艾索倫電力 (EXC) 2012 Q2 法說會逐字稿

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. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions).

It is now my pleasure to turn the call over to Ms. JaCee Burnes, 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 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 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 in 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 continue 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 two units.

The first six 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 and 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 adding 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 utility system weathered the heat extremely well, when we experienced 8 to 12 consecutive days of temperatures above 90 degrees across the three 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 service to our customers, often through intense heat periods.

We spoke to you at length in 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 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 should assist you in financial modeling efforts.

I do continue to be extremely pleased with our merger. The operations have been seamless, due in a large part to very effective integration planning and how well we are working together. We remain on track to achieve $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 three years.

Turning to slide 3 -- on June 22, the Illinois Commerce Commission agreed to rehear key elements of 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 solidly supported by the existing legislation. The ICC's timeline for rehearing calls for an 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 three 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 1 in California is an example of the type of renewable project we find attractive. The 230-megawatt solar facility is 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 2013. Antelope Valley will be free cash flow accretive in 2013. And due to 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 things 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're 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 a 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're 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 excellent 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 have been if not for the impacts of the ICC order in their formula rate case. Given that the Commission agreed to revisit its 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 offset the net impact of load variances.

Updated load trends 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 developments surrounding the acquisition of the Conoco Philips and Sunoco 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 and mid-Atlantic baseload 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 length we carried into the quarter, and timed our sales to capture the higher pricing prevalent earlier in the quarter. This execution led to a $1.00 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 are 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 had been agreed to by 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 tax 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 in growth. ExGen also announced they completed a private exchange offer for all of 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 pre-tax cash interest expense by approximately $7 million.

And I'm pleased to announce that we are executing on an "Amend and Extend" strategy for $7 billion of credit facilities, which will enable three key benefits. First, we'll extend the tenor by one year on Exelon Corp's, Exelon Generation's, and PECO's facility, and by two 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 for 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 $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, ISI Group.

Good afternoon, guys. I'm good. I noticed that the open gross margin numbers and the hedge gross margin numbers are down from the Analyst Day because you used a June 30th deck. But can you give us a sense of what pricing has done since then?

Yes, Greg, June 30 was a relative low point from a pricing perspective. And prices were largely down from $1.50 to $2.00. As of the end of July, here, the prices have rebounded about halfway. So $1.00 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, 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 recent vintage, that you may not be aware of, is that 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. Basically what that resolution does is point out the three big issues that the Commission is taking upon rehearing, and expresses the General Assembly's view that the three issues were not decided in accordance with the legislation that they had passed.

That's basically what I was asking. Thank you very much.

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

Good morning. I 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 rose. Could you maybe talk a little bit about the dynamics that you saw underlying the disconnect between the movement in gas and power?

It's going to be driven off load. But, Ken, do you want to -answer this?

Stephen, you did see a decline in heat rate in the last couple of months. Obviously, some of that is it driven by increases in natural gas prices. We've noticed a tendency for power prices to be sluggish in how they move, relative to gas. And, really, as we got into the summer period and started to see summer spot heat rates increase. That has created a rebound somewhat in the power price dynamic, and you've seen 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 of 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 hearing 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, 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. As you remember, 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 -- Anne, is there any you want to add?

Yes, so, the three 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.

Great, thanks so much.

Steve Fleishman, Bank of America.

Yes, hi, good morning, everyone. Couple questions -- first, there's been some commentary by other PJM generators, that there is more 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 are engaged in the dialogue with the Generators and PJM. I'll ask Joe Dominguez to cover where we're at in process now.

We've had several discussions with PJM and other stakeholders. We remain cautiously optimistic that were 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 is 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 -- I think it's the 205 -- it's more of an uncontested, unified voice from PJM; but we don't plan on stopping. We'll continue to push the issue.

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

Yes, we expect to have 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 we don't expect any bumps in the road.

Okay. And one last question. On the tax cash flow item that you mentioned [unintelligible]. I hadn't recalled that being delineated out as a special cash flow item. I just want to make sure that the, let's say, the fixed income/rating agency community knew that there was a one-time 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 are updating them on the expected timing of when those cash flows recover.

Okay. Thank you.

Jonathan Arnold, Deutsche Bank.

Morning, guys. My questions are mostly answered, but on this cash flow question, I just wanted to clarify that the difference between the $1.425 billion ComEd OCF in the Analyst Day Deck 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 x-ed out when you did the analyst meeting deck, then.

The ICC rate order would have been x-ed out; but some of the assumptions around working capital and timing we did not build into our operating cash flow assumptions at 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 tax cash.

That's correct.

That's the best part of $400 million, and then the ICC staff is $75 million or so?

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

Okay, thank you.

Julien Dumoulin, UBS.

Hi, good morning. 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, 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?

