Good day, ladies and gentlemen, and welcome to the Q3 2012 NRG Energy Earnings Conference Call. My name is Laura and I will be your operator for today. [Operator Instructions] We will conduct a question-and-answer session toward the end of the conference. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I'd now like to turn the call over to Mr. Chad Plotkin, Vice President, Investor Relations. Please proceed, sir.

Thank you, Laura, and good morning, everyone. I'd like to welcome you to NRG's Third Quarter 2012 Earnings Call. This morning's call is being broadcast live over the phone and via webcast, which can be located on our website at www.nrgenergy.com. You can access the call, associated presentation material, as well as a replay of the call in the Investor Relations section of our website. This call, including the presentation and Q&A session, will be limited to 1 hour. [Operator Instructions]. Before we begin, I urge everyone to review the Safe Harbor information provided in today's presentation, which explains the risks and uncertainties associated with future events and the forward-looking statements made in today's press release and presentation material. We caution you to consider the important risk factors contained in our press release and other filings with the SEC that could cause actual results to differ materially from those in the forward-looking statements in the press release and this conference call. In addition, please note that the date of this conference call is Friday, November 2, 2012, and any forward-looking statements that we make today are based on assumptions that we believe to be reasonable as of this date. We undertake no obligation to update these statements as a result of future events, except as required by law. During this morning's call, we will refer to both GAAP and non-GAAP financial measures of the company's operating and financial results. For complete information regarding our non-GAAP financial information, the most directly comparable GAAP measures and a quantitative reconciliation of those figures, please refer to today's press release and this presentation. With that, I'd like to turn the call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Chad, and good morning, everyone. Today, I'm joined as usual by Mauricio Gutierrez, our Chief Operating Officer and Kirk Andrews, our Chief Financial Officer, and both of them will be giving part of the presentation today. I'm also joined by 3 other executives of the company, who will be available to answer your questions: Chris Moser who, as you know, runs the trading operations, will be available to answer any questions you have about the commodity markets that we are involved in; and for the first time, we have with us today, Elizabeth Killinger, the President of Reliant; and Jim Steffes, the President of Green Mountain. Elizabeth has just recently become President of Reliant, but she's been with the company for 10 years and most recently, she's been responsible for the residential business for Reliant and the customer operations business for all of Reliant. Jim joined us several months ago from Direct Energy when Paul Thomas retired from Green Mountain, and I think the important thing about both of them is, both of them have been integral to the success of NRG's retail business in the year-to-date. So we'll look forward to them getting to know you and you getting to know them. So as we get into it, I first want to say how much I appreciate you joining us on this call and also for your understanding of our interest in moving the call from Wednesday when it was originally scheduled in today. As everyone's been very busy over the past few days, this call also represents my first opportunity to speak to the NRG staff as a whole since the storm, so I hope you'll be patient if I touch upon a couple of points that might naturally be of more interest to employees than…

Thank you, David, and good morning, everyone. Before we go into the results for this quarter, I want to join David on expressing my respect and appreciation to our colleagues in NRG's Northeast operations that kept our units available throughout the summer. To all of them, thank you, and job well done. Now back to the results for the quarter on Slide 8. Our integrated platform performed well despite low power prices across our Texas region. Our improved risk management activities not only protected the retail business during the few periods of high prices but also provided an opportunity to hedge our wholesale portfolio at attractive levels in the weeks and months ahead market leading and during the summer months. Our operational performance was solid, led by our South Texas project's perfect record during the quarter. Noteworthy is the plant record set by Unit 1 with 530 consecutive days in operation before entering a refueling outage this fall. This is a great accomplishment by the STP team and one that makes us all proud of their operating track record. On the environmental front, I am pleased to announce a reduction in our environmental CapEx from $553 million to $440 million, driven primarily by changes to our mass compliance plan for Big Cajun II, Unit 3. We conducted additional stack testing and engineering studies to evaluate the performance of the existing ESP unit with activated carbon injection. Based on these results, the need for a backhouse in Unit 3 has been replaced with an operational ESP. The remainder of the reduction relates to completing the Indian River projects under budget, thanks to the excellent job of our EPC group and changes in the smaller air quality and 316(b) projects. The other positive news is that we have come to agreement with…

