NRG Energy Inc (NRG) 2007 Q1 法說會逐字稿

Good morning, ladies and gentlemen.

Welcome to the NRG Energy first-quarter 2007 earnings results conference call.

(OPERATOR INSTRUCTIONS).

As a reminder, this conference is being recorded today, May 2, 2007.

It is now my pleasure to introduce your host, Ms.

Nahla Azmy.

Please go ahead.

Thank you, Jennifer.

Good morning and welcome to our first-quarter 2007 earnings call.

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

You can access the call presentation and press release furnished with the SEC through a link on the Investor Relations page of our website.

A replay and podcast of the call will be posted on our website.

This call including the formal presentation and the Q&A session will be limited to one hour.

In the interest of time, we ask that you please limit yourself to one question with just one follow-up.

And now for the obligatory Safe Harbor statement.

During the course of this morning's presentation, management will reiterate forward-looking statements made in today's press release regarding future events and financial performance.

These forward-looking statements are subject to material risks and uncertainties that could cause actual results to differ materially from those in the forward-looking statements.

We caution you to consider the important risk factors contained in our press release and other filings with the SEC that could cause actual results to differ materially from those in the forward-looking statements in the press release and this conference call.

In addition, please note that the date of this conference call is May 2, 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 quantitative reconciliation of those figures, please refer to today's press release and this presentation.

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

Well, thank you and good morning to everyone.

As usual, this morning I'm joined by Bob Flexon, the Company's Chief Financial Officer, who will be giving part of the presentation, and as many of you know, over recent quarters we have usually been joined by Kevin Howell, who heads our Commercial Operations.

Kevin is not available today.

So in his stead, we're joined by [Mauricio Gutierrez] who runs our [trade] for us.

I cannot guarantee that Mauricio will be any more forthcoming in answering questions about our specific hedging strategies than was Kevin, but he is here to answer questions.

So, as I go through the presentation, I will be referring to the slides here on our website.

So starting on slide four, what I would like to do is start by just looking back just very quickly.

For those of you who have not been keeping count, I wanted to remind you that this is the 13th quarterly call in the life of the new NRG.

And that number 13 I think is symbolically important.

Not because it is usually considered to be a unlucky number, but because being 13-years-old is often associated with coming-of-age.

I think in many ways the actions we're announcing today are an appropriate manifestation of NRG coming-of-age as a Company.

As you all know from the VIN and now our numbers which appear on the slides, today we are a vastly bigger, stronger and more stable company that we were during our first year of operation.

And when I speak of stability, I mean stability in terms of having a much more consistent and predictable cash flow stream.

And the key, of course, to our cash flow stability is our baseload hedging program.

In that regard, as demonstrated on slide five, we are in an extremely robust position for the next four to five years.

We have at present roughly 8800 megawatts of solid fuel fired baseload generation in our domestic portfolio.

And you can see from this slide that we are very substantially hedged out into the medium-term.

This hedging position and the baseload powerplants associated with it are truly the source of NRG's core financial strength.

Today while we come here to present another solid quarter of commercial, financial and operational performance, I suspect that the main attention will be on our comprehensive capital allocation plan, a plan which is made possible by our successful implementation of this baseload hedging program.

So before I get actually into the quarterly performance, I would like to give you just my views about this capital allocation plan.

The several components to this plan are depicted on slide six.

These five components are interrelated to varying degrees, but they all share the same philosophical underpinning, and that is this.

We strongly believe that after 13 quarters of effective operations and prudent balance sheet management, we should be afforded significantly more leeway to manage the Company's capital in the manner that will maximize the benefit to all of our stakeholders.

This capital allocation plan is but the latest chapter in our never-ending quest for that flexibility.

Bob will provide you with more details on the mechanics of the whole co-op co-structure, which is the key to the plan.

But I want to past that critical step to outline how in general we intend to deploy the additional NRG capital, which will be freed up by our successful implementation of the plan.

We will initiate a recurring dividend on our common shares.

The dividend will be sized not to turn us into a yield player or into a utility equivalent, which we emphatically are not, but rather to establish the simple principle that given the robust and predictable cash flow generation of the Company over the next several years, our shareholders deserve a regular return on their investment.

In our meetings with investors and analysts, a lot of you on the phone over the past 13 quarters, many arguments have been put to Bob and me in support of the introduction of the dividend.

While all of these arguments have merit, the rationale which has particular resonance for me has to do with capital discipline.

It appears that we're entering a period where our markets in our industry are heating up, and while that is generally a welcome development, it also creates some risk of overheating.

Under such circumstances as a company, we must be vigilant and disciplined, particularly in the areas of capital allocation to new growth investments, brownfield projects and potential acquisitions.

Servicing a dividend will help keep us on the same straight and narrow path of prudent balance sheet management, select acquisitions and disciplined intrinsic growth which we have been pursuing successfully since 2003.

In addition to the dividend, we also will continue with share buybacks.

Buybacks have in the past played a critical role in our Company's ongoing capital allocation.

We will continue to look for opportunities to buy back our shares in order to leverage our shareholders further into the Company's equity upside.

We will start in this regard by completing the remaining $165 million of the 1 billion share buyback that we announced last fall.

Our hope had been to complete the current buyback by the end of the second quarter, but emblematic of the constraints that we currently operate under in the area of capital allocation, we are unable to complete the current buyback at this point because of the constraints imposed by our lenders through the restricted payment basket.

We will, however, make significant progress on the buyback in this second quarter and then complete it in the third quarter of this year.

Turning to slide seven, for us the magnitude of the capital allocation decisions which we face cannot be overstated.

