Exelon Corporation (EXC) Q3 2012 Earnings Report, Transcript and Summary

Good morning. My name is Tracy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Exelon Third Quarter Earnings Call. [Operator Instructions] Thank you. I would now like to turn the call over to Ms. JaCee Burns. Ma'am, you may begin.

Thank you, Tracy, and good morning, everyone. I'm JaCee Burns, Vice President of Investor Relations for Exelon. Welcome to Exelon Third Quarter 2012 Earnings Conference Call. Thank you for joining us today. We hope that you and your families are safe and sound, particularly for those of you on the East Coast, who have been dealing with the aftermath of Hurricane Sandy. You've really been in our thoughts a great deal. 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 Chief Executive Officer; and Jack Thayer, Exelon Executive Vice President and Chief Financial Officer. They are joined by 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. Before I discuss the Exelon third quarter results, I'd like to take a moment to recognize the more than 8,000 PECO and BGE employees, contractors, mutual assistant workers, who are working around-the-clock to respond to Hurricane Sandy. This devastating storm slammed our Pennsylvania and Maryland service territories with heavy rain, high winds and is causing historic damage. Many of you know this firsthand, being in the New Jersey and New York area. We are grateful to the dedicated men and women in the field, who are repairing the damage and restoring service to our customers as quickly and safely as possible. And that's not to mention the thousands of out-of-state contract workers, including our ComEd employees, who have made their way east to assist in the service. We have today, for those of you in New York, around 50 underground technicians arriving in New York City to assist with the recovery of the underground system there, and we'll continue to keep our folks on the East Coast as long as we can to help in all regions. I'd also like to acknowledge the employees that are for -- in Mid-Atlantic nuclear plants for effectively preparing for the hurricane. And then they worked diligently to respond to the storm, particularly Oyster Creek, which was at the point where the storm came ashore, which felt the greatest impact. Because of their dedication, we are able to resume normal operations. With that, let's turn to Slide 2. The third quarter financial performance was very strong for Exelon, particularly at ExGen. We reported operating earnings per share of $0.77, which was well above the midpoint of our guidance range for the quarter. Based on our financial performance to date, we are revising our 2012 full year earning guidance range to $2.75 to $2.95 per share. This range incorporates the preliminary cost estimates of the impact of the Hurricane Sandy in our service territories, which we have preliminarily forecasted to be around $100 million of incremental O&M expense. We're in the midst of the restoration, so that could have a plus or minus 20%. We'll be finalizing it by weekend. The merger continues to go very well. We are on track to meet our commitments to various stakeholders, including our shareholders. We expect to achieve the $170 million merger-related O&M synergies in 2012 that we announced at Analyst Day, as well as the $500 million of run rate synergies beginning in 2014. In the course of the bottoms-up construction of our long-range plan, we have also identified an incremental $50 million of O&M cost reductions, bringing the total synergies to $550 million. As we complete the integration and continue to refine our financial plans, I expect we will identify further cost reduction opportunities. We've signed a sales agreement for the mandated asset divestiture in Maryland, received FERC approval for the sale and expect to close the transaction in the fourth quarter of this year. We are benefiting from our well-matched generation and load footprint as demonstrated by our year-to-date financial performance, highlighted by the Constellation portfolio optimization success. Our integrated operations are seamless, the management team is working very well together and the merger is working. Jack will provide you with more detail about the financial performance, but first let me give you our view on the current market environment and how we assess our overall financial priorities. I'll wrap up with a discussion on the outcome of the rehearing process at ComEd and the implications of the ICC's ruling on the pace and scope of future investments. So moving to Slide 3. During the quarter, we saw considerable volatility in the power and gas markets. In August, prices declined significantly to levels lower than June 30 prices, which were the basis for our second quarter hedged disclosure. In September, power prices recovered, driven largely by rising gas prices. However, we continue to see a disconnect in heat rates and forward power prices in PJM. We recently updated our fundamental analysis, which now indicates that even after the recovery and power prices, there is roughly $3 to $6 per megawatt hour upside not being reflected in the prices. The expected upside is the result of plant retirements, higher operating cost for compliance with environmental standards and a continued disconnect between heat rates and gas prices. We forecast that approximately 42 gigawatts of capacity will be retired in the Eastern Interconnect by 2016, with over 30 gigawatts of retirement already announced. Other third parties have even higher forecast of retirements. We believe NiHub has the most heat rate upside. At the current gas prices, we expect to see greater than 1 heat rate point increase over the current market, or approximately $6 of upside in 2015 at NiHub prices. Given the lower number of retirements in the MATS portion of PJM and less of a disconnect in heat rates, we see an opportunity of approximately $3 per megawatt hour upside in the PJM West Hub prices. There are 2 primary factors can explain why we are not currently seeing this upside. First, approximately 15 gigawatts of capacity will be retired in Eastern Interconnect this year and next. As these units come offline, we expect to see an increase in prices. Second, there is a potential for an increased liquidity in 2013 forward prices for the year -- calendar year of 2015 and beyond, as load auctions take place with delivery in 2015 and customers procure power in the commercial, industrial and the Muni-Ag space. For these reasons, we think we expect the forward curves to reflect