NRG Energy Inc (NRG) 2012 Q2 法說會逐字稿

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.

At this time all participants are in a listen-only mode.

We will be facilitating a question-and-answer session toward the end of today's conference.

(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 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 no more than 45 minutes.

As such, we ask that you limit yourself to only one question with just one follow-up.

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, and the press release in 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 a lot of it may be anticlimactic compared to previous earnings calls, because as everyone I think on the phone is aware, we did speak with everyone just two and-a-half 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've spent the last two 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'm pleased to report 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 of this year and we're on track for completion in 2013 and it is a truly impressive undertaking there.

And our partners in this transaction, our ownership partners, Google and our technology partner, BrightSource, and the construction company, Bechtel, are doing a fabulous job.

So let's get into this.

I'm going to refer to the slide presentation that's on our website, so on slide 4, in terms of second quarter highlights, starting financially.

I think as most of you know, given the normal seasonality, the second quarter is not generally the most exciting quarter for competitive power companies, or IPPs.

For us, it's better than most, and this is in part due to the fact that the summer comes earlier in Texas than it does in the northeast United States, and that has a good result on both our wholesale and our retail business.

And of course the advantage we have over most others is the fact that we do have a particularly vibrant retail business and our second quarter results, which are listed on this page, and which Kirk is going to go into greater detail on, shows this $539 million of EBITDA for the quarter, which rolls up to $839 million for the first half of the year.

Not listed on this page is a very robust free cash flow performance for the quarter, but Kirk's going to go into that, so I don't want to steal his thunder.

We did list the retail contribution, and this is very important, obviously, in a year where I think to date in the summer, as I'm sure people are wondering about, even as we get into the third quarter, we've had sort of broadly good weather, summer weather across most of the United States.

We have not had the extreme weather in Texas that we had last year, and so the contribution from retail is very important and very positive.

As we mentioned two and-a-half weeks ago, and we will reaffirm yet again today, we are reaffirming our guidance for the year 2012, and in a good position to reach that.

We also again reiterating what we talked about two and-a-half weeks ago.

We are giving preliminary guidance for 2013 and 2014 and per undertakings that we've made since then.

Kirk's going to give a little bit more detail on how we get to those points.

Obviously, this guidance in this presentation is given for the Company on a standalone basis, which actually serves as a building block for what we actually expect to achieve when we successfully close the deal with GenOn at the end of the year.

I think the important thing to me about this preliminary guidance, and there was a lot of discussion on this in the last quarter, recall is that after several years of -- in a declining, low commodity price environment with hedges wearing off, which has sort of led to declines in our full year, full Company performance, is that we intend to and expect to stop that decline in terms of the range of outcomes that we expect.

And this is largely as people will see when Kirk talks about it, because the other parts of our business are coming on to support our original wholesale business.

Beyond our financial results just listed on this page very quickly as everyone knows, we also are moving on several fronts in terms of doing things which we think are in the great interest of our shareholders.

We'll be making our first dividend payment, first ever, record date August 1. Payment to be made on August 15.

We increase our overall corporate liquidity position through the sale of Schkopau, which was our last remaining non-core asset in Germany.

And as I mentioned with Ivanpah, our other solar projects remain on track, and you may have seen a recent announcement that Agua Caliente is now the largest operating photovoltaic plant in the US, and is massively ahead of schedule.

Moving to slide 5, which just, again, a slide which sort of depicts the strategic direction of our Company in the wake of what -- of the NRG GenOn proposed combination.

I think this is well-known to everyone on the phone.

The combination itself is the center of our Management focus, but in the context of our investor outreach over the last couple weeks, we really didn't find any investor that had any serious question about how this fit with the strategic direction of NRG, so I'm not going to dwell upon it.

Obviously, while the strategic logic is clear and compelling, as Management what we're paid by our shareholders to do is achieve the financial results that can come out of the combination.

So we're very focused already in terms of integration planning on this $300 million of combination synergies that we expect that we can get out of this transaction, and planning is proceeding very well for that, even though it's in the early days.

So finally, before I turn it over to Mauricio to talk about the second quarter operating performance on page 6, we put down the approvals that we need to achieve in order to get to GenOn.

Again, transaction done.

Again, it's early days, but the filings are proceeding on time.

