model and have been modeling when that would be a good opportunity for us for those type of developments. And what we're messaging with the other market participants, the more that's done to subsidize generation, the uncertainty in the market is created, and we have to pull back on investing capital. So that's good infrastructure not being built because jobs are not really coming in, and that's the company's view and that's why we're taking the position we are.

Your final question comes from the line of Paul Patterson from Glenrock.

Just to follow-up quickly on James' MOPR question. It sounded like, if I -- and maybe I heard it wrong, that there might be a stakeholder consensus among the stakeholders with respect to this MOPR issue? A little unusual for stakeholders. It's hard for -- I'm just wondering, did I hear that correctly?

I think actually, James' question was if there is a stakeholder consensus, do we expect it to get through FERC, and my answer was yes. But I also said that there's a good bit of work to do to get a sufficient number of stakeholders on board with MOPR revisions. We're in process with that. I don't think anything we will come to will have universal support. We're going to try to get majority support for some changes, we're cautiously optimistic we're going to get there, and that's as much as we can say about the process at this point in time.

Okay, fine. Great. The second thing is, whether in the third quarter here, a little bit in the second quarter, really hot weather in PJM and we didn't see any peaks, any new peaks. And I was wondering if you could sort of comment on that. I mean is that a demand response issue? Is that because there were some storms? Just I mean -- or were there peaks that I just don't know about at ComEd or PECO or what have you in PJM?

No, there were no new peaks. I mean, there was some curtailments in, I think, at least 1 day, if not 2, in East and MACT or West Virginia, but it showed that the transmission investments are working, there is adequate generation and that the system was able to cover the load. Denis, anything else?

Yes, we'd have to do the math on it, but I think if you looked at the demand side response programs and added them to the peaks that each of the company's had, they would've had a new peak relative to past performance. So I think demand response is playing a role in eliminating higher peaks.

Do you think that might have something to do with the energy tariff now with demand response that was recently implemented at PJM? You know what I'm talking about. In other words, there's suppose -- the capacity market, there's the new pricing mechanism for realtime for the energy market that demand response can now get.

No, Paul, it's Ken. The demand response was called for emergency situations. And on July 17 and 18, really, speaking of the -- that full LMP concept was not in place at the time. This demand was last committed to the capacity market so that kind of -- the demand response was called for reliability reasons in the East as Chris indicated.

Okay. And then just finally, great disclosure, it was very useful. But I did notice that the BGE load slide, you had it for PECO, you had it for ComEd, and you had the BGE one for the Analyst Meeting, but I didn't see it in this one. Is there any update in terms of what you're weather adjusted demand growth looks like in that?

We hadn't put that in since BGE's decoupled. It really is just a pass-through. I don't know if you want to discuss your load anymore, Ken, but the...

The forecast for the end of the year is weather adjusted down 6/10 of 1%, about in line with what PECO and ComEd are showing.

Okay. And that's just basically what you've seen -- the reason why they've decreased from last time is because of just what the results have been? Is that pretty much what you're extrapolating? Is this the second quarter came in and that's why?

I Yes, I think that's correct. It's just an update based on the earlier parts of the year.

Okay. Thank you. And thank you again for your time today. We look forward to seeing many of you in the near future. I know we have many sessions where we'll be going out. In closing, again, this quarter, the Exelon companies have demonstrated its commitment to operation and financial results. We do maintain a disciplined approach to investing in the future, paying close attention to the market conditions and the policy decisions that have meaningful impacts to our business. I am excited about the opportunities that our unique platform brings, both through our existing operations, as well as towards our sustainable growth plans. I'm very proud of the progress that we made with the merger and more importantly, extremely grateful for the commitment and the dedication shown by everybody to remain focused on delivering the operational and financial goals as we advance through the transition. Our unique platform creates the opportunities, as I've said, for both the existing operations and for the future operations. And with that, thanks for attending.

Thank you, Stephanie.

Thank you. This concludes today's conference. You may now disconnect.