艾索倫電力 (EXC) 2013 Q3 法說會逐字稿

Good morning. My name is Tiara, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q3 2013 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)

Mr. Ganti, you may begin your conference.

Thank you operator, and good morning everyone. I welcome you to Exelon's Third Quarter 2013 Earnings Conference Call. Thank you for joining us today. We issued our earnings release this morning. In case you did not receive it, the release is available on Exelon's investor 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, and the actual results could differ from our forward-looking statements. Please refer to today's 8-K and Exelon's other filings for a discussion of the factors that may cause results to differ from Management's projections, forecast and expectations, and for a reconciliation of operating-to-GAAP earnings.

Leading the call today are Chris Crane, Exelon's President and CEO; Ken Cornew, Exelon's Chief Commercial Officer and President, CEO of Exelon Generation; and Jack Thayer, Exelon's Executive Vice President and Chief Financial Officer. They are joined by other members of Exelon's Management team, who will be available to answer your questions following the prepared remarks. We have scheduled 60 minutes for this call. I now turn the call over to Chris.

Thanks Ravi. Thanks everybody for taking the time to join us this morning.

Operationally we had another strong quarter, with great performance in both the utilities and the entire generation fleet. Financially the third quarter was strong, and results were higher than our guidance range. The third-quarter operating earnings were $0.78 per share. Jack's going to cover that in more detail in his remarks. Low commodity prices, low load growth, and tough retail margins continue to challenge our industry. While these challenges are mostly beyond our control, we are leveraging our core competence to control what we can and influence what we cannot. We're focused on operational excellence, regulatory advocacy, financial discipline, and investment that provides value to our shareholders.

As I said, operationally we had a good quarter, and we are having a very good year. Once again, our generation fleet performed at high levels. For the quarter the nuclear fleet ran at 94.8% capacity factor, and during the summer period had a 97.4% capacity factor. The fossil and the renewable fleet had a strong quarter as well. In particular the fossil hydro fleet performed at exceptional level, with a dispatch match rate of 99.1%. The utility performance remains very solid. All three utilities year to date improved on the customer satisfaction index year over year, and in some places we are reaching our highest numbers that we've seen in over a decade. No major storms did contribute to this favorable quarter for the utilities.

On the regulatory advocacy side, we continue to push on many fronts. The rate case at ComEd and BGE are on schedule, with decisions expected in December for both. On the RPM stake holder process, we continue to work with PJM and other stake holders on improving the capacity market rules. The stake holders are discussing reforms in the area of reducing speculation, demand response, and imports. PJM has committed, and continues to commit, to proposed tariff reforms to FERC in time to take effect before the next auction in May. We were very pleased with the federal court decision on the New Jersey LCAPP program. Combined with the decision in Maryland, these decisions uphold the principles of the competitive electric markets by finding state programs such as these subsidizing certain power generators are unconstitutional.

Our financial discipline is key to our success. With right-sizing the dividend early in the year, our balance sheet remains strong and provides us with the flexibility to make investments in challenging times. We continue to look at ways to strengthen it further -- for example, the work that has been done in completing the continental wind off-balance-sheet financing that was closed earlier this quarter. We believe project financing allows us to grow the business in a credit-supportive manner. Again, Jack's going to cover more of that in -- detail in his remarks. On the investment side, we continue to invest in our regulated and merchant businesses to drive value for the shareholders.

On the utilities side, we are growing rate base with investments in gas infrastructure, transmission and distribution systems, and the Smart Grid and Smart Meter installations. On the Smart Meters, the installation of the projects at all three utilities are under way in 2013. BGE has installed over 426,000 meters through the third quarter. PECO is at 465,000 meters, and the ComEd Smart Meter deployment began in September, and is off to a good start, installing nearly 10,000 meters in the first month. At Exelon Generation we have installed 153 megawatt's of solar capacity as part of the AVSR to date. There are two blocks that have been delayed due to issues on the construction. Jack's going to talk about the impacts on capital and revenue on that when we go through his comments.

For the full-year guidance, given our year-to-date performance, our expectations for the balance of the year, we are narrowing the full-range guidance from $2.35 to $2.65, to $2.40 to $2.60 per share.

Now I'll turn it over to Ken, who will discuss the hedge disclosure, and put some color on how we are incorporating the gas basis into our hedging.

Thanks Chris, and good morning everyone. As Chris mentioned, I'll cover changes in natural gas basis, and how we incorporate these risks while we hedge our portfolio, as well as our hedge disclosures.

If you turn to Slide 3, I'll turn to Exelon Generation's results this year and the outlook for the next two years. Challenges we have faced over the past year have continued over the third quarter, with natural gas modestly down across all years, power prices mixed across all regions and years, heat rates modestly increased in the mid-Atlantic and Midwest, very little volatility outside of ERCOT, and retail competition continues to be aggressive. These factors all combined to put further pressure on our ability to extract margin through our wholesale and retail businesses. To offset these pressures, we have mentioned $100-million reduction in 2013 O&M during the second quarter call.

