Good day, ladies and gentlemen, and welcome to the Second Quarter 2012 NRG Energy Incorporated Earnings Conference Call. My name is Erin, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I will now turn the presentation over to your host for today's conference, Mr. Chad Plotkin, Vice President, Investor Relations. Please proceed, sir.

Thank you, Erin, and good morning, everyone. Welcome to our second quarter 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 the 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 no more than 45 minutes. [Operator Instructions]. Before we begin, I urge everyone to review the Safe Harbor statement provided in the 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 Wednesday, August 8, 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 direct comparable GAAP measures and a quantitative reconciliation of those figures, please refer to today's press release and this presentation. With that, I'll turn the call over to your host, David Crane, NRG's President and Chief Executive Officer.

Thank you, Chad, and let me add my good morning to everyone, and thank you for joining us on this -- our second quarter call. I'm joined, as usual, by Mauricio Gutierrez, our Chief Operating Officer, who will be presenting; as well as Kirk Andrews, our Chief Financial Officer, who will be presenting. Chris Moser, who runs commercial operations for NRG, is with us and available to answer any questions that you might have. As we go into this call, I think that while that it may be anti-climatic compared to previous earnings calls because as everyone, I think, on the phone is aware, we did speak with everyone just 2.5 weeks ago, where in the context of announcing the pending transaction with GenOn, we gave a sense of where we would be for the second quarter. We are acutely aware that most of you on the phone were kind enough to give us your time at that point, so we don't expect -- we figure what we can give back to you here is we're going to keep this call shorter than normal, no more than 45 minutes. One other small matter that I wanted to mention to everyone before we get into the call, which is a little bit unusual, is that I'm actually not physically with my colleagues in the Princeton office, but in fact, I'm participating in this call from Nevada, where I spent the last few days visiting our Ivanpah project under construction in the desert, about 45 miles south of Las Vegas. And since I've been down there, I am pleased to report to all of the NRG shareholders on the phone that construction is proceeding smoothly at that site. We expect to start testing the first unit in November this year, and we're…

Thank you, David, and good morning. Our integrated platform continue to perform well during the second quarter despite cooler weather across Texas and lower power prices compared to last year. Our operations group successfully brought the last remaining unit of our virtual plant in Texas out of mobile status. On the commercial front, we kept our focus on managing the exposure in Texas this summer given the increased volatility in the market. Retail had another strong quarter, growing both customer counts and margins. Finally, our construction projects out West, both solar and conventional remain on track. Moving onto our operational metrics on Slide 8 and starting with safety. 40 of our 51 facilities finished without a single recordable injury, giving us another quarter of top decile performance across the fleet. We are proud of our strong safety culture and continued commitment to safety excellence. And as such, I am very pleased to inform you that our Big Cajun II plant outside Baton Rogue received PPP star recognition from OSHA. This is the highest level of recognition in the program, and Big Cajun is our 10th plant in the fleet to receive this honor. I want to congratulate all our colleagues at Big Cajun for achieving this important safety milestone. Our total generation was down 7% for the quarter compared to last year. We continue to see lower production from our coal fleet, primarily due to mild weather, low prices and additional maintenance outage days compared to last year. As we have said before, the benefit of performing these maintenance outages with little opportunity cost more than offset the negative impact on our availability metrics. The reduction in coal generation was partially offset by higher production from our Encina plant in California, our Cottonwood combined cycle facility in South Central and…

Thanks, Mauricio. Beginning with the financial summary on Slide 13. NRG has reported second quarter 2012 adjusted EBITDA of $539 million, with $320 million from our wholesale business and $219 million from our retail platforms. The first 6 months of 2012 adjusted EBITDA totaled $839 million, with $508 million from Wholesale and $331 million from Retail. Meanwhile, Cash flow from operations for the quarter was a robust $661 million, which helped drive free cash flow before growth of $413 million through the first half of 2012. Our first half performance also led to a $300-million improvement in liquidity since year-end 2011, which I'll review in greater detail. Turning to capital allocation. On July 22, NRG reported its first-ever quarterly dividend of $0.09 per share, which will be paid one week from today on August 15. During the second quarter, we also made open market debt repurchases totaling $72 million, resulting in a commensurate reduction to our corporate debt. Turning now to the guidance overview we've provided on Slide 14. As is reflected in the first column of the slide, we're maintaining our guidance for 2012 EBITDA of $1.825 billion to $2 billion and 2012 free cash flow for growth of $800 million to $1 billion. In addition, we're reaffirming the guidance ranges for 2013 and 2014 EBITDA and free cash flow before growth, which we established as part of our announcement of the GenOn transaction on July 22. Specifically, we are maintaining the guidance for standalone adjusted EBITDA of $1.7 billion to $1.9 billion, and that's for both 2013 and 2014. And we expect free cash flow before growth of $650 million to $850 million in 2013 and $500 million to $700 million for 2014. Free cash flow before growth in 2014 is impacted by planned environmental capital expenditures, primarily…