NRG is at present a $10 billion market cap company, which is projecting that it will have $10 billion of cash flow from operations to allocate over the next six years.

We have a multiyear master plan that calls for us to allocate capital in roughly equal amounts.

First, to return capital to shareholders through dividend and share buybacks.

Second, to pay down our corporate debt.

Third, to reinvest in our existing assets through our ongoing CapEx program.

And fourth, to invest equity capital in the intrinsic growth projects being pursued under the repowering NRG banner.

At the same time, as you can see from this slide, there is fifth wedge, which remains free to be allocated either to stakeholders or back into the business as industry and market circumstances dictate.

And I want to emphasize that that fifth wedge is not smaller than $2 billion.

So finally, on slide eight we present our four core initiatives -- FORNRG, future NRG, repowering NRG and echo NRG.

Since we spend a lot of time with the outside world articulating our core growth plans through FORNRG and repowering NRG, you should be well aware of these programs.

Future NRG and echo NRG, both of which were launched internally during 2006, are less well-known and for now at least indirect in their benefit.

I want to briefly describe them to you as a significant amount of time within NRG is spent on these initiatives, and they remain very important to the success of the two better known initiatives, as well as to NRG's business overall.

Future NRG is intended to address our personnel needs.

We are fortunate to have a deeply experienced and highly professional workforce.

But, as with the rest of our industry, our workforce is aging.

Moreover, with our intrinsic growth plans, we face the need for significant additional managerial and technical talent over the next several years.

Future NRG consists of a targeted mix of workforce planning, management training and entry-level recruiting.

In the months and years to come, we also intend to do further outreach to ensure that the vocational schools and technical colleges in the areas of our facilities are training the type of people who we will need to secure NRG's future.

Echo NRG is the umbrella program under we gather all of our efforts to comply with existing environmental rules and regulations, evaluate best technologies to remediate emissions from our existing plants in order to comply with current regulations, and finally, to seek out new environmental solutions which we can demonstrate at our facilities and potentially invest in, which seek to address the unsolved environmental issues of our time, particularly, of course, carbon emissions.

These four core initiatives although seemingly separate and independent of each other are part of an integrated whole.

Together they form the basis not only for our effort to ensure the best possible current performance, but also to ensure that we are in the best possible position to compete effectively in our space over the medium to long-term.

Now I would like to turn back and talk about our operations during the quarter and moving to slide 10.

Starting with safety, we are off to a good start with improvement in year-on-year performance so far.

But, as they say, a lot of time remains on the clock.

The improvement in performance across the NRG classic suite is particularly noteworthy.

But, of course, counting accidents and injuries after they happen is not the main thrust of our safety philosophies.

Prevention is and in that regard I am particularly pleased at the staff and plant management at five NRG classic plants are working together to qualify for OSHA's VPP program, which has been such a success for us at our NRG Texas plant.

In terms of operating performance, there are many important performance metrics which we monitor, but the single most important remains the forced outage rate at our baseload facilities, which is shown in the bottom left quadrant of this slide.

In the first quarter, our Texas baseload plants turned in a spectacular performance under the leadership of [Mike Reed], [Don Poe] and [Bob Osco].

Our Northeast and South Central coal plants for the most part performed strongly as well, except for one unit, Indian River 4, which suffered condenser and water wall issues throughout the quarter, leading to an [E4] rate for that unit of over 20%.

That, in turn, pulled up the E4 rate for the entire NRG classic baseload fleet.

Indian River 4 is now in the middle of a previously scheduled 10-week outage, which we expect to dramatically improve its reliability as we and it enter the critical summer months.

Indeed, in terms of summer preparedness between our expansive spring outage work at Indian River 4 and at virtually all of our other units across the fleet, and the coal stockpiles which had been built during the recent period of soft coal prices, we are in a better position this year going into the summer than I have seen during my previous three summers at NRG.

On a final operational note, I want to reaffirm that we remain on track to achieve our $200 million FORNRG target for 2007.

We continue to achieve large and small successes in this program across the Company, and I would just like to leave you with one example.

At our Devon facility in Connecticut, we had LM6000's operating under an RMR agreement.

Their start time averaged 40 minutes.

With the introduction of new capacity markets in [Needpoole], Tom Walker and his Devon saw an opportunity to capitalize on the locational forward reserve market.

By working with contractors at a minimal cost, the Devon staff has cut the start-p time of their units in half, enabling those units to participate in the 30-minute fast-start market, which is the LFRM market, and consequently providing significantly improved capacity revenue returns.

Now looking at the capacity markets more generally, we continue to see positive capacity market development in our core Northeast regions.

These markets have been clearing at higher price levels, providing evidence of the tightening reserve margins across the regions.

The most significant upside for NRG in these regions comes from the [Eastern Mac] pricing point in PJM, which is New Jersey, Delaware and in Needpoole.

The stronger pricing which we expect in these capacity markets in the near-term has now been reflected in our forecasts and have contributed to the increase in our revised forecast.

Now turning to slide 12 in the energy only ERCOT market.

We first take a look at the very modest change in our baseload hedge positions since the last quarter.

Our philosophy has been to put on additional hedges during bullish commodity cycles, but we are quite comfortable with our overall hedge position so we can be quite selective about how bullish that cycles needs to be for us to put on substantial additional hedges.

While commodity prices were generally strong during the quarter, our view is that based on fundamentals, prices will only get stronger over time.

On the fuel side and specifically commenting on coal, I would first note that we are very heavily hedged beyond our burn needs in 2007 as we have started to build inventory during the low-price period of recent months.