As seen on Slide 3, for 2013 the total reduction of gross margin from last quarter is $50 million. While prices were lower, especially in ERCOT where summer peak prices came in lower than forecast, our hedge position and execution of $100 million in our power new business target provided an offset to the open gross margin decrease of $150 million. Unfortunately, the lack of volatility in other regions and our outlook for the remainder of the year has caused us to reduce our expectations for incremental margin from our commercial business. Our non-power business continues to rateably transition from our to-go bucket to our executed bucket. It's important to note that we expect this $50-million reduction in 2013 to be offset by cost reductions. Jack will be highlighting these a bit more as he discusses our full-year guidance.

In 2014 and 2015, our disclosure indicates a reduction of $50 million for each year in the total gross margin. In 2014 the open gross margin saw a decrease due to a significant peak spark spread drop in ERCOT, as well as a reduction in the expected output from our wind assets. This was offset in our mark to market of hedges by the execution of some of our power new business to go. In 2015, our gross margin was impacted by price decreases in nearly all regions on our open position.

As you have heard us say for the last few quarters, the retail space is extremely competitive and challenged. We have remained disciplined, and have not gone after volume for the sake of volume, and have maintained appropriate margin on our sales. We have not seen anything in the market to lead us to believe that we have turned the corner and are headed for growth in this business, and the guidance we gave previously on retail volumes and margins still stands. While we expect little to change, we will provide an update to our volumes at EEI. As we mentioned to you earlier, we will be providing you the details of our 2016 hedged position and gross margin estimates at EEI in a couple of weeks. If I had to make a statement directionally about what you'll see, I would say our gross margin estimates would largely be unchanged year over year, except for a value of our hedges, which is simply a reflection of the amount of hedging we've done for 2016 so far this year.

Going to Slide 4, as you know, the impacts of shale gas on the United States energy industry are immense. We have seen the prompt-month price of Henry Hub natural gas fall from its highs of $13 in 2008 down to $2 in 2012. A decline in natural gas prices has had a corresponding impact on power prices. Much of this gas comes from the Marcellus Shale formation, which largely lies within the footprint of the PJM power grid. A surge in natural gas production has caused a fundamental shift in the pricing structure of gas in the mid-Atlantic location, sometimes referred to as basis, from a premium priced area to a discount area. The discount is in relation to Henry Hub, the primary trading point of US natural gas.

The Henry Hub location has historically traded at a discount to the northeast region, due to its formally significant gas production in the Gulf of Mexico, and confluence of pipelines. The surge in gas production in the Marcellus has caused this relationship to reverse. With the rapid expansion of production within Marcellus, we have begun to see what was once approximately a $0.60 premium at M3 to Henry Hub in 2010 move to a discount of approximately $0.25. This change in the basis relationship was expected, and has been in steady decline over the last few years.

Over the next several years, we anticipate new pipelines to be built, and some pipelines to reverse, enabling the surplus to be moved to higher-priced areas. This will work in tandem with all other factors that will impact the market, such as expanding LNG exports, exports to Mexico, industrial expansion, and gas demand for power generation. A combination of these factors will stabilize mid-Atlantic basis, and support our fundamental view that natural gas will trade between $4 and $6 in MMBtu between 2017 and 2020.

Over the last several quarters, our hedging profile has tracked at or ahead of rateable in PJM east. This has limited the impact of the basis move on our portfolio. Although Chicago basis has also been weaker recently, this has a minimal impact on PJM power prices at [Nihook]. We believe the size of the basis discount seen in the east will not be seen in the Midwest. This view is primarily driven by local supply and demand, and pipeline capabilities for natural gas in the Midwest. We continue to stay behind rateable in our PJM Midwest power portfolio because of our view that heat rates will expand.

Now I'll turn it over to Jack to review the full financial information for the quarter.

Before we go to Jack, I need to correct one thing I said. I said the range was going to $2.40 to $2.50. It's $2.40 to $2.60, is the new range.

Thanks Chris. Good morning, everyone.

I'll review the third quarter financial results, our full-year guidance range, key events of the quarter, and our balance sheet and cash-flow outlook, starting on Slide 5. As Chris mentioned earlier, Exelon's results for the quarter exceeded our expectations. Operating earnings for the third quarter of this year were $0.78 per share, well above our Q3 guidance range of $0.60 to $0.70 per share. Compared to our guidance, favorability at both ExGen and our utilities drove us well above the range. While we expected to be at the upper end of the range provided, we continued to limit costs, resulting in lower-than-planned O&M across all our businesses. We are realizing merger synergies faster than forecast, and that is helping results.

Utilities accounted for just over half of the savings compared to guidance. As Ken alluded to earlier, the full-year 2013 RNF reduction shown in the hedge disclosures was offset by ExGen, with lower O&M and interest. The lower O&M was driven by reduced O&M costs related to outages of power, and lower labor and benefit costs. Across our operating companies, some of the reduced spending were one-time benefits, like fewer-than-expected large storms, and others may reverse in the fourth quarter. But in general, our focus on execution on cost management helped drive these results.

