NRG Energy, Inc.
Q2 2010 Earnings Call Transcript

Published: 3 Aug 2010

[Operator:]

Good day, ladies and gentlemen, and welcome to the Second Quarter 2010 NRG Energy Earnings Conference Call. My name is Carissa, and I will be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today's conference, Miss Nahla Azmy, Senior Vice President of Investor Relations. Please proceed.

[Nahla Azmy:]

Thank you, Carissa. Good morning, and welcome to our second quarter 2010 earnings call. This call is being broadcast live over the phone and from our website at www.nrgenergy.com. You can access the call presentation and press release through a link on the Investor Relations page of our website. A replay of the call will also be available on our website. This call, including the formal presentation and the Q&A session, will be limited to one hour. In the interest of time, we ask that you please limit yourself to one question with just one follow up. And now for the obligatory Safe Harbor statement. During the course of this morning's presentation, management will reiterate forward-looking statements made in today's press release regarding future events and financial performance. These forward-looking statements are subject to material risks and uncertainties that could cause actual results to differ materially from those in the forward-looking statements. 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 August 2, 2010, 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 the 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. Now with that, I'd like to turn the call over to David Crane, NRG's President and Chief Executive Officer.

[David Crane:]

Thank you, Nahla, and good morning, everyone. I want to slide [ph] [15

[John Ragan:]

Thank you, David. Good morning, everyone. During the second quarter of 2010, NRG continued to sustain the strong operating and commercial performance it achieved during the first quarter, solidly positioning the Company to enter the critical summer months. On Slide 12, we've highlighted some of our second quarter accomplishments. Our focus on safety across the entire organization, including Reliant, has remained strong with an OSHA recordable rate of 0.7 through the first half of the year, which continues to exceed the top decile benchmark for the industry. During the second quarter, our Encina plant was awarded OSHA's VPP Star designation. OSHA's Voluntary Protection Program, or VPP, is a voluntary program that allows a facility to attain one of the highest levels of safety recognition available within the power industry. To achieve this designation, a plant must demonstrate to OSHA that both management and the employees have achieved an exemplary health and safety record in addition to creating a steadfast safety culture that is embraced by the entire organization. This is the first NRG facility to achieve this award outside of our Texas fleet, and is a testament to our employees’ desire across the organization to strive for continuous improvement in safety. Our baseload fleet had another very good quarter of operational success with our plant personnel delivering strong performance. During the quarter, we continued to face challenging market conditions caused by cycling and additional starts for our coal assets. This was followed by periods of extreme heat in June. Through these widely fluctuating conditions and multiple plant maintenance outages, our coal fleet reliability was better than the second quarter of last year. Most notably, I want to point out the superior quality quarterly performance of the Indian River and Limestone stations, both with E4 below 2% and the Huntley station with an E4 below 1%. Our EPC group has continued to move forward with multiple construction projects. We have completed the Devon peaking plant in Connecticut and these fast-start units have been transitioned into our operating portfolio. Middletown is currently under construction and is expected to come online about this time next year. During the quarter, we have also acquired and integrated the South Trent wind farm into our wind portfolio. And lastly, we were successful in being awarded a $167 million DOE grant to design and construct a 60-megawatt carbon capture and enhanced oil recovery system at our Parish plant in Texas. Finally, our commercial operations group has continued to effectively manage the hedging and dispatch of our wholesale generation portfolio in addition to executing the integration and risk management requirements for the Reliant energy retail supply. This quarter was also marked by wins in additional load following contracts and portfolio hedges, which I will review later. Now turning to our plant operation performance on Slide 13. We have continued to operate our fleet safely and efficiently during the second quarter. While net generation and baseload availability were slightly off for the first half of this year as compared to 2009, this was primarily the result of three specific events within the fleet. These include a refueling outage at STP unit 2 as compared to no outages at STP during the same time period during 2009, the movement of an outage from 2011 to the second quarter of 2010 for Limestone unit 1 and a generator rotor outage at Dunkirk’s unit 4 in January that was discussed during the first quarter earnings call. Our units did experience some limited fuel switching, primarily during the shoulder months of March and April, that impacted net generation. However, this was partially offset by strong load from weather-related events during the second quarter. From a unit reliability perspective, our baseload E4 for the second quarter was 2.05%, which is an exceptionally strong showing from our operations team. When taking the events into account that I previously mentioned, our overall plant reliability and availability during the first half of the year was solid and within our expectations for strong operating performance. We also recognized that in the low-margin price environment that we currently operate in, it doesn't always make economic sense to spend that last marginal maintenance dollar in order to achieve the highest possible availability statistic. At NRG, we are always making those analytical decisions based on real-time information. We can promise you that we are scrutinizing our spend relentlessly across the fleet and putting our maintenance dollars to the best possible use where we can capture the value of the last marginal megawatt hour while making the best cost-benefit decisions to manage our overall plant assets. Finally, on the chart to the bottom left, at the end of the second quarter, we have achieved 50% of our full year FORNRG targets. This achievement was accomplished through contributions from our retail, tax and other corporate departments, continued plan efficiency improvements within our generation fleet and the sale of Padoma. We are on track to complete this year's goals and have the potential of getting a head start on the 2011 targets. Turning to our retail operations on Slide 14. Warmer-than-normal weather across Texas with cooling degree days above the 10- and 30-year benchmark coupled with lower gas prices created an opportunity to deliver higher volumes and stronger margins from our Mass Market segment. The dramatic decline in the commodities last year allowed us to deliver margin significantly above our targeted run rate while the market became much more competitive. The steady state of commodities this year, we have taken disciplined, targeted marketing pricing and actions to begin to stabilize our customer count while maintaining strong margins, thereby driving towards higher customer retention levels. At the same time, we have strengthened our sales channels and maintained our leadership in customer satisfaction and brand preference. The result for the quarter reflects an optimized balance between customer count and margin which is consistent with our long-term mass-market strategy for the Reliant brand and the specific customer segment we desire to serve. In the C&I segment, we improved renewal rates of existing customers during the second quarter and extended the term and diversity of our portfolio while experiencing profitable margins within the segment. Reliant remains the largest C&I retail provider, the second-largest residential provider and the largest retailer overall based on volume in Texas. Before I conclude the operations section, I want to provide some thoughts on EPA's recently proposed Clean Air Transport Rule or CATR, which was developed in response to the court’s rejection of CAIR. The primary objectives of the newer rule as compared to CAIR are outlined on Slide 15. The rule initiates new NOx and SO2 trading programs in 2012 with a second phase in 2014 which further lowers SO2 emission caps in certain states. The main difference between CAIR and CATR are

