NRG Energy Inc (NRG) 2007 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the NRG Energy fourth quarter 2007 earnings results conference call.

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

Following the presentation, we will conduct a question-and-answer session.

(OPERATOR INSTRUCTIONS).

Also note that today's conference is being recorded.

I now would like to turn the meeting over to Ms.

Nahla Azmy.

Please go ahead.

Thank you.

Good morning and welcome to our fourth quarter 2007 earnings call.

This call is being broadcast live over the phone and from our Web site at www.NRGEnergy.com.

You can access the call presentation and press release furnished to the SEC through a link on the investor relations page of our Web site.

A replay and Podcast of the call will be posted on our Web site.

This call, including the formal presentation and the question-and-answer 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 February 28, 2007, 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.

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.

And now with that, I'd like to turn the call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Nahla, and good morning, everyone.

I'm joined here today, as usual by Bob Flexon, the Company's Chief Financial Officer; Kevin Howell, Head of Commercial Operations; Drew Murphy, our General Counsel; Krishnan Kasi, our Chief Risk Officer, John Ragan, our Northeast President -- the Northeast region had a phenomenal year last year; and for reasons that should be obvious from anyone who has read the earnings release, by Clint Freeland and Mauricio Gutierrez.

This is the first call of the year where we normally set the stage for the year ahead, and we are going to do some of that.

We are also going to talk about the changes in the organization that were announced in the press release today, because they are a little bit out of the ordinary.

But as I said in the press release today, these are evolutionary changes rather than revolutionary changes in the way that the Company is organized.

And this is actually the end of an organizational process rather than the beginning, in that these changes were determined and decided upon last July and we've been working through to this conclusion today.

So I'm going to be referring as we go through the presentation to slides which appear on the Web site, and I will be referring to those.

So starting on slide 3, the table of contents, actually, after 15 quarters of using the same format, in the last few quarters, we've actually not even had a table of contents.

I only remark on it now is that this is actually the organizational format that we're going to be using going forward.

I will be giving the operational review this quarter, but in subsequent quarters it will be given by Bob Flexon.

So let's begin.

On slide 4, since we have a lot of information to go over today, as always, and there's a lot of information on our earnings release, I wanted to flag for you the three things that I think are most important about today's announcement.

First, with respect to the Company's full-year 2007 financial performance, to me, the key number is $1.25 billion.

That's our free cash flow result before special environmental projects and growth CapEx.

This healthy result, which exceeds our guidance, leads directly to the double-digit free cash flow yield, which you can find calculated in Bob's section of the presentation, and which remains the fundamental investment proposition of this company.

I have said on these calls and in many one-on-one meetings in the past, we manage this business for cash, and this result proves that 2007 was no exception.

Second, while our company has adopted a slightly more conservative posture with respect to our liquidity, in light of the current capital market environment, we have never been more strongly positioned, both from the point of view of our current liquidity and in terms of how we collateralize our commercial operations activities.

Perhaps more importantly, the current capital market environment has not affected our commitment, which we first made approximately one year ago, to return to our shareholders on an annual basis at least 3% of our market cap, either by way of a share buyback or through common stock dividend.

And indeed, we are disclosing today that we have already begun the share buyback program for 2008, having repurchased $100 million worth of our shares in the last few months, of course, prior to entering the current close period.

And third, while the development process for new power plants, particularly those involving new technologies, remains very lengthy, we made meaningful progress across almost all of our development efforts in 2007, and we are positioned to put further distance between us and our competitors in this area in 2008.

Moving to slide 5, in 2007 you can see some of the highlights of how we executed across our major areas of day-to-day business.

I can't go over all these because of time, but would like to highlight a couple of items.

First of all, in terms of asset sales, as we have always told you, we are always looking to optimize our asset portfolio, both core and noncore.

With respect to noncore assets, our record has been to act deliberately to ensure that we realize maximum value, and that has worked for us through the more than 20 asset disposals which we have carried out over the last four years, almost all of which have exceeded market expectations in terms of sales proceeds.

This is the approach we have taken with respect to our Brazilian project, ITISA, in recent months.

We have a binding sales agreement for $288 million, and we expect when that project closes to be able to repatriate to the United States about $250 million net cash.

The project is not yet closed; we expect it to close by the end of the second quarter.

Not all approvals have been obtained yet, but we are confident as to what has been obtained that there is no obstacle that we see to closing out this transaction.

With respect to safety, NRG ended 2007 with an OSHA recordable injury rate of 1.6, which is a 20% improvement, and well beyond the 2006 industry average of 3.9.

This is an important milestone for our company, because 1.6 puts us in the top quartile within the power industry.

This great result was achieved only by an all-hands-on-deck effort at all NRG locations and at all levels of the organization.

I want to commend everyone at NRG for their contribution to this result, and I want to particularly commend the plants that either are participating in the OSHA Voluntary Protection Program at this time, or are going through the lengthy application process now.

In terms of plant operations, there was an equally broad and deep level of accomplishment across our fleet, so again, I can only note a couple of the true highlights.

The first is that we contributed mightily to keeping the lights on in Southern California, first, through our timely completion of the emergency repowering of the Long Beach plant in time to support the grid during the late summer heat wave, where the plant made 36 starts with 99% reliability; and secondly, during the late fall California wildfires, which disrupted transmission into San Diego County, forcing the [Cal ISO] to rely totally on the very limited in-county generation like ours to keep the lights on.

Similarly, in New York City, our Arthur Kill plant was repeatedly dispatched out of the merit order, so much so that its energy production for the year was up 97%, and the plant responded with admirable reliability.

The other highlight that I want to mention was our South Texas nuclear plant.

At this point, everyone knows that we have applied to build a new nuclear plant at STP, STP 3&4.

But quite distinct from that effort is the exceptional work the STP operating team has done with STP 1&2.

I could recite the numerous operational awards that this plant received in 2007, but suffice it to say that for the year, STP was again the top generating two-unit site in the United States.

These special performances feed into the fleet performance statistics, which appear on page 6.

Although our 2007 baseload Equivalent Forced Outage Rate performance was down year-on-year, they remain much better than two years ago.

I don't intend to try and explain this result away to you, because as a company which bases its operations on a philosophy of continuous improvement, we are not happy to have taken a step backwards from 2006 to 2007, and we hope and expect to change the direction of this bar chart in 2008.