The $0.78 compares to our operating earnings of $0.77 per share during the third quarter of 2012. The quarter-over-quarter difference was largely driven by improved performance at our utilities, specifically at BGE and ComEd. I will go into greater detail on the quarter drivers in a few minutes. As Chris mentioned for the full year, we are narrowing our guidance range to $2.40 to $2.60 per share from our previous guidance of $2.35 to $2.65 per share. With our strong year-to-date performance at the utilities, we are bringing up the bottom of our range. When we look at the fourth quarter, we see some unfavorability in gross margin expectations from our Constellation business, as shown in the hedge disclosures and addressed by Ken during his remarks. As I mentioned earlier, we were able to offset those reductions with cost savings.

Additionally, since our second-quarter earnings call we had delays in two blocks at our Antelope Valley solar project, moving their in-service date and the related portion of our expected investment tax credit into the next year. Overall, we are confident we can deliver 2013 results comfortably within the revised full-year guidance range.

Please turn to Slide 6. Turning to Exelon generation on slide 6, ExGen's results were $0.05 per share lower quarter over quarter, primarily driven by lower R&F, due to lower realized energy prices. This was partially offset by higher capacity prices, favorable nuclear performance, lower income tax -- primarily due to AVSR investment tax credit benefits -- and lower O&M costs due to merger synergies.

Before I turn to the quarterly earnings for the utilities on Slide 7, let me provide a brief update on our load forecast. In general, we saw a slight dip in our load expectations for the full year, compared to the update I provided on last quarter's call. This decrease was largely driven by lower residential usage during the summer, and some uncertainty about the economy heading into the fourth quarter, driven by the recent government shutdown. Our overall load growth view is still very modest, and virtually flat for the full year 2013, when excluding the impact of RG Steel's bankruptcy for BGE. More detail on the utility load can be found in the appendix on Slide 19.

ComEd's earnings increased $0.05 per share compared to earnings in the prior period last year. This is primarily driven by the benefits of higher distribution revenue, due to the recovery of pension costs, additional investments that resulted in a growing rate base, and higher allowed ROE from a rise in treasury rates. These are partially offset by unfavorable weather compared to the third quarter of 2012, when northern Illinois experienced above-average heat.

PECO's earnings decreased $0.03 per share compared to the earnings in the prior period last year. This decrease is a result of one-time items that occurred last year, with favorable weather, and a benefit from the gas distribution tax repairs reductions not repeating this year. BGE's earnings increased $0.06 per share compared to the earnings in the prior period last year. The combination of lower storm costs without the derecho storm from July 2012, and improved electric and gas rates helped improve BGE's quarter-or-quarter earnings.

Third quarter saw further progress for the utilities and the regulatory and legislative arena. During this quarter, BGE filed its Strategic Infrastructure Development and Enhancement, or STRIDE, plan to accelerate the modernization of its natural gas distribution system. In addition, ComEd and BGE continue with their rate case proceedings that were filed earlier this year. The ComEd distribution formula rate filing requests an increase of $353 million, which reflects actual 2012 expenses and investments, and forecasted 2013 capital additions to our distribution network. We expect a decision by year end, with the new rates going into effect in January of 2014. Additional information on the ComEd rate filing can be found on Slide 20 in the appendix.

BGE's ongoing rate case with the Maryland PSC requests an increase of $86.2 million for electric and $24.4 million for gas, adjusted for the actual data submitted in August of this year. We expect a final order in mid-December, with new rates going into effect shortly thereafter. BGE rate case details are shown on Slide 21 of the presentation.

Slide 8 provides an update of our cash flow expectations for this year. We project cash from operations of $5.8 billion. This is up from last quarter by about $225 million. The primary driver of the increase was favorable working capital at ExGen, mainly driven by higher accounts payable related to the AVSR project delays. Our CapEx forecast is decreased by $70 million from last quarter, mainly due to AVSR construction delay I mentioned earlier, and some lower-than-projected spend at the utilities. That decrease was partially offset by additional wind and non-AVSR solar project spend. Our current five-year plan includes $16 billion in growth CapEx, with approximately $13.5 billion of that at the utilities, where we have the ability to earn a stable rate of return.

On the financing side, we had long-term debt issuances at both ComEd and PECO during the third quarter. In August ComEd issued $350 million of 30-year bonds, with an annual interest rate of 4.6%. In September PECO's bond issuance was for $550 million, including $300 million of three-year bonds with a 1.2% annual interest rate, and $250 million of 30-year bonds with a 4.8% annual interest rate. We do not anticipate any additional long-term bond issuances during the remainder of the year. Our expected financing cash flows are $150 million lower than what we provided in our second-quarter update, with the decrease largely driven by a reduced AVSR Department of Energy loan draw, given the construction delays I briefly referenced.