We haven't really come across anything, or had anyone sort of raise their hand and say they see a big problem with this.

And so we're very confident about the direction of this transaction and the timetable, and continue to be on target for closing by the first quarter of 2013.

I look forward to answering any questions that you have later and with that I'll turn over the call to Mauricio.

Thank you, David, and good morning.

Our integrated platform continued 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 at our Bertron plant in Texas out of mothballed 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 on to 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] 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 Rouge received Star recognition from OSHA.

This is the highest level of recognition in the program, and Big Cajun is our tenth 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 costs more than offset the negative impact from our availability metrics.

The reduction in coal generation was partially offset by higher production from our Encina plant in California, our combined cycle facility in South Central, and the return of STP from its unplanned outage.

Our GAAP portfolio continues to perform exceptionally well with a 98% starting reliability.

Longer run times this quarter reduced the number of starts by 30%, leading to less stress on our units.

Moving on to slide 9. NRG's Retail business had another strong quarter.

Year-to-date, our combined Retail business grew by over 60,000 customers, while also increasing volumes, even with weather less favorable than the second quarter of 2011.

Furthermore, the business added new products and expanded into new geographic markets.

We now have a retail presence in 12 states with over 300,000 customers buying more than one service from our retail business.

For the quarter, margins increased slightly driven primarily by lower supply costs.

Our enhanced retail supply strategy mitigated the impact of price spikes during the heat wave in late June.

The result for the quarter is that we struck a balance between customer count and margin, consistent with our long-term strategy, and this strong performance enabled NRG to remain the largest retailer in Texas.

Turning to slide 10.

I want to share a few observations on two of our key value drivers.

Lets me remind you that our generation portfolio, like any other merchant, is significantly leveraged to both heat rates and natural gas prices.

Our Retail business provides counter cyclical earnings, which we continue to realize this year.

Our rich management framework allows us to be exposed to short-term price spikes with our peaking units.

And more broadly, structural commodity changes in the medium to long term.

In Texas, so far this summer has been relatively moderate with just a few hot days at the end of June and July.

Those were enough to set new peak load records for each month.

Leading prices have been low as a result of moderate temperatures.

Prices spike when hot weather showed up resulting in volatile week and month ahead markets.

These spikes have provided us an opportunity to hedge some of our megawatts at attractive prices while managing our operational risk.

We continue to believe the market fundamentals in Texas are very bullish.

Load growth is expected to remain robust.

Return margins continue to tighten and are expected to be single digit as early as 2014.

And the market reforms implemented by the PUCP are a good first step towards providing the right economic signal to support new investments.

But as you can see on the lower left chart, more structural improvements to the competitive market are required to achieve ERCOT's reliability targets.

Turning to natural gas.

There are some additional signs that the market has started to work off the excess supply and appears on its way back to sustainable balance.

[REIT] Counts are down more than 50% from the peak, year-on-year gas storage have been cut in half, and we're seeing our sixth straight month of flat production.

Gas prices have responded accordingly and have increased more than 50% over the past few months with forward prices also firming up.

Moving on to our hedging disclosure on slide 11.

As you can see, we did not change significantly how we have positioned our portfolio.

In the short term, we remain well insulated from natural gas prices and most of our exposure is to heat rates in Texas, where we believe recovery is imminent.

In the medium to long term, we remain largely open, and if the market improves, we will benefit from a heat rate and a gas recovery.

Turning to coal, and more specifically transportation.

We're in advanced negotiations around our limestone coal contract which expires at the end of this year.

Our coal inventories remain manageable, and we continue to work with coal suppliers and rail companies to add flexibility into our contracts.

As I mentioned to you in prior calls, we are constantly evaluating the economic viability of all our power plants, particularly those in the northeast where capacity and energy prices have been significantly depressed and plant economics are challenged.

I am pleased to inform you that we have reached agreement with National Grid to allow two units at Dunkirk to continue operating until May of 2013, and our plant is very well positioned to fulfill the remaining reliability needs identified through 2015.

Finally, while in the short term we're pretty well hedged from gas prices, our integrated wholesale retail model, and our exposure to the Texas market will provide significant upside in the very near future.

With that, I will turn it over to Kirk for the financial review.

Thanks, Mauricio.