Thank you, Mauricio. Beginning with the financial summary on Slide 16. NRG is reporting third quarter 2012 adjusted EBITDA of $657 million, with $449 million from our wholesale business, $173 million from our retail platforms and $35 million from our solar projects, which are now a growing part of our financial performance. For the first 9 months of 2012, adjusted EBITDA totaled nearly $1.5 billion, with $928 million from wholesale, $504 million from retail and $64 million from our solar project. Year-to-date, NRG has generated nearly $1 billion in adjusted cash flow from operations, which drove free cash flow before growth of $806 million through the first 9 months of 2012, placing us already within the range of our previous free cash flow guidance for all of 2012. This performance also contributed to an increase of over $600 million in total liquidity since the year end, after taking into account the redemption of the remaining $270 million of our 2017 senior notes on October 24. Turning to capital allocation, with the refinancing of the 2017 notes, we've now achieved $100 million in debt reduction toward our plan of at least $1 billion of deleveraging announced as a part of the GenOn transaction. Importantly, this reduction in debt, combined with a lower coupon on the newly issued 2023 notes, will result in an annual interest saving of approximately $14 million. This gives us a head start on realizing the $100 million in annual cash flow benefit driven by balance sheet efficiencies resulting from the GenOn transaction. And as Mauricio previously mentioned, our environmental capital expenditure forecast for 2012 through 2016 has also been reduced by approximately $110 million. This is primarily the result of a decrease in estimated costs related to match compliance, in particular our Big Cajun II facility, as…

Kirk, thank you. In closing, let me say that one of the things we always try to do at NRG is tell the market what we're going to do and then go out and try and do it. Towards that end, for the 9 years that I've been in this job, it's been my practice during the first quarterly call of the year to lay out for our shareholders what we hope to accomplish during the year ahead. And then on the last quarterly call of the year, to measure our progress against the objectives that were previously announced. Accordingly on Slide 21, you will find our goals for 2012 repeated from our February 2012 earnings presentation, together with my personal assessment of how we have performed against those goals. Suffice it to say, I feel that we have substantially advanced and strengthened our position against each of the 4 pillars of our strategy: Enhance core generation, expand retail, lead clean energy and maintain prudent capital allocation. Now as Kirk was saying, we intend to end the year strong, close the GenOn transaction and hit the ground running in 2013 as a 46,000-megawatt generator with ample liquidity, enviable asset portfolios across each of the 3 key regional competitive electricity markets in the United States, a robust and growing multimillion base of retail customers in markets that match up nicely with our generation, and a leading first mover position in the provision of critical consumer-oriented and customer-focused clean energy technologies that we believe may have a disruptive impact on our sector over the medium to long term. The future is indeed bright for NRG. With that, Laura, we'd be happy to answer any questions that anyone might have.

[Operator Instructions] And your first question comes from the line of Jon Cohen, ISI Group.

My first question is on the Texas resource adequacy project. It seems like the only thing that all 3 commissioners [indiscernible] can now agree on is that demand response has to be part of the solution in ERCOT. And I know Commissioner Anderson is hopeful that the reps can actually come up with some sort of market-based solution to that, but I can't really figure out how that would work. So if Reliant for instance were to figure out some incentive to curtail customer load during the peaks and that should lower prices for everyone not just the Reliant customers and the benefit you get from peaking would seem to erode. Have you given any thought to that and how do you think such a demand response retail product might look, especially if there's no consensus on a centralized capacity market?

Well, Jon, let me first say, and not only say, that we've given a lot of thought to it and it is a competitive environment and I'm not sure how much detail we want to give you but I'm looking at Mauricio, who's shaking his head. Now Elizabeth, do you want to say anything about this because there is a clear opportunity here.

We have invested over the years in our e-Sense suite of products, which actually includes everything from time-of-use products to some device-based solutions, and we do believe -- we have thousands of customers on products like that, and we do believe that there will be growing needs and interests in products like that and we're continuing to develop those in the months ahead.