the $3 to $6 per megawatt hour upside during 2013. We continue with our traditional ratable hedging but we are executing our Bull/Bear program in this period of volatility to capture the incremental value from a heat rate recovery while ratably locking in cash flows to support the balance sheet. We have flexibility in our program to increase or decrease our hedge within a 10% band of ratable. You've seen us exercise this flexibility in the past, where we have hedged at or above ratable and locked in on incremental value. Now we have slowed our hedge activity over the last few quarters from ahead of ratable at the end of 2011 to ratable levels. At this pace, we will trim below a purely ratable program over the next few quarters, absent a power market recovery. However, we will always look to shift our strategy when we see better pricing opportunities. We are also leveraging our financial and physical products, such as selling underlying gas and utilizing gas and power options in order to preserve the ability to capture the heat rate expansion when the ultimate pricing -- the price comes back into the market. And note that, that natural gas underlying an option hedge is less than 10% of our expected generation. This portfolio optimization is a core skill for Constellation. This year we were able to capture considerable value through the portfolio management by optimizing our generation load positions. In ERCOT, large moves in the forward summer heat rates allowed us to sell our peaking generation open link as forward prices rose prior to the summer, and we continue to perform this optimization into the spot market while we manage the load variability. In PJM, we saw low falling products that better match our generation through our retail and wholesale channels, reducing basis exposure and capture incremental value for our base generation. With that backdrop on markets, I'd like now to speak about our latest forecast for retail. As we discussed our -- in updated generation hedge disclosure, flip to Slide 4. As you heard us discuss in the last month, both the retail and the wholesale markets have been impacted by aggressive competition and pricing. We maintained the same disciplined approach to valuing and pricing the risk and the full requirements load that has led to success in our portfolio optimization in the past. This approach has resulted in us not winning as many of the recent Muni-Ag RFPs in Illinois and certain other competitive procurements in other markets. Our recent experience in the competitive environment has tempered our near- to mid-term outlook for our retail business. We have adjusted our commercial load expectations as reflected in our updated Exelon generation disclosure from what we presented back at Analyst Day. At Analyst Day, we were projecting 20% growth in commercial volumes from 2011 to 2014. Reflecting the current market dynamics, we are now projecting a 9% growth in volumes from 2011 to 2015. We still expect retail to support growth in our commercial business and serve as a key channel to market. We also view the current pricing dynamic as unfortunate, but a necessary aspect of what we expect to be consolidation of retail providers. This experience also highlights the importance of the ability that we uniquely possess to utilize other channels to market to optimize our portfolio. Turning to Slide 5. We can discuss the impact of these changes on our ExGen hedge disclosure. Compared to second quarter open gross margin improved by $600 million from the 2012 to 2014, as power prices increased across the curve. We have continued to hedge and have moved the portfolio back to near ratable. In our PJM baseload regions, we are close to ratable and we have utilized discrete hedging products to preserve the opportunity to benefit from the market realization of our fundamental views that forward market heat rates will move higher. In ERCOT and NEPOOL, we are slightly behind ratable, leaving room for upside participation in what we believe will be higher spark spreads. We are fully hedged in 2012, roughly 90% hedged in 2013, approximately 60% hedged in 2014. We've introduced hedge disclosures for 2015 that we have approximately 20% of our portfolio hedged in that year. We are mostly open in 2016 and highly leveraged to the recovery in power prices as reserve margins tighten. During the quarter, we benefited from our balanced load serving and generation portfolio, which is reflected in the $100 million increase in our total gross margin for 2012. In particular, due to the hot temperatures across the country, we experienced stronger-than-forecasted wholesale and retail loads, resulting in favorable variances as the majority of our contracts are executed at higher prices. In addition, we leveraged our dispatchable fleet across the country to realize higher margins during this period. The impact of the degradation in the retail market can be seen in 2013 and 2014 through the reduction in power new business to go bucket. The decrease of $50 million in 2013 and $100 million in 2014 is a combination of both a decrease in volume expectation as well as a lower dollar per megawatt hour margin. At our June -- at our Analyst Day in June, we shared that our retail C&I margin average, $2 to $4 per megawatt hour. With the increased competition, we're now seeing those margins at the lower end of this range. As we move into the selling season in the fourth quarter of 2012 and early into 2013, we will gain more insight as to where the margins and the volumes are trending. While we're disappointed with these reduction -- reduced expectations, history has taught us that discipline is more integral to value sustainment than unfettered growth. So we'll continue to monitor the competitive environment, strive to attract and serve new customers and improve our market share, but we will be -- remain disciplined in our pricing. Before we leave this slide, I want to tie it back to our discussion about the expected upside in the power markets. In the appendix, back on Slide 19, we provided our standard gross margin sensitivities. Hitting that, in 2015, we're only 20% hedged. A $5 move per megawatt hour increase over the current forwards will result in roughly $700 million of additional gross margin. In 2016, where we're mostly open generation position, this opportunity is approximately $1 billion or roughly $0.70 of earnings per share. If our fundamental view is realized, this is a boost to earnings that is not reflected in our current valuation. Now let's talk about our financial