艾索倫電力 (EXC) 2011 Q3 法說會逐字稿

Good morning and welcome to Constellation Energy Group's third-quarter 2011 earnings conference call. At this time, all participants are in a listen-only mode.

(Operator Instructions)

Today's conference is being recorded; if you have any objections, you may disconnect at this time. I will now turn the meeting over to the Director of Investor Relations for Constellation, Miss Sandra Brummit. Sandra, you may begin.

Thank you. Welcome to Constellation Energy's third-quarter earnings call. We appreciate you being with us this morning. With me here in Baltimore today are Mayo Shattuck, Chairman, President and Chief Executive Officer, and Jack Thayer, Senior Vice President and Chief Financial Officer. Mayo and Jack will provide you their perspectives on our performance for the quarter as well as our expectations for the future. Following their remarks, we'll take your questions.

Please turn your attention to Slide 2, a reminder that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties. For a complete discussion of these risks, we encourage you to read our documents on file with the SEC. Our presentation is being webcast and the slides are available on our website, www.Constellation.com. On Slide 3, you will notice we will use non-GAAP financial measures in this presentation to help you understand our operating performance. We have attached an appendix to the charts on the website reconciling non-GAAP measures to GAAP measures.

Turning to Slide 4 -- we will discuss our pending merger with Exelon during this presentation. In connection with the merger, we provided to our shareholders a joint proxy statement, prospectus and other relevant documents in connection with the proposed merger of Exelon and Constellation Energy. We urge investors to read the joint proxy statement, prospectus, and any other relevant documents which contain important information about Exelon, Constellation Energy and the proposed merger. With that, I would like to turn the time over to Mayo.

Thank you, Sandra. Good morning, everyone, and thank you for your participation today. This morning, we reported third-quarter adjusted earnings of $0.68 per share, which includes a mark-to-market timing loss of $0.27 per share and Hurricane Irene storm restoration costs of $0.17 per share. Excluding these mark-to-market timing losses and restoration costs, our adjusted earnings would have been $1.12 per share.

Including 1-time items, Constellation reported third-quarter GAAP earnings of $0.36 per share. Excluding Hurricane Irene restoration expense and mark-to-market timing, we are reaffirming our 2011 guidance of $3.05 to $3.35 per share. At this point, we expect to come in at the low end of that range. Jack will discuss our third quarter results and earnings outlook in more detail later in the presentation.

Our new energy segment continues to execute on its integrated multi-product energy supply and management strategy, bringing innovation and more choices to its customers. We have continued to perform above plan in our wholesale load serving business, with win rates higher than expected. In September, we announced a solar panel leasing program that we are offering to residential customers in 6 states. We also launched the next generation of our online energy management application for commercial users, VirtuWatt 3.0, which is also available as an iPhone and iPad app. Currently used by approximately 2,700 of our customer accounts, the application enables Constellation customers to better manage their electricity use and maximize the benefits of load response programs through real time metering, pricing, bidding, and curtailment capabilities.

In addition, the integrations of our recently purchased residential business, MXenergy, and StarTex, are progressing as planned. At the same time, record-breaking heat in Texas presented a challenge to the new energy segment for the quarter, as we will discuss in more detail in a moment. Within our generation segment, our Texas plants performed well through the extreme stretch of heat and our New England assets again outperformed for the quarter, as net generation from the plants exceeded our expected output.

During the quarter, our regulated utility, BGE, faced Hurricane Irene and some of the most damaging conditions we've seen during the utility's 200-year history. While our employees performed extremely well in safely restoring 750,000 BGE customers who lost power, the massive storm was undoubtedly a major challenge for our business and our customers.

Turning to Slide 6, I'll discuss in more detail the storm's impacts and our response. Hurricane Irene hit BGE in central Maryland particularly hard, resulting in more than 60% of BGE's 1.2 million electric customers losing power. Leveraging lessons learned during prior severe impact storms, BGE began pre-mobilization efforts and initiated requests for mutual assistance early, which allowed us to ultimately secure nearly 2600 personnel from 20 states. We also executed on BGE's advance pre-storm communication and outreach plan to prepare customers for the possibility of extended outages.

The restoration efforts were complicated by the widespread nature of the damage, with more than 50% of the outages resulting from downed trees and limbs. Despite these difficult conditions about 6,700 people, primarily Company employees, worked tirelessly to restore power safely to about 80% of the affected customers within 2 days, 95% of BGE's customers within 5 days, and the remainder within 7 days after Irene passed through our system. On average, BGE's customers were restored 20% faster than in Hurricane Isabelle in 2003. We understand the frustration of customers impacted by the storm and are discussing ways to continue to improve operations and enhance communications in order to get customers back online more efficiently.