However, there are two significant mitigating factors.

The first is that only four out of the 20 operating coal units in our fleet had a preponderance of the unsatisfactory EFOR performance.

This allows us to concentrate our focus on those units as we troubleshoot the problems.

The second mitigating factor is, as demonstrated in the upper left, one of our principal FORNRG objectives was to recapture nameplate baseload capacity.

And our achievements in this area had a positive impact that exceeded the impact of the incrementally higher EFOR rate.

Despite the EFOR results, our total free generation was up year-on-year.

The substantial increase in production at STP I already mentioned is noteworthy.

But also, there's the enormous decrease in energy sales from our Texas gas plants.

This has nothing to do with the reliability of those plants, but was a result of the extraordinarily wet and mild summer in Texas last year.

We expect our Texas gas fleet to do much better in 2008, assuming normalized summer weather.

And finally on this slide, I want to talk a bit about our coal inventory, because I know that the coal world is abuzz with red-hot coal pricing that people are telling you will last forever.

As you can see from this chart, our aggregate inventory levels stand at approximately 45 days as of the end of January.

We opportunistically increased our inventory prior to the current run-up in coal prices.

And if you now turn over to slide 7, you'll see our total fuel position longer-term -- 100% contracted for 2008, 93% for 2009, 64% for 2010, and so on.

And please keep in mind as you consider our exposure to higher coal pricing that Eastern coal represents only a fraction of the coal that we consume.

It is so little in fact that the less than 1 million tons a year of Eastern coal that we use is subsumed in this table on the lower right in the category labeled other.

The other important point you need to understand about NRG and coal consumption is that even among Powder River Basin coals, NRG uses much more 8400-BTU coal then 8800 coal.

And 8400-BTU coal is even less-suited to the international and the Eastern coal markets than the 8800, and as a result, has been subject to considerably less pricing pressure in recent months.

The other point I want to make on slide 7 is actually about a nonevent.

You will note if you compare our hedging chart on the left to the one that we showed last quarter, there's been essentially no change in our hedging profile.

This means that it's been almost a year since we engaged in significant additional hedging activity.

And to me, that is the beauty of our strategy.

We can sit out the market when gas and storage is high and gas price volatility is low, as they both have been, and as such, we consider ourselves a patient bull waiting for the time when strong fundamentals and weather push gas prices above our targets, enabling us to lock in long-term prices at favorable levels.

On slide 8, this slide goes hand-in-hand with the prior hedging slide.

And again, there's very little change.

We have the fundamental short-to-medium-term risk posture that we think provides the best risk-adjusted return to our shareholders, low to moderate gas price sensitivity over the next few years, and much greater exposure to increases in baseload heat rates.

Now turning to slide 9.

I want to highlight one other benefit of our hedging strategy, which is highly profitable at this point in time.

We have run sensitivities of our earnings to general economic recession using the 1990 recession as our guide, because we think that recession is more similar to what the country is facing now, but on the assumption that the expected recession that we face now would be significantly longer and harder than the one that occurred in 1990.

On these assumptions, the negative impact on our 2008 EBITDA would be significantly less than 1% of the total.

I also want to point out that while not being an economist or an expert on these things, I have to question how much of a recession we will face in two of our core regions, Texas and Louisiana, with crude oil prices hovering at $100 per barrel, even if there is a national recession.

But all the same, the impact on us is less than 1% of our EBITDA in 2008.

As such, I think it's fair to say that while NRG may not be recession-proof, we are highly recession-resistant.

These discussions of merits of our hedging strategy over the past few slides provide an appropriate point of departure for me to discuss the management changes that are being announced today.

I am firmly convinced that this company and you, our shareholders, have benefited enormously from the hedging strategy, including the hedge reset of November 2006, which was implemented by our commercial operations group over the past three years.

While speaking on these quarterly calls, and otherwise to investors in one-on-ones and at industry conferences, we generally have not sought to feature the invaluable role played by our comm ops team in the success of this company.

We have kept it low key because comm ops generally doesn't like to give any signals to the market as to what they are thinking.

And also, a little bit more selfishly, for reasons of human resource retention, we don't like to flaunt to the market how good our team is.

So let me blow that tactic out of the water and basically say that NRG has the most capable asset-based trading and marketing team in the business, and the person who has built that team and led it to considerable success that it and we have achieved is Kevin Howell.

What has also impressed me in working with Kevin over the past three years is not only what he and his team have achieved, but also how they have achieved it.

As AEP and others found out several years ago, there's considerable challenge in grafting or developing a hyper-aggressive and self-interested trading and marketing team on top of a generating asset base and a power plant company culture.

Yet Kevin has built a team that functions effectively and pretty much harmoniously alongside our plant operations.

This has taken a deft touch with respect to personnel, both his own team and his colleagues in senior management.

Indeed, I can say I have learned more about personnel management from Kevin Howell then I have from any other single person in my entire career.

It is these management qualities that caused me to ask Kevin to take on the role of Chief Administrative Office, a post from which he will be responsible for ensuring that NRG has all the capabilities that we need, both in terms of software -- and by that, I actually mean the right people -- and hardware to realize all the extraordinary opportunities that currently are presented to us in our marketplace.

With Kevin in charge, I'm confident that we will have the tools that we need to achieve our destiny as a company.

Now before I cede the floor to Bob Flexon for his 16th and last quarterly turn as the Chief Financial Officer of NRG Energy, I want to take a quick look back at what has been accomplished on his watch.

I could think of no more fitting testament to Bob Flexon than, as he might say, to go to the numbers.

Slide 10 attempts, through a long series of financial metrics, to show the financial strength of this company at the time of Bob's arrival in early 2004 and where we are now.

I know of no other chief financial officer, certainly not in this industry, who has achieved so much, starting with so little, in such a short time as Bob Flexon.

Now, a reassuringly large number of you on the phone have been with us since the beginning, and have witnessed the financial strengthening of this company over the past four years.

I know you don't need to be convinced of what Bob Flexon has accomplished with this company and this balance sheet.

Indeed, it seems to me that the Company's progress in this area has been so obvious that there are only three people in the whole financial world who don't get it.

Unfortunately, as you can tell from the bottom of this page, those three people are named Mr.

Standard, Mr.