And as PRB prices have recently risen, albeit modestly, we have added that additional inventory at prices below current market levels.

We have purchased approximately 2.8 million tons in additional PRB coal supply for delivery during the 2007 to 2009 timeframe.

Now I would like to draw your attention to the heat rate curve shown in the bottom right of this slide, specifically in Texas, which, of course, has the most significant impact on our portfolio.

What I would like to point out here is the improvement in the 2008 to 2010 range.

This is essentially evidence of the strong fundamentals in that market due to tightening reserve margins and now the anticipated lack of sufficient new build.

That lack of new build has not been reflected beyond 2011 yet, but we expect that it will when people realize that the new build is going to be slow to come.

On slide 13, as we always do, we show our sensitivity to gas and heat rates.

We have significantly reduced our exposure to movements in the gas prices from the hedge reset as you can see on the left-hand chart.

That said, we continue to maintain our view that we should retain significant heat rate upside, particularly for the 2010 to 2012 period which we do and as shown by the chart on the right.

Now, before I hand the floor over to Bob, I would like to give a brief update on our repowering NRG initiative and the industry and market circumstances that surround it.

In short, as demonstrated on slide 14, with the well-publicized events of the past few months, the new build market is in more turmoil than ever.

Some of these factors, traditional pulverized coal plants, developments under severe pressure to the point where some people are referring to it as a de facto coal moratorium.

IGCC plants awaiting government funding and also a public/private solution to the sequestration issue, the entire spectrum of construction costs and equipment costs from wind turbines to steam turbines have become more expensive and more uncertain as to what exactly the prices are.

And then the virtual certainty is that there will be imposed a cost on carbon, but uncertainty as to who, when, by how much and to whom they will be applicable.

When you add these four factors to the fact that even though heat rates have strengthened substantially in our core markets, they generally are not yet at a point that would support on its face a decision to proceed with the construction of new capacity, and what it adds up to from our point of view is paralysis and indecision.

This paralysis and indecision is compounded by the fact that in virtually all situations in all regions public policymakers are in a position to make pivotal decisions about what gets built and by whom and with how big an environmental footprint.

This is a clear distinction from the last construction phase that our industry went through and a key reason why the likelihood of an overbuild developing is much reduced.

In this opaque environment, we want to be prepared to succeed in all potential outcomes.

We believe that between our proposed investment in new capacity through the repowering NRG program, which is the logical solution to policymakers planning for the long-term, and our maintenance and environmental investment in our existing portfolio, we are well positioned to do well in the two extremes shown on this slide, namely rational public policy implementation or no public policy implementation.

What we are now working on is to ensure that we do well in the middle phase where the public policymakers act but only after they are faced with a near emergency.

We have a natural advantage in this regard as states looking to add capacity on a super fast-track basis inevitably will need to turn to incumbent generators like us who already have site control, fuel-in and transmission out.

Looking at slide 15, with respect to our repowering objectives over the balance of the year, we have many significant milestones on virtually all of our projects, but probably the three most important are finishing the Long Beach emergency repowering project on time and on budget.

Second, submitting the combined operating license application for South Texas project three and four.

And third, securing the necessary funding and commercial arrangements for the Huntley IGCC project.

As I have stated previously, our repowering NRG program has never been premised on achieving 100% success rate.

But success in the program in the broader sense is essential to the revitalization of our plants, the gradual decarbonization of our generation fleet and to the servicing the wholesale generation needs of our customers and our markets.

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

Thank you, David, and good morning.

Today I will cover our first-quarter results, provide an update for our 2007 outlook and present an overview of our comprehensive capital allocation plan being announced today.

I will begin with a review of the first-quarter results.

The first quarter 2007 adjusted EBITDA was $508 million versus $295 million for the same period last year as shown on slide 17.

Operating results benefited from a full quarter of NRG Texas financial results in 2007 versus two months in 2006.

January 2007 Texas operations contributed $51 million of pre-tax operating income and $123 million of adjusted EBITDA, excluding the impact of $23 million of mark-to-market movements.

NRG West contributed $8 million of additional EBITDA as a full quarter of consolidated results in 2007 are included due to the acquisition of West Coast Power on March 31, 2006.

The West region's operations in the first-quarter 2007 benefited from $26 million in capacity revenues from new tolling agreements that are Encina and El Segundo generating stations.

During 2006 revenues from the sale of excess emission allowances totaled $4 million versus $57 million for the same period last year.

Prior year sales were primarily in the Northeast region where mild weather and lower generation lead to a greater bank of available allowances.

This year's higher generation combined with the 59% decrease in SO2 emission allowance market prices led to the $53 million decline in emission revenue.

EBITDA for the Texas region benefited from higher plant availability and the accompanying $39 million reduction in purchase power and $21 million in lower natural gas costs.

In addition, energy contract prices were higher due to last November's hedge reset, which contributed $39 million in additional revenues.

Coal costs were $6 million lower in 2007 due to lower transportation costs.

Northeast margins benefited from higher powered prices and from an 11% or $11 million increase the Northeast generation following a relatively colder winter in 2007 than in 2006.

[Oswego] had five times more generation in the first quarter of '07 versus the same period in 2006.

Power price increases in Western New York, New York City, New England and Eastern PJM ranged from 4% to 12% higher in the first quarter 2007 compared with the first quarter 2006.

Increased market prices, along with favorable settled positions on hedge contracts, combined for a $42 million quarterly revenue improvement.

Northeast capacity revenues increased approximately $25 million, $12 million from the Needpoole assets and $12 million from the New York assets, mainly attributable to the Western New York market.