[Christian Schade:]

Thank you, John. Good morning, everyone, and thank you for joining us to discuss the second quarter and year-to-date financial results achieved during my first quarter as CFO. Let's begin with a brief overview of our achievements during the second quarter on Slide 20. As David previewed earlier, the Company delivered strong financial results in the second quarter, totaling $693 million of adjusted EBITDA. Reliant Energy contributed $195 million of adjusted EBITDA. With robust gross margins our Retail business benefited from favorable weather conditions in a favorable commodity environment. Meanwhile, the Wholesale business contributed $498 million of adjusted EBITDA, only $19 million lower than Q2 2009 performance. The year-on-year difference was affected by a refueling outage at STP unit 2 and a major planned outage at unit 2 of our Big Cajun facility, which occurs every six to eight years. Baseload generation in the Northeast was comparatively flat but due to hotter-than-normal weather during the quarter, oil and gas generation increased 20%. Benefiting our wholesale performance was increased capacity pricing in New York City, as well as new projects that came online as a result of our retiring and renewable initiative, including Cedar Bayou 4, Blythe solar facility and our Langford wind farm. Year-to-date, EBITDA for the first six months was a record $1.294 billion, representing a 6% increase over $1.22 billion generated in the first half of 2009. The addition of Reliant Energy added $385 million of EBITDA as favorable weather drove an 11% increase in customer usage partially offsetting a 2% decline in average customer count. Also, the improvement in customer payment patterns we mentioned in the first quarter continued into the second quarter. Meanwhile, the Wholesale business generated $909 million of adjusted EBITDA for the first half of this year, solid results despite a low commodity environment. The strong quarter and year-to-date financial results were directly influenced by our strategic forward hedging program and the continued focus on operational excellence. Our record results also reinforced the benefits of our strategy of owning both generation and retail in Texas. Finally, on this slide, I want to touch briefly on our liquidity position as I will review it in more detail on the next slide. We entered the first half of 2010 with a total liquidity of $3.5 billion, an increase of $290 million from the end of the first quarter. Cash on hand of nearly $2.2 billion provides ample capacity to serve our capital structure objectives and current capital allocation strategies. Of particular note during the second quarter is we successfully completed the amended extend of our first lien facilities, an important step in improving the financial flexibility of the Company. The highlights of this transaction include