On Slide 9, in late September Exelon completed the largest ever wind finance transaction. Continental Wind a 667-megawatt portfolio of 13 projects located in six states and across five different wind regimes, issued $613 million of project finance bonds with a 6% coupon, maturing in February 2033. Net proceeds were dividends up to Exelon Generation. This financing is non-recourse to Exelon, and solely dependent on the cash flows of Continental. The transaction is consistent with our previously communicated strategy to use project financing as a means of strengthening ExGen and Exelon's credit metrics. As a reminder, the appendix includes several schedules that will help your modeling efforts.

Now I'll turn the call back to Chris for his concluding remarks before we open the call for Q&A.

Thanks, Jack.

There have been a few reports in the past month commenting on the impact of the lower gas and power prices on our earnings. I think these reports all assume we'll sit on our hands and not take any action, and the market participants will not rationalize their behavior. In fact, we continue to take a hard look at our assets and determine their economic viability. We will shut down facilities that we do not see a path to a long-term sustainable profitability. We built our record on reducing costs and improving productivity of our business, which is shown in the $550 million of synergies from our merger, exceeding our original estimate.

We are hedging our portfolio to reflect our fundamental view of the market, and that it will improve. We continue to look for opportunities to grow. We'll continue to advocate for public policies and market designs that properly compensate our fleet, victories in the court and the legislative and regulatory fronts that will support competitive pricing. We'll continue to optimize the use of capital structures, differing capital structures like the Continental Wind project financing. The current view of some of the analysts on Exelon's expected performance is not where we see it to be. We believe that the analysts have it very wrong, and we will act to change that.

With that, I'll open it up for questions.

(Operator Instructions)

Our first question comes from the line of Greg Gordon.

(technical difficulty) question guys, good morning.

Good morning, Greg.

You guys have been doing a good job on the cost side. Can you tell me, I think we have been assuming that total O&M and TOTI at Ex Gen, if you include CENG of around $5 billion, but given the head way you have made on costs this year, could you tell us what the right run rate is as we go into 2014?

Greg, as you mentioned, we have pulled a substantial amount of costs out, and we will update on our O&M at EEI. But I think it's safe to assume we are in the midst of our 5-year planning process, that we are targeting flat O&M across the business plan at ExGen.

Okay. Second question is -- and this goes to a statement you made earlier, and I think that you reiterated. There is a view that this negative gas basis that we are seeing in Pennsylvania is going to migrate west as this Rex pipeline partially flips around. Can you go into a little bit more detail why you feel like the expectation that negative basis permeates west is incorrect?

Greg, good morning, it's Joe Nigro. There's a couple of reasons for that. The first is -- I think you're right, we do expect the Rex pipeline to move gas out of the mid-Atlantic into the Midwest. Historically, we have seen the need for in-flows to the Midwest area of natural gas to meet the demand, and they've historically come out of Canada and the Gulf Coast. We would expect to see the displacement from the gas moving in from the mid-Atlantic, and displacing that gas that historically has come out of Canada and the Gulf.

I think the other important point to mention though, Greg, is the gas basis is one component of it. When we look at our fundamental forecasting and do all the puts and takes of what we expect from a generation change perspective over the next few years, you still only have gas on the margin a lot less than you do in the mid-Atlantic, so the impact on the gas basis change. When we see a $0.25 change in gas basis lower, for example, the impact on power prices is less than $0.25 a megawatt hour. When you convert that to power, the impact isn't nearly as great.

Great. The final question for Chris. I don't know how much of this you want to answer, but obviously also a lot has been written about the potential for further consolidation in PJM. You guys have done a remarkably good job, notwithstanding the bad overall macroeconomic environment and making the best of your merger with Constellation, would you try to -- do you think that in Exelon's future there is further consolidation, given how you have refined your expertise in managing costs and optimizing portfolios?

Greg, we have continually supported further consolidation in the industry, not only across PJM where it can be done, but in other RTOs, also. We have a small group that's constantly looking at value-accretive potentials, and will continue to look at that as we go forward.

Thank you, guys.

The next question comes from the line of Dan Eggers.

Hello, good morning guys. Chris I guess just following up at the end of your comments, you talked about the idea that looking into fleet and rationalizing assets if they don't make sense or you don't see a recovery as you guys expect. How do you frame out the timing of making those decisions relative to the longstanding internal review that market conditions are going to recover?

We think through 2014 and into the first part of 2015 we should see the up-lift in the market. If we have it wrong, then there are some assets that we'll have to look at for the long-term profitability. That would be around the time frame that I think it would be a very serious conversation taking place.

You're saying about 12 months is the time horizon when you think that would be -- you have the natural progression to see a recovery?

Yes.

Okay. You guys have talked previously about the freeing up some capital because of the dividend reduction earlier this year -- the idea of potentially buying more assets or getting more contracted assets. Can you share your thinking on A, what you are seeing in those markets; and B, with some downward pressure on the upper end of your open gross margins at Ex Gen, is that going to have a bearing on the timing of maybe deploying that capital?

Jack, do you want to go?