priorities and some actions we have taken as a result of the volatility we've seen in the markets and to give ourselves some more opportunity. So turning to Slide 6. Our #1 priority is to remain investment grade across all our registrants. Our investment grade rating is fundamental to the business, given our sizable collateral requirements, our counterparty and customer relationships and our significant nuclear capital expenditure. In close proximity of importance, our next financial priority is returning value to the shareholders through our dividend. We understand the importance of the value of the dividend to our shareholders. Our third priority is to invest in growth opportunities, smartly deploy growth capital to value -- to provide value to our shareholders. In order to fulfill our top priorities and sustain certain investments, which benefit from the anticipated market recovery, we've adjusted our capital spend plans. This repositioning of capital has 3 key components. First, we're deferring the Limerick extended power upgrade by 4 years. Second, we're deferring the LaSalle EPU by another 2 years. If you remember at Analyst Day, we announced the deferral of LaSalle by an initial 2 years, and this will create a 4-year overall deferral. The licensing activities, which is the amendment to approve that power uprate, will continue to be submitted to the NRC by the end of the year. This allows the flexibility to execute the EPU projects when prices recover. Lastly, we removed the undesignated renewable spend from our financial plan. In total, we removed roughly $2.3 billion of growth capital from 2012 to 2015 capital plans at Exelon Generation since our Analyst Day disclosures, which meaningfully improves our free cash flow over the period. The deferral of these projects is a matter of better aligning our growth capital spend with the expected timing of the power market recovery. We still believe that these projects add significant value and can earn attractive IRRs. The long-term -- the long-lived nature of these assets will allow us to defer the investment and still capture returns in a more balance sheet friendly manner. On Slide 7, we'll provide the comparison of our current ExGen growth CapEx forecast to what we presented at the Analyst Day. So flipping to that -- excuse me, they gave me a long script today. So flipping to Slide 7. You can see the impacts of the deferral of Limerick and LaSalle as well as the elimination of the unidentified renewable spend. We're moving forward with the EPU at Peach Bottom as planned. The additional 130 megawatts from this upgrate are expected to come online and generate returns beginning in 2015, resulting in an unlevered IRR on a go-forward basis well above 10% across the range of potential price scenarios. We are the farthest along with Peach Bottom. To date, at our ownership level, we have invested $55 million, with roughly $360 million of spend planned through 2016. In terms of investment dollars, Peach Bottom is the smallest of the 3 uprates and the size of the investment results in limited strain on the balance sheet. You can also see that we are moving forward with our plans for upstream gas. These investments provide strong returns with no impact on credit metrics as calculated by S&P, given their treatment of the reserve base lending facility that is utilized to fund the business. We view these investments as value-creation opportunities for our shareholders that support our strategy but with limited balance sheet impact. Now I'll speak to the decisions -- now I'll speak to how these decisions impact our balance sheet and how we think about the dividend going forward. We've maintained a strong balance sheet to help us weather this challenging market. With the expected year-end FFO to debt of 31% in 2012, we are strong heading into 2013. However, these metrics weaken as our higher-priced hedges roll off and we enter into the new hedges at lower prices. Based on 9/30 prices and with the deferral of the upgrade and the elimination of the undesignated renewable spend, our FFO to debt at Genco plus HoldCo is more focused -- excuse me, forecasted to be above the 25% to 27% range for 2014 and '15. We believe our metrics are sufficient to maintain investment-grade ratings. But with the recent market volatility we experience, we have to continue to monitor this. We believe the materialization of our fundamental view of power prices will allow us to strengthen our credit matrix and watch the markets closely to ensure that we have no structural changes that could impact our fundamental view of the $3 to $6 upside. It is, of course, also possible that the power prices will not recover as completely or as rapidly as our fundamental views suggest. In that regard, with the actions we've taken, we have time to see how things play out. But if they do not play out favorably in the next 6 months, revisiting our dividend policy will be in the range of options for preserving our investment-grade rating that management and the board will need to consider. Before I turn the call over to Jack, I'd like to speak to the implications of the Illinois Commerce Commission's decision in the rehearing of ComEd's formula rate, which is on Slide 8. On October 30, ICC granted ComEd recovery of the cost of funding its pension but denied the cost of recovery of 2 other key issues, which ComEd appealed in the courts, along with other items previously denied in the ICC May ruling. The adverse ruling on the interest rate and rate base issues impair ComEd's ability to finance long-term investment programs. While we remain committed to fulfilling the promise of the Energy Infrastructure Modernization Act and intend to meet our obligations under the law, we have to be thoughtful about making the investments, if we do not have a full cost recovery mechanism, as authorized by the legislation. As a result of the ICC decision, ComEd has deferred $450 million of capital expenditure through 2012 -- from 2012 to 2014 to 2015 year. Obviously, that schedule could shift as a result of regulatory, legal or legislative developments. At EEI, we'll be providing a more comprehensive update of the ComEd and other utility CapEx spends forecasted through 2015. Given the negative impact of the ICC decision, we believe the decision should be reversed. This will take time. So we'll continue to update you as we work through it. And like I said, we'll talk more about this in EEI. I'll now turn the call over to Jack, who will speak to our financial performance during the quarter.