In the aftermath of Hurricane Irene, we identified successes during the restoration effort, as well as opportunities for improvement. BGE will continue to participate actively in hearings and schedule meetings in the community to obtain feedback that will enhance coordination and communication with local jurisdictions. We will leverage this recent experience to be more responsive to our customers and lessen the impact of future storms. Jack will provide details on the financial impact of the restoration efforts later in the call.

Turning to Slide 7 for a discussion on weather events this August in Texas. As most of you know, Texas experienced record-setting weather this past summer. The hot weather was intense and sustained across the state. In Dallas and Houston, daily highs remained above 100 every day in August, except 3 in Dallas and 1 in Houston. The extreme heat led to unprecedented demand in August, that was much higher than forecast the prior month and previous record highs. As you can see in the chart in the left, ERCOT daily peak load in August consistently came in above the previously set record in 2010 and our forecast for 2011 peak load.

On August 3, peak demand in ERCOT reached an all-time record of 68,379 megawatts, almost 4% higher than the record set last year. While ERCOT in June forecasted that the ISO's reserve margin would be about 17.4% for the summer of 2011, this peak demand resulted in reserve margin of just 4%. The prolonged heat wave, compounded by fossil generator outages and a lack of wind plan availability throughout the ERCOT region led to price spikes well above the range of prices seen in previous years. As depicted on the chart on the right, realtime prices in the Houston zone were above $1500 per megawatt hour 71 times in July and August of this year, versus only 2 times for the same period last summer. And prices reached their cap of $3000 per megawatt hour 53 times in July and August of this year.

Given this backdrop, August was a challenging month for load-serving entities in Texas and as a large market participant, Constellation had to manage the extreme weather and the cost of managing our positions under these circumstances. For perspective, we serve an estimated 8% of the people out in ERCOT. Based on forecasted demand, we typically hedge our fixed price obligation with our owned or contracted generation and an assortment of other market hedges to cover price volatility and load variability. As demand came in well above our forecast throughout the month of August, we had to purchase incremental power in the real time market at peak prices. The events after-tax impact to third-quarter earnings was a reduction of approximately $0.16 per share.

Continuing to Slide 8, I'll provide more detail on what we can take away from this summer's events. The ERCOT market structure highlights the importance of matching fiscal generation to load. As it's designed, ERCOT without a capacity market, and with such a steep generation supply stack at the high end of the demand curve, allows prices to rise significantly, up to a cap of $3,000 per megawatt hour, as we saw in both February and August. To the extent that you have increased volatility or opportunity for volatility in the market, the benefits of owning generation become even more clear. Given Exelon's approximate 3500-megawatts of gas fire capacity in ERCOT, the prospect of a better matching our Texas load business with the combined company's generation portfolios validates a key strategic benefit of the merger. Of particular value when managing peaking loads will be Exelon's high heat rate load following generation assets.

To the extent that we need to go to the market to procure additional hedge coverage in the form of swaps, shape products or options, we price these costs into the products that we sell. By actuarially pricing any remaining risk, we can assure a return commensurate with the risk of the obligation over a planning period. It is fair to say that power marketing firms have perhaps underpriced their actuarial exposure in a low gas price, low power price, low volatility environment. While we did not see meaningful margin or risk premium impact from February's ice storms, we do expect to see margin uplift from this summer's event as risk is appropriately priced back into the system.

Lastly, Constellation's market diversity will continue to be a benefit, as we manage exposure to regionally specific risks, such as weather and commodity price events. While the impact from the Texas weather event was disappointing, our portfolio performance in other regions confirms our strategy of broad geographic reach.

Let's now turn to a key area of focus for the year, progressing with our merger with Exelon. Turning to Slide 9, during the quarter, we continued to make considerable advances through the approval and integration processes. The SEC completed its review of the merger proxy, which has been mailed to our shareholders in advance of the November 17 shareholder vote. Elsewhere on the regulatory front, we have received merger clearance from the Public Utility Commission of Texas and the Massachusetts Department of Public Utilities. We expect to hear from the New York State Public Service Commission this quarter, and in Maryland, the intervener's' testimonies were filed with the Maryland PSC in mid-September. We carefully reviewed the testimonies and proposals and filed additional testimony in October.

Today's, status conference will provide additional insight into the process. We've already reached a settlement with the PGM market monitor on market power issues. We look forward to continuing the dialogue through formal live hearings, which will begin next week. Under the schedule that the Maryland PSC has established, we expect an order-- still expect an order by January 5. On the federal level, we're awaiting the completion of review by the Federal Energy Regulatory Commission, the Department of Justice, and the Nuclear Regulatory Commission. We expect FERC approval this quarter and DOJ and NRC approvals by January.