Sure. Dan, you have heard us speak about the reduction in the dividend. It gives us between $1 billion and $2 billion of balance-sheet space or growth capital that we could use and deploy. As we have looked at various markets and assets, interestingly, you are seeing in certain markets very attractive pricing from a ownership standpoint in ERCOT -- and obviously, we're a very major owner -- that isn't necessarily translating into perceived value into our merchant fleet.

In other markets, there have been recent transactions in New England, as well, at attractive values. As you know through our Boston Gen acquisition, we are a significant owner in that region, as well. There hasn't been a lot. I would say there has been a whole lot of speculation about PJM, there hasn't been any actual assets. We'll watch, as will others, as other companies may look to strategically realign to a more regulated footprint.

Okay, got it. Thank you, guys.

Next question comes from the line of Steven Fleishman.

Yes, hello. Good morning. First question for Ken. I think Ken you mentioned briefly you will be giving the 2016 margin information. I think you said 2016 will be kind of flattish with 2015. Is that on an open basis, open gross margin?

Steve, I would say if you look at our hedge disclosure and go down the lines between 2015 and 2016, we will relatively see flat 2015 to 2016, in open in several other areas. I would say we have a marked-to-market of hedges in 2015 that's $450 million. We have been hedging 2016, and we have positive marked-to-market value of those hedges, as well. I wanted to make sure you all were thinking about that. We'll go into much more detail at EEI in a couple weeks.

Okay, but is the flattish more open, or could it even be on a hedged margin?

The flattish is open in several areas. On the hedge there is a lower hedged marked-to-market of hedges in 2016 and 2015, but it is not drastic. We have positive marked-to-market value. Like I said, I would like to go through that in more detail at EEI.

Okay. Then Chris just your comment at the end of the call that your view that the analysts have it wrong with all the recent downgrades. When you say that, how much of that is the analysts have the kind of power market view wrong, versus if the power market stays just as it is, that you can continue to do more to make sure Exelon handles the conditions better? Could you just give a little color where you see people having it wrong?

Yes. I'll start and let Ken continue to fill in the blanks. We have talked about this upside in 2015 with the 22 gigawatts coming out. There has to be a market rationalization of that. There is a tightening of the stack. We have gone back and the team is in process of modeling asset by asset again in the stack to make sure we have it right. We'll have more details on that at EEI. Ken, do you want to fill in?

Greg, I think we're making -- I'm sorry, Steve. Steve, we are making a couple of comments there. Chris talked about what we see as up side. I sound like a broken record when I do this, but I'm going to do it again. In 2013 so far, we're seeing an 8.6 heat rate. We're seeing close to $32 power prices. When you look out the curve you see you have sub-$31 prices until 2016 with contango and gas, and you see heat rates that are a full point lower.

We scrub and continue to scrub our modeling of coal retirements. We look at all the announcements and the activity that's going on in the market, whether it's plants that some may think we're retiring and are now being converted to natural gas, whether it's some plants that a lot of people didn't think are retiring that are retiring.

We've actually, given the latest information we've seen on coal plants, we actually are a little more bullish in our analytics about our $2 to $4 upside. We quite frankly have been conservative and had some plants running on coal long-term that now have been announced they are either being converted to gas, which will take them up the stack and not running nearly as much, or actually retiring. We do think, when the spot market rationalizes itself in 2015, 2016, you are going to see a very different heat rate environment than what the forward market's projecting.

I think the other thing that's important to realize here is, as Chris said, we are going to be very disciplined and rational about our actions if this is the market, and we are not going to sit on the current market evaluations and prices and do nothing about it. I think that's what we are trying to say. We do think the market will improve. We do think we need to be compensated fairly for the assets and what we provide with our fleet, and we are going to work hard at it.

It's hard to get your head wrapped around an implied valuation for our nukes at $100 a kW.

Thanks, guys.

Our next question comes from the line of Julian Dumoulin-Smith.

Good morning, can you hear me?

Yes, we hear you fine, thanks.

Excellent. First, in light of the latest transaction, NRG Edison Mission, I would be curious to get your views in terms of what that did to the market, versus your $2 to $4 expectations, if you could?

Julian, I think I just commented on that at some level. Let me let Joe Nigro dive into that a little more for you.

Good morning, Julian. We take into account all the changes we see in the generation stack when we run our analytics or our fundamental forecasting. We've seen a number of changes over the quarter, with some units that we expected to remain in the generation stack actually retiring. Some units that we expected to be refueled no longer going to continue operations. We have seen some of the announcement of what specifically NRG plans to do with refueling some of the assets that they would be acquiring from EME.

When we take all that into account, as Ken mentioned a minute ago, we still see that $2 to $4 of upside in the market when you look at the changes coming to the generation stack, between the increased dispatch cost for the coal that remains, the increased costs for plants that are going to refuel. You are talking about PRB coal plants that currently dispatch at $25 a megawatt hour, and a refueled environment there closer to $40 a megawatt hour, so that has an up-tick to energy. Then we continue to see that 20-plus gigawatts of coal retirement that we expect in PJM alone. When you put it all together, as Ken said, we expect to see the $2 to $4 in upside.