Thank you Chris, and good morning, everyone. As Chris mentioned, I'll review the second quarter financial results, and then update you on changes to our 2012 cash forecast and earnings outlook. I'll start on Slide 9. We reported third quarter 2012 non-GAAP operating earnings of $0.77 per share versus $1.12 a share in the third quarter of 2011. Beyond the impact of the merger-related share differential and the addition of earnings from the legacy Constellation business, revenue net of fuel at ExGen is the primary difference between 2012 third quarter results and the third quarter prior year. The drivers of lower RNF include lower realized market prices and lower PJM capacity revenues due to the transition to the 2012-2013 capacity auction clearing prices, which averaged about $36 per megawatt day lower than the 2011-2012 planning period. When comparing our financial results for the quarter with our expectations, we delivered solid results for the quarter and we exceeded our $0.65 to $0.75 of earnings per share expectations. We outperformed our guidance range largely due to favorable RNF at ExGen and tax benefits at PECO and favorable weather at ComEd and PECO. ExGen's $0.53 non-GAAP earnings per share this quarter reflected about $0.04 of favorable RNF. This RNF upside is the net of approximately $0.07 of revenues from effective portfolio management optimization by Ken Cornew's Constellation team, partially offset by $0.03 due to lower-than-expected nuclear volumes. Chris already spoke about the source of the portfolio optimization benefit earlier, but I will add that event-driven opportunities such as this are difficult to forecast. When they do arise, having a skilled team that can execute and capture the benefits such as ours is an asset. Moving to the utilities. ComEd's non-GAAP earnings of $0.10 per share for 2012 third quarter includes $0.01 more earnings than expected from favorable weather, driven by the amount of cooling degree-days over normal. The number of cooling degree-days at ComEd this quarter exceeded normal expectations by nearly 250 degree-days or 40%. Likewise, PECO's 2012 third quarter non-GAAP earnings of $0.14 per share reflect an additional $0.01 of earnings above our expectations due to weather. PECO's 2012 third quarter results also reflect a larger than estimated benefit from the deductions associated with the tax treatment of repairs for gas distribution assets. We elected and recognized a similar benefit for the treatment of electric transmission distribution assets the same time last year. The actual benefit for this item came in higher than our estimate by $0.02. BGE's 2012 non-GAAP operating earnings this quarter were completely offset by storm cost. BGE's non-GAAP operating earnings would have been about $0.03 if not for the cost incurred for the derecho storm in July. Despite BGE's absorption of the storm cost, BGE will still contribute positive earnings to full year consolidated earnings. Turning to Slide 10. Our cash from operations projection is up $450 million since the last update. There are several puts and takes to this number, but it's largely due to changes in net income and changes in taxes coinciding with the company's annual tax filings. In addition, the latest cash from operations projection includes the updated expected net proceeds from the sale of the Maryland coal assets, as outlined in the 8-K we filed on August 9. Now I'll turn to Slide 11 on earnings outlook. On Slide 11, I'd like to provide our updated earnings outlook for 2012. As is typical at this time of year, we are narrowing our guidance range. We've had a few positive developments occur this quarter that warrant us raising the top of our range as well. We now expect 2012 full year earnings in the range of $2.75 to $2.95 per share, up from our initial earnings guidance range of $2.55 to $2.85 per share. The revised earnings expectations reflect the $0.10 of earnings per share ComEd will record in the fourth quarter to recognize the impact of the commission's rehearing decision issued on October 3. The guidance adjustment also considers the incremental earnings contributed by the favorable RNF at ExGen, offset by our preliminary estimate of incremental storm cost related to Hurricane Sandy. So in closing, our next update would be at EEI, where we will refresh much of the information we shared at Analyst Day, including capital expenditure estimates through 2015 and pension contribution expectations. That concludes my comments. I'll now turn the call back over to Chris before we open the line for Q&A.