Poor's, and Mr.

Moody's.

When I think that we have one major rating agency that has not acknowledged any improvement in our financial condition since our inception, and we have another major rating agency that has had us on negative outlook for 14 months, notwithstanding our $2.7 billion of current liquidity, I am literally at a loss for words.

But maybe my speechlessness is a function of what my daddy used to say.

David, he would say, never try to rationalize the irrational.

Never try to defend the indefensible.

Anyway, trying to get back on the high road here, it's been my immense honor and pleasure to work with Kevin and Bob in their current positions as the Head of Commercial Operations and CFO, respectively, and I look forward with great anticipation to working with them in their new positions as Chief Administrative Officer and Chief Operating Officer.

I know I should probably say something at this point in time about Clint and Mauricio, if only because they are both sitting here in this room looking at me.

But rather than singing their praises now, I would rather do that after they've proven themselves to you, the owners of this company.

But I would say that they've been a big part -- working with their teams and with their extremely capable colleagues, they've been a big part of the success of this company to date.

And suffice it to say that the three of us -- Kevin, Bob and myself -- have total confidence that they will succeed in their new positions.

And they have our full support.

So with that, I will turn it over to Bob Flexon.

Thank you, David, and good morning.

Today I will provide our customary review of the fourth quarter and full year 2007 financial performance, update our guidance for 2008, and set forth our 2008 capital allocation plan, along with the necessary implementation steps.

Also, in response to requests, for the first time I will provide adjusted EBITDA information on our portfolio, assuming a [limited to unhedged] position.

Slide 12 provides an overview of our financial performance and plans.

2007 adjusted EBITDA of $2.28 billion was well in excess of our initial 2007 guidance of $2.05 billion, but $20 million below our November 2007 target of $2.3 billion, primarily due to the impairment of two commercial paper investments and higher-than-expected outage costs in December.

Although full-year adjusted EBITDA came in slightly below November guidance, our free cash flow from recurring ops exceeded our November target, coming in at $1.25 billion.

The 2007 recurring free cash flow yield was a very healthy 12.8%.

As we typically do, our capital allocation plans for 2008 are off to an early start with the December 2007 launch and January 2008 completion of $100 million of common share repurchases.

In addition, our board authorized in February 2008 an additional $200 million in share repurchases, which we expect to be complete by November 2008.

On December 31, 2007, we prepaid $300 million of our term loan B.

By doing so, we achieved a corporate debt to corporate EBITDA ratio, as defined in the credit agreement below, [of] 3.5 to 1.

By achieving this threshold, the Company benefits by receiving a 25 basis point step down in the interest rate charge from the $2.8 billion term loan B and $1.3 billion synthetic LC facilities.

Slide 13 provides additional high-level financial comparisons for the 2007 results.

The left-hand side of the slide shows the free cash flow and the primary reasons for the actual result of the $75 million higher than guidance excluding collateral.

As I noted a moment ago, the free cash flow yield on primary shares outstanding was 12.8%, while the fully diluted calculation resulted in a yield of 11.2%.

Adjusted EBITDA for 2007 was $2.279 billion, a 52% increase, or $777 million higher compared to 2006.

We were $21 million below guidance, mainly due to the commercial paper impairment of two investments and higher-than-expected outage costs.

Liquidity has improved dramatically from last year, while our net debt to capital ratio also showed significant improvement as compared to 2006.

For a more detailed look at the fourth-quarter results, please turn to slide 14.

The fourth quarter 2007 adjusted EBITDA results increased $182 million to $518 million compared to 2006.

The current-quarter revenues and margins benefited from a $169 million increase in the Texas region from the November 2006 contract hedge reset.

Energy margins for the quarter increased by $149 million, as the increase in revenue from the hedge reset were slightly offset by lower prices from bilateral contracts and other merchant energy sales.

Generation in the Texas region was up a net 297,000 MW hours.

This increase in generation quarter-over-quarter reflected exceptional operating performance at STP, contributing 577,000 MW hour increase, which was partially offset by reduced gas plant generation and slightly lower coal-fired generation from unplanned outages at Limestone and WA Parish.

The Northeast reported improved results compared to 2006 with a fourth-quarter adjusted EBITDA of $113 million, a $51 million increase from the $62 million reported in last year's fourth quarter.

The quarterly adjusted EBITDA improvement was driven by increased energy margins and capacity revenue.

Energy margins benefited from higher prices and increased generation.

At Indian River, generation increased 23% as demand rose from favorable pricing and colder weather in December, while at Arthur Kill, generation increased 96%.

Capacity revenues in the Northeast region increased by $26 million for the quarter, mostly due to the transition capacity market in NEPOOL, which started in December of 2006, and the new RPM capacity markets in PJM, which started in June of '07.

South Central's fourth-quarter adjusted EBITDA declined by $35 million compared to 2006.

Energy margins were $30 million lower during the quarter, mostly due to the major planned outage at Big Cajun Unit 3, higher coal costs, and higher transmission costs.

The outage resulted in lower merchant sales and required increased purchased power to fill our load requirements.

Development expenses in the fourth quarter are $28 million lower than the fourth quarter of '06, as we received a $39 million reimbursement from our partner, CPS, for development expenses for the STP 3&4 nuclear project.

As I noted earlier, we recognized during the quarter an $11 million impairment on two commercial paper investments.

These losses on previously highly-rated paper were triggered by the liquidity constraints in the money markets at the time of default and the issuer's inability to refinance its maturing commercial paper.

Our cash is currently invested in money market funds backed by US treasuries.

Our full-year earnings comparisons are illustrated on slide 15.

Our adjusted EBITDA excluding mark-to-market activity grew $777 million, with many of the same factors that influenced our three-month comparisons also appearing in the 12-month comparison.

Again, the Texas revenues attributable to last November's hedge reset, new Northeast capacity revenue programs, and the significant increase in development spending, are the primary factors.

These and other key contributors to the year-over-year improvement include $123 million and $8 million for the full-year inclusion of Texas and West regional results, respectively; $594 million from the year-to-date impact of the hedge reset on Texas contract revenue; $170 million higher Northeast margins due to the combined impacts of higher generation and higher realized prices within the region; $130 million in increased capacity revenues, of which $80 million was in the Northeast; and $65 million increase in net development expenses, mainly to support the STP COLA submission, which was a net cost after reimbursement of $52 million in 2007.