Needpoole assets benefited from the introduction of the [Elatharan] market on October 1, 2006 and transitioning capacity market on December 1, 2006.

Western New York capacity prices increased to $2.16 per KW month from $0.82 per KW month in 2006 as load growth increased demand for capacity, while new capacity markets in Needpoole reduced exported supply into the New York market, thus improving the supply/demand dynamics.

South Central margins declined $13 million from the first quarter of last year.

Merchant sales were 300,000 megawatt hours lower in 2007, primarily due to cooler weather, which increased demand from load serving customers, thereby reducing the available megawatt hours for sale to the merchant markets.

Revenues from energy sold to contract customers increased by $17 million, while merchant revenues declined by $38 million.

Development spending for the quarter was $23 million.

$16 million for the expansion of the STP nuclear generating station as we prepare for the submission of the combined operating license application.

Other quarter-over-quarter reduction in EBITDA were caused by $6 million in property taxes, $17 million for the timing of outages, $8 million in net G&A increased due to staffing and related costs and an $8 million decline in equity earnings, mainly from our [Meadedrag] investment.

As shown on slide 18, much of the first-quarter EBITDA improvement was offset by higher interest and collateral payments.

Adjusted free cash flow was a net use of cash of $15 million, largely due to $208 million in cash interest payments, $155 million higher than last year's result of the additional indebtedness incurred to finance the Texas acquisition and the hedge reset.

In comparison to last year, this increase was mostly offset by the reduction and refinancing payment associated with last year's NRG Texas acquisition.

Net cash collateral movements this quarter are $120 million in cash outflow for collateral postings and collateral return to counterparties in connection with hedging activities versus a net $230 million received in 2006, a swing of $350 million.

Capital expenditures increased from $35 million to $85 million quarter-over-quarter.

The increase was primarily due to $38 million for STP nuclear fuel and maintenance CapEx in 2007.

In addition, the Company incurred $22 million in capital investment for the Long Beach repowering project.

Adjusted free cash flow exclusive of collateral movements more than doubled from $38 million in 2006 to $105 million in this year's first quarter.

The Company's liquidity at March 31, 2007 is presented on slide 19.

The $155 million decrease in liquidity since December 31, 2006 was due to the $15 million negative free cash flow just discussed, as well as $19 million in scheduled debt repayment.

Also, during the first quarter, we continued with Phase II of our previously announced share repurchase program and reacquired 1.5 million common shares for $103 million.

As I mentioned at our year-end earnings call in February, our internal forecast was updated in the first quarter for the balance of 2007.

Our updated guidance is shown on slide 20.

We have increased our annual adjusted EBITDA guidance by $100 million to $2.15 billion.

Roughly 25% of the increase is due to the favorable first-quarter results.

Another quarter can be attributed to the delay in the Gladstone divestiture with the balance in increase to power and capacity prices and the EBITDA attributable to our Long Beach repowering project.

Due to delays in securing the approvals from our partners in the Gladstone investment, we added the projected equity earnings back to our guidance for the balance of the year.

Cash flow guidance has been updated for collateral where we increased our forecast to 2007 outflows by $25 million for collateral supporting positions that mainly settle in 2008.

Working capital where we are voluntarily accelerating our projected pension funding by $31 million in light of the new pension funding legislation.

CapEx where we slightly increased both maintenance and repowering capital requirements for this year.

The increased repowering capital reflects our recent decision to proceed with the Cos Cob, Connecticut project.

This project will add 40 megawatts of peaking capacity at a total cash cost of $18 million, including $7 million this year.

Free cash flow guidance for 2007, inclusive of these changes, increased to $893 million from $879 million.

I will now shift the discussion to provide additional detail on today's capital allocation announcement.

As our shareholders are well aware since the Company's rebirth in December 2003, we have continuously experienced the high-quality problem of generating strong free cash flow levels that lead to the buildup of cash balances, only to get trapped by the restricted payment covenants contained in our various debt agreements and indentures.

Historically, working within these restrictions, we successfully developed structured solutions that provided a pathway for the efficient use of excess cash balances for returning capital to shareholders, coupled with debt reduction initiatives.

Today's announcement builds upon our past success of creating solutions, which allow for the efficient allocation of excess capital and the optimization of NRG's capital structure.

Slide 22 provides an overview of today's announcement that impacts the Company's debt and equity.

In connection with our Term Loan B announcement announcement on May 4, we plan to meet with our first lien lenders to propose amendments to the credit agreement that include the following.

First, we intend to reduce our synthetic LC facility from $1.5 billion to $1.3 billion.

This reduction is possible due to an arrangement with an existing counterparty that eliminates any LC requirements on existing hedges.

Reducing this LC facility will generate $4 million annual cash savings.

Second, we will be pursuing a repricing of our existing first lien facilities through a 25 basis point reduction to the pricing grid for the Term B debt and the synthetic LC facility.

This change is expected to generate annual cash savings in excess of $11 million per year.

Third, we will seek amendments which will provide greater flexibility in executing the repowering NRG initiative, and fourth, we will be asking our lenders for their commitment to replace at NRG's option up to $1 billion of NRG's existing term loan with a new delay draw senior secured Holdco term loan.

In addition to the cash savings outlined above, the announcements today that affect our common shareholders include, declaration of a two-for-one stock split to shareholders of record on May 22, 2007.

The planned completion of our previously announced Phase II common share buyback.

The remaining portion of the Phase II amount to $165 million and will be completed in the second and third quarter of 2007.

Our original plan was to complete the buyback in the second quarter.