Thanks, Jack. Before we move to Q&A, I just want to reiterate a few points. We've had a strong financial performance in 2012, even with the impact of the hurricane. As a result, Jack mentioned, we are increasing our earnings guidance range. While the recent market dynamics do give us concern, I'd restate we believe $3 to $6 per megawatt hour is not priced into the market, and our expectation is that we will see the upside for 2015 and beyond materialize in 2013. We've taken the right platform to take the right advantage of what we expect for the power market recovery. Investment-grade ratings and maintaining the dividend are our top priorities. We have options, we have time to maintain these objectives. To time our investments for the power market recovery in giving us some flexibility, we've repositioned our growth strategy and we deferred certain upgrade projects. We'll also, as we stated, eliminate the undesignated renewable spend. Lastly, we remain focused on protecting and creating value -- shareholder value through continued advancement of growth projects at Exelon utilities, Peach Bottom, Antelope Valley Solar Ranch and upstream gas. With that, we will open it up to questions.

[Operator Instructions] And your first question comes from Greg Gordon with ICI Group (sic) [ISI Group].

I just wanted to ask you a few questions about the numbers from sort of the -- from the Analyst Day from April 30 to present. So when we look at power pricing, power prices dipped but have -- sort of substantial to come back more or less to where they were at the Analyst Day deck, slightly higher in some regions like Zone A, New York; slightly lower in other regions like PJM -- I'm sorry, like NiHub. But you have also done things to reduce CapEx, further cut O&M and your gross margin targets are substantially the same. So is it fair to say that your credit metrics, as things look today, are still within the 25% to 27% FFO to debt that you were projecting in April?

Yes, they are.

So why would you, 6 months from now, when things aren't improving, be sort of thinking about a change in dividend policy if at the current forward curve you're still on those credit metrics? Is it that over time, you start to -- you're deferring capital expenditures but you can't -- you're sort of pushing out the decision but you can't permanently eliminate that decision unless power prices go up. Is that the right way to think about it?

Here's how I'd look at it. The capital isn't part of that decision any longer. If the markets don't come back, which we think they will, most likely we will not do those upgrades. So you've got to see the market recover and then you see the strengthening of the balance sheet, then you understand we should be back into a sustainable growth mode, optimizing our assets. Continuing to watch the markets come forward, if you look at 2012 and 2014 -- excuse me, 2013, 2014 NiHub or West Hub, those years on an ATC are back to where we were talking with you at Analyst Day, and some a little bit better. But if you look at '15 and '16, there's still a buck and change disconnect there. So we haven't seen them strengthen as much on the back end. We saw a lot of volatility in August. It was unbelievable where the numbers were going, we couldn't model them. We want to make sure that we're being very open and clear. We said we wouldn't surprise anybody. If that volatility comes back into the market, we don't see the recovery, you do not want to -- we do not want to be living on the edge, and the edge is 25%. We've been given some flexibility by the rating agencies because they think this is a stress period. But if something structurally change there and you're dealing with a 90% payout on a dividend for a long run and we have to question if we're getting value. You don't want to live on the edge. There is potential volatility, but I think we have time to watch it going into 2013.

Okay. So just to recap and make sure I'm hearing you correctly, you've sort of moved yourself back into a comfort zone for the short term with the actions you've taken, but if we don't see the back end improve, those actions sort of aren't a permanent solution?

I don't think they would be a permanent solution under these market conditions right now. And that's why we've got to see the market come back up.

Great. Just a follow-up question on that. One of the things that is sort of an obvious observation is that this is probably leading to lower prices is the anemic low growth that you're seeing in your service territories. I think that's a concern that's come up on a number of other earnings calls in a number of other regions as well. Is there anything you can point to that's leading to sort of such sluggish activity? And anything that might lead to a potential change in that perspectively?