Well, thank you, Kirk. Erin, I don't -- I think everything has been said, so Erin, if you're -- we're ready for you to open the lines for any questions.

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

Just had a couple of questions. First on retail, it looks like you've had some pretty strong sequential quarter-over-quarter growth in customer numbers. Can you give us some indication of how much of that is in Texas versus some of the Northeast markets?

Mauricio, do you have that information available?

David, I don't have it handy, but we can get back to you, Jon, and give you the breakdown on the growth.

Jon, I mean, my rough sense is it's about equal. It's not a particularly remarkable outcome, but we will get you the exact numbers.

Okay. And Mauricio, on the Northeast load, is there any rule of thumb or way to think about how much your supply cost would go down by having generation to back up load?

Well, I think the way we -- we've always portray the, I guess, the synergy value between wholesale and retail and ERCOT, which is what we're trying replicate in the Northeast is, one, the collateral savings that we get by costing generation alone. And then the second is just providing or being more comfortable capturing the low following premium using our retail vehicle as supposed to managing or hedging our portfolio in the wholesale market. So I would say that those are the 2 main drivers, and it is different depending on the market dynamics. But I -- specific numbers, I think it will be very difficult to tell you at this point what is the incremental value. In the past, we have provided some guidance in terms of what are those benefits in Texas, and as we continue to integrate the Northeast platform and expand our retail business in the Northeast, we'll provide you additional clarity on that.

And then one question for Kirk. On Page 15, there's about $250 million or $260 million of conventional CapEx in '12 through '14. Is there an EBITDA contribution associated with whatever those investments are in your guidance of $1.8 billion?

In the $1.825 billion to $2 billion in 2012...

I'm thinking more about the '14.

Okay, yes. Once you get to 2014, the bulk of those repowering projects were just -- the biggest component of that is our El Segundo project out in California, which is online in 2014. So that contributes to a full boat of EBITDA in 2014. I don't think we've provided specific guidance as to what that is. I think it's -- the best way to think about it is just a little less than $100 million on an annualized basis once it reaches run rate in 2014.

Okay. But El Segundo, I think, the remainder of the spend is going to be project financed, right, so this is -- should be other stuff as well? So I mean, I know you're thinking about expanding some plants in Texas. I was just wondering if there was any EBITDA contribution in there?

Yes, I mean, the bulk of El Segundo or the bulk of the repowering project is El Segundo. I mean, there's some minor degree of capital expenditures around eVgo and some of the new businesses, but the lion share of the EBITDA contribution from the repowering investments comes from El Segundo.

And your next question comes from the line of Angie Storozynski from Macquarie.

I know I asked this question last time, but I just want to go back to it again. So you're showing us $320 million to $330 million of EBITDA contribution from solar by '14. Could you tell me what's the corresponding total debt for NRG for those projects?

Kirk?

Sure. Once you get out to 2012, the total amount of -- or 2014, I should say. The total amount of debt or the total capital associated with that is about $4.3 billion. Of that number, about $3 billion of that is the total amount of solar debt.

Okay. But what's your share? Is that $3 billion your share of debt, of the solar debt?

No, that would be on a consolidated basis.

Well, okay. So what is the NRG service portion of the solar debt?

If you go through, Ivanpah, for example, Ivanpah is about $1.5 billion in total debt. We obviously own 50.1% of that particular project. So if you were looking for an allocation of our percentage, it's about half of that. Agua Caliente is just under $1 billion worth of debt, and we own 51% of that by virtue of the transaction with MidAmerican. So you deduct basically half of those 2 components from the total.

So roughly speaking, about to $2.1 billion of that debt would be serviced by NRG?

Yes, I think that's probably a good number, yes.