In the Texas region, the gain from the hedge reset, higher baseload generation of $1.4 million MW hours, and higher merchant margins on bilateral sales executed by our comm ops group, helped offset a 35% decline in Texas gas generation and reduced contract revenue, resulting in increased energy margins of $577 million year-over-year.

O&M expenses within the Texas region increased by $30 million, mainly due to increased outage and other costs at our Parish facility and at gas plants, and increases in property taxes.

Northeast gross margins benefited from 6% increase in generation due to colder weather in 2007 versus 2006, higher realized prices, increased capacity revenues, and increased generation at our Arthur Kill station.

Average realized power prices in the Northeast rose an average 9% compared to last year.

This, combined with 6% increase in Northeast generation, led to a $170 million increase in energy margins.

Capacity revenues in the Northeast increased by $81 million in 2007 when compared to 2006; $39 million in NEPOOL, primarily from new (inaudible) market and transition capacity payments introduced in the fourth quarter of 06; $36 million in PJM, mostly from the RPM capacity market, which started on June 1, 2007.

Net sales of excess emission allowances for the entire company decreased by $32 million, due to the combination of increased generation in the Northeast and decreased market prices.

Development costs for repowering projects totaled $101 million, including $52 million for STP, after recognizing the $39 million of reimbursement, and $17 million for wind projects.

G&A costs increased by $26 million year-over-year, exclusive of January 2007 for Texas, due to higher wage and benefit costs attributable to higher corporate headcount and wage benefit increases.

Franchise taxes in Louisiana increased by $5 million, due to the higher levels of the Company's capitalization from the Genco acquisition.

Free cash flow generation remains a core strength of this company, as illustrated on slide 16.

Although slightly below adjusted EBITDA guidance, free cash flow from recurring operations was $38 million higher than guidance, primarily due to $43 million in higher-than-forecasted working capital improvements fully offsetting the $37 million greater-than-expected collateral requirements, and $21 million in lower maintenance CapEx, primarily due to project delays and lower-than-expected costs.

Recurring free cash flow yields for 2007 were 12.8% and 11.2% on basic and fully diluted shares outstanding.

Repowering CapEx was lower than guidance due to the timing of wind power investments.

As shown on slide 17, the combination of the free cash flow results, and our active management of the balance sheet and credit facilities, resulted in the Company's 2007 year-end liquidity increasing over 2006 by nearly $500 million.

Even more impressive is that this increase is net of the $200 million reduction we made to the LC facility during 2007.

Primary cash uses during the year included debt repayments of $408 million and common share repurchases of $353 million.

As we reported in Q3, the Company now has the right under its credit agreement to grant a first lien collateral position to commercial trading counterparties.

During the third quarter, existing counterparties were transferred to a (inaudible) first lien collateral position from their second lien position, in exchange for the return of previously issued letters of credit.

This transfer resulted in the return of $557 million in letters of credit.

Since year-end, an additional counterparty has moved to the first lien position, resulting in an additional $65 million of LCs being returned to the Company.

Our initial 2008 full-year adjusted EBITDA outlook provided last November was $2.2 billion, as shown on slide 18.

To reflect the planned sale of our Brazilian subsidiary, ITISA, we are removing its expected 2008 adjusted EBITDA contribution from our current year's guidance.

ITISA had been expected to contribute approximately $40 million to the 2008 guidance.

Therefore, our 2008 adjusted EBITDA guidance from recurring operations is now $2.16 billion.

Our cash flow from operations guidance for 2008 remains at $1.5 billion, despite the dropping EBITDA from ITISA.

This is due to an expected $42 million increase in the returned collateral, compared to the $3 million return originally estimated.

The decrease in cash interest cost reflects the extension of our nonrecourse sub, CSF I, which I will cover shortly.

Forecasted maintenance CapEx decreased by $17 million as we finalized our 2008 capital spending plan.

The changes in environmental and repowering investments from initial guidance are related more to the timing of projects, primarily wind power, rather than project scope changes.

In response to requests, slide 19 is a high-level look at market EBITDA across our portfolio.

While the market -- while the application of market or (inaudible) EBITDA varies from company to company, our objective here includes being transparent on items included, excluded, and how the numbers are derived.

The bar on the left-hand side is our 2008 guidance, which is based on market price curves adjusted for the hedge profile of the portfolio.

The bar towards the right indicates the 2008 adjusted EBITDA guidance at $2.521 billion, reflecting for the most part an unhedged profile using price curves as of December 31, 2007.

The three bars that bridge the difference represents the impact of three primary groups of hedges -- financial derivatives, normal purchase and sales contracts, and South Central load contracts.

The value ascribed to each of these bars are based on December 31, 2007 market-based price curves contained in our highly controlled risk system that supports our financial statements, as well as our risk monitoring system.

The indicative market prices used at December 31, 2007, are shown in the gray box at the top right-hand side of the slide.

In reality, hundreds of specifically tracked price curves within our risk valuation and monitoring systems are used to value the other line positions.

I've included the same indicative quoted price curves as of February 25, 2008 as the comparisons to the curves of December 31, 2007.

Using the sensitivities provided in the blue box, you can adjust the market EBITDA for the various curve movements.

For example, the impact to the natural gas and coal price changes between the days of December 31, 2007 and February 25, 2008, results in a market EBITDA of $3.17 billion, a $647 million increase.

The EV to EBITDA ratio in this example would be approximately 5.6 times.

For clarity of disclosure, certain contracts and transactions were excluded from the market EBITDA calculation, such as the West region tolling agreement, the RMR contracts in NEPOOL, nuclear fuel contracts, transportation contracts, and certain transmission contracts.

The net derivative assets that are in the money in 2008 slip to a liability in subsequent years, for a total net derivative liability of $473 million.

The roll-off schedule of the derivative liability is disclosed in our 10-K.

The normal purchase and sales contracts, which include coal power and capacity contracts, are below market at December 31, 2007 by $573 million, (inaudible) nearly 90% of the contracts rolling off by the end of 2009.

Going forward, and we'll assess the value of providing this type of disclosure, along with ways to improve it in future calls.

Slide 20 provides a review of our how capital was allocated in 2007.

Consistent with our philosophy of pursuing a balanced approach, highlighted are our primary allocation objectives.