Thus conversely, what do you think about the wind impact, perhaps, in subsequent years offsetting retirement?

Yes, we do see -- there's a couple of elements to that. We do see the impact of wind greater and greater, especially on some of the plants at the nodal level or the generation bus-bar-specific level, but we do factor that all into our modeling. The disclosures that we provide you represent the values of what we expect the plants to receive at the generation bus bar. We take that all into account.

Excellent. Then perhaps this is more of a high-level, as you think about your disclosures, the non-power margin executed versus to go. Just thinking about the to-go side of that. For 2013, you're talking about, I suppose, $400 million executed, $200 million in theory to go. Given where we are in the year, how do you think about achieving that to-go piece? Is that sort of in theory something you achieve more on a spot basis in sort of a transactional sense, or is that something you still need to sign contracts to get? I'm just trying to understand what you are saying?

Yes, there is a couple of elements to that. The non-power bucket includes our fuels business, both on the retail and wholesale side. It includes our services business on the retail side. That would be energy efficiency, demand response, our BGE home business, our solar business. Lastly, it includes the results of our proprietary trading book.

What I would say is as noted in the disclosure, the gross-up of our services businesses for expenses really inflates the amount that remains to go. The results of these businesses have been reflected on an EBIT basis in our earnings guidance. The gross-up of those businesses, the way it's reflected, is approximately $100 million. We are in line generally with the expectations that we remain with that non-power to go business. Again, it's across the three areas that I mentioned -- our services business, the seasonality to our fuels business, and then finally our proprietary trading results.

Great. Yes, go.

Julian, it is -- just to reiterate though, a large piece of that is run-rate business on our services and our natural gas sales that renew themselves on a monthly basis.

Great. A quick clarification, actually, on a prior question. When you were referring to Texas and New England, is it that you want to acquire more there, or that it's a potential sales opportunity? Sorry, if it wasn't clear.

We are looking at growing the portfolio where it makes sense and we see good returns. Conversely, if we think the market's right and it's a good time to harvest capital, we would also sell assets.

Got you.

Julian, some of the reference is similar to the Continental wind financing, there are opportunities that we can look at within certain parts of our fleet that could be considered non-core to look at structured finance opportunities as another means of extracting value. ERCOT, New England, and then our hydro assets would be areas where we might consider pursuing that activity, as well as incremental financing at the Continental holding company level.

So project finance has some of the thermal assets.

Correct.

Great. Thanks again.

Thank you.

Our next question comes from the line of Jonathan Arnold.

Hello, Jonathan.

I just want to revisit the last question that Julian had there. On Texas, I think you talked about sort of disconnect between asset values and some expectations in the market, something like that. Are you, can you comment on recent changes and expectations around market structure? Are you more inclined to be a buyer or a seller in that market?

We would like to be more of a buyer in the ERCOT market, where we see the market rules going. The most recent assets that have traded have been slightly above a value that we would put on them. We'll still participate. Nothing I've seen yet would say it's time to liquidate. We think there is up side to that market, so there's upside to those asset valuations for the ones we have. We'll continue to participate as things come to the market, but other entities have placed a slightly higher value on them than we can see getting out of them.

Thank you, Chris. Could I just -- on the wind question in the Midwest, I think this is Ken or Joe -- is there a way of giving us a sense. You see that forward curve, but obviously it's made up of expectations around hourly pricing. As you look out into 2014, 2015 and 2016, how much of an impact does incremental hours of potentially negative pricing have on the sort of aggregate calendar year strip that we look at? Any help you can give us on that?

Yes, we have seen negative prices at some of our nuclear plants, up to -- call it 15% of the hours. When we look at the modeling that we do, we see that there's constraints on the system and congestion. We take that into account when we're building the value of a disclosure up from the bottoms up, I would call it. We're not marking the generators to a NI Hub price, we are marking the generators to a Bus Bar price that has an expectation of what the congestion and marginal losses will look like at each of those plants for each of the years. Included in that is the expectation of what the wind development will be in that time period, and the impact that it has.

Is there -- are you saying that you'll have more wind but more infrastructure, and it's kind of a wash?

Yes, we continue to grow the wind development in the Midwest, and we've continued to see degradation in the basis value of some of our plants. That degradation is reflected in the build-up of our disclosure. We do expect as you get out past the period that we have disclosed. With some transmission changes you could see possible improvement, but that's not reflected in this current disclosure. The current disclosure reflects the degradation that we've seen. Is that 15% -- is that specific to history, and it's going to get worse from there? Or is that what you are expecting it to become?

Yes, let me bring it up and summarize, and then going to have Joe Dominguez talk about a project we've got in the short term to mitigate it. What we've taken in the model is the most conservative with the RPS standards that the state's being fully met. Then we have that with a lot of in-flow coming from MISO into the system, and the negative impacts of the worst case scenario of meeting the full RPS standard is in the model. That's -- we're not betting on something better to happen with that. But in the meantime, Joe, why don't you cover the project that you have in place there?