Internally, we moved into the organization design phase of our integration planning. As many of you already know, the senior leadership team of the combined company was named in September and we expect future leadership announcements as we get closer to the merger close. In summary, the challenges experienced this quarter at BGE and in Texas further highlight the rationale for our merger, which will allow us to share best practices across utilities and match Exelon's generation fleet with Constellation's leading customer facing retail and wholesale platform, which will benefit customers, shareholders, and all stake holders.

With that, let me turn the presentation over to Jack for the financial review.

Thank you, Mayo. As Mayo mentioned, adjusted earnings for the third quarter of 2011 were $0.68 per share. As you may recall, our adjusted earnings include mark-to-market timing gains and losses that serve as hedges of customer and generation positions. This past quarter, we recorded a mark-to-market timing loss of approximately $0.27 per share. These mark-to-market results will fluctuate on a quarterly basis, as underlying commodity prices change. In addition, our adjusted earnings include Hurricane Irene restoration costs of $0.17 per share. Excluding these mark-to-market timing losses and Hurricane Irene storm restoration expenses, our adjusted earnings would have been $1.12 per share.

Looking at our results by segment, BGE reported adjusted earnings of $0.00 per share, down from $0.14 per share in the third quarter of 2010. This year-over-year variance is primarily due to Hurricane Irene restoration costs accounted for as O&M. In total, BGE estimates it spent approximately $90 million to restore power to its customers. Of this total cost, approximately $55 million, or $0.17 per share is accounted for as O&M, with the remainder as capital. Somewhat offsetting the Hurricane Irene costs this quarter is higher distribution revenue, which was approved in the Maryland PSC's 2010 rate case order. Our generation segment reported adjusted earnings of $0.29 per share for the third quarter of 2011, up from $0.27 per share in the third quarter of 2010. The increase is primarily the result of the earnings contribution from our New England assets, partially offset by lower power prices, and increased outage days at CENG.

Our new energy segment reported adjusted earnings of $0.23 per share for the third quarter of 2011 as compared to an adjusted loss of $0.07 per share for the third quarter of 2010. This year-over-year variance is due partially to the $0.20 per share loss experienced in third quarter of 2010 resulting from contract novations related to our legacy UK coal and freight business. Also contributing to the variance are incremental third quarter 2011 contributions of $0.36 per share from wholesale load serving and structure products and a $0.07 per share gain from the divestiture of the majority of our share in Constellation Energy Partners. These gains were partially offset by the $0.16 per share loss resulting from this summer's extreme weather in Texas and a $0.12 per share decline in our retail business, $0.07 per share of which is dilution from our MXenergy and StarTex acquisitions.

Turning to Slide 11, and a discussion of our earnings guidance. As mentioned earlier, excluding Hurricane Irene restoration expense and mark-to-market timing, we are reaffirming our 2011 guidance range of $3.05 to $3.35 per share. Given the extreme heat in Texas this summer and its impact on our load serving business, we expect to come in at the low end of this range. At BGE, excluding the Irene restoration expense, we continue to expect to earn between $0.60 and $0.80 per share in 2011. Our generation earnings guidance range for 2011 remains $0.75 to $0.95 per share. While negatively impacted by the summer's extreme heat in Texas, we continue to expect the new energy segment to earn between $0.90 and $1.10 per share in 2011. As an affirmation of our diversification strategy, strong performance by portfolio management in other regions and by other parts of the business, including wholesale load and our upstream operations have provided an offset to the challenges we experienced in Texas.

With that, I would like to turn the call over to the operator for questions. Operator?

Thank you. (Operator Instructions)

Ameet Thakkar, Bank of America Merrill Lynch.

Good morning. Mayo, real quickly, we've seen a lot of testimony and filings at the Maryland Public Service Commission in support of the merger. But could you just kind of quickly run through how you see what the main issues are that you think need to be addressed in Maryland and what the -- what is it the MPSC and at the governor's office -- where do you think that they stand and what are the key issues that you see needing to be addressed over the next couple of months?

Sure. I think as we've discussed at the last call, maybe 2 calls, we spent a considerable amount of time in advance of the merger trying to assess what we thought the parties would be most interested in, such that the merger would be perceived in Maryland as beneficial to the BG&E customer, as well as other stake holders in the state. So, our conclusion from all of that was that we needed to have a meaningful rate credit. We know the state in particular is very interested in the renewable area. And thirdly, I guess I would place jobs as being the topic de jour. And in particular the impact of locating what we perceive to be the growth businesses of the Company here in Baltimore. And really based off of our front-end marketing operations that have been built here over the last 10 years or so and which have more than a thousand people working in it. When we put the, the package together, we felt that we were being very responsive to these and a few other lesser considerations.