During the year, NRG invested almost $300 million in the existing fleet for maintenance and environmental CapEx, and a like amount for RepoweringNRG initiatives, including both direct investment and development spending.

Simultaneously, NRG continued to return capital to both debt and equity investors in roughly equal amounts by repaying $408 million in debt and buying back $353 million in common stock.

As outlined in the past, our objectives continue to target a net debt to capital ratio of 45 to 60%, a maximum corporate debt to corporate EBITDA ratio of 3.5 times, and a return of capital to shareholders of approximately 250 to $300 million per year.

Slide 21 provides the capital allocation plan for 2008.

As we begin 2008, our objectives remain the same -- achieving balance across the program.

Due to increasing environmental CapEx requirements, we expect investments in the existing fleet to increase to $563 million net of tax-exempt financings.

At the same time, we anticipate investing $321 million in repowering growth initiatives, net of nonrecourse financing.

Concerning debt management, NRG is committed to offering $446 million to its first lien members as part of an excess cash flow offer provision in its existing credit agreement, [and] paying down an additional $129 million in other debt, primarily a capital leases.

Since we believed that our lenders would accept 100% of the required excess cash flow offer upon filing of our 10-K, we accelerated the repayment of our term loan B debt and prepaid $300 million on December 31, 2007.

As a result of this payment, we achieved the required leverage ratio, resulting in a 25 basis point reduction.

The $300 million prepayment will be credited against the required offer to first lien lenders, resulting in a $146 million offer to lenders in the first quarter.

For the capital return to shareholders, we also accelerated the initiation of the 2008 share buyback plan by purchasing $100 million of common shares during December and the first week of January 2008 at an average price of $41.99.

In February 2008, the board authorized the purchase of an additional $200 million in share buybacks, bringing the total 2008 program to the targeted level of $300 million.

We expect to complete these repurchases by November 2008.

In order to have the necessary restricted payment -- or RP -- capacity under our bond indentures to complete the authorized share repurchases, NRG and Credit Suisse have agreed to extend the maturity date of CSF I from October 2008 to June 2010.

While the maturity date of the CSF I debt is being pushed out an additional 20 months, the call options in the structure will expire during November and December 2008, an extension of 30 days, enabling the restricted payment capacity addition from the third quarter 2008 net income to be available for option settlements.

By pursuing this refinancing, NRG retains 100% of the upside associated with the CSF I structure after the option settlement, and shifts the use of RP capacity from debt repayment to common stock repurchases.

As we look forward, we see a clear path to generating sufficient restricted payment capacity to facilitate the return of at least $300 million per year to shareholders in 2008 and 2009.

As slide 22 illustrates, with the natural expansion of the RP basket in 2008 from net income that is expected to be greater than $300 million, combined with the CSF I debt extension to 2010, we have sufficient RP capacity to complete the additional $200 million in share repurchases during 2008.

The remaining capacity in 2008, currently estimated at greater than $130 million after settlement of the CSF I call option, coupled with significantly higher basket additions in 2009 due to a higher expected net income, should provide adequate RP room to deliver our targeted return to shareholders next year as well.

Should additional capacity be needed, NRG may consider extending the maturity of the CSF II structure, currently scheduled for October 29th, or may pursue other alternatives as market conditions allow.

As my tenure as CFO at NRG winds down, I'm certainly proud of the many accomplishments our team has achieved, recognizing that many more accomplishments remain in our future.

As CFO, I had three goals upon arrival at NRG in March 2004 -- build a best-in-class financial team to control infrastructure that safeguards the investments of our stakeholders; prudent balance sheet management that provides an ongoing return to our debt and equity holders; and deliver our numbers.

The people within the CFO organization are very talented and very dedicated.

While time doesn't permit me to individually name everyone, I would like to recognize for their contributions, I do want to recognize three of my direct reports who have been with me from the start -- [Carolyn Burt], [Jim Inglesby], and [Raymond Solor].

I look forward to my new responsibilities, knowing my previous role is in very good hands with Clint Freeland at the helm.

I'll now turn it back to David.

Thanks, Bob.

I know we've already taken up a great deal of the time.

And those of you who are looking at the slide show are experiencing anxiety that we're going to turn this into a Fidel Castro-length earnings call.

And as you look at those --

(technical difficulty)

-- turn impending carbon regulation from a very modest negative to a significant positive in the long-term.

What the relentless focus on carbon has overlooked over the past few months is that there are at least four dynamics underway in our industry which are more immediate, more certain, and more impactful than carbon risk, and all four of them are highly and inherently positive to NRG.

These four are higher forward gas prices, higher heat rates, new sources of capacity payments, and the ever-increasing costs of new entrants, which tends to lift all boats indirectly when it comes to incumbent power generation.

Not only are these four trends positive for NRG, but we're not just a passive price taker with respect to these trends.

As we've tried to depict on this slide, we are pursuing a variety of programs to make sure that we capture these trends to the fullest extent of our potential.

One of the ways we do that is through RepoweringNRG.

And turning to slide 25, I want to actually start here with a bit of housekeeping.

We announced this program in June of 2006 with an initial lineup of 19 projects comprising 10,000 gross MW and costing at that time an estimated $16 billion.

While we said at the time that it was a dynamic program and that projects would be added and others would be dropped, and that we certainly would not achieve 100% success -- and I believe the analysts and the market understood and believed all that -- the original numbers that we attached to the program -- the 10,000 MW and the $16 billion -- we fear is becoming etched in stone.

So to avoid that, we are updating this list, and we intend to do this once a year, and recalculating the current estimate of the cost of the program.

So you can see that on this slide, and there are three main points that I think you should take away from this update.

The first is that while there is no definitive trend in the makeup of the program, our portfolio of new projects is definitely trending from black to green, from coal to know carbon.

Second is that, true to our word, we have been disciplined about investment, and we have dropped development projects that did not meet our risk profile or return criteria.

A case in point is Big Cajun II-4, which was a fully-permitted, large-scale traditional coal plant, which we dropped because we were only able to contract 450 MW out of the 700 MW of nameplate capacity, and that wasn't enough.

And third, while the cost of building generation has definitely gone up over the past few years, as you can see from our estimate here, if you strip out risk premium and profit margin, the price of building things in this country has not gone up as astronomically as many have indicated.