[David Crane:]

Thank you, Chris. Carissa, I think we're prepared to take any questions that callers may have.

[Operator:]

[Operator Instructions] And our first question comes from the line of Dan Eggers of Crédit Suisse.

[Dan Eggers:]

David, I was wondering if you could just go to South Texas for a minute. Can you just maybe revisit or talk through a little more the thought process from the timing of the major components when you could reasonably expect decisions kind of on major things like U.S. loan guarantees, Japanese loan guarantees, EPC contract, PPAs, equity sell down? And are there certain pieces you see as contingent of getting done before the other pieces can get done right now?

[David Crane:]

Well, Dan, I could take the air out of the ball for the remaining 18 minutes of this call in terms of answering that question, but I'll try and give you the short form. I think the way, Dan, that we've gone around planning South Texas and the new reality is around this fact that we just literally have no idea when the U.S. government will do the two things, the Department of Energy actually finished the loan guarantee process hopefully in a positive fashion and the money be appropriated. It's really the second part that's more uncertain. I mean, we are really at the final stages with the DOE with negotiations of the loan agreement complete. But as to when the money would be there for an award, I mean, to be frank, Dan, as I'm told, it could be today or worst case scenario, if it gets to be part of the 2011 budget appropriations and that takes the track that it’s taken in recent years, it could be as far away as next February or March. So that's really the timing horizon that we've looked at all of those critical decisions. And we expect to have all of those, the four things that I talked about, resolved within that time period. So the U.S. government financing, the Japanese government financing, the EPC and the offtake. In terms of further sell downs, Dan, I would say would that's the one thing that's really changed in this because our motivation to sell down early in the project was actually to reduce the amount that we were spending every month. Left to our own devices, if we weren't spending as much as we were spending, we would prefer to sell down later rather than earlier because the project gets more valuable as it gets towards closing. So since our spend rate has been cut by 95%, I think the one other significant change in terms of the things that you mentioned is that you probably shouldn't expect additional sell-downs, unless they're for highly strategic reasons, until we get these other four main critical path items resolved. Dan, that's the best short answer I can give. I mean did you want to follow-up on some aspects of that?

[Dan Eggers:]

The other question, I guess, maybe if you could talk to in this venue is, coming in to the year you guys talked about the amount of economic exposure NRG has for shareholders in the project, and what kind of cash unwind or commitments would be required if the project wouldn’t have forward when you were negotiating with San Antonio. Can you give an update on where that stands and kind of where you guys are going as far as future development commitments have been made beyond your CapEx run rate right now?

[David Crane:]

You're saying, if the project would actually be canceled, would there be exposure beyond the cash that we already have sunk in the project?

[Dan Eggers:]

I guess, I assume there would be, and I guess just kind of the magnitude of the potential exposure?