However, our restricted payment capacity or lack thereof under our bond indentures prevents us from completing it until Q3.

And finally, initiation of a cash dividend in 2008, along with the commitment to continued common share buybacks in the future.

The key takeaways concerning these announcements are that without changing NRG's consolidated leverage, we are creating sufficient restricted payment basket capacity through organization and capital structure adjustments to ensure continued covenant capacity to support our ongoing commitment to return on average about 3% of the Company's current market cap to shareholders each year through dividends and share repurchases with just under half in the form of cash dividend and the balance through open market common share repurchases.

Before going into detail on the Holdco structure on slide 23, I will first summarize the key takeaways.

Successful implementation of the Holdco structure will expand the restricted payment capacity of our bond indentures by nearly $1 billion.

Upon formation of Holdco, existing NRG common and preferred shares will be exchanged for identical Holdco level securities.

The financing for Holdco, which has been underwritten by Credit Suisse and Citigroup, is being syndicated as part of the May 2007 Term B repricing and amendment process in which we will ask investors to simultaneously commit to a strip of new Holdco loans with the (inaudible) facility.

And finally, Holdco debt is a delayed draw facility and will not be funded until appropriate regulatory approvals are received, which is expected to be in the fourth quarter.

Now I will go into more detail in implementing the Holdco structure.

On the left hand side of slide 23 is a very high-level chart depicting the corporate legal entity structure.

Currently NRG Energy, Inc.

is the parent company, as well as the operating company or Opco, which holds our first lien debt.

(technical difficulty) -- company as shown on the right-hand portion of the slide.

At this time, the Holdco debt will be funded by the Term B lenders, and the net proceeds will be paid to Opco as an equity contribution.

Opco must and will use the net proceeds to pay down its Term B debt to the lender group.

The net impact of this transaction will be the expansion of NRG's restricted payment basket under the indentures by $1 billion without changing the leverage profile of the Company.

The mandatory take provisions under the Opco first lien remain the same, while the Holdco debt will have a mandatory offer commencing in 2009.

Slide 24 provides a historic and future view of capital allocation at NRG.

A review of our capital allocation accomplishment demonstrates an established track record in addressing debt management, returning capital to shareholders and reinvesting in the existing operations and expansion opportunities.

The future capital allocation model is a balanced approach providing combining the fixed commitments of mandatory debt paydown, recurring common stock cash dividend and ongoing environmental and maintenance CapEx with a variable opportunistic approach for additional debt reduction, common share buybacks and repowering investments.

Slide 25 reverts back to our financial objectives provided during our year-end call.

Progress has been made on all fronts, and combined with our first-quarter performance, we are off to a strong start for the year.

With today's announcement on capital allocation, we have created a win-win solution for our debt and equity holders while creating a more efficient flow of capital to investment opportunities.

I will turn it back to David for closing comments and questions.

Thank you, Bob, and really I will be very brief, Jennifer, before we open the lines for questions.

I simply want to say that while it may seem like that these quarterly calls we're introducing new concepts, I think that what we're doing here is all very consistent with the strategy that we have been pursuing from the beginning.

So, as we look forward and as you think about NRG in the next quarter, I think what you will see is more of the same.

More focus on operational success, more focus on our commercial operations and hedging and also efficient allocation of our capital for the benefit of all our stakeholders, our equity investors and our debt investors.

With the trends favoring us, I think that we are in a very good position to move forward.

So with that, Jennifer, we would be happy to take any questions that anyone on the line has.

(OPERATOR INSTRUCTIONS).

John Kiani, Deutsche Bank.

The first question is for Bob.

Can you walk us through some of the deciding factors in going the holding company route instead of the bondholder consent option?

Was it I guess partly the lower cost of the holding company structure and maybe the ease of execution?

Can you walk us through the thought process there, please?

Sure, John.

When we look at the alternatives, and basically the alternatives are coming down to a consent process or going with Holdco, we felt the certainty of execution around the Holdco and it's also a very cost-efficient structure.

If you look at it on after-tax costs, you are talking in the order of magnitude 10 to $15 million for a $1 billion capacity.

So it is a very economical way to approach this.

We have certainty of execution, and we can do it in a relatively short time line.

So for us it was clearly the best path for us to go.

Thanks.

That is helpful.

And then, David, can you give us an update on the Padoma wind generation team and their progress in their development process?

Do you have any sites secured?

What is the status there?

John, what I tell you about wind, it is just a few things.

One is we're very, very pleased with the progress that Jan and his team at Padoma have made in terms of developing wind sites.

As you know, we slightly reoriented them when we acquired them last summer, indicating we wanted them to focus on developing wind projects in places where we had fossil fuel fired plants under the idea, which is as yet unproven, that there is going to be a premium market developing for those who can offer firm wind.

But anyway they have taken up that challenge, and they have progressed at several sites still in the sort of -- still in the confidential stage.

But I would also note that some of the uncertainty that I talked about in the development world in general very much applies to the wind world.

It tends to be an overheated sector.

Certainly the prices at which wind acquisitions have transpired recently is well beyond our price range.

Wind turbines themselves, particularly those that are manufactured outside the United States, are moving up with the weakness of the US dollar.

So we have to be very disciplined as we look at wind investment to make sure that it is in the right place and it is at the -- it meets the right investment criteria.

But we're confident that you will be hearing positive things from us in this area certainly before the year is out and maybe before the next quarter is out.

Great.

And just one more quick question.

Can you give us the status on the partners and the decision-making process for the STP expansion?

I think that, on the STP expansion, I mean I think we remain confident that the situation with the partners is progressing in a favorable manner.