And I just have one other question for Kirk on solar. And I guess the question is, once you have the projects up and running and they reach COD, how much time do you have to sell down a stake to a JV partner to tax equity before the unutilized tax losses have to be booked on the balance sheet and be sort of taken down over time versus monetized immediately? And is that the end of the tax year or do you have another year after that? And the second question is, in your stand-alone free cash flow guidance, how much of the cash flow can be attributed specifically to the utilization of solar tax losses in '13 and '14?

Sure. The answer to your first question, Jon, on the free cash flow side, once we reach the levelized contribution of EBITDA, which purports with that range in 2014 of $300 million to $330 million, the corresponding cash flow associated with that number, which we expect from the projects, which is really solely the result of the operating cash flow separate and apart from the benefits of the -- on the tax side, is approximately $80 million. Now above and beyond that, while we are not currently in a position to be a tax payer given our NOL balance, over time, our utilization of that beyond 2014 will enhance the cash flow benefits above and beyond the number I just shared with you. As far as selldowns are concerned, the opportunity for us to engage in selldowns really, speaking specifically to the Agua Caliente project first, it was important to us to monetize that particular project because of the need to be able to realize the benefits fully in the monetization of the selldown around the ITC component of that project, which is unique relative to the other projects in the Tier 1 solar portfolio, which as you know are all cash-grant projects. It is necessary, if we're going to get paid or provide to our partner the benefits of the ITCs, to sell that down before COD. Beyond that point, we have the opportunity to pursue selldowns in the future beyond COD and we don't have a necessary limitation from a capital perspective as far as sharing the benefits from a depreciation standpoint.

Your next question comes from the line of Keith Stanley, Deutsche Bank.

I was hoping for some more color on the Alternative Energy segment. The release said solar has contributed $64 million of EBITDA year-to-date but the segment as a whole has only contributed $35 million. And I guess, my understanding is that the Alternative Energy segment is wind and solar but it seems like there's also some drags in that segment. So can you just talk about some of those things that are offsetting.

Sure. Our Alternative Energy segment, in addition to the businesses that you just mentioned, also include some of our new businesses, which are as you know in a start-up mode, one of which is our eVgo business, which currently, we're in the process of ramping up on the customer side. Obviously, we have a significant amount of capital spend, which has been increased by virtue of the settlement that took place in California. And as we begin to add customers, we expect the EBITDA contribution from that to offset the overhead. So right now what you're seeing reflective, as you say, the difference between the positive EBITDA on the alternative energy along the solar side being offset by some of the early-stage costs associated with the ramping up some of those businesses like eVgo, as well as there's a slight amount of overhead associated with the Petra Nova project as well.

One other follow-up, if I can. Just looking at the retail contributions, the projections through 2014, can you talk a little bit more about the increase that you expect there from 2012 to 2014 just given the now rising gas and power prices from a 2012 base? Should we assume you can hold margins flattish on existing customers and then see some EBITDA growth from new customers or how should we think about your margin assumptions there for the existing customer base over the next few years?

Well, I'll answer that in terms of the guidance and I'll let Elizabeth follow up with anything she'd like to add. From my perspective, looking at the guidance and the growth therein, we certainly would look given the commodity environment that the preponderance of that growth would come from the customer side of the equation rather than the margin expansion side of the equation. And certainly, our focus is on growing the customer base in the Northeast, where we see the real growth potential for us moving forward. As far as margins are concerned, I don't think we see certainly a lot of expansion on the margin side of things but I'll certainly let Elizabeth or Jim address any particulars around what they see moving forward on the margin side of the equation.

Thanks, Kirk. No, we don't expect to see expansion in margins. But to Kirk's point, we do expect to see customer growth. But that said, we -- our long-term strategy is to balance margins and customer account, and so we will do the right thing to make sure we can deliver on those commitments as well as adding additional services to customers we currently have so it increase the share loss we have in a particular customer.