Beginning with the financial summary on slide 13, NRG is reporting second quarter 2012 adjusted EBITDA of $539 million, with $320 million from our wholesale business, and $219 million from our retail platforms.

For the first six months of 2012 adjusted EBITDA totaled $839 million, $508 million from wholesale and $331 million from retail.

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 recorded 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 provided on slide 14.

As 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 before 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 a part of our announcement of the GenOn transaction on July 22.

Specifically, we are maintaining a 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 in our south central region, and some modest increases in environmental spend in Texas.

As I indicated in my remarks on July 22, the guidance ranges for 2013 and 2014 reflect our expectations for NRG on a standalone basis, and exclude the accretive benefits from the pending transaction with GenOn, which will be incremental to these numbers.

Finally, in order to provide some further clarity regarding our EBITDA guidance for each of these years, we've broken down the expected EBITDA contribution from our solar projects, retail and wholesale.

And we expect our committed solar projects to contribute $70 million to $75 million of EBITDA in 2012.

That's an increase of about $5 million over the range of expected solar EBITDA I discussed during our first quarter call.

That's reflective of the impact of accelerating the pace of the construction in our Tier 1 solar projects.

As these projects continue to reach COD, we expect our EBITDA contribution to increase to a range of $200 million to $210 million in 2013 and $320 million to $330 million in 2014.

Our retail businesses is having delivered more than $330 million EBITDA through the first half of the year, despite the milder weather, especially in Texas, remain on pace to contribute $625 million to $700 million in 2012.

We expect retail to deliver EBITDA of $650 million to $725 million in 2013 and EBITDA of $675 million to $750 million in 2014, as we continue to reinforce our position as the leading retail provider in ERCOT and our expansion into the northeast delivers additional growth.

Importantly, these retail numbers reflect our expectations for standalone growth and are prior to any of the additional benefits from significantly expanded northeast generation platform resulting from the GenOn merger.

The wholesale segment includes the addition of El Segundo, which will achieve COD in August of 2013, with 2014 benefiting from a first full year of operations at the plant.

Now turning to slide 15.

On committed growth investments, we now expect a total of $470 million of growth investments for 2012, which represents a $45 million increase over our May 3 guidance of $425 million.

This increase is primarily due to the accelerated spend in our big three solar projects, which as you know, are Agua Caliente, CVSR and Ivanpah, as well as investments in distributed generation.

And for 2013 and 2014, we now expect a total of $379 million of growth investments, and actually that's a $10 million decrease over our May 3 guidance of $389 million.

And that's largely due to the impact of accelerating that spend in 2012 that I spoke of a few moments ago.

Finally, turning briefly to corporate liquidity on slide 16.

Our total liquidity increased by $336 million during the quarter, due to higher revolving credit facility availability, partially offset by lower restricted cash balances.

The increase in the revolver availability was due largely to the impact of the Agua Caliente sell-down, and changes to cash and cash equivalents are primarily due to the net impact of $540 million of adjusted cash from operations, plus proceeds from the sell down.

These items are offset by $448 million of capital investments, $104 million of debt payments and that includes the $72 million of open market purchases I mentioned a few moments ago.

Our liquidity position will be further strengthened during the second half of the year by the proceeds from the sale of Schkopau received in the third quarter.

And that $174 million in sale proceeds will also increase our RP basket by a commensurate amount, which, when combined with the $250 million in net income for the second quarter, further enhances our ability to support our newly initiated dividend from an RP perspective.

With the issuance of shares in connection with the GenOn transaction as I mentioned on July 22, which we expect to close by the first quarter, will further expand RP capacity, eliminating any perceived constraints on capital allocation flexibility on the whole going forward.

With that I'll turn it back to David for some closing remarks.

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)

Jon Cohen, ISI Group.

Hey, good morning.

Just had a couple questions.

First, on retail.

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 in.

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

Okay.

Jon, 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 costs would go down by having generation to back up load?

Well, I think the way we've always portrayed the synergy value between wholesale and retail in ERCOT, which is what we're trying to replicate in the northeast, one, the collateral savings that we get by crossing generational load.

And then the second is just providing or being more comfortable capturing the load following premium using our retail vehicle as opposed to managing or hedging our portfolio in the wholesale market.