I think in our discussions, given the aggregate value of this package, it is substantial, it's clearly way in advance of what was agreed to in the First Energy and Allegheny mergers, which we could at least use as a proxy to help develop some of our strategies on this front. But I think we've been very pleased by the receptively to the original package in these areas. Everyone has different views on it, as you can imagine. I do think that, you know, probably the most substantial ask in the equation that will be debated over the course of the next couple weeks has to do with the renewable commitment within the state and I suspect there will be plenty of debate about that. In general, I think we've been very pleased by the response, at the level of support that's been sent in to the PSC in advance of the hearings. I think we're going to have a healthy -- I know it will feel like a noisy debate for a few weeks, but I think it will be a healthy one and we're very optimistic about how the proceedings will go.

Okay, Mayo. Certainly appreciate the comments on the renewable, but just to clarify, do you guys view the Maryland Public Service Commission's RFP for additional gas generation as a kind of a separate and distinct process from the merger approval?

Well, I think that is actually a tough question. I guess the answer is, in theory, yes. I think they are separate issues. I wouldn't be surprised to see in the course of the hearings attempts to integrate them. As you may know, there has been an interest on the part of the state to actually change the specifications of the RFP to include things other than gas. So there's, I would say, a little bit of a wrinkle in terms of the input from constituents in Maryland as to where that's headed. And I, I believe that the commission has signaled, at least from a timing standpoint, that this is an issue to be dealt with after the conclusion of our merger hearings.

We may hear a little bit about it in that context, but, as you know, our position as a Company and Exelon's, too, has been to be a strong advocate for competitive markets. And when we do get into that RFP process, I think you're going to hear a lot of different views as to the economic impact of approaching new generation in this way and I can see the commission coming to any number of different conclusions about this, so it's very hard to speculate. When they see what the cost is submitted of new generation, we may find that's an unacceptable option from their standpoint or we may find that they open it up again to consider a broader set of options within the RFP beyond just what is now there, which is gas plants.

Thanks, Mayo.

Jon Cohen, ISI Group.

Just had a question on new energy. It seems like by affirming guidance for 2011 at $3.05 to $3.35, you're sort of implicitly reaffirming your new energy guidance of $0.90 to $1.10. If we assume that the $0.17 from the hurricanes is coming out of BG&E. When we look at what your adjusted EPS is for the 9 months ending September, it's $0.41. So, how do we get another $0.50 in the fourth quarter? And maybe if you could just take us through some of the puts and takes. I know in the first quarter, you had $0.14 for the ice storms in Texas. You had another $0.16 this quarter, and you have $0.07 of dilution, so what are the offsets to those negatives?

Sure, Jon. This is Jack. I think actually we're explicitly affirming the range that you suggested of $0.90 to $1.10. With respect to that business, as you mentioned, we did have the event of the ice storm in Texas, which actually, as you think about our business being somewhat unique with the segmentation of generation separate from the new energy business, a good portion of that impact in Texas during the ice storm in February was actually showed in the generation segment. And that's been offset this year by better-than-expected performance from our Boston generating acquisition and -- as well as, our plants have performed extremely well during the summer in Texas that we purchased as part of the Navasota transaction.

On the new energy side, obviously the summer events in Texas were felt acutely in the portfolio management element of that business. As you mentioned, we do have the impact in retail, primarily driven by dilution associated with, as well as integration expenses for, MXenergy and StarTex with the contract amortization as well as the one-time costs of integrating our existing residential business with StarTex and MX. Then we have seen some margin degradation in the retail business, as market participants have moved away from the wholesale load serving business and focused on retail. Actually, we've seen margins expand in the wholesale segment as competition's diminished, just as we've seen margins compress in the retail business, as competition's increased.

And what I say there, is that just speaks to the diversity of the marketing channels we have at our disposal and the importance of the value of the breadth of the business, to the extent that we see competition increase in one area, historically we've been able to direct our business in other areas. And, at times in the 2008 and '09 period, that competition was acute within the wholesale segment and we were making very attractive margins in the retail segment. As market participants struggle to price and manage attrition, as prices have declined, we've seen market participants exit that space and, and focus on the retail space and obviously as they have zigged, we've zagged. With respect to your comments on how we have confidence in the remainder of the year, I think that's actually the beauty of this business, is you are constantly building a backlog that you measure and deliver on a quarterly basis and we have a high degree of visibility on delivering the $0.90 to $1.10 full- year result.

Okay, thanks, Jack.

(Operator Instructions) Your next question comes from Jay Dobson, Wunderlich Securities.