The filing is based off of our desire for that 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 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 it's caused some damage with the timing of 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?

Yes. And there is no question that the Maryland Commission has not been particularly amenable to forward-looking adjustments. They didn't agree to 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 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 regulatory process.

Great. And then on the ExGen side, I'd just be curious, we've seen some shifts in power basis -- AD-Hub, NI-Hub, and, perhaps more interestingly, towards the East -- how structural are some of these changes, as we're thinking about it? Or are they due to more a temporary type items?

Yes, Julian, clearly spot basis figures have dropped significantly. And it really was explained, in my mind, by coal-to-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 cost; and higher heat rate units in the East. 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.

Great. Thank you for the time.

Jay Dobson, Wunderlich Securities

Good morning. Chris, I wanted to follow up on your CapEx comments in your prepared remarks, particularly around and 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 will 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 number around what the wind going away would do -- 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. We'll continue to look at other areas.

Okay. So we shouldn't assume the $425 million goes away. It might just be reallocated. So, if we're staring at 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 -- we've talked about how sustainable growth is really focused on the flexibility that we have on the balance sheet. Look at what our potential investment opportunities could be. They meet their hurdle rates, they help drive the out-year earnings, so it's not that we would -- if wind is not there, we are not investing any more. We go to different areas, and see if there is 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 do have a very strong view on PTCs. 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 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. Let's stabilize the fundamentals so we all know where we can make our investments.

Okay, perfect. Just two more questions, then. A quick one for Joe, I think. On the PJM MOPR -- understanding it's all confidential discussions -- but assuming you've got to something that was somewhat unanimous and uncontested, would it be your view that that is 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 for that, I think it would get through FERC fairly easily. Obviously, the premise being that we get to that solution; and we have some work to do to get there. Again, we're cautiously optimistic that we will.

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

Yes, as I stated on Analyst Day, we expect margins in the $2.00 to $4.00 area, and we don't see any reason to change that perspective.

Great. Thanks much.

Brian Chin, Citigroup.

Hi, good morning. Just a quick clarification on slide 15, which is a helpful slide. In the footnotes, you guys talk about how CENG going into the 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 stub and the full-year our comparable, so we can really compare those?

Do you want to cover that, Duane?

You can think of that as comparable, the full-year earnings estimate on only reflects BGE's contribution --

CENG's.

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

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

That's correct. Yes.

Understood. And just to clarify --

Brian, just the rationale for giving you this, it 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 times 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 and the full-year estimate -- like for taxes other than income -- why they're similar. That's just due to rounding. Really, there's probably -- the full-year estimate is probably a little bit higher than the stub estimate, just pro rata-ing up, right?

That's right. It's rounded to the nearest $50 million. And it's the nature of the numbers, that the spread is really within that $50 million band.

Appreciate it, thank you.

Paul Fremont, Jefferies.

Thank you very much. I guess, yesterday, we heard for the first time that Midwest Gen may find its way into bankruptcy at some point. If they were to reject contracts, including their obligation to deliver capacity under RPM, what would happen to -- would they have to re-run the auctions, basically? Or what would happen with respect to filling in that capacity that's already been sold in auctions?

Yes, I don't think we're prepared to address the Midwest Gen, and I hadn't heard about that. But the commitments -- the commitment in the auction, I don't -- they would not re-run the auction.

Joe or Ken, you want to jump in? The default provisions are --

Yes, there are obviously default provisions and 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 -- Midwest Gen's particular situation.

And if you were to take Midwest Gen out of the equation, can you give us a sense of what reserve margins might be in Chicago? Because, as I understand it, that is a bottleneck.

I don't think we know what Midwest Gen units cleared in any particular auction. We can't know that. So we definitely cannot do that calculation.

And then the last question for me is -- it looks as if gas prices, since the ones that you are 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 have been higher spot heat rates in the mid-Atlantic and 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. But 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 16 timeframe.

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 are not doing so. Again, it's a sluggish, illiquid market, where in the 2015, 2016 timeframe we don't see a lot of buying interest and buying activity.

Okay, thank you very much.

Michael Lapides, Goldman Sachs.

Just talk a little bit about the feedback you've gotten from the rating agencies, maybe even the fixed income community more broadly. And post analyst day, in terms 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 with 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're 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 it would cover the upside of that -- it would cover the dilution of the equity issuance. But there hasn't been any real dialogue beyond what we've had with you at the Analyst Day.

Okay. And a question on the New York power market -- there is, obviously, a very important docket still open at the FERC regarding Zone J capacity pricing, but it will have a ripple effect throughout all of New York. Can you just give your point of view about the regulatory structure of the New York market? Whether you have any concerns about the regulatory viability 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 into 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.

You saw the Astoria case that we were involved in get decided last month. And I think there are continuing stakeholder discussions about how to handle capacity needs. The governor, obviously, has a plan 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.