[David Crane:]

I think in terms of -- first of all, there are not a lot of hidden commitments. I mean, if the partners -- and Dan, one thing I want to emphasize here, and I apologize to all our shareholders because I may not have spoken as accurately as I should have about the way this works, when we talk about like shutting down the project, this project like every other jointly developed product I've ever been in my life, one party does not have the right to shut down the project. One party only has the right to reduce or stop their spend in the project. The other party always has the right to unilaterally go forward. So when I talk about our decision-making in terms of actually shutting down a project, let's assume we have a joint decision of Toshiba and NRG to shut down the project. I think our overall sense is that while it will take a few months to wind down spending and money spent on demobilization and the like, there are not like enormous commitments that have not been disclosed before. I think the overall commitment of the Company would be in the $500 million range, but that $500 million includes the money that Toshiba's put to date. So that's more of an earnings number. You'd have to deduct the $150 million from Toshiba to get the cash exposure of NRG.

[Operator:]

Your next question comes from the line of Lasan Johong of RBC Capital Markets.

[Lasan Johong:]

David, if Toshiba is accelerating spending and NRG is reducing spending, does that mean that should the project either go forward or not proceed, that there is going to be some make-up on NRG’s part going forward after the decision point is reached?

[David Crane:]

Lasan, you're saying, is part of this arrangement with Toshiba that there would be some sort of reimbursement agreement, if it goes forward?

[Lasan Johong:]

Yes.

[David Crane:]

So the answer that question is no. There is no reimbursement agreement. We tried to depict on Page 9 and Lasan, this is a work in progress. But in terms of funding the work and -- again, I wouldn't say that -- I mean just make sure that we’re 100% accurate with the words. I'm not sure if Toshiba is accelerating the payment. They're just bearing more of the ongoing cost. The spend rate of the project is being reduced from about $30 million a month to about $20 million a month. And in terms of the part of that, the very significant part of that, that NRG is not going to be funding, what we're showing on the right-hand side of Page 9 is the various alternatives that Toshiba has to bear that cost. And it could be vendor financing or there is the TANE credit facility. Toshiba also has the option of doing it through equity in NINA, in which case there would be some dilution of NRG. But there's no sort of reimbursement agreement we've entered into to cause us to have to make up the cost that Toshiba is bearing in these months going forward.

[Lasan Johong:]

And just as a follow-up to the STP issue, if NRG felt that this was not a project that was good for shareholder value, either because you couldn't sell down the shares or you couldn't get financing, or you can’t get a long-term contract or you can't get DOE loan funding, does that imply that you have no hesitation in pulling NRG out of this project?

[David Crane:]

Well we could, I mean, that’s possible. But Lasan, what I would tell you is we’re announcing today that we've cut spending on the project by 95%. I mean, that is, from a point of view of removing the burden from the shoulders of NRG shareholders, I would say that that's a very significant step. If we decided and Toshiba agreed that the project really made no sense to go forward, would we cut from $1.5 million a month to zero? I don't think we would do that immediately because there's significant value in the project. I mean, first of all, we would probably keep the license going to conclusion, given how far we've come. And between some long lead time items that we've ordered, the intellectual property involved in the application process, the design, the Americanization of the Japanese ABWR design, I mean, we're talking about a set of the development assets that have significant value, and we would certainly not just throw those into the ocean. I think we would keep a team going to see if we could monetize that value.

[Operator:]

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

[Angie Storozynski:]

Two questions about Reliant. First of all, should we assume that the ongoing EBITDA for this business is actually above your previous expectations? And also, any comments regarding the cost level, especially the G&A and selling expenses? Should we assume that there's simply a lower run rate going forward?

[David Crane:]

Well, I may ask Jason to answer the second question. Let me just say on the first question, I think, Angie, if I'm getting your question right, I mean clearly, we've upgraded the expectations of Reliant for all of 2010. We haven't changed what we've considered, what we've said before, is like a midcycle run rate of $300 million. I think the question out there is that how much money can Reliant make on a steady state business during a prolonged trough in the market? I think that's what we're gearing our strategy for. I mean, clearly, if we believe that Reliant is going to make in the range of $600 million this year, it's not going to revert to $300 million going from December 31 to January 1, 2010 to 2011. So we don't have a perfect insight in this crystal ball. But I would say, clearly, we’re impressed with the resilience of Reliant's ability to outearn this sort of midcycle return during a prolonged trough, and we're doing everything in our power to extend that as long as possible. As to the cost structure, Jason?