Mayo, Jack, how are you?

Good morning, Jay.

Hey, Jack, could I just finish up on that last question, because I'm still sort of not there. I hear you on the, I guess to a certain degree, your visibility into the business. But, again, in the quarter here, even forgetting about February, your press release indicates $0.16 negative impact from Texas and then sort of $0.12 from, as I interpret it, lower margins. So, that was unexpected, yet you're still, guiding to the $0.90 to $1.10 for new energy. Help me with what happened in the quarter that gave you the offsets to that $0.28, ostensibly.

Sure. Jay, let me maybe first off clarify the $0.12. I wouldn't relate the $0.12 in retail to margins. I think as we called out in the third quarter, $0.07 of that $0.12 is related to integration expense, as well as contract amortization from purchase accounting associated with StarTex and MX. As you know in purchase accounting, as those customer contracts roll off, that expense is felt most acutely in the front 4 to 6 quarters. So, that's really what's driving that. I would remark on the margin degradation, the remaining $0.05 is really a year-over-year experience. I think, fair to say, that in 2010, we were still benefiting from the phenomenon that I mentioned earlier, whereby there had been reduced competition in the retail space and we had very attractive customer margins. This is just the very programmatic roll-off of those higher margins, as well as the renewal of customers at lower margins in a low volatility, low price environment.

With respect to what are the offsets to the $0.16, as well as the retail $0.12 -- as I mentioned, we have seen, and on a year-over-year basis just in the third quarter alone, we're seeing significant benefit from the contributions of our wholesale load serving structure products business. That in and of itself is a $0.36 year-over-year positive in the business. Obviously we had the, the divestiture of our CEP assets. That's the upstream business. As you know, we've continued to make investments and we'll continue to develop and harvest those investments in the gas space, as we're investing in a non-operating position with operators to both procure natural gas for our gas-fire generation, as well as, we're developing distillates and oil that are helping fund some of the development of our properties.

Then finally, if you look at the portfolio management -- and we alluded to this in the presentation -- if you looked at the portfolio management contributions in regions other than Texas. That has been and continues to be a very positive contributor, offsetting in part the experience in Texas. Again, I think that just speaks to the importance geographically of being diverse and not overly weighted towards one region, as well as -- obviously as I mentioned before, the importance of the diversity of marketing channels with which to focus on, to the extent that competition increases in one area, you can divert resources from that area and apply it to less competitive parts.

That's helpful, Jack. So, for clarity, the $0.07 gain on CEP, you would include that ongoing and would be part of the $0.90 to $1.10?

That's correct.

Okay, got you. And then the $0.36 structured products and sort of wholesale load serving seems like a big number. Would you characterize as having increased risk in order to get to that number? Or, is this sort of regular way and just seeing opportunities?

Well, one I would say this is not -- the $0.36 wasn't originated in this quarter. It's the culmination of many years of origination efforts, as well -- whether it's winning load auctions or other structure products efforts. So on a year-over-year basis, that's just the nature of the backlog as it's realized and delivered into earnings. With respect to risk, I would say actually we are benefiting from others inability to manage a price risk that our strategists and portfolio management capability are expert at delivering against a broad array of risks that we manage. We price actuarially and deliver to the bottom line. I would say quite the opposite. This is really -- our structure products are really, in some parts, just leveraging our core experience within the wholesale load serving markets to deliver bottom line results and contributions to our shareholders.

That's great. And then last question, on Texas, I hear you on the $0.16 loss in retail. Can we look at the other side of the ledger and sort of say what was the benefit you guys realized in Texas specifically? There's legacy Navasota assets from this extreme heat, if we were to look into sort of a regional basis net number of the extreme weather.

Maybe said differently, Jay, as we think about -- what has us excited about the Exelon merger is the ability to leverage physical generation to manage our load positions in the state. And in terms of their contribution, no doubt the excellent performance of the 2 Navasota assets that we procured were very valuable in helping the $0.16 not be a bigger number.

I think importantly, prospectively, as we're thinking about how we'll manage our risk in Texas, because of the extreme volatility in that market where you can see within a span of hours prices clear from anywhere from $3,000 to $50 to $100 a megawatt hour, the ability to manage that extreme superpeak risk is best done with physical assets. As we look at the Exelon high heat rate assets, not only are they earning important ancillary revenues, but more importantly to the extent you keep them open, and I think it would be prospectively our plan to do so, as Exelon has historically, keep those open to manage in a physical manner that superpeak exposure. What that allows us to do is to better manage the diversity of outcomes that we see and reduce the risk embedded within that ERCOT market, which is very much one of superpeak high price risk exposure during extreme volatility periods.