Sure. As Joe said, we are seeing 14% to 15% of off-peak hours at our facility that is most exposed to the problem. It is not a problem that we faced at every one of our nuclear units. In fact the problem really exists where you would imagine it would, geographically more located to where the wind is coming across the steam. We have been working -- I think this has been reported in the press and by some of you -- we have been working with PJM to ramp our nuclear assets down at night when we are seeing a negative pricing event, or when PJM is seeing a negative pricing event.

We have worked with PJM market monitor to formulate a program that allows us to start doing that on a pilot basis. We've experienced the first couple evolutions of that. It is difficult for us to capture all of these events, because the events are ultimately as unpredictable as the wind itself. But that's one method that we're working through.

The other thing we have accomplished is some rule changes in MISO where the intermittent resources now have to have a price bid into the system, which will allow for their dispatchability. We have seen some improvement in negative pricing events, really as a function of that rule change. I think as Joe indicated, this problem is very much a part of the transmission constraints that these plants face. As different plants get the benefit of our transmission expansion programs, and other transmission work that is occurring in Illinois, it wouldn't necessarily be the case that the problem is going to increase, for example, from 14% to something greater in the off-peak hours.

It is, however, an issue. It's an issue that has driven us to take positions on the production tax credit and other incentive programs that are distorting the market. That really explains the Company's position over the last couple of years. When Chris talked about the ongoing policy work, it's going to continue to evolve across all of these areas -- the subsidy work as well as the regulatory response to the subsidies -- so that we can try to clear up this problem as best we can.

Can you quantify the offsets?

Well, I don't think so yet. But I think it's fair to say that, for example, the plant that we experienced the 14% impact in 2012, that impact is significantly less. I'm going to call it 4% to 6% lower in 2013 as a result of some transmission expansion. We'll see how the market reacts to this. It is hard for me to differentiate between the dispatch intermittent resource rule that was accomplished in MISO and the transmission work. But I think we can marginally improve it. That said, it's a continuing problem.

Thank you for all the detail.

Next question comes from Hugh Wynne.

I wonder if you might comment on the demand assumptions that underpin your outlook for the power market recovery? In particular, what are your expectations for energy efficiency gains? Looking at page 19 of your slide deck, it seems like we are seeing declines in power demand across the regulated utility system. That's the first question. The second question is what are your assumptions for the shape of the load going forward? In particular, will there be a flattening of demand as demand response gets bid into the energy market in PJM?

Hugh, it's Joe, couple of things. From a demand perspective, we forecast about 0.8% load growth in our $2 to $4 of modeling across the PJM footprint. Historically, you've seen a conversion rate of -- call it 0.6% versus a 1% change in GDP. We're down to about 0.3% conversion, and it's on the back of what you're talking about -- energy efficiency and demand response. In addition to that, we've run a sensitivity that if we were flat over the five-year horizon with zero load growth, the impact to that $2 to $4 is about $1 a megawatt hour, just to give you some frame of reference of what the load-growth value represents.

I think to your question on the shape of the load flattening, I think it's safe to say we have seen that already, given the fact that we have seen a substantial amount of demand response, and we have seen the impact of energy efficiency. I think the element I would add, though, in our $2 to $4 of modeling, we don't include any upside associated with the rule changes in PJM, as it relates to demand response bidding into the energy market.

For frame of reference, we saw a couple of times this summer where the energy market went to $1,800 a megawatt hour in the back of demand response bidding, and I think just as importantly from the Exelon perspective in September during the heat wave, given some generation outages and transmission outages, they implemented about 6,000 megawatts of demand response that if you are bidding in the energy market, would have had a price associated with it that would have made this LMP look very different than it actually did. So yes it does flatten the load, but I think there is an ancillary benefit when you think about what price that demand response will be bid in at, and it could set the locational marginal price.

Great. Thanks very much.

Our next question comes from the line of Stephen Byrd.

Good morning. Most of my questions have been addressed. I wanted to just go back to the retail business a bit. Ken, I think you said that the margin outlook is unchanged. I wondered if you might be able to talk a little bit about competitive dynamics in the business, any trends you are seeing in terms of degree of competition, or changes in the business over time?

Stephen, it's Joe Nigro. Good morning. Our retail business is -- the market environment overall still remains extremely competitive. It's extremely competitive both on the commercial-industrial side and on the mass market side. What I would say to you is we've seen some stabilizing effect on our margins, meaning we have talked to you that our margins on the C&I side for power have been sub-$2. They remain so, but they have stabilized slightly below that. Our expectation in our plan as we look at next year is not to see much improvement in that area. We have seen consolidation with what went on with the Hess book with Direct Energy and the process of buying that, but the market is still highly competitive.

Okay, thank you. Just hitting on the heat rate outlook, you had spent quite a bit of time on the Midwest. As you look out at PJM east and west, what is your general view from where we stand now in terms of the heat rate outlook in the east and west?