[Jason Few:]

Angie, on the cost structure, we have taken actions to actually reduce our overall G&A, and we continue to do that not only as part of our FORNRG efforts but just overall in terms of operational efficiency and other things we’re doing from an automation standpoint in our business. So you should assume that you will see reduced G&A in our business.

[Angie Storozynski:]

How about the new contracts? We heard from other competitive retail providers that there seems to be higher competition, which is partly related to low volatility and natural gas and power prices. Should we assume then that new contracts that you are signing are actually at compressed margins, I mean, versus now for sure but versus your expectations?

[Jason Few:]

As you know, Angie, we don't give segment level. But I will answer it in two ways. We’re actually seeing although on our lower volumes, on our C&I business actually our margins are up for Q2 versus Q1. And on our residential side of our business or mass side, we've taken deliberate pricing actions to actually bring down margins to respond to competitive pressures in the market. So overall, from the mass side, you've seen some of that compression, which is intentionally driven. And on the C&I side, we're actually seeing the ability to create some expansion there.

[Angie Storozynski:]

That's for new contracts, that's not for realized margins. That's for new contracts signed during the quarter.

[Jason Few:]

For new contracts, that's right.

[Operator:]

Your next person comes from the line of Ameet Thakkar of Merrill Lynch.

[Ameet Thakkar:]

On the Texas wholesale, it looks like EBITDA was relatively flat versus the prior year. Just kind of looking at your hedging disclosures in your 10-K, I mean, it looked like the equivalent price of GAAP that you were hedged at was $8.37 in '09 and something closer to $7.70 in 2010. So I was just kind of wondering how you were able to kind of keep that flat at that business when volumes looked like they were actually down slightly?

[Mauricio Gutierrez:]

Ameet, this is Mauricio. Some of the revenue comes from ancillaries. We've been able to position our portfolio to take advantage of a higher or juicier ancillary prices. As you think about our portfolio, as our solid fuel portfolio ramped down during off-peak hours, we've become basically the least cost provider of ancillary services. And during on-peak hours, our GAAP portfolio can meet those obligations. So think of our portfolio as the least cost provider of ancillaries and as these ancillaries increase in price, we've been able to position ourselves to mitigate some of the lower gas prices that you mentioned and that we have experienced in the business. I mean that is one of the drivers.

[Ameet Thakkar:]

I mean you guys are 112% hedged in 2010 and I think you guys talked about this on the last call, some of that is just kind of maybe a little bit less volumes expected. But how do I think about you being over-hedged? I mean, are you basically kind of booking additional kind of trading-related revenue because you're essentially short of the market more than the fleet expected to run?

[Mauricio Gutierrez:]

Well, I mean I think you already addressed the first reason. I mean we were hedged against the expected levels that we had back in October of 2009. As the gas prices have decreased, our expected generation has decreased with it. We have not pared down completely our hedges. We want to be consistent with our market view. And I think it's pretty simple to deduct that we were somewhat bearish in the front part of the gas market. And we didn’t see the need to change our hedge profile for the balance of 2010.

[Operator:]

Your next question comes from the line of Neel Mitra of Simmons & Company.

[Neel Mitra:]

I just wanted to follow up on Ameet's question on the strong Texas outperformance, specifically on increased ancillary sold to Reliant. I was wondering if you could quantify that? And then also, why would the ancillary services revenues go up this quarter versus last year within I guess lower gas prices continuing to occur?

[Mauricio Gutierrez:]

Well, Neel, one of the benefits of our combining wholesale and retail is the stability that it provides to our generation portfolio in ancillary services but also shape products and an optionality that the Reliant business needs to manage the low variability. So this is just, I would consider, a perfection of hedging wholesale and retail after 14 months of ownership. With respect to the ancillary question, I think people try to get -- as you look into two years out, the market tends to pay off for insurance in the form of ancillaries. So we've been able to capitalize on that back in 2009 going into 2010. So I think the combination of combining wholesale and retail in providing these ancillary products, as well as the market being able to pay up for ancillaries I mean, I think that's the combination that has provided or that has mitigated some of the downside risk on gas prices for our Texas fleet.