Got you. No, no, no, absolutely agree with where you're going on the merger. But you're not suggesting the $0.16 includes any netting of the generation benefit from the operation of the Navasota assets, are you?

So the -- as we think about how we manage, and we have obviously the generation segment and then we have the new energy segment. The construct by which those works is our generation is effectively sold at mids to our new energy business, who then uses it in its portfolio management experts to manage the exposures that we have through our wholesale and retail load serving business. The strong performance of those assets during what was an extreme heat period, obviously was an important risk management tool for our portfolio managers in managing and navigating the risks in Texas. So there's -- I can't say that there's netting, but that said, those assets were very much part of our risk management strategy for ERCOT in the third quarter.

Okay, great. Thanks very much.

Paul Fremont, Jefferies & Company.

Thank you very much. I guess the starting point would be your guidance for this year is $3.05 to $3.35, excludes Hurricane Irene restoration costs, which I assume are $0.17 on the year?

Yes.

And then the mark-to-market loss in the third quarter was $0.27. What is that year-to-date?

On a year to date basis, Paul, that's $0.29. So, it was $0.13 loss in the first quarter, $0.11 positive in the second quarter, and then $0.27 loss this quarter.

Okay. So, in terms of the previous quarters then, just on the mark-to-market, that's almost a $0.30 adjustment to your range, assuming -- we don't know the fourth quarter obviously.

Paul, I think maybe it's important to take a step back and understand what that mark-to-market timing element is. As you know, we employ hedge accounting and we also use financial instruments that hedge accrual exposures in our load serving business. To the extent that whether it's coal prices move, gas prices move, power prices move, any number of constituent pieces of how power gets priced move, depending on whether we're using financial hedges or financial instruments to hedge physical obligations, that can obviously create a positive or a negative.

You also have, to the extent that they are significant moves, and there have been, if you look at the price of coal, I think it's down $10 this quarter on a per ton basis at NYMEX. If you look at natural gas, it's down significantly within the quarter as you look out the curve. Those declines in prices show up in the form of mark-to-market timing. It doesn't actually impact the overall cash that will flow to the business, and therefore, we exclude that from our adjusted operating results.

Yes, no, I just wanted to sort of understand. And you would expect that obviously reverses in future periods, right?

I think it's fair to say depending on how commodity prices move, we will continue to have this on a recurring basis and it can be either positive or negative. Importantly, the cash that we expected from the business that we have conducted, we expect to flow and hit the cash flow statement.

Going back to Texas, I mean, you'll have more generation; you'll still be short relative to the amount of supply sales. Does that mean that you ultimately need to change your options and hedging strategy, or are you going to continue to sort of be at risk for weather anomalies, either cold or hot?

I think, Paul, what's unique about ERCOT is really the exposure that you're most concerned about is the superpeak and load-following exposure. And so if you look at the composition of assets in ERCOT, there is an abundance -- if you look at actually the supply stack, it's very flat until you get out to the extreme. And then it gets very steep with the high heat rate unit, such as the ones that have-- sorry, Freudian -- Exelon owns. As we look at our ability to manage our ERCOT exposure, it's really the combination of those load following assets. We were very excited to see Exelon success in buying Wolf Hollow. We obviously have our Navasota assets; they have other combined cycles in Texas, as well as the superpeak plants. Those are the types of assets that are incredibly valuable in that market in helping you manage your exposure. It's not as relevant or important to have base load exposure just because of its abundance, given the wins composition in the state.

Looking at the most recent Ohio auctions, is there any way for you to comment on margin, supply/margin expectations in that market? Did they play a role in leading to a weaker total number in the auction? And are you seeing significant compression of margins there?

Are you asking from the generation side, or from the -- ?

From new energy's point of view.

From new energy's point of view, actually I think we've been very pleased with the margins that we've earned, both in the Ohio auctions, as well as in New England and in the Mid-Atlantic. So, from our perspective, those auctions cleared at very attractive prices. I could appreciate how if you were a generator with own generation in the state, or in the region, that auction might have been perceived as not as positive, but I think that's just a reflection of the low gas price, delayed [casper] environment that we're in.

Okay, and the last question for me is, in Maryland, do you see that going to a litigated final order, or is there a possibility of the party settling?

You know, I think there's always the possibility. Given the timeframe we're in right now, we're clearly going to go into hearings. There may well be an opportunity between the end of those hearings and final order to be in some settlement discussion, but I don't think we can count on it. So, I think the next few weeks will be sort of dynamic in that respect and we'll see where it ends up.

Thank you very much.

Thanks, Paul.

Thank you.

Julian Dumoulin-Smith, UBS.

Thank you, good morning.