Well, the first initiating event for the market prices is the retirement of the assets that have been stated already, and we think that tightens the reserve margins there and should be reflected in the market prices. The load growth has been flat to negative. We continue to work on saving industry and trying to attract industry in. But I don't think you can beat energy efficiency over the next couple of years. So there -- on some sides, you're seeing housing come back. You're seeing auto come back. We saved the refineries in Pennsylvania, that's the load sting or a little coming back in. On the other side of that equation, you're seeing the effects of energy efficiency come in. So the real needle mover is on the market reflecting the tightening reserve margins of the retirements.

Your next question comes from Jay Dobson with Wunderlich Securities.

Following on the last question, given the volatility in August, is there a change in your confidence in your fundamental view? Or is it simply just the volatility itself? I'm trying to understand what's causing the injection of the dividend uncertainty.

We're not injecting that today. I think we've messaged clearly that we'll never surprise anybody. We talked about the levers we had back in Analyst Day, when we were looking at tight market forwards. We've come back to that point. August had more volatility than we expected. Now there's a couple of things that came in, in August. We think there was more coming to market, then the liquidity was there. It -- other portfolios were coming into the market. We need to substantiate that in the next quarter, next couple of quarters to see -- and we believe the prices would come back. But can -- I don't think we're shaken by the volatility but we do want to confirm our assessment, right?

That's right, Chris. Obviously, Jay, we have and continue to reiterate that we see heat rate upside in this market that is not being reflected, particularly in the '15, '16 time frame. The volatility in price you've seen this summer largely was driven by a couple of things, natural gas price movements and selling behavior in the marketplace. We have seen some recovery on the back of natural gas prices, but we still have not seen the market reflect what we think is a fundamental shift in the stack based on the retirement of over 40,000 gigawatts coal plants in the '15-'16 time frame.

Okay, fair enough. And then Chris, on Illinois, can you talk just a little bit about the legislative outlook? I know you filed an 8-K and are probably getting out and talking to folks about the ICC decision. Just I know you're appealing it, but what legislative attempts might be on the horizon?

We have Anne Pramaggiore here. I'll let her speak to that.

Thanks, Chris. Our view is we've got free pass to resolving this issue, which is essentially recovering the cost of making the investment that the legislature envisions us to make over the next few years. One is the appeal path, and I think you've all seen that we filed our appeal. We also asked for an expedited appeal, and that was -- we did not -- we were not successful on that. So we're on the appeal path. The second path is to try to deal with this in the commission itself. There's a current rate case in front of the commission that is -- will be resolved by the end of December, and there's some opportunity to deal with it in that case. And then finally, obviously, there's a legislative path. So we view all those paths as options right now. We are talking to all parties and having conversations. I don't think we foreclosed any path, but we'll see what looks like the most opportune path and the one where we can get it done as quickly as possible so we can get back on track with making these investments and creating jobs in the state.

And your next question is from Jonathan Arnold with Deutsche Bank.

First question. Chris, when you were talking about just looking out into next year and recovery, I think you mentioned the dividend being one of the options that you'd have to address, maybe your fundamental view is not playing out as you hoped. What would the others be?

We would continue to look at other capital spends. Stacie Frank and treasury are looking at some things in project, financing some of our renewables we have. Now, they're not as large or meaningful, but if it's just to buy more time as we see the market come back, there are other steps that we'll be looking at.

Okay. And so those would be -- you see you have incremental sort of levers on CapEx, potentially?

Yes.

We have to be very careful about the next step. So the next step is, is this a reliability cut, and are you going to pay for it in the long run? So you look at some of the upgrade projects around digital systems at the nuclear plants or other things like that, that are addressing each of the infrastructure, which -- you really have got to be careful, but we will look at them. And if it's moving in some amount of time, months or a year and we don't think it'll be impactful, we can look at that. But again, they're not the 2.3 billion size that we are able to just pull with the actions we are taking now.

Okay. And then secondly, if I may. Like last quarter's 10-Q disclosed some pretty substantial pension contributions that you expected to have in the '16-'17 time frame. How should we -- I mean, firstly, have those numbers changed much as you update for this quarter? And how should we think about those as they fit into this plan?

Sure. We've been working on that. Jack, do you want to talk a little bit about that?

Sure, Chris. So Jonathan, as you might expect, with the declining interest rates, the liability has grown. Importantly, under Doug Brown, who heads up our investments organization under Bill, we had put in place a liability matching strategy that reduced the impact on the overall obligation. That current unfunded status, if you look at the pension, is roughly $3.9 billion. That's relative to an end of year '11 of $2.2 billion. And I would say that, that growth is despite the fact that we've seen a very strong performance on both the equity, as well as the liability matched elements of our pension assets. As we look forward, as you may know, the President has put in place a -- or is looking to put in place a policy that allows us to adjust the pension liability and how we fund that. And that would have the impact of pulling forward certain of our expenses and reducing our expenses in out years. This strategy, we'll be updating at EEI, and we'll be able to walk you through after we've issued the Q3 10-Q, the specific details of the impact of that adjustment. But it does result in further funding in the initial years but moderates that funding and reduces it in '16 and '17.