Okay. And secondly, I know you're not trying to give us anymore insight into your retail growth prospects in PJM, but I mean, how should we think about it? I just -- David and Mauricio, I doubt that you're merging with GenOn through cost synergies only. I think that there is -- there are growth prospects embedded in the plan. And could you give us a sense of where we are now for PJM volume wise and how should we think about it volume wise, not margin wise, but volume wise going forward?

Well, Mauricio, do you want to give that information?

Yes, David. I think, at this point, we're not prepared to give information around the growth prospects in the Northeast. I think that is -- Angie, I mean, that's something that we will provide you in the coming months. What I would say and just to characterize a little bit more the growth that we have seen on our retail business, half has been in Texas. Half has been outside of Texas, particularly in the Northeast. Green Mountain, with some of the premium products, have been very effective in the Northeast markets, particularly around the mass customers, so we are very encouraged by those results. But I think you should expect from us more disclosure around our growth prospects in the Northeast. I will say that on the plans that we have provided and the forecast that we have provided today through '14, the growth assumptions that we have are pretty conservative across the retail businesses.

But Angie, let me add to what Mauricio is saying because I think if there is any single thing that surprised us in terms of investor and analyst reaction to the proposed combination with GenOn is the extent to which people are interested and even excited about what this greater generation platform in the Northeast will do for us on the retail side, and we are happy with that because we agree with that. But I will tell you, as we have done the evaluation of the combination with GenOn, since the matter first came up a couple of months ago, our first focus was on the cost synergies and the other synergies that were announced 2 weeks ago. And that, the second focus was then on the synergies we could achieve with GenOn just on the generation side of the business. To be frank, no part of the evaluation that the NRG board did or NRG management did said, well, wow, if we own all those other megawatts in the Northeast, we can grow our Northeast retail platform at twice the speed. That's all going to be upside, and we can -- and we will be evaluating that going forward and talk to you more about that. But I would say most of our customers in the Northeast come from Energy Plus, and virtually all of Energy Plus' customers are on month-to-month basis. One of the advantages this allows us to do is they'll make it easier for Energy Plus, through their platform and our other retail platforms, to offer fixed-price contracts. And that's going to be an upside because how many more customers that will attract and the profitability of that we will -- we'll be talking about in the future. But none of that's built in into the basic application of why want to do this transaction.

And your next question comes from the line of Dan Eggers from Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Mauricio, I just wondered if you can just give a little more update on what you guys are seeing in ERCOT by way of kind of coal and gas switching,, coming back with the gas price rally in both as the second quarter progressed and what you guys are seeing as we roll through July at this point? --

Well, I mean, I think, Dan, if you look at -- and we try to provide some specific examples on the earnings slides. With the gas rally, you're kind of out of the PRB switching area. You're starting to get -- getting closer to the Eastern coal markets. Particularly in Texas, I would say the combination of that and some heat rate recovery, we have seen the reversal of that coal to gas switching that we experienced in January. So I mean, that's what I would say in terms of coal to gas switching. Our expectation and Dan, keep in mind, I mean, natural gas is one component, but the heat rate then, which from our perspective there is a small relationship between heat rates and natural gas, but to a greater extent, heat rates are a function of the finest in the market. Natural gas has all the different drivers. We think that -- we don't expect that to persist, I guess, in balance of the year. And certainly, on the forward market, when you start getting into '13, '14, '15, with gas prices in the high 3s, low 4 territory, I mean, you're significantly out of the PRB switching area. Dan Eggers - Crédit Suisse AG, Research Division: And I guess just on ERCOT in general, obviously, the price caps you have made maybe room for some volatility in pricing but probably not enough to attract or sustain attractive and durable investment in new assets. Can just give us an update kind of on conversations you guys are having as far as alternatives are concerned and what kind of progression or what steps we should be looking for as you guys see the conversations going?

Sure. I mean, I think you're right, Dan. The forward spark spreads do not incentivize new build economics. We believe that there is at least $10 per megawatt hour of off-site on the on-peak hours to start getting into that new build economics. And these are not necessarily based on very aggressive overnight cost to build. I mean, I think the range that we have provided is $800 to $1,000 per kW. In terms of the conversations that we have been having with ERCOT and the PUCT is we want to see a well-functioning, competitive market that provides the reliability that the state requires. And I think the Brattle report was very clear that even with the steps that the PUCT have taken in terms of price caps or floor prices on reserves, there is still a gap to incentivize those new builds. And that missing money has to come from somewhere else, whether it's a capacity market or some other form or type of resource adequacy program. And from our perspective, it's going to be -- there's going to be a lot of conversations around that topic. I think a lot of the constituents are recognized that price caps will not get you to the target reserve margin, that you need something else. And over the next couple of weeks, through the ERCOT workshops, I think we're going to be discussing that with other constituents. But I think the -- everybody recognizes that there's got to be something else done to be able to incentivize those new build economics. Dan Eggers - Crédit Suisse AG, Research Division: And Mauricio, you think about kind of the timeline between the workshops and people trying to build toward a consensus or something else? What do you think is the realistic conversion from some sort of conclusion here to an new implementation and how it could affect the power markets from a tangible monetary perspective?