And Elizabeth, I think your comments about margins and all was sort of focused on the ERCOT market. Jim, did you want to say anything about the Northeast market in margins and customer account and the like?

I mean, I think we do see growth opportunities in the Northeast clearly aligned with the multibrand, multisegment business that we have. Building on what Elizabeth said as well, we do have the opportunity to expand share of wallet. We intend to do that to go beyond commodity in the Northeast but we're just really getting started there. I think there is a huge opportunity in the Northeast overall.

There is a huge opportunity in the Northeast but, Keith, I would say that what you're seeing in the projections expects growth in the Northeast but while we'll be seeking heroic growth in the Northeast, there is no assumption of heroic growth in the numbers that we put out there for 2013 and '14, it's more sort of linear growth.

If I could just follow up quickly, so for just looking at the Texas business and the existing customers, it sounds like you're not embedding any margin expansion for sure. But should we assume there's some margin contraction, given the rising price environment or should we assume more of a flattish outlook on that core customer base?

Yes, I think you should assume, Keith, that we -- our assumptions that margin stay relatively stable on the retail side in Texas. And so we appreciate the question, Keith, I've got to tell you, just for everyone, the next questioner, I've been warned by Chad that we have to keep it to one follow-up question because -- so unfortunately, Keith, we'll have to go on, if you have any other questions, though, give us a call.

Your next question comes from Neil Mehta from Goldman Sachs.

So when do you plan on providing more clarity around capital allocation guidance, is it your 4Q call early next year? And maybe as a sneak preview, can you provide some sort of framework here, for buybacks versus dividends versus other sources of capital allocation?

Well, I think it's fair to say that guidance on further capital allocation, the fourth quarter call February next year is a good bet. Depending on when the transaction closes and the circumstances, if we have newsworthy things to talk about, we've contemplated maybe having a call after the transaction closed that might have more information about capital allocation, but you can't put that in the bank. So I would say February next year. The only thing I would tell you, speaking on half of the company about capital allocation is, clearly, you can see from the words that we've used consistently for the last 9 years, prudent balance sheet management, we've tended in terms of returning capital to the stakeholders to return capital through buyback and debt reduction in sort of equal amounts. Now we have the dividend. We feel that we owe the market a little bit more information about directionally where we're going to take the dividends. You certainly can count on that. But between buybacks and paying down debt, I think I would repeat what I believe I said on the last quarter call is, maybe relative to where we were over the last few years, we've got a little bit more of a lean towards the debt repayment side just because this combined company -- it's got a lot of cash flow, but it's got a lot of debt as well, so we'd like to get that number down if we could.

My follow-up question is around Texas here. In 2011 we had, I think, it was 27 hours of scarcity pricing. In '12 we had almost none. Assuming normal demand levels, how do you think about what is the normal number of scarcity hours as you look at 2014?

I'm going to ask Mauricio to answer that question and then you're not going to be allowed a follow-up question, so even if Mauricio doesn't answer the question, you'll just have to call in and get -- try to get a better answer.

Look, I mean, I think the amount of scarcity pricing hours that you can see at any given year is, as you know, a function of weather and you alluded to 2011 extreme weather, and we actually felt that in 2012 it was a normal weather. We were surprised to see that many few hours, I guess, of scarcity pricing. So I think -- and then you have the supply side of the equation to deal with and specific unit outages that may contribute to that. Instead of answering exactly what is the number of hours, what I can tell you is that if market is a good indication for what the potential impact is in terms of dollars per-megawatt hour, we saw 2013 move anywhere between $3 to $5 per megawatt hour on a round-the-clock basis. So I think that just gives you a little bit of a proxy in terms of not only the number of scarcity hours but also the impact of the new price caps that the commission has approved.

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

Best of luck on the continued recovery after the storm. Just had one question on solar growth outlook. In the past, you've talked about tax advertising, this was discussed earlier a little bit. But as we think about potentially reloading and continuing to grow the solar business, does tax appetite have a -- does that play into that decision? In other words, should we -- when we think about 2013, '14 and into '15, should we be thinking about continued ability to greatly expand the solar portfolio?