I think in the past we have indicated that one or both the partners may or should make a decision during the second quarter.

I think that, John, as a result of the timing of city counsel meetings and the like that that actually might be a third-quarter decision.

But we feel that it is completely on track in that regard.

Elizabeth Parrella, Merrill Lynch.

Bob, I just wanted to quantify, the dividend payment and the interests on the Holdco debt, do those flow through the RV capacity of the high yield bond?

I mean are they deducted annually against the RP capacity?

It will be a hit against the RP basket for the high yield.

So it will be carved out of the first lien, but for the high yield, it will be a reduction of the available basket.

But the high yield would still grow by 50% of net income every year?

Yes.

And as I look forward and we talk about capital allocation in terms of returning capital to shareholders, order of magnitude call it $300 million a year, and I look how that basket grows, that combined -- the growth of the basket will pretty much offset what we are committing to give back to shareholders, as well to a large extent cover the level of costs of servicing the debt up at the Holdco level.

So when we look at the RP capacity under the bonds going forward, we have considerable room in our planning period.

I don't see us really having much difficulty at all given the assumptions that we laid out today of having any problems with RP capacity in the future.

Understood.

And that really leads to my real question, which is when you look at this basket or you look to sort of the free cash flow which as I understand the first lien is still tied to more of a free cash flow standard, there seems to be much more ample room to do something more than a 3% return of cash to shareholders.

I am just wondering why that target or what your thoughts are on doing something with the cash above and beyond that 3% target?

Yes, I look at it two ways.

First of all, we are sizing the commitment to shareholders at the same level that we see the mandatory take playing out for the bond.

So we see us deleveraging and paying out the shareholders at a relatively equal pace.

So that is part of the thinking and sizing of where we are.

But the second portion really goes back more to the slide that David has that shows we know we have got variability in terms of excess cushion in the cash flows as we look forward.

We don't want to overcommit on that today, but we do know that we have that opportunity as you have described.

But at this point I think it is premature to commit that in one direction versus another.

Okay and just one last question.

Can you give us an update on what the NOL was at the end of 2006?

The NOL under the tax return filing position was $1.7 billion.

For financial statement purposes, I think we're around -- I think at the end of the first quarter, you will see in our Q that I think it is about $70 million.

And so when would you expect to become a cash taxpayer?

2009 was the way that I look at the cash taxes going out is that we are probably about a 25% effective cash tax rate in 2009 and then closer to a statutory rate after 2009.

David Silverstein, Merrill Lynch.

Just a clarification.

Bob, if you could just remind me or remind us on the CSFB facility liquidation that occurs in '08/'09, that is a$500 million cash outlay still?

Yes.

Well, we have to pay down the debt on that.

Yes.

But that goes in the form of a restricted payment, correct?

That's right.

That comes out of the RP basket.

Okay.

So basically I was looking at the new RP capacity given the assumptions for the Term B contribution to the Opco, and I'm looking at year-end this year of around $1.05 billion or so, assuming you complete Phase II and get 50% net income for the balance of the year.

But after once you -- if I consider the CSFB facility, the dividends, the balance between the dividend and the 3% that Elizabeth pointed out for share repurchases, so I'm looking at year-end '08 at $570 million as your basket?

David, we have to go through that because I see -- I think our planning shows a bigger basket.

Maybe from a net income -- maybe on a net income basis or maybe because you liquidate some in '09.

(multiple speakers)

I mean that is part of it.

The bond is the net income tax that is a little different.

I mean, I look at this, I look at your profile, I look at your cash flow visibility, your environmental program.

You compare it with other guys in your space, and everyone else is taking advantage of the market's appetite for covenant-like transactions.

And you are paying you say 10 or $15 million incremental.

When I realize the makehaul on your bonds of $500 million looks like a large amount, but it is probably incremental on a cash basis like $35 million or $38 million a year in interest expense.

And the market is accepting at least -- I don't want to speak for investors out there, but they seem to be acceptable of no restricted payment limitations on companies.

David, the way that we looked at it and the way that I look at it is do a $4.7 billion takeout in refinancing, and the risk that comes with that.

I mean I just cannot justify at this point in time the cost of doing that, which far exceeds what we need to do.

What we have here is we have -- we are very comfortable with the basket capacity going forward, and we have got the flexibility that we need.

So I mean at this point in time I cannot see the benefits of the costs of doing a takeout.

Dan Eggers, Credit Suisse.

When we look at or when you show the heat rate outlook for Texas and the fact that we are not seeing any meaningful expansion there, what do you guys see as being the major signal, or how do you see that market developing by way of incentives to build new capacity, or are we just going to (inaudible) a shock event in four years?

Well, I will turn it over to Mauricio in a minute to see what he sees in sort of the traded market, but yes, the pricing of the new build, of course, is an imperfect pricing on that -- I think there is a general view, of course, of there being a liquidity discount in the later years and the fact that the electricity price in Texas is so closely tied to natural gas prices.

Natural gas prices are not moving on the dynamic of whether there needs to be new powerplants in Texas.

So one thing is I think people like us are going to take a look at the fundamentals and try and develop a point of view.

But, of course, you are also -- the fact that you have to do that anyway because, of course, you're talking about building a 40 or 50 year lived asset and you have only got price signals for five years or so.

So that is the one thing.

But, Mauricio, maybe you can say whatever you want to say about the way that you see the market developing in terms of heat rates.

Well, we have seen heat rate expansion over the past six months, and that means a possible favorable move, which we expected.

But, as David articulated, we continue to be bullish, and I think that is reflected on our hedge position on our long heat rate position.