[Neel Mitra:]

And Mauricio, the new collars or put options that were put out this quarter, can you guys quantify how much the cost of those auctions are and where they would show up, I guess, in expenses?

[Mauricio Gutierrez:]

Well, I don't believe we have disclosed the absolute amount of the cost. What I will tell you is, most of the hedging that we did in 2011 was under the collar structure. So moving it from the low 70s to the mid-80%, it was incremental on the back of the collars that we executed.

[Operator:]

Your next question comes from the line of Jay Dobson of Wunderlich Securities.

[James Dobson:]

David, I was wondering if you could go back to STP and NINA. On the offtake agreement, you sort of went by it somewhat quickly in your prepared comments but I interpret it to be that you're going to be focusing there a bit more? And if I got that properly, maybe confirm that and then sort of what exactly you mean in light of the sort of ongoing uncertainty?

[David Crane:]

Well, Jay, it's a good question, and you surmised correctly that when you say that we plan on focusing on it a bit more over the next several months. I mean, I think one way to look at it simplistically is that really the STP development project has three work streams. The one that which I think when people started we would've talked the most about, which was the regulatory approval work stream at the NRC. We don't ever talk about that anymore because it's working perfectly. It's right on track. It's the other two work streams, one is how to get money for the project and then of course the commercial arrangements. And there's been a lot of focus on the getting money work stream because of the DOE loan guarantee process. But the third work stream is the offtake. The offtake is the uncertainty that has caused us to not push so hard on the offtake thus far is not really related to the money. It's more related to the fact that you have to have a solid EPC price in order to talk to offtakers about the power and what it's going to cost. And we're getting much closer to a conclusion there in terms of getting a final EPC price that we then can work into something more specific to take to the offtakers. And so we expect in the second half this year, maybe spilling into the first quarter, to be looking for binding commitments from the several people that we've been talking to about long-term offtake for the project.

[James Dobson:]

And then on a separate topic, Devon, I assume that wasn't synchronized with the grid in time to give us any benefit in the second quarter as your comments are, it sort of got done late June, early July and sort of moved forward from there? Is there COD data I guess I'm asking on that?

[David Crane:]

It's multiple units, John a couple came on in June.

[John Ragan:]

We had three of the four units come on in June, kind of spaced out on a one-week basis. So they were synchronized to the grid during June. Three of the four units.

[Operator:]

Your next question comes from the line of Michael Lapides of Golden Sachs.

[Michael Lapides:]

Can you walk us through which of your coal plants you expect to spend capital on for environmental retrofits and just the timing of that? And can you also walk through, with contract expiring in 2014 at big Cajun, how the cost of that gets recovered from your counterparty?

[David Crane:]

John, do you want to?

[John Ragan:]

Michael, right now, we finished all the work at Dunkirk and Huntley. We are currently putting controls in place on Indian River 4. As we'd mentioned earlier, this year we stopped work on Indian River 3 and completed a new structure with Delaware that allows us to continue to run that unit for a period of time and then shut down. So that's really where our CapEx is being spent right now. Regarding the lodge in assets, again, we see these being able to recover that CapEx and new contracts that we structure with the co-ops in Louisiana. So we do think that we can get recovery for that CapEx when those controls are put in place.

[Michael Lapides:]

And Texas, what are your planning in terms of environmental CapEx in Texas?

[John Ragan:]

Well, again, right now we’re doing the engineering work to determine what we need to do. But again, until we get a better sense of the macro about acid gases, it's a little more difficult to determine exactly what we will do there. If, as we expect EPA to be pragmatic around how they go about facilitating the reductions, again, we don't see the worst case scenario where we have to control unit by unit. So until we have a better sense of that, it's a little hard to say how the CapEx will be spent in Texas.