Well, the first thing I would say is, yes, we certainly have the ability to continue to expand the Solar portfolio. I think, however, in contrast with the past, our expectation is that the magnitude of individual opportunities that would make up that continued growth on the Solar portfolio would certainly be smaller, especially than what we've in the past with the Tier 1 portfolio, especially as regards what I tend to refer to as kind of the Big 3. In terms of our tax position, I think that it's safe to say that we will evaluate and investments in Solar will be made under consideration of either our ability to monetize the tax attributes or our ability to efficiently use them given our existing tax position. And so we will make decisions as to investment in Solar on the basis of one or the other of those 2 moving forward. But we don't see that as being a material constraint on expanding the business moving forward.

Stephen, can I actually -- I'd like to add a little bit more to what Kirk said. Because I mean you're -- I think you're touching upon what's a very important area I think to this industry and to us as a company, which is that we obviously are incredibly bullish on Solar. We see enormous opportunity for our company in Solar. We also are -- completely recognize that Solar is a business that, as you say, is driven by tax matters to some degrees, but it's a very capital intensive industry with all the capital being required up front. And it requires a lot more capital than we have as a company. We've been, maybe from your perspective, taking our time to get other people's money involved in our solar projects because we still think the market is mispricing on a risk-adjusted basis or I should say on a lack of risk-adjusted basis, the returns that people should be willing to accept in the solar business. Having said that, we see enormous creativity going on in the banks and in the markets in terms of more people being attracted to the solar space. So we're very confident that during the course of 2013 and beyond, you will see our company continue on the solar path we're on and getting other people's lower cost capital involved in our projects in a way that's enhancing for everybody, including and most notably for us, our shareholders.

Your next question comes from the line of Anthony Crowdell, Jefferies & Company. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Hopefully just a quick question. I'm wondering if you could break up the wholesale guidance, say, $1.17 billion to $1.19 billion for 2012. What's the contribution there from non-baseload assets?

Anthony, we're not going to break down the difference between baseload and non-baseload where that's concerned. I think we're comfortable taking into consideration all what we see in the forward market, especially with the changes that have most recently come about in ERCOT, and we've taken that into consideration in terms of the contribution on the peaking side of the equation. But beyond that, I don't think we're going to break that down in further detail.

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

First, just on Jason's departure from Reliant. I was wondering if you could discuss any updates to your strategy. Thus far, it doesn't sound like anything but just kind of curious on that, is there anything we should read from his departure?

No, I don't think there is. What I can do -- I mean, honestly, no one wants to have their personal situation discussed on this type of public call, but I can assure that had nothing to do with the type of issues that shareholders usually care about, which would be like the strategic direction of retail. And we see enormous opportunity in retail, we want to grow it, we want to grow it aggressively. Today, we have with us Elizabeth and Jim, and I would tell you, Julien, that probably one of the most significant changes that's occurred in this company that no one on the outside would have seen, but I can see from the inside is, really when we bought Reliant a few years ago, I mean, we were basically a generation company run by generation people and then we had a retail subsidiary. And the business model that we're talking about in these investor presentations of a generation retail model with equal weight on both is very much the way our management is. And both Elizabeth and Jim are backed up by very strong retail-experienced management team. So I have the highest confidence in both of them and their teams and there really is nothing that is worth you reading into about Jason's departure.

And maybe a quick follow-up here, just discussing the year-on-year drivers, looking at 3Q for the Reliant segment, I -- intuitively, I thought a mild summer would drive higher results. Looks like the release at least alludes to cost inflation due to customer acquisitions, perhaps, be it premised on mid-Atlantic expansion. What kind of cost inflation are we talking about -- have we seen, thus far, and particularly going forward in your '13 and '14 guidance, if you can talk to that.

So cost inflation specifically on the retail side. I mean, look...

Yes, exactly.