I think a lot of the backwardation in heat rate is driven by deal flow, and probably the front three years give you good clarity on heat rates.

And beyond that, it is driven just by deal flow.

So there is some liquidity discount on that, which we expect the market is going to start working on that.

Okay.

With your BTU spreads on fuel oil versus gas, quite a bit more narrow than they were last summer.

Do you guys have any thoughts going into this year how your fuel plants should run kind of on a year-over-year basis and how that is layering into guidance right now?

Right.

Well, we're seeing fuel oil in I would say in our Western New York markets where we have a big oil position still be over where the current market is indicated.

With respect to New England, a lot of the runs that we have are for reliability issues.

So we expect a very consistent run on our oil generation in the New England market.

And (multiple speakers) New York is going to come down to the weather and the summer volatility that we can expect there.

And a portion of our increase in guidance is attributable to getting more generation from the oil plants.

Order of magnitude we are talking about an increase of around $20 million or so.

Gregg Orrill, Lehman Brothers.

I was wondering if you could talk about the trend in annual free cash flow?

Just heading out over the next several years if the environmental CapEx roll offs, it looks like before the repowering spending that you will probably be comfortably over $1 billion?

Am I thinking about that the right way?

Yes, you are.

The environmental CapEx is heaviest in 8 and 9, and then it settles down.

And also, you start getting the reimbursements in from South Central.

Generally speaking when I look and describe the Company in the near-term years, we are around $1 billion free cash flow level.

As you get closer to the end of the decade, you start going beyond that.

Okay.

And going back to the slide seven of the 20% still uncommitted over the next six years, what sorts of things should we be looking for?

Well, I think that the 20% -- I mean part of it would be how attractive we find the opportunities in the repowering, sort of what I would call the growth CapEx.

Part of it also depends on I guess how the market values the stock in terms of how much we committed to the share buyback.

So I think those would probably be the two main swings.

We don't expect a lot of swing in the environmental and major maintenance or in the debt paydown.

Bob, would you see it that way?

Yes, I mean there's opportunistic reasons to do something like open market repurchases of the bonds.

We have done that in the past as well.

If for some reason they were trading lower, which I don't see likely, we could also use it for that if we wanted to commit more of it to the debt side.

Terran Miller, UBS.

Bob, I was wondering if you can just give us a little bit more detail on the structure of that senior secured facility, exactly what will the security be and why is it senior?

Sure.

What we're trying to do when we go to the bank meeting is for the existing Term B lenders, we're going to reprice and resyndicate that Term B note.

We will ask them to take -- basically give us a call option on shifting one-third of that to the Holdco level.

We like doing it that way for a couple of reasons so that, one, the covenants match up, but also there is plenty of flexibility in terms of if we wanted to pay it down faster.

And it's just very manageable.

I guess it's just a very cost-effective way for us of doing it.

In terms of pricing, we are looking to get 25 basis point reduction in the grid, which would take our first lien facility today at the Opco level down to 175.

The security at the Holdco level would price probably 25 to 50 basis points outside of that.

So we will have some financial incentive for it to be there as well.

But I think for us it was just the ability to be able to place that in a coordinated way, and it fits nicely in our capital structure.

We like the flexibility of that, say, versus a bond.

Okay.

And what is the security at the Holdco?

Is it the equity of the subs?

It is equity of Opco.

And there is going to be no upstream guarantee?

No, there is not.

Michael Lapides, Goldman Sachs.

A real quick question.

Some of the other senior management or executives from some of the other IPPs have talked about how this industry is still very much ripe for consolidation either corporate-wide or asset transactions.

We just love your kind of high-level commentary and the point on the sector as a whole.

Well, I mean, Michael, we have always believes that consolidation will occur, and certainly I don't see anything out there today that is saying different.

I mean when people first started talking about consolidation a few years ago, we thought it was inevitable, but thought it would be slower than some other people who were speaking at the time.

Because we thought some of the legacy issues from the last bubble period would get in the way of near-term consolidation.

As I look around the industry, it seems pretty clear to me that virtually everybody is -- has dealt with those legacy issues.

So I think it is going to happen.

Our point is as it has always been.

With our size, a midsize company in the power generation space, the most important thing for us is to put ourselves in a position where since we don't really control how consolidation will occur that our stakeholders will benefit from it whether we are a consolidator or consolidated.

And we do that by having very strong power generation positions in the markets which are up for grabs.

And that is the Northeast, Texas and California.

So I think that continues to be the right strategy, and that continues to be the strategy that we are pursuing.

We as a company can go either way.

It just depends on where is the value for our shareholders.

One quick follow-up.

Do you believe we will see a rash or not a rash but an enhancement in the number of corporate transactions over the next two to five years, or will it mostly be individual asset or smaller portfolios of assets that get transacted in the market?

Well, I mean from my perspective the individual asset transaction is something that we barely even look at anymore.

Because one there always seems to be someone who can offer an extraordinary price for the odd powerplant.

So to me our singular focus in this area to the extent that we have any focus in it is on corporate consolidation.

Again, whether or not that happens, I think it is really the big guys that decide when and how that will happen.

So I think we just need to wait a bit longer to see how they decided to go after it.

Because obviously, as you know, it is pretty clear that the paradigm that everyone was following a year ago of big utility consolidation is not the current form of consolidation in favor because of objections at the state level.

So our approach is we just keep pushing on the strategy we have, which we think has been very effective and very value creating.

We're just going to keep doing that.

David, thank you, and congratulations on the 13 quarters.

Anthony Crowdell, Jefferies.