The overarching point I'd like to make is that development and power business, particularly with these new technologies, is a very long leadtime item.

We have made great progress over the last two years in terms of our development program, and even more so in terms of our internal development capabilities.

And now, I think, we have first mover advantage.

And I think one of the things that you should be looking to us in the year ahead to show is how we're going to build on that first mover advantage, and how we're going to turn that first mover advantage into shareholder value now, not just several years down the road.

Turning to slide 26, since the nuclear project is the centerpiece of our development effort, I want to give you as candid assessment as I can of where we are at.

This is particularly the case because as many of you are aware, the Nuclear Regulatory Commission set aside a portion of our combined operating license application until we could provide proper support to those sections.

They took this action at our company's specific request.

Now, to step back a little, at the outset of our planning for nuclear development, we identified the single-most important issue as being determining who would take commercial and technical responsibility for building these new plants on a fixed-price/fixed-scheduled basis.

We reasoned that such an arrangement would most likely only be available from someone who actually had successfully completed a new nuclear plant of the same design.

That is what led us to the ABWR design, which was first built in Japan in 1996, and that is what led us to Toshiba and Hitachi, which are the only two companies in the world that have built an advanced nuclear plant on time and on budget.

It turns out the we were extremely prescient in our thinking.

It has become increasingly apparent, and should be apparent to any of you who are trying in one way or another to invest in the so-called nuclear renaissance, that the issue that is right now threatening to slow or stall the nuclear renaissance in the United States is not a regulatory problem with the NRC; the NRC has been tough but fair, and they are extremely responsive; it's not the rest of the government, since both the legislative and executive branche have now done virtually all that's been asked of them.

What is threatening to slow or stall new nuclear in this country is whether the private sector in the United States doesn't have what I call the will to build.

And let me emphasize that when I said slowed or stall, I was talking about the nuclear renaissance in general.

And when I talk about lacking the will to build, I was referring to the industrial manufacturing and construction complex in the US.

And that, I will remind you, is why we went to Japan in the first place, and to the companies which have actually done this work successfully, with project managers and schedules who are still in the business.

In any case, we are currently in the middle of finalizing the commercial arrangements with respect to the engineering, procurement and construction arrangements for STP 3&4.

Those discussions are going very well.

But even when working with people who have built these plants before, these are highly complex and important negotiations on all sorts of levels, and we would rather sacrifice a few months of permitting time while we get the arrangements right, rather than burden the project with excessive costs or assume unmanageable completion risk as the owners of the plant.

We recognize that we owe our stakeholders a full briefing on RepoweringNRG in general, on STP 3&4 in particular.

We expect to be able to provide that detailed briefing sometime in the next few months.

At that time, with respect to STP, we expect to be able to provide you with substantial clarity as to the ownership offtake and EPC arrangements, the base-case project economics, the financing plan, and the path to regulatory approval.

I am confident that we are on the right track.

Moving to yet another zero-carbon development pipeline, on slide 27, actually, today as we speak, we celebrate with British Petroleum in Texas the ground-breaking of our first joint development project, the 150 MW plant at Sherbino, which will be online by the fall of this year.

We have other projects in advanced development, and expect to announce other locations not too far in the future.

Wind is an important part of both our RepoweringNRG and our ECO-NRG initiatives, and I couldn't be more pleased with what Jan Paulin and his team at Padoma have accomplished to date, with the future prospects that they have in the pipeline, and with the entrepreneurial developer ethos that they have brought to NRG.

In closing, there's a lot going on at NRG, as always.

And in terms of the potential value enhancement, ours is a target-rich environment.

We have listed on this last page some of our vehicles to capture this value.

And to echo my comments from the beginning of the session, we can and will over the next several months pick off these topics with you one by one and cover them in much greater depth.

But in many ways, today's call is about management.

I'm convinced we have the best management team in the business, bar none, and today we are promoting and redeploying not only Bob, Kevin, Mauricio and Clint, but several other key managers who are shifting their position or responsibilities as well.

Each and every one of us at NRG takes very seriously the premise that when you invest in NRG, you are investing with management and also with the 3000 highly capable individuals who made this company hum in 2007.

So with that, operator, I think we have a few minutes for questions.

(OPERATOR INSTRUCTIONS).

John Kiani, Deutsche Bank.

Congratulations on the promotions.

I have some questions on slide 19, the market EBITDA slide.

Bob, you were walking through this slide.

And if I'm reading this correctly, the 3.16 billion of market EBITDA, using Cal '09 curves, is just using the forward curves.

Do you have any numbers or analysis that you can share with us as to what that 3.16 billion of market EBITDA would look like with heat rate expansion and market recoveries?

Some of your IPP peers show this figure not with just the current forwards, but what it looks like under a market equilibrium-type scenario.

Do you have any guidance or help you can give us on that?

John, I included the sensitivities.

So if you look in the blue box on that slide, the last two lines in the blue box show the sensitivity around heat rates.

So if you get a half a heat rate improvement as an example, say, in ERCOT, you get an upside of about $200 million on an unhedged power basis.

So the sensitivities are there; you can just pivot off the prices that are given in the gray box to come up with your own, what you think heat rates could do.

And then you've got the sensitivities there on how to do the math to adjust the EBITDA number from there.

Thanks.

On the restricted payment basket, I think you made some comments that '09 looks like -- looks to be a year where you have incremental or better RP capacity.

Can you walk through that in a little bit more detail?

Sure, John.

When we file the 10-K today, we'll have the chart updated on our baseload hedges that go out to 2012.

And the natural gas hedge price, if you will, on that chart for 2009, at a 73% hedge profile to $7.70, which is $0.20 higher than what it is in 2008; plus you've got 20% -- 27% of the baseload open.

So if you just take that higher hedge price in '09 versus '08, you're going to get a significantly higher net income in 2009 than 2008.

And the basket expands based upon the net income calculation.

Thanks.

That's helpful.

Elizabeth Parrella, Merrill Lynch.

Actually, following up on that same line of questioning.

Bob, your comments with respect to the RP expansion this year -- does that assume no unrealized losses on mark-to-market activity, or is it based on what you see those losses would be using the forward price of gas?