I mean, well, I guess, well, there's the customer acquisition aspect and there's also I think everyone recognizes that with greater volatility in Texas, I mean that there's greater cost in terms of arranging your wholesale supply on the retail side. And that's an area where we believe we have a competitive advantage relative to other retail electricity providers because of our own wholesale position. So -- but Elizabeth, if you want to talk about cost of acquisition in Texas or the cost question. And Jim, I don't know if you have anything to add from the Northeast that you can...

Yes, so we do have slight increases in costs but to David's point, they really are associated with the growth. Some of -- the bulk of that this year has been Northeast expansion, but we've also added some new products and expanded sales channels in ERCOT and in the Northeast as well. And I would expect that going forward, not significant increases. Jim, I don't know if you'd add anything.

We can go into it further, if you want to talk about it, call us directly.

Your next question comes from the line of Angie Storozynski from Macquarie.

First about the Northeast and your retail business. So you've added thousands of new customers and you don't really have much of a generation assets to serve them. So I understand that you're using market purchases to meet your load obligations and how should we think about it now that the Hurricane Sandy hit and then many of those customers are not connected to the grid anymore and you have purchased power to serve them, shouldn't we imply that actually this should have a negative earnings contribution?

Wow, Angie. Mauricio, do you want to take a whack at that?

Yes. I mean, keep in mind that we have 7,000 megawatts of generation in the Northeast and many of the products that you use to manage your retail load like capacity and baseload generation or block generation, we can source it internally from our existing resources. I mean, so far, the portfolio -- the size of the portfolio is small enough that 7,000 megawatts is more than enough to manage that retail load obligation. But clearly as the retail grows, the need for having additional generation in the Northeast becomes critical and that's where the transaction with GenOn, we see synergies similar to what we've been able to do in ERCOT. But that's on the supply side. In the impact of Sandy in our Northeast customers, it is -- I would say, I would characterize it as immaterial. And what I would say just from what we can tell on the wholesale side, load in general in the Northeast, depending on what state you were, was down anywhere between 20% to 30% for the last couple of days. So while load was down overall, the impact to our retail franchises were very small and immaterial.

And the last question. You mentioned the renegotiations of your Limestone coal contract. Could you give us any color of how beneficial to your earnings that is?

Angie, I wish I could but -- this is a -- we historically haven't provide specifics around coal transportations because of the confidentiality that we're bound with our counterparties and the competitive nature of them. What I can tell you is that it was in favorable terms and we have seen, I think, the height of the rail contract rates when gas was $10 to $12 from MMBTU. I think they're behind us, so not only they're favorable, but they're also more flexible in terms of our operational, I guess, flexibility being redundant -- operational flexibility around the rail contract.

And we like to give credit where credits due and we've talked in the past on these calls about the constructive attitude that's been taken towards these negotiations in terms of the commodity price environment we're in and we just want to say that we appreciate Burlington Northern in particular in terms of the way that they've worked with us in a constructive fashion to keep these plants competitive. So -- but that's about as much detail as you're going to get.

Your next question comes from the line of Gregg Orrill from Barclays.

I was wondering if you could talk about the next later generation growth opportunities beyond what you've talked about earlier in the backlog. And understanding that you haven't completed the GenOn transaction yet, just sort of from a -- what are the conventional buildup opportunities or areas that you think you might need to add assets so we can get a sense for how that might play a role in capital allocation over the next few years.

Well, Gregg, it's a good question. I tell you, it's hard to make a general comment. I mean, I guess the most general comment I would say is that there hasn't been a large build of conventional generation in this country, across our core markets obviously, since the recession. And reserve margins, I mean clearly, we focus here on Texas and Mauricio talked about how they are tightening. But while we haven't seen the same level of demand growth over the past few years in the Northeast United States and in California, there there's more a question of retirements and how those retired assets get replaced and California has in particular the 316(b) issue that could cause the retirement of a lot of coastal issues and the Northeast just has a lot of old assets. And so it's almost region by region and location by location. We are looking -- we think we have a competitive advantage really across our fleet in terms of brownfield versus greenfield, in terms of the cost advantage and other advantages you get by redeveloping at your existing sites. But virtually anything that we're looking to do at this point because of the sort of overall depressed nature of wholesale electricity prices is going to be on a long-term PPA basis. So you would expect normal project financing and I don't really see a situation in the next year or 2 where we get on one of these calls and say, "You know what, we just decided to build an 800-megawatt combined cycle plant and we're going to put the whole thing on balance sheet, so there goes $500 million or $600 million. So again, I think that was your first question. So if you have a follow-up question about a specific area, I'd be happy to talk about the New York energy, highway or something like that. But in the interest of time, that's about as much of an overview as I could give you.