Good morning.

I'm just trying to reconcile to the baseload power hedge position on slide 12.

I'm just trying to make sure my thought process is correct.

If I look at -- actually I think it is the gas price sensitivity on page 13.

If I look at the open position or the $218 million sensitivity and I divide it back by what the open baseload generation is forecasted it, wouldn't that give me what the market heat rate would be for the company baseload fleet?

So you are saying you are looking at the year 2010 -- (multiple speakers) on page 13 and then comparing that back to page --

To page 11 when I look at like you know in the K where you guys announced the baseload that is sold forward, what you guys expect to generate, look at the open position, wouldn't that not give me what the market heat rate would be you are assuming to calculate that gas price sensitivity?

I mean yes, I mean without having to sort of do the calculation right now, I mean no one here has any reason to dispute your logic on this.

Because it's coming out like around 10,000, and you think Texas would be the highest heat rate market.

Your forecast -- you know, the chart that you show shows about an 8000 heat rate in Texas or slightly north of 8.

I think it's best to probably work this one off-line because it's just too many numbers to make sure at this point.

We will get back to you.

Brian Chin, Citigroup.

Can you provide some color on the recent Texas legislation regarding regional generation caps?

It is my understanding that there is still a little bit of question as to how applicable it would be to NRG?

What are some of the milestones to watch out for, and how do you think the process will unfold for you guys?

Well, Brian, you ask a difficult question as you always do, and it is a very fluid situation in Austin right now where we are spending a lot of time.

I have been down there quite a bit.

Thad Hill who runs Texas for us is there virtually all the time.

Clearly the bill, which I think has not gone out of the Texas house yet, is more workable for us than the one that passed the Senate early in the session.

So it is going to come down to the committee.

Quite frankly, it is not clear yet how that will -- obviously it is not clear how that will resolve itself.

I mean we remain confident.

We have a dialogue with all the key members of the Legislature, and our role we see this as mainly education to indicate to them where NRG stands in this.

We have been a very good citizen in Texas, never accused of market manipulation.

We have talked about how to deal with the real concerns they have to make sure that Texas consumers are getting the benefit of competition.

And we have very healthy discussions on this.

So I'm confident that it is going to turn out in a way that is conducive to us running our business down there in the way that we have run it.

But I cannot tell you right now exactly how it is going to come out.

But the important thing is you don't have too long to wait because I think there are only two weeks left in the legislative session.

Okay.

Well, a follow-up question to that.

Let's say that you guys have to explore looking at selling a few of the Texas gas plants.

If that were to happen, does that change the capital allocation outlook with regards to the proceeds you would receive as a onetime dividend possible?

Can you just walk us through the thought process in the event you have to explore selling some of the gas fired assets?

Like every action, Brian, if we had to sell some gas plants, it would not be a very large number of plants.

I mean I cannot remember the exact number of gas plants we have down there.

I think it is 5000 or 6000, but I don't think it would be anywhere near that number.

And the gas plants, keep in mind, are not enormous EBITDA contributors.

I mean they have been a very positive -- not a surprise, but their performance has been much better financially than we modeled when we bought Texas Genco.

But the point we make in Austin is that the most important thing about us owning those plants is that they provide us with a physical insurance, which enables us to put on a very heavy baseload hedging program, knowing that if we lose one of our baseload units we have the gas plants to back them up.

And we think that's a very important benefit for us.

It is also a very stabilizing benefit for the market down there.

So if it happens, I think the good news is it is obviously a good time to be selling any type of powerplant anywhere, but particularly in Texas.

So I think we would undoubtedly get more money for it than we valued when we actually bought the plants.

But it would be so much money that it would actually influence or lead to a special dividend?

I think that that is unlikely.

Well, I think you first have to -- since they are part of the collateral package, you first have to offer the proceeds.

If you don't reinvest the proceeds, you would have to make an offer to the first lienholders.

Brian Taddeo, Bank of New York.

Just one quick one.

I just wanted to make sure I understood correctly the new structure you are proposing here.

In essence all you are really doing is taking $1 billion of debt and basically shifting it from -- basically shifting it from ahead of the bonds to behind the bonds in order to free up the restricted payments.

Let's just say you are basically taking $1 billion and moving it behind the bonds.

It is just going to be subordinated to the bonds at this --

That is exactly right.

Okay.

That is it.

I think we have got time for one more question.

Brian Russo, Ladenburg Thalmann.

Most of my questions have been answered, but could you just give us a quick update on the Big Cajun expansion plans, and have those plans recently changed?

Well, Brian, I mean the situation with Big Cajun, you know it is 700-some megawatt unit.

We have contract -- we have lined up either offtake contracts or partnership arrangements with about 451 megawatts of those 700 megawatts.

In most markets that we are in, that would probably be enough for us to go forward and begin construction.

But, of course, in the [intergy] zone, bilateral market that it is, where even your transmission out is a dicey prospect, being along those 250 megawatts with no home is more than we can have an appetite for at this point.

So we continue to look at -- well, and discuss with various other offtakers and partners more offtake there.

But we are also pushing forward on Big Cajun I, which is a [CFP] project just a few miles down the road and is -- could be smaller and quicker, 200 megawatts.

And so it may end up being that Big Cajun I moves ahead of Big Cajun II-IV.

But we are really moving -- we're trying to move forward on both.

Well, operator, I just want to thank everyone for participating on the call.

We will look forward to talking to you again next quarter.

Thank you.

Ladies and gentlemen, this concludes the conference call for today.

Thank you for your participation.

Disconnect your lines and have a great day.