So I would say that those are the two main drivers, and it is different depending on the market dynamics.

But specific numbers I think it would be very difficult to tell you at this point what is incremental, 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.

Okay.

Thanks.

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, which is the biggest component of that is our El Segundo project out in California, which is online in 2014.

So that contributes a full boat of EBITDA in 2014.

I don't think we 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.

I know you're thinking about expanding some plants in Texas.

I was just wondering if there was any EBITDA contribution in there?

The bulk of El Segundo or the bulk of the repowering project is El Segundo.

There's some minor degree of capital expenditures around eVgo and some of the new businesses, but the lion 's share of the EBITDA contribution from the repowering investments comes from El Segundo.

Okay.

Thank you.

Angie Storozynski, Macquarie.

Thank you.

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 contributions 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, 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 50% of that.

Agua Caliente is just under $1 billion worth of debt and we only 51% of that, by virtue of the transaction with MidAmerican.

So you deduct basically 50% of those two components from the total.

So roughly speaking about $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 any more insight into your retail growth prospects in PJM, but, how should we think about it?

I just, David and Mauricio, I doubt that you're merging with GenOn for cost synergies only.

I think that there is -- there are growth prospects embedded in the plan.

Could you give us a sense where we are now for PJM volume wise, and how we should think about it volume wise, not margin wise, but volume wise going forward.

Mauricio, do you want to give that information?

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, 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, 50% has been in Texas, 50% has been outside of Texas, particularly in the northeast.

Green Mountain, with some of the premium products have been very effective in the northeast market, particularly around mass customers.

So we are very encouraged by those results.

But, Angie, 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 through April 14, the growth assumptions that we have are pretty conservative across the retail businesses.

Angie, let me add to what Mauricio's saying.

Because I think if there's 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 months ago, our first focus was on the cost synergies and the other synergies that were announced two 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.

We will be evaluating that going forward and talking 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's customers are on month-to-month basis.

One of the advantages this allows us to do is it will 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 be -- we'll be talking about it in the future.

But none of that's built into the basic calculation of why we want to do this transaction.

Okay.

Thank you.

Dan Eggers, Credit Suisse.

Hey, good morning, guys.

Mauricio, I was wondering if you could give a little more update on what you guys are seeing in ERCOT, by way of coal to gas switching coming back with the gas price rally, both as the second quarter progressed, and what you guys are seeing as we've rolled through July at this point.

Well, I think, Dan, if you look at -- we tried to provide some specific examples on the earnings slides.

With the gas rally, 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 that's what I would say in terms of coal to gas switching.

Our expectation, and keep in mind, natural gas is one component, but the heat rate, which from our perspective, there is a small relationship between heat rate and natural gas, but to a greater extent heat rates are a function of the tightness in the market.

Natural gas has other different drivers.

We think that, we don't expect that to persist I guess in balance of the year.

Certainly on the forward market, when you start getting into '13, '14, '15, with gas prices in the high $3s, low $4 territory, you're significantly out of the PRB switching area.

Okay.

Thanks.

And I guess just on ERCOT in general, obviously the price caps you have maybe room for some more volatility in pricing, but probably not enough to attract or sustain attractive and durable investment in new assets.

Can you give us an update 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 think you're right, Dan.

The forward spark spreads do not incentiveize new build economics.

We believe there is at least $10 per megawatt hour of offsite 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 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 PUCP, we want to see a well-functioning, competitive market that provides the reliability that the state requires.

And I think the [Brower] report was very clear that even with the steps that the PUCP have taken in terms of price caps or floor prices on reserves, there is still a gap to incentiveize those new builds.

And that missing money has to come from somewhere else, whether it's a research -- a capacity market or some other form or type of resource of equity 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 recognize that price gaps will not get you to the target reserve margin, that you need something else.

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 everybody recognizes that there's got to be something else done to be able to incentiveize those new build economics.

Mauricio, you think about kind of the time line between the workshops and people trying to build toward a consensus for something else, what do you think is the realistic conversion from some sort of conclusion here to an implementation and how it could affect the power markets from a tangible, monetary perspective?

Look, I mean, if you take your reserve margin as your barometer on how tight is supply, demand.

You're seeing in 2014, basically single digit reserve margins, significantly below the 13.75% target from ERCOT.