Just maybe a follow-up on your comments about 316(b) and I think you've -- that was a reduction to the environmental CapEx and what are some of the solutions you're finding there?

To reduce the environmental -- the current?

Well, I mean, just to be clear, I mean the main reduction of the environmental CapEx was due to the change from a back house to an ESP operator. And I'm going to say that was 80%, 90% of the total reduction. I mean, some of the unit changes from the 316(b) were relative to the screens that we have used in the Northeast and that we've been very successful on some of our units but I would say that those are the much smaller dollars on the CapEx reduction.

We've gone over the hour but let's take 2 more questions and we'll try and be quick with the answers.

Your next question then comes from the line of Brandon Blossman from Tudor. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Let's see, I will be quick. So ERCOT baseload, Mauricio, the PRB hedging strategy, no incremental hedges this quarter, a lot of price volatility, what's the thought process on a go-forward basis around layering in PRB hedges and then on the quarter, it looks like there's an outage on the baseload coal plant in ERCOT, was that a forced outage or something planned?

No. Well, let me start with the ERCOT. I mean, we have some 2 weeks that it's I would say normal operations when you're running a coal plant in the middle of the summer. It was a normal summer from a weather standpoint. It still was warm by any other standards. So we had a -- what I consider a solid availability performance by our baseload fleet but it was not the stellar performance we had in 2011 when, if I recall, we had over 95% availability on our coal fleet. And what was your first question again? Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: The PRB strategy on a go-forward basis.

Yes. Look, I mean, we said that we try to keep a -- balance the hedges on coal and natural gas. We put the coal hedges in 2013. We just closed that. Basically that dark spread with the additional hedges that we layer on the power when natural gas has run up the last few weeks. When you look at 2014 and beyond, we still see an angle in the PRB market and given some of the dynamics and some of the price differential between spot prices and forward price, particularly in 2014, we're going to continue to evaluate where natural gas prices go, where power prices go and make a determination in the future but we're watching that constantly.

Your last question comes from the line of Steve Fleishman from Bank of America Merrill Lynch.

Just at a very high level on the retail business, a lot of competitors have complained about either lower margins or certainly not the level of -- lower customer growth than they expect. How would you characterize the ability to differentiate versus others in the business?

Well, I would say, look, maybe -- I mean, the lower margins again have their cost -- for them, has to do with how expensive it is for them to arrange their wholesale supply. I don't really know. I mean, we're comfortable with the margins that we're achieving and I would say that the one thing that we've tried to distinguish ourselves from in what's historically been a very much commoditized business, but I think with each day is becoming a less commoditized business, is that we offer a differentiated product. I mean, Reliant offers a full-service product that increasingly is offering, as Elizabeth said, various smart meter technologies and the like. If you went to the Reliant website as I did yesterday, you would see a picture of the Nest thermostat, which I have in my house and Reliant -- Elizabeth has it in her house, so they're offering a differentiated product there with more smart energy technologies in the house. And Jim in Green Mountain, with obviously with the all-green energy and Energy Plus with the frequent flyer miles and other affinity programs, we're trying to offer something other than just undifferentiated grid power and it seems to be working. And I completely believe that that's the direction that retail is going in and you're not going to see us cut back on that. You're going to see us doing more and more of that. So thank you all for being patient. And sorry, we took an hour and 10 minutes, but we look forward to talking to you on the February call, if not before, hopefully at the time of the closing of the GenOn acquisition. So thank you.

Thank you for joining today's conference. This concludes the presentation. You may now disconnect. Have a good day.