Good morning, Julien.

Couple quick questions. First, with respect to your comments earlier on wholesale versus retail, how would you characterize your origination efforts as they stand today, one versus the other? And maybe you could address that a little bit more granularly, vis-a-vis geographies?

Obviously, the wholesale auction is only active in markets where they conduct that. So, within New England, we see that. Within the Mid-Atlantic, whether it's BGS or whether it's the Maryland load auctions, and then out into Ohio and Pennsylvania. And from an activity standpoint, we have, relative to our expectations in the year, had a higher win rate in those auctions at attractive margins than in our beginning of the year assumptions. On the retail side, we continued to do a robust business there. We're seeing attractive renewal rates on the win rate side relative to the expectation. We're coming in a little bit less than we expected, but in part, that's just a reflection of the increased competition we're seeing in that market. Which really, I think reflects certain generators viewing that as a more desirable, less risky hedge of their generation output.

Interesting, and how does the pending Exelon merger kind of integrate into your plans? I've noticed you guys have certainly engaged in a number of acquisitions this year. How would you think going forward, both from an acquisition perspective and from a new territory approach? I mean, would Illinois or Ohio be more so on the map now than in the past perhaps?

Well, I think no doubt, we view the business strategically as a growth business and a business where market share matters. We're the leader in the business nationally and I think we completely expect to be able to build on that position. You know, we have introduced over the course of the last several years a multi-channel strategy, number one. So, in the more recent experiment on the residential side, where we have close to a million customers now, I think we'll clearly keep expanding the penetration rate in each of our states, is moving in the right direction. We have switching rates early in their adoption phase into New Jersey and Illinois where I think there's a lot of opportunity going forward and we will keep trying to refine that model so that the customer acquisition side of it makes sense for us. But I think we're very committed to that and feel it's a promising channel development for us.

At the same time, and something we keep trying to allude to, particularly in the last 2 or 3 years, is the opportunity for us to increase the scope of the business with respect to our C&I customer base. So, there have been a lot of new products introduced. The sales force has been reoriented to sell multiple products; the retail gas business is going along quite well and growing. I think the opportunity for both channel development and scope development is still very significant. When you combine that with markets that are still underpenetrated with switching rates that haven't really yet moved on the steep part of the S-curve, I think that there's a lot of opportunities. So, we're approaching this as a very, very interesting growth opportunity.

The renewable component of this with our customer base is expanding quite rapidly. Solar installation, and we expect other distributed generation opportunities to come up in the years ahead. So, probably the most important strategic rationale behind the merger has to do with this match between physical generation and our front end. But at the same time, the longer term strategy has to do with customer acquisition and penetration and I think both companies are very committed to that.

Great. Very much appreciate it. Quick last question here as I'm looking at the Maryland proceeding, if you will. Curious to what extent you can comment on palatability of investing in renewables. I mean, what are the puts and takes in your mind -- what is the caution in your mind in committing to perhaps a little bit of a higher level of build out, if you will.

Well, I think we've put together a pretty aggressive offer of 25-megawatts on the renewable side, which would be a substantial increase in Maryland. I believe in the [FE] order, the number was more like 5-megawatts. And part of our assessment of what a reasonable commitment would be had to do with looking at that benchmark. So, we think that's a good offer.

Maryland is not ripe with a huge amount of resources with respect to thinking about things like wind and solar. There are some other opportunities that are a little bit less conventional in arenas like chicken litter and biofuels, and so forth, which will also be examined. But I think that we feel like we're in a pretty good space there. We're obviously in a market where there is some likely, or there's importation of power now, but there's also importation of [Rex] and that will likely be the case in future years. But we'll see how that dialogue goes, but I think that we've -- amongst a number of constituents that we've discussed this with, I think that they feel like our commitment is quite substantial.

Great. Thank you very much.

Paul Patterson, Glenrock Associates.

Good morning, guys.

Good morning, Paul.

I wanted to touch base with you on the wholesale transaction, that $0.36. What exactly was that?

I think first of all, Paul, it's the culmination of a series of transactions, really related to our, both our wholesale load serving business, as well as some of the structure products that we offer to our customers, whether that's generator products in the form of unit contingent hedges off nuclear assets, whether it's in the form of those that are exiting the wholesale load serving market, selling us their books of business. Those are all types of transactions that would fall in that category.

Again, it's really related to our core business that we've been doing for the last 10 years, participating in wholesale load options and our ability to price both customer attrition, as well as VLR and the other constituent risks, variable load risk, which is just the relationship between temperature and consumption. All of those constituent risks, we I think have developed an expertise over the 10-plus years that we've been doing it starting with the Goldman joint venture in DNA of pricing an actuarial risk and we're the best in the business, we believe, at it.