Okay. And could I just ask one sort of a related topic, is equity something you would look at as a way to bridge either the trough in the power cycle or maybe this pension funding issue as it comes -- it will arise?

So we would always look. But at this point, I believe that our equity is -- the value isn't reflected in our equity right now. So it would be unlikely that, that would be a fix. If we don't see markets recovering, something's fundamentally shifted. Issuing equity to buy time only to have to make some other decision in the future just seems more destructive than we'd be willing to take at this point. But that said, it's not totally off the table. We'll look at where we're at when -- middle of the year and see what fits best based off of the financials that we're facing.

Your next question is from Steve Fleishman with Bank of America.

Just a question with regard to the $3 to $6 and thinking about the base, you've been communicating that range for a while but the base has continued to move around. Should we think about the base being this 9/30 price stack when you think about the $3 to $6 that you're looking for?

Yes. That is right. It's the -- around the 9/30 and it's in the out years, gaining that recovery where it still has stayed flat. Jack, you got any more on that?

No, I think that's right, Chris. We have talked about, at varying times, the upside that we see in heat rate recovery. At varying times, we've said it's actually priced into the market and aggressively hedged at above ratable to lock in that value. And at this point, as of 9/30, that $3 to $6 is what we see as the fundamental upside.

Okay, great. And then just on the retail margin and disclosures, it looks like you are expecting some kind of normalization, maybe by the 2015 forecast, is that correct in terms of margins? Or are you assuming like lower end?

No, I think we do. Ken, you want to talk about that?

Yes. Steve. we do expect margins to revert back to historical, where we would think of more rational levels in 2015 timeframe. You are correct.

And when we think about rational, is that the midpoint, the $2 to $4 for low end?

Yes, commercial industrial business, it would be in the midpoint area, the $2 to $4. Obviously, much larger for gross margin on the MATS market side.

Your next question comes from Paul Ridzon with KeyBanc.

What do you know as far as the schedule of auctioning of the Illinois load?

Do you have any update on that? Yes, we'll ask Anne.

Yes. I mean, I don't know if you're asking about municipal aggregation or the Illinois Power Agency. The Illinois Power Agency typically goes out in April. But with the load shift under municipal aggregation, I think there's a question right now as to whether they actually will go out in April. If the question is on municipal aggregation, we've seen about 50% of the residential load shift year-to-date. We've got about 60 more referenda to go next week. And if they all go, we'll see about 75% of the load move off of ComEd into the market by first quarter of next year.

And when -- how soon would you act on the dividend if -- when you do your 6-month look and things haven't improved, under that scenario, would you do something immediately?

I couldn't venture to say that. We've got to see what's going on in the market. We have had a lot of conversations with the board if we got to that point, but -- and I said we wouldn't surprise anybody. We'll have many more conversations between here and there, but couldn't commit to a timeframe. As I said, we believe the market is going to come back. We believe the market has to come back. And so we're more on the side "let's get the market back" than we are "here's the date we would plan on cutting a dividend."

And your next question is from Paul Patterson with Glenrock Associates.

Just on the credit quality. I mean, you want the investment grade, but again I think of you guys as being -- you're not exactly BBB-, right? I mean, how far down would you go, I guess? Is there any particular range we should think about here? Or...

Well we are at the HoldCo BBB-, BBB at the Genco. So we're there.

I'm talking about the Genco. Isn't that where the big issue is? Or is it at the HoldCo, as well?

We wouldn't allow ourselves at any registrant to go below. Due to the constraints on the other businesses, would be too cumbersome and too costly.

Okay. And then Kewaunee, they're shutting that down, which would sort of lead me to believe that it could have been gotten for a song. I know it's not in PJM. I know that there are obviously different characteristics with their plant. I'm just wondering sort of your thoughts about that. The opportunity I'm sure you guys probably would have seen -- anything in terms of -- give us any flavor for that?

Demand has done a lot to improve that plant. There are good people there. It's sad to see a nuke come off, but there isn't a market to cover -- it's a small unit, so it's all -- and costs are a little bit higher. It's tough to compete in the PPA area for that. So the economics just don't work. We're -- across the board, we continue to look at the valuations of all the nuclear assets. And smaller, single site assets are more challenged with these power prices that are not only damaged based off of the lower commodity price but also some of the issues that we're having around excess wind generation. So we'll continue to look at plants as they come up, but it just doesn't make it.