I think Ken mentioned this earlier. When we still hold the view of $2 to $4 of upside and the $2 when we reflect it is on the eastern side of PJM, excuse me. It's driven -- really, when you look at the changing composition of the dispatch stack in the locational marginal price model, there are still hours that the eastern units benefit, from that change to the dispatch stack. We have seen the degradation in basis, as we talked about earlier, that market basis is reflected in our analytical modeling, and we're using those prices. With all of that, we do see the $2 of upside expected in the mid-Atlantic.

Great. Thank you very much.

Next question comes from the line of Brian Chin.

Hi, good morning.

Hello, Brian.

Just a point of clarification on the gross margin comment earlier. When you said that the gross margin generally is unchanged year over year in 2016, were you referring to only the open gross margin row? Or were you talking about the total gross margin, the $7.6 billion?

Brian, the open gross margin's unchanged. Most of our disclosure lines, like power new business, non-power margins, those elements are largely going to be unchanged. We are hedging, so we do have positive value in the marked-to-market of hedges. We will disclose exactly what that is in a couple of weeks. I was referring to a similar 2015 to 2016 outlook, except for that we have had less hedging, so somewhat less marked-to-market of hedge value.

Okay, great. Just as a reminder, the open gross margin includes capacity revenues, so the drop in 2016 capacity revenues is obviously being offset by something else in our open gross margin comment?

That's correct.

Great. Then my second follow-up question. We have seen other competitors out there, where they have used a YieldCo structure to tap a lower cost of equity for consolidation purposes. Can you just comment a little bit on -- to what extent does that present either challenges or opportunities for you, and how you think consolidation can progress so far as Exelon is concerned?

Brian, this is Jack. Where you have seen the YieldCo-- particularly at NRG -- have success, they really have a shareholder base that values and owns those shares on the basis of exposure to power markets, and on an EBITDA-multiple basis. They had a modest dividend, but they had an opportunity to carve off assets into a yield-oriented vehicle to optimize that.

I think people own us for both our upside to power markets, and also our dividend, and certainly our renewables assets and the contracted nature of them as it factors into our ability to pay a dividend and drive value, and reduce volatility in the earnings profile of the Company, we think create value. That said, we do look at many structures, and we certainly have assets that align to those types of structures. To the extent that there are -- that the price of capital for those structures and the need to acquire assets drives the markets higher, then the implied value of our renewables fleet should improve along with that.

Does the renewables fleet that you own now more merit a closer look towards a YieldCo structure, so that way you can compete on a similar cost of equity footing?

I think it has us look at more project financing for the credit quality that it gives us, and then bringing that cash back in for investment. The reality is, Brian, as you know, we can tap many markets to secure capital to grow our business. If you think about who the investors are in those yield-oriented names, whether they are pension funds or insurance companies or other elements, we are tapping similar capital, as Chris mentioned, through the project financing side.

We could, through other means, secure capital as well from those entities at a lower cost of capital. There are opportunities in a non-public vehicle to form relationships with entities to benefit from that lower cost of capital. Rest assured, we are looking at any and all ways to optimize the cost of capital for our Company as we look to deploy capital for growth. The implied yield or cost of capital on certain of those YieldCos is not lost on us.

Thank you very much, and see you at EEI.

I think we have time for one more call.

Our final question comes from the line of Shahriar Pourreza.

Good morning, thanks for taking the call. Most of my questions were answered. Chris, in your prepared remarks you mentioned that your cash flow outlook puts you in a position to make potential acquisitions in the space. Does your cash flow outlook also assume a scenario where EDF may put the new clear assets to you as early as 2016, in what could potentially be a pretty challenging core spread environment? I have a follow-up.

We do stress the balance sheet for any potential commitments that have to be made. If you look in the disclosure, we have the like-kind exchange issue in the out years, that -- where we feel we are going to prevail on, but there was a probability shift, and we had to put that into the disclosure. We stressed the balance sheet to make that commitment before we agreed to the EDF potential put, we made sure that that was stressed. We are very comfortable where we are at right now with the balance sheet.

Remember, there's -- as part of that contract -- there's a baseball arbitrage-type evaluation approach. To the extent we're in a challenged core spread market, that should slow up in the implied value of those assets, thereby reducing the put value.

One more question is under an assumption that the power price for heat rate recovery doesn't materialize, and you find yourself in a scenario where you are rationalizing your fleet, a couple of the assets in those put options could also face cash-flow challenges. I'm curious on how the change in outlook could impact that transaction. Do you have a clause where you can back out of the transaction, or is it essentially the flexibility is going to come where the economic value of the assets are?

Yes, that's where the flexibility comes in this. If they're negative NPV, the negative cash flow would be in the valuation, so they're really not worth anything in a baseball arbitration. We don't feel stressed over the deal. We think the up side we're getting from driving the synergies, the cost savings, out of it is the real focus of this.

Terrific, thanks so much.

Thank you operator, that ends the call.

Thank you ladies and gentlemen. That does conclude today's conference call. You may now disconnect.