How should we think about that (multiple speakers)

It's based on our forward view of net income, which we just strike -- when we strike that curve, we don't forecast what mark-to-market gains and losses could be going forward, so that will create some noise in the numbers on the net income.

But that's why -- and that's one of the reasons that we leave as much room as we do.

I show that 2008 will have greater than 130 million; we'll actually be fairly higher than a pretty significant increase, over the 130 that I showed.

But that's kind of the cushion that we keep to be able to absorb changes caused by those types of fluctuations.

But, I mean, that assumes -- I just want to be clear -- that assumes you would book some mark-to-market losses, which one would expect given where your hedges are for gas and where the current gas price is, or does it just zero those out for the remainder of the year?

Yes.

And the way you need to look about it as well is that when I show that greater than 300 million expansion, that's the fourth quarter of '07 result, and then the first three quarters of 2008.

So be aware of that risk on the next three quarters.

Okay.

And then, just with respect to the deal with Credit Suisse on rolling this out, if I understand it correctly, their upside, kind of, is capped; as of December, it ends; they don't get any more upside if the stock continues to move up.

We're going to let the CAGR feature, or the option feature in that structure -- we'll settle that out in the fourth quarter.

We're not going to roll that into the future.

So it will just be pure debt beyond November of this year.

Then we'll just settle that out, and we'll keep 100% of the upside of any share price movement within that structure.

My recollection, I think, was that you accrue the interest on this sort of through October of 2008.

Is now there going to be additional interest expense associated with rolling this out another 20 months?

Correct.

At the sort of same type of rate?

Yes.

Actually, the way we are structuring it is we're going to -- it's going to be pretty much exactly the same rate.

It will be the blended cost of, like, 7.5%.

Just one other question.

The hedging profile that you've given us on slide 7, you mentioned what the average gas price was for '08 and '09.

Is that going to be disclosed in the 10-K for all the years in that (multiple speakers)

It is.

It is disclosed.

And I think the slides that we showed earlier on the hedge profile, I believe, is as of the end of January.

And I think that matches up with our K.

Thanks very much.

Michael Lapides, Goldman Sachs.

Congratulations on a great year.

Can you provide a little bit of update on longer-term thoughts regarding your environmental CapEx on existing coal plants?

I'm sorry; longer-term -- how longer-term did you want?

I mean, beyond the multiyear --?

Just in terms of what's contracted, what's not contracted, what you're seeing in EPC costs.

The environmental CapEx budget for 2008 is 359.

Of that 359, about 223 is in the Northeast.

That construction is pretty well -- it's underway and it's pretty well locked in.

So that pretty much covers 2008.

Towards the end of 2008, the South Central will start ticking up, and then in 2009 it becomes the higher level of spend.

I think we're in the beginning process now of tying those costs down, so that's in an earlier stage.

But then further out, really, the one that's up in the air right now is Indian River, which carries a pretty high environmental CapEx cost.

That's at the very early stages, and we're still [wrestling our own minds] whether or not we're going to make that level of investment or not.

So that's still up in the air.

What are your options if you decide not to make the investment in Indian River?

Divestiture?

I think everything is on the table.

We're going down, certainly, the path of making the investment.

We're doing the permitting work that we need, so we're not delaying anything there.

So we are retaining that option to make sure that we do have time to make the environmental improvements.

But if we decide at some point that it's just not economic, the choices then are either you just run it to the end date, or you sell it, or you look for some type of alternative plans for the site, whether it's other forms of generation.

So I think everything is on the table with it.

When you have this type of spend, or this level of spend, you're going to look at four or five different paths, and make sure you take the most favorable one from an economic standpoint as well.

Michael, just to add a little bit to that, the difficult proposition for the Delmarva Peninsula, which is, obviously, geographically a peninsula, is that there's definitely discomfort in that area with coal-fired generation of any type, as we found over the last year.

But there's no gas pipeline down there.

So the options are pretty limited.

So that's the issue that not only we need to struggle with, but the people charged with maintaining responsibility for the grid in that area have to struggle with as well.

Thank you, guys.

Much appreciated.

Brian Chin, Citigroup.

A question on the market EBITDA slide.

For the South Central load contracts -- and please correct me if I'm wrong on this -- there were, if I remember right, a couple of environmental CapEx provisions on those contracts.

How is that embedded in your 1.2 billion number, or is the 1.2 billion just the delta between the current contractual sales price and the current floor curve?

It's the latter.

I didn't do anything to adjust for the environmental CapEx spend and the pass-through.

I'm just, literally as you described, just using current market price versus contracted market price, contracted price.

So if I want to think about this in an open EBITDA framework, what I probably need to think about, then, is what is the value of the environmental CapEx provisions that you have in those contracts as a reducer to the net present value negative impact of this contractual value here?

Is that correct?

Yes.

I think that's correct, Brian.

I would do that.

One other thing, just a qualitative question.

You've got the ABWR contract at South Texas Point from GE, and then you have Toshiba and [Floor] pouring the concrete, effectively.

Given that Toshiba owns the Westinghouse design, how has managing that relationship between those two camps been?

Can you comment on just what's been going on there?

Have there been any problems?

We can comment on a little of it, and most of it we can't comment on.

What we can comment on is that you're right; while Toshiba is also the owner of the AP 1000 design, at no point in our dealings with Toshiba have we ever seen any sense of compromise or a priority of one over the other.

I don't know how much you follow nuclear in Japan, but ABWR is the chosen design of the Tokyo Electric Power Company.

And Tokyo Electric Power Company and the rest of the Japanese utility industry are quite insistent that Toshiba and Hitachi both support the ABWR design now and into the future.

So we've been 100% pleased with Toshiba's support and interest in the ABWR design, whatever they are doing with the AP 1000.

And the rest of your question about -- I'd really rather not comment on at this point.

Fair enough.

Thank you.

Gregg Orrill, Lehman Brothers.

Just coming back to slide 8 on the heat rate sensitivity.

Two questions.

The first is, you have provided the sensitivity around (inaudible) BTU per MWH for around-the-clock heat rates.

How far do you think we are between now and peak for your baseload fleet?

Secondly, you left on the table the upside for the [mid merit] and peaking part of your fleet.

What would that also entail?

I'm going to pass that on to Kevin, so he can give you one of his patented oblique to total non-answers to that question.