I think 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 we will be -- we would be happy to continue this conversation, Dan, in terms of the clarity and the visibility that we see in the ERCOT process.

Great.

Dan, if I could just add to 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.

Thanks, guys.

Gregg Orrill, Barclays.

Hi, thanks.

Sorry to stick with the last question, but I was wondering if you could elaborate a little bit more on kind of the unwillingness, it seems to -- or the trouble that policy makers 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 sort of the resource adequacy, and I think there's a greater sense among the policy makers in Texas that something akin to 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 works and sends the right price signal.

So that's the type of dialogue we're having with them.

As Mauricio said, we've been very encouraged that there has been 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 matter is modifying.

I don't think that what ERCOT will end up doing is something that -- 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.

Great.

Thank you.

Brian Chin from Citigroup.

Good morning.

In the last few weeks we've gotten a fair amount of updates on San Onofre out in California.

Could you just comment on what does the bilateral capacity market or resource adequacy outlook in California look like over the next few months to year, say?

How has that changed?

And then can you give us a little 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 recontracting 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 it the old college try or else he'll avoid it.

But, just for everyone on the phone, 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 Encina has worked, been online much more this summer.

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 at San Onofre?

Well, I mean, our official position, we don't comment on anything that might be pending but I would say 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 question.

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 on that one, David, if that's all right.

That's fine, Chris.

Okay.

What we've seen so far is a lot of uncertainty on potential return dates.

Obviously, that really has -- what it's done is muddied the water quite a bit.

It's obviously a big unit there that's missing and know 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, has really kind of widened out and that's about the update that we have right now.

I can't say that it's tracking one general direction because it's so wide right now, because no one knows really what's going to happen out there.

Could I ask what the bid ask numbers actually are.

I can get those for you.

I don't have them -- we can go into some details another time.

I think we've got another couple people we still need to get through.

We can chat about that at another point.

Okay.

I'll follow up with you offline.

Thanks.

Sounds good.

Operator, I think we have time for two more questions.

We want to adhere to our undertaking to get people on their way earlier this time.

Julien Dumoulin-Smith, UBS.

Good morning.

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 it would be, if either, a little bit more of a retail push, although we have an active C&I capability that's working in the region and doing a good job.

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 pursue both.

But since you said more C&I, I wanted to push back and say maybe a little bit more mass market.

Great.

Thanks for the clarity.

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?

Not to provide guidance, but just getting a sense on New York, seems like that could be pretty material.

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

Sure.

Julien, as you know, there is a -- I would say that there is 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 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.

We saw how I would say digital the price can be in New York, just by virtue of having one unit announced mobile, that they're retiring and then taking a second look.

So I would say that the -- I think that the fundamentals are there and it's just a matter of determining when that will happen.

Great.

Thank you for the clarity.

Do you have one more caller.

Keith Stanley, Deutsche Bank.

Good morning.

I'll stick to just one question, given the time here.

Can you just provide a little more color on progress and a potential time frame for selling down more of the solar portfolio or looking at the tax equity market?

I would think as some of these projects are coming into service, and 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 then as a second part of my question, are there any restrictions at all in place on sell downs of solar assets or accessing of the tax equity market under the merger agreement?

Well, Keith, I think let me -- the second question about -- it seemed like a three part question for one question.

But at least the second part about the sell-downs or -- Kirk can answer those questions.

What I would say to you is, from our perspective, for us when we sold part of our 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 it 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.

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 sell-downs, especially on the larger projects, and I'll use that as a segue to answer your other question.

We're certainly continuing to pursue straight sell-downs along the lines what you saw Agua Caliente.

I think if I had to predict, that is the that is the type of modernization you'd see, more along the lines of our larger solar projects, the big three.

We are also in parallel continuing to work on the tax equity front, and that's more likely to be the case with respect to some of the smaller projects, for example, the remaining six of our Tier 1 solar portfolio.

And we would 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 pendency of the merger.

Thanks a lot.

That's very helpful.

Well, Erin, I think we've run over our stay, so I just want to thank everyone for participating in this call.

Obviously, we will be back with you for our third quarter earnings call at around the beginning of November.

But given that we do have the GenOn merger pending, and I think there will 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.

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.