[Michael Lapides:]

And on South Central, little confused about the cost recovery. I mean your hedge prices there roll up to about $50, $51 a megawatt hour. Foreign energy prices, kind of the low 40s. So even if you put a capacity payment on it for a combined cycle, it would get you mid- to really high-40s, low-50s. I'm a customer, why do I do it?

[David Crane:]

Well, I think there are a few things going on, Michael. First of all, I think that you -- I mean first of all, I mean we're sensitive to the fact that the co-ops, like everyone who serves load are very price sensitive, and it's one thing to say that we have the right to charge it through and at least for the customers whose contracts expire in 2014, they obviously have the right to not renew. But I think when people have looked at this issue at South Central, they've exaggerated the ease with which a customer to Louisiana Generating could switch because it's a constrained transmission system down there. Our plants have the transmission rights to serve these customers who as you know, are spread all over Louisiana. So it may not be a straight, look, I can get a price 2% lower from someone else that you're suggesting. It's a more complicated assessment. Having said that, like I said, we want to work with the co-ops to smooth out the path, and get the right outcome for them and their customers. Mauricio, did you have anything to add on that?

[Mauricio Gutierrez:]

The only thing that I would add or emphasize is the congestion aspect of it. We have firm transmission to the customer, the customer has firm transmission from our facilities. Anybody else who wants to serve that customer will have to have firm transmission, which could potentially require cost transmission operates or redirect our transmission cost. So that's puts us in a competitive advantage with respect to a generic combined cycle, economics in the region.

[Operator:]

Your next question comes from the line of Jonathan Arnold of Deutsche Bank.

[Jonathan Arnold:]

Question on STP and just if you could clarify what the status of the TEPCO investment is that was announced on the last quarterly call? And I apologize if I didn't kind of glean this from the prepared remarks. I wasn't quite sure what you said on that.

[David Crane:]

Well, TEPCO go investment is conditioned upon receipt of the DOE loan guarantee, so it hasn't happened yet. Having said that, TEPCO has been a technical adviser to the project from the beginning and since they fully expect the DOE loan guarantee to come through, I mean, we're working with them. But the trigger for the injection of the first fund from TEPCO has not occurred and will not occur until the DOE loan guarantee is received.

[Jonathan Arnold:]

So nothing else has changed on that front. It's part of the working through the Japanese financing aspects.

[David Crane:]

Well, no. I mean, when you say Japanese financing, to me you're talking about the Japanese government co-financing on the debt side which TEPCO is working with us to get those funds or those guarantees from the Japanese government. No, I'm talking about the TEPCO equity investment which is not related to Japanese financing. It's actually related to DOE financing. Once the DOE award is granted and accepted by us then that will trigger their injection of capital into the, I think, $155 million. That would be the trigger for them to inject $155 million into the project.

[Operator:]

Our last question comes from the line of Brandon Blossman of Tudor, Pickering and Holt.

[Brandon Blossman:]

But just kind of to make it explicit, Wholesale 2010 guidance up $100 million to $150 million. What has changed in your view for the year?

[Mauricio Gutierrez:]

Two things. One, is the Texas fleet being able to serve or sell premium products to Reliant. And then the second is some upside on the Northeast markets. I mean we just saw very little fuel switching, particularly around March and April time frame. All the other months, we've been running pretty healthy on our solid fleet.

[Brandon Blossman:]

So I mean to be fair, it is largely Reliant retail driven for the guidance update both on explicitly on the retail side and implicitly on the product transfer pricing picture?

[David Crane:]

But your question was on the Wholesale side. I mean, I think we split out the extent to which it was Reliant and the guidance on Slide 22. But yes, on the Wholesale side, it was both Texas and the Northeast.

[Brandon Blossman:]

It continues to be a great acquisition. A little bit of hedging in '11, you mentioned it was largely option-based. Is that gas collars or is there some power in there also?

[Mauricio Gutierrez:]

It's primarily gas collars.

[David Crane:]

Well thank you very much. And operator, thank you for your assistance and again thank everyone for tuning in on Monday and for your interest in NRG.

[Operator:]

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.