Okay. Thanks, guys. Much appreciated.

Ali Agha, SunTrust.

Thank you. Good morning. One thing, just clarifying on 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 2013, 2014, looking forward as well? Is that the way to think about that?

There's a catch-up period. Anne, do you want to cover that?

Yes, so the three issues that are on re-hearing at the Commission stands about $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, that we've got some issues that we'll take to appeal that didn't get picked up on the re-hearing, to get us all the way back.

I see. Okay. And second question, Chris, looking a little longer-term, obviously you're at the vagaries of the commodity cycle. But your capacity prices are pretty much set through mid-2016. And you look at the forward curve, your cost production, et cetera -- when do you think you're in a position to be close to the earnings base that you earned back in 2011? You know, the north of $4.00 earnings base. When does 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 retirements. 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 and the earnings from the utilities. So there's a lot of things in play. I couldn't pick, 2016, we are back there; but there is work that we can do, and we are doing it. And then, there are the market fundamentals that will drive a significant portion of that.

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

I wouldn't go there. I wouldn't go one way or the other. We don't project earnings in the out-years. And there is a lot of fundamentals around that. We do have a ratable hedging that secures us, slowly blends in wild perturbations of market adjustments, but I don't know if I'd hit that point yet.

Got it. Thank you.

Nathan Judge, Atlantic.

Hi. I just wanted to ask about page 5; the middle of the page, it says Midwest, mid-Atlantic wholesale was pared down in a low-price environment. Can you just elaborate on what you were going for with that bullet point?

(multiple speakers). Nathan, it's Ken. You're referring to the bullet point on slowing down our hedging, pare down our hedging, in the Midwest and the mid-Atlantic?

Yes, I guess more thematically, are you visiting 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 plan 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 pace to fall back to a ratable position at this point.

Thanks. Could you just update us as to what 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?

(multiple speakers) They are predominantly gas -- mostly gas, but there are some electricity options there, as well.

Thank you.

Angie Storozynski.

Thank you. My questions have been asked and answered. Thanks.

Kit Konolige.

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 the public service and others are conducting. (A), do you guys have a view on how that might turn out? And (B), does -- in your view, does it matter how that turns out, ultimately? 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 signal to states, in the future, not to subsidize power plants?

I'll let Bill answer the details. I think it would clearly message to states what is -- 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 -- 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 Bill - you want to talk about our view, overall?

Yes. Kit, this is Bill Von Hoene. As you referenced, the court heard argument yesterday for about three 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 is going to do. But, as Chris referenced, the results, if they were favorable to us, would be largely prospective. And we do think they would be material to what will happen in other states that may otherwise have an inclination to do this subsidized generation.

There are many participants in the market today that are willing to invest for new generation. We're doing so in our nuclear uprates. There are others that are doing so with new iron in the ground. We continue to model, and had been modeling, when that would be a good opportunity for us, for those type of developments. And what we are messaging with the other market participants, the more it's done -- the subsidized 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. It's jobs not really coming in. And that's the Company's view, and that's why we're taking the position we are.

Stephanie, we'll take one more question, and then we'll turn it over to Chris to close out the call.

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

Good morning. Just a follow up, quickly, on Jay's MOPR question. It sounded like -- 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 -- I'm just wondering, did I hear that correctly?

I think actually, Jay's 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 was a good bit of work to do to get a sufficient number of stakeholders onboard with MOPR revisions. We are in process with that. I don't think anything we will come to will have universal support, but 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, hot weather in the third quarter here, 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 comment on that. Is that a demand-response issue? Is that because there were some storms? Or were there peaks that I just don't know about at ComEd or PECO, or what have you, in PJM?

There were no new peaks. There was some curtailments in, I think, at least one day if not two, in Easter MAAC -- or it was 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 look at the demand-side response programs and added them to the peaks that each of the companies had, they would have had a new peak relative to past performance. So I think demand response is playing a role in eliminating the 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, as opposed to the capacity market there's this -- the new pricing mechanism for real-time -- for the energy market that demand response can now get.

Paul, it's Ken. The demand response was called for emergency situations. And on July 17 and 18th, really, that full LMP concept was not in place at the time this demand response committed to the capacity market. So 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 BGE one for the analyst meeting. But I didn't see it in this one. Is there any update, in terms of what your weather-adjusted demand growth looks like in that?

You know, we hadn't put that in, since BGE is decoupled. Really, it's just a pass-through. I don't know if you want to discuss your load anymore, Ken, but --

The forecast for the end of the year is weather-adjusted down 0.6%, about in line with what PECO and ComEd are showing.

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

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

Okay, great. Thanks much.

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 impact for a business. I am excited about the opportunities that our unique platform brings, both to our existing operations as well as towards our sustainable growth plans.

I'm very proud of the progress that we've 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.