Look, I mean, if you take the -- your reserve margin as your barometer on how tightly supply and demand, I mean, you're seeing in 2014, basically, single-digit reserve margins, significantly below the 13.75% target from ERCOT. So I think the timeline, I think, in the next couple of months, we're going to see a pretty good conversation around what other steps need to be taken. But I mean, we would be happy to continue this conversation, Dan, in terms of the clarity and the disability that we see in the ERCOT process.

Dan, if I could just add that because -- I never want to predict when government entities or quasi government entities do things. So it's best not to make a prediction on that. But in our conversations with the powers that be down there, they obviously -- as Mauricio says, they do have a sense of urgency about this. So hopefully, whatever happens, will happen in a very timely fashion.

And your next question comes from the line of Gregg Orrill from Barclays.

Sorry to stick with the last question, but I was wondering if you could elaborate a little bit more on kind of the unwillingness that seems to or the trouble that policymakers are having with moving to a capacity market in Texas.

Well, Gregg, I don't know if there's any magic to the words capacity markets. In California, they have the sort of the resource adequacy, and I think there's a greater sense among the policymakers in Texas. That's something -- can do a capacity market or something that has the same consequences or impact is necessary. But to be frank, we don't really care what it's called, and we don't think it needs to be exactly the same as what they have in PJM or any of the Northeast markets. As long as it's -- it works and sends the right price signal. So that's the type of dialogue we're having with them. And as Mauricio said, we've been very encouraged that there has been some dialogue with the people, the stakeholders in the market with us and we presume, with others, about how things would work and things like that. So I think the historic reluctance to go down that path as a practical manner is modifying. But I mean, I don't think that what ERCOT will end up doing is something that -- it's one day -- I don't think you need to worry that you're going to wake up one day and say, we just adopted the PJM capacity market model full stop. I don't think that's what will happen.

And your next question comes from the line of Brian Chin from Citigroup.

Can -- in the last few weeks, we've gotten a fair amount of update on San Onofre out in California. Could you just comment on what is the bilateral sort of capacity market or resource adequacy outlook in California look like over the next few months to a year? Say, how has that changed? And then could you give us a bit of color on -- particularly on the Encina resource adequacy contract, which I think expires at the end of the year, when we might hear sort of re-contracting news around that?

Well, I mean, yes, I don't know if Mauricio will be able to answer your second question. But he'll give the, call it, the old college try or else see you avoid it. But I mean, just for everyone on the phone, I mean, in San Onofre -- the difficulty at San Onofre has had a very significant impact on our Encina plant, the existing plant and from my perspective, the prospects for Encina going forward, since it's located in a very similar position in the grid -- and we've -- and Encina has worked, been online much more this summer. I -- actually, Brian, I'm sorry, what was the first part of your question about San Onofre and its impact on us?

Just wanted to get a sense of have you seen the resource adequacy values or contracting environment for power plant assets in Southern California tick up as a result of the difficulties in San Onofre?

Well, I mean, we -- our official position, we don't comment on anything that might be pending, but I would say, there -- consistent with my remarks, there has been much greater interest in the power from Encina since San Onofre started with its difficulties. But I think we need to leave it at that -- on that specific questions. But in terms of impact on the market, Mauricio, do you want to talk about that? The resource adequacy market?

This is Chris Moser. I'll Jump up on that one, David, if that's all right.

Yes, that's fine, Chris.

What we've seen so far is a lot of uncertainty on potential return days, and obviously, that really has -- I mean, what it's done is muddy the water quite a bit. I mean, it's obviously a big unit there that's missing, and no one knows when it's coming back. So really that's thrown a big cloud of uncertainty around that. So what we've seen is bid ask on the capacity or on the resource adequacy really kind of widen out. And that's about the update that we have right now. I can't say that it's tracking in one general direction because it's so wide right now because no one knows really what's going to happen out there.