Okay. And is there anything we should think about with respect to anybody in your fleet? Is there -- are there any Kewaunees to put it directly?

No. No, there's no Kewaunees that -- we go through our asset valuations on an annual basis. But we are looking at things to try to improve the financial performance. Our Clinton station, which is a large single-unit site, it's a high quality, newer asset, is struggling with this MISO market in the wind generation. We're looking at going to annual refueling cycles to save on our fuel costs that will help its sustainability on the grid. So we're in the mode of continuing to figure out how to help these things survive this market downturn versus the outright sell or close-type thing at this point.

Okay. And then on the positive side Sandy and the Rachel, I think, are in guidance, is that correct? And I know -- I think you said it was about $100 million for Sandy? What was the impact of the Rachel? I'm sorry, if I missed it.

Is that...

The derecho

Yes. You got that, Jack or Ken?

The derecho was roughly $0.05 -- or sorry, $50 million, $0.03.

And your next question is from Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just if we can get into the retail conversation a little bit, I mean, Jack, you guys have been in this business for a long time. Is the pressure outside of Muni-Ag, are you seeing similar pressures on the C&I customer base kind of across the country? Or is this a more of Midwestern localized issue as you've seen some of the other big integrated utilities try and hedge their outlook this way?

Ken, do you want to cover that?

Yes. Dan, we've clearly seen pressure on both the Muni-Ag side and C&I space. C&I selling season is really Q4 and Q1, so we're now in the midst of what will be a 6-month run-on selling in C&I space because that's how the buyers -- this is the time here when buyers buy. So it remains to be seen whether the behavior persists. But clearly, through the summer, there have been -- there has been margin pressure in all segments of retail. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And then I guess, Chris, just I don't want to belabor the dividend question. But when you and the board stepped back and kind of looked at the dividend relative to the business mix and the earnings power, how do you guys think about your coverage or payout ratios between the utility and the generation businesses as you formulate kind of comfort with a dividend at a certain level?

So what we've done in the past, we have a more traditional payout strategy for the utilities, 65% to 70%. And that resonates well as we benchmark to other regulated entities. On the growth side for the competitive part of the integrated, we have tried to benchmark more of the yield and keep track with the sector and the yield. Now since we've got a little bit more damage with the gas and our concentration in NiHub, our yield is 5.9%, last time I looked at it, where the others are probably 1% lower, if not more. So we're outpacing the yield. Now we get this $0.70 back, it's a different conversation. And we're more sensitive to the upside. And that's what -- we just got to reaffirm with -- in our policy as we look at this, is that the right thing? We think we're hitting the stress low, and we think the recovery is there. But that would be part of the conversation, how do you benchmark the yield and the payout percentage on that other side of the business?

You're next question is from Ali Agha with SunTrust.

Chris or Jack, when you look at the margin profile you laid out for us for '15, I guess you've now added that to your disclosure and you factored in cost escalation, et cetera. Should we be thinking of '15 still as flat to down year for you guys? [Technical Difficulty]

I'm sorry, we're having some technical difficulty here. [Technical Difficulty]

So you were asking about the margins that we baked into the disclosure on '15?

Yes. And my question was when you look at cost escalations and the like, are we still looking at '15 relatively flat to even down for Exelon as a whole, given those margin trends you've given us?

Are you talking in... [Technical Difficulty]

On an EPS basis.

Yes, we are giving EPS for 2015. So we're only going to focus at the first of the year on '13. We don't go out there.

Yes, I understood. Understood. I was just looking directionally not really trying to pin you down on a number. A separate question, Chris. As you look at your portfolio today, and of course you have to sell those assets as part of the merger, but are all the current assets pretty much core for Exelon? Is asset sale or divestitures the source of capital that you may revisit given market conditions?

So there are some assets on the edge, they're not big assets. There's something in Las Vegas that's historical. There's a few small assets in California that we're looking at divesting. We continue to watch what we're doing in Alberta. But the meaningful assets are all core, and we think that they are undervalued at this point. I mean, you look at our nuclear assets and the implied valuation well under $1,000 of KW. I think anybody would buy it at that price right now. So I don't think we would look at asset divestitures in this devalued state besides those small ones, which won't be meaningful to cash flows. With that, we're going to wrap up before the music starts again. We apologize for any of the background noise or any of the issues. We actually have everybody spread across all the service territory attending to storm issues. So there's only a small portion of us back in Chicago here now. We'll be at EEI, and we look forward to being able to provide additional modeling information for the company as we address your questions and talk about more of the strategic focus going forward. So we hope all of you in New York, they get you back soon and everybody stay safe, and we'll see you in Scottsdale. Thank you.

This concludes today's conference call. You may now disconnect.