Sure. It just seems like I haven't seen this for several quarters. Seems like a large amount this quarter. I wondered if there's a particular reason or if that's just how it worked out this quarter.

Again, it's a year-over-year quarterly comparison and I think it's very much a reflection of just the nature of the way the backlog--

That will work. Okay. I got you. Then when I'm looking at this -- I see this $0.12 decline in the business, sounded like $0.07 of that's because of dilution of the MX and StarTex acquisition, is that right? So it's really more a $0.05 decline, outside of that?

$0.05 year-over-year, quarter over quarter, that's correct.

Okay. So when I'm looking -- actually when I run down the numbers, when I take $0.23 for the quarter and I back out the wholesale load. When I back out the CEP divestiture, when I back out the $0.16 hit from Texas weather, and from the $0.07 of MXenergy, I come up with about $0.10 delta. What else is sort of going on there that we should be thinking about?

So you have the absence of the 2010 novation is $0.20.

Right.

Year-over-year.

I'm including that as well.

You've got the $0.36 related to wholesale load serving structure products, $0.07 of CEP, $0.16 loss from Texas, $0.12 loss from the retail business impact, primarily MX and StarTex, and I think you get to roughly $0.05 that is just other items.

Okay.

Of year-over-year loss that's just a variety of puts and takes.

The cats and dogs. Okay. What I wanted to ask you is in Texas, this floor for non-spending reserve that they discussed yesterday, I guess, of about 120 and I think 180 for online/offline, it's a little complicated. What do you guys think would be the impact, all things being equal, or ball park obviously, of that kind of a floor being instituted in Texas?

I would say, Paul, it's too new for us to have done our deliberate work. I will say that certainly the experience of ourselves and probably, more specifically for other market participants, does support the value of peakers in terms of managing the variability as well as the volatility within that Texas market. Certainly we're glad to have as part of the Exelon merger their high heat rate plants. We're actually, even, at the early stages of analysis as to whether it might be economic to build air-derivative peakers at our existing Navasota sites. Obviously, nothing further than initial pencil work and model building, but the experience this summer definitely validates the physical value of offsetting that superpeak risk.

Right, but we don't have -- do you guys have any idea about what this -- I'm sure you have some idea, but can you share with us just a little bit of flavor as to what this nonspinning reserve floor -- if there's any sensitivity to that, that we could maybe think would, could quantify to some value for us, or is it just too early to say I guess?

Too early to say, Paul. Sorry.

Okay, and as you know, in April, there was a FERC order in not just with respect to the MOPR in New England, excuse me, in PJM, but there's also another order that happened in New England that basically was sort of positive, I would think towards generation, at least incumbent generation by trying to prohibit the impact of out-of-market new generation from coming into the market and influencing the capacity market. I was wondering if you guys had any thoughts about how that might change the outlook and the capacity markets in New England.

I think, again, at this point, Paul, you know, hard for us to comment on the outlook for capacity in New England. Obviously you're starting at a very low base, particularly given the impact of what's being done in Connecticut. So anything that adds to the value of existing generation is a positive for us, given our New England exposure.

Okay. Just thought I would try. Thank you very much.

I think we have, Operator, one more question.

Brian Chin, CitiGroup.

Hi, good morning.

Good morning, Brian.

I hate to beat a dead horse here, but on the renewables question in the merger, if I understand it right, the governor's office is actually asking or starting from a much higher request for megawatts. Could you give us a sense of, under what condition would you more strongly consider moving your offer from 25 megawatts to a higher number?

Well, that's probably exactly what you would not want us to do over a call, an earnings call. I think again, the offer is very strong, but the -- in the realm of renewables -- you have to keep in mind that it's also an aspect of a package of things, so that in totality, we're talking about an offer that exceeds $250 million, of which renewables is a component. And part of this process is actually to allow the interveners and all interested parties to debate the merits of that package. So, would it surprise us that that mix changes a little bit? No. But I can't give you any guidance, because you can't really negotiate one component without thinking about the overall package. We highlight the fact that the state is more interested in renewables than they might be one other aspect of it, but there's going to be another constituent that cares more about another element of it. I think in the end, that's what the next two weeks is going to be all about and then we'll see where it comes out.

Okay. That's helpful color. I appreciate that was kind of a difficult question. Thank you, appreciate it.

All right, great. Well, thank you all very much and I'm sure you'll be interested in reading the newspapers over the course of the next few weeks, and we'll look forward to getting a positive vote on November 17 and moving towards finalizing the merger. So, thanks for all your support.

This does conclude today's conference. Thank you for attending. You may disconnect at this time.