Chris, could I ask what the bid ask numbers actually are?

I can those for you. I don't have them on the -- we're not going to -- we can go into some details another time, but I think we've got another couple of people we still need to get through. So we can chat about that in another point. Okay, I'll follow up with offline.

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

So firstly, not to beat a dead horse here, but on retail again, in the Mid-Atlantic, as you look at the Northeast expansion here, is it more of a C&I push? I think that's what you guys had historically articulated? Or is it more of a mass market push through Green Mountain and Energy Plus, et cetera?

Well, Julien, first of all, I think that we're obviously going to be active in both. But in the absence of Jason, I would say that I don't think we actually ever have historically said it would be more of a C&I push. I think that we -- it would be -- it's either a little bit more of the retail push, although we have an active C&I capability that's working in the region and doing a good job. I mean, there's been more pressure on C&I margins than there has been on the retail side. So as we have done in Texas, we'll probably to pursue both. But since you said more C&I, I want to push back and say maybe a little bit more mass market.

And then perhaps talking about some of the developments in New York, what kind of improvement do you think we could look towards in 2013 in the Northeast segment? I mean, not to provide guidance, but just getting a sense on New York. It just seems like that could be pretty material.

Yes. The New York capacity markets, Mauricio, you want to talk about that?

Sure. And Julien, I -- as you know there is a -- I would say that quite a bit of uncertainty about retirement dates, people pulling in and out plants from mobile status and not, so we actually -- in general, we believe that the Northeast either because of the economics that are significantly challenged for the plants or the -- some of the environmental regulations, we believe that the capacity markets will start moving towards a constructive territory. And in terms of the timing, when that's going to happen, I think there is quite a bit of uncertainty. I mean, we saw how, I would say, digital the price can be in New York just by virtue of having one unit, announce mobile, but they're retiring and then taking a second look. So I would say that the -- I think the fundamentals are there, and it's just a matter of determining when that will happen.

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

I'll stick to just one question given the time here. Can just provided a little more color on progress and the potential time frame for slowing down more of this solar portfolio or looking at the tax equity market? I would think as some of these projects are coming into service now more rapidly than you guys initially thought. The amount of the makers and ITC tax benefits are going to start to increase pretty rapidly. And as the second part of my question, are there any restrictions at all in place on selldowns of solar assets or accessing the tax equity market under the merger agreement?

Well, Keith, I think -- let me -- I mean, the second question about -- it seemed like a 3-part question for one question. But at least the second part about the selldowns or the -- Kirk can answer those questions. But what I would say to you is from our perspective, for us, when we sold the part, Agua Caliente to MidAmerican, we demonstrated that we could sort of sell down these assets at value. I think we said at that time and continues to be the case that our testing of that market has indicated that there are many viable players that are interested in positions in these assets. But if you want to sell at maximum value with the broadest possible range of potential buyers, you need to do that as close to -- you need to eliminate the sort of tail construction risk to the fullest extent possible. So we are happy where we are for now. But as you say, with the plants coming online over the next few months, you could see more activity in that area, but -- and on the tax equity side, I mean, I think the short answer is we are looking at that market on a sort of a continuous basis to deal, to optimize the tax benefits. But Kirk, do you want to elaborate on that?

Sure. First of all, Keith, in reverse order of your questions, we have the flexibility in the merger agreement to continue to pursue selldowns especially on the larger projects. And I'll view that as a segue to answer your other question. We're certainly continuing to pursue straight selldowns along the lines of what you saw on Agua Caliente. I think if I had to predict that, that is the type of monetization you'd see more along the lines of our larger solar projects, the big 3. And we are also, in parallel, continuing to work on the tax every front, and that's more likely to be the case with respect to some of the smaller projects, for example, the remaining 6 of our Tier 1 solar portfolio. And we'd expect to provide some additional updates on that as we progress in those efforts. But we have full flexibility to pursue both of those opportunities or avenues during the patency of the merger.

Well, Erin, I think we've run over our stay. So I just want to thank everyone for participating in this call. I mean, obviously, we will be back with you for our third quarter earnings call around the beginning of November. But given that we do have the GenOn merger pending and I think there'll be events, approvals and all you'll be hearing from us, and we will obviously be involved in the continuous investor outreach that we're always involved in. And any questions anyone has, please feel free to call Chad and Stefan at NRG's IR group. So thank you all very much for participating, and we look forward to talking to you soon.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.