The way I think about it, clearly, I think we saw all along that we're still bullish heat rates, which has led to our bias towards gas hedging against the fleet, particularly in Texas.

And we've seen a nice recovery in heat rates.

We're still bullish from this point forward.

Where the absolute peak is, I really don't want to say what we think is left in the market, but we are still bullish from this point on the heat rates.

And I'm sorry; what was the second part of your question?

You provided a sensitivity on baseload to heat rate changes; what about the rest of the fleet?

Just so that we can be comparable to what other companies are providing?

I think -- remind me, Bob -- I think in the past we've kind of notionally said we think about our peaking assets as more kind of out-of-the-money options.

They tend to come into the money very quickly for short periods of time.

But to try and model those in the forward market, you really don't throw off a lot of value from them.

I think notionally, we've talked about those, the way we think about them.

And our forward guidance, Bob, is around 100 million?

On the intermediate, the peaking, on the gross margin, it's the 100 to $150 million.

And if you had a heat rate movement of about a one unit movement, the sensitivity to that is an order of magnitude -- it's around $60 million sensitivity.

Thanks.

Anthony Crowdell, Jefferies.

A question on the New York City capacity market.

Are you seeing any changes in the capacity pricing?

And now that you see, I think, public service in New Jersey is trying to bring a line into the New York City market, have you noticed any changes in the capacity (inaudible)?

Our view is -- and I think we have the information on one of the pages in here -- that we are seeing a definite softness in the New York City capacity market.

It's already trending down.

So, you know, that's the one soft spot in terms of the Northeast capacity markets, where all the other capacity markets we're in we're seeing strength and increasing strength.

But New York City is definitely trending down.

Actually, if you look at the table on the top right-hand corner of page 7, you'll see some numbers on that.

Thank you.

Dan Eggers, Credit Suisse.

Just wanted to follow up on the open EBITDA conversation, just given the breadth of where it looks -- where it could be from where it is today.

Have you guys considered another hedge reset, and is the market available to do that if you've looked at it?

No.

We haven't looked at that, and that's not in our plan.

The other question is -- Exelon's proposed nuclear power station in Texas also has an ownership agreement with San Antonio.

How does that affect your agreement on South Texas, or are we just seeing San Antonio being that power-hungry right now?

I don't know all that much, obviously, about the arrangement that San Antonio has with Exelon.

But certainly, my general sense about the Exelon development is that they're tracking to quite a different timeframe from we are in terms of the path they're on.

Obviously, I don't want to speak for them.

But it just seems that the pace that they're going about it, and going with the design, the sort of more futuristic design that's never been built before, I think they're trending towards the end of the decade rather than the middle of the decade as we are.

So, as far as I know, the load in San Antonio grows quite quickly.

So it would be up to San Antonio, but I don't see any way in which they're sort of setting this up as it's either STP 3&4 or the Exelon one.

And I would see probably more that they think about it as that their load -- baseload for two different time periods.

Thanks.

Operator, I think we probably -- it's 10 minutes after the hour; we probably have time for one more question.

Maura Shaughnessy, MFS.

A couple of quick questions.

What's the expected cash tax rate for '08 and '09?

For 2008, I would use the -- we have -- the forecast for 2008 is $27 million in cash taxes.

For 2009, I'm using for our planning purposes a 25% cash tax rate.

And for 2010, I would use a range from 30 to 35% for cash taxes.

Could you also just talk about what the major outage schedule is in '08 and '09 on the major plants, like STP or what have you?

I know on STP that they actually have two outages in '08, so that's a rare year.

Beyond that, I'm trying to think of anything else that's exceptional.

John, is there anything in the Northeast that strikes you that's different year-on-year?

In the fall of this year, we'll be doing the Huntley -- the Huntley outage will be a little longer than normal, due to the baghouse installation.

Other than that, everything is fairly normal.

Maura, is there something more specific that you're concerned about?

No.

I just wanted to be able to track that schedule.

I think the main year-on-year change is with STP.

Because with the 18-month for two units, there are times when they get through a whole year without one.

And then there are years where they have one.

And then there are years like this one, where they have two.

And given how many megawatt hours they throw off, that one is pretty significant.

But beyond that, I think, it's a pretty normal schedule.

Last, but not least, I was just wondering -- there's, obviously, been a fair amount of wind projects announced in Texas, particularly in West Texas.

And there's some reliability issues there.

I guess there were even some yesterday on the overall wind side.

How do we think about the expected heat rate expansion and just the overall reserve environment in ERCOT vis-a-vis some of the -- all the noise around on the wind side?

I think you raise a very important point, and one that, obviously, is highly topical after yesterday's wind events in Texas.

I can't give you a 100% clarity.

We look at it, obviously, from both sides -- the impact on our fossil fuel-fired fleet, and the fact that our subsidiary is successfully developing wind into that market.

I'll make a couple of comments.

First, in terms of what our overall portfolio -- what we want it to look like.

We want to have wind in the portfolio, but I don't think anyone on the phone should think of NRG as becoming a wind play.

We see wind as complementary to our fossil fuel-fired plant, and we look forward to sort of folding a few wind farms into the seamless operations of our Texas fleet.

The question that you raised and that was highlighted by yesterday's events is, I think, a huge one for ERCOT.

If the system can go unstable -- because in the winter -- because 1500 MW of expected wind turns into 400 MW winds, and then fossil has to scramble to come online, and with several of our plants that had to scramble to fill the gap, you know, that's a big issue.

And there's going to be a big debate.

I think you probably read that ERCOT has commissioned a study to try and decide how much transmission they should bring from the West Texas wind area into the markets.

I think the question of how you maintain system stability in the face of a massive wind portfolio is a big one.

So I think that's probably the single-biggest policy issue that's going to be addressed in any of our markets over the next 12 months.

I know that's not an answer, but that's the best I can -- all I can tell you is that we are fully engaged in thinking about this on all levels.

And, obviously, we'll provide our input wherever we can to whoever will listen.

Thanks again.

I just wanted to say congratulations to Bob.

Thanks for doing such an awesome job over the last couple of years.

Thanks.

Okay, operator.

With that, again, we appreciate everyone's interest in the Company and look forward to talking to you next quarter.

Thank you.

Ladies and gentlemen, this does conclude your conference call for today.

Once again, thank you for participating.

And at this time we ask that you please disconnect your lines.

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