NRG Energy Inc (NRG) 2006 Q3 法說會逐字稿

Good morning, ladies and gentlemen.

Welcome to the NRG Energy third-quarter earnings results conference call. (OPERATOR INSTRUCTIONS).

As a reminder, this conference is being recorded November 3, 2006.

It is now my pleasure to introduce your host, Ms. Nahla Azmy, VP of Investor Relations.

Thank you, Jennifer.

Good morning and welcome to our third quarter 2006 earnings call.

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

You can access the call presentation and press release 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 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.

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 statement.

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

In addition, please note that the date of this conference call is November 3, 2006, 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 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.

With that I'd like to turn this call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Nahla.

Good morning, everyone.

I'm joined here today by Bob Flexon, our CFO, who will also be presenting, and also Kevin Howell, who won't be presenting.

Kevin, as you know, runs our Commercial Operations group, and will be available to answer questions, or to avoid answering questions about our hedging strategy and our hedging position.

During the course of my presentation, my presentation and Bob's presentation, we will be referring to slides which appear on our Website.

Today we're here to talk about two things -- our third-quarter results and our newly-announced hedge extension and enhanced capital allocation program, which we call the Hedge Reset program for short.

The Hedge Reset program is a complicated and interrelated set of transactions with significant commercial and financial consequences for the Company.

And as a result, both Bob and I are going to be talking about it.

I'm going to be focused more on the rationale for the first part of the transaction, which is the hedge extension;

Bob's going to be a little more focused on talking about the commercial and financial consequences of the second half of the transaction, which is the enhanced capital allocation program.

But before I begin on these two topics, I want to note that we met many of you just 2.5 weeks ago in Houston for our first-ever analyst day.

I personally want to thank each of you who made that trip.

I hope it was worthwhile to you and that we provided you with a much better understanding of our repowering NRG initiative.

Today we don't intend to comment on the repowering initiative at all.

That's not because we aren't still excited about it; it's because we have other value drivers to talk about.

As many of you know, those of you who were in Houston certainly know, the repowering initiative is a long-term value driver for the Company.

Many of the other value drivers that we are pursuing are much nearer term, and several of these are depicted on slide four of the presentation.

That really leads to my overall theme for the day, the one thing that I hope will stick with you as a takeaway point when this call has ended, and that is this -- what sets NRG apart from other companies is the number of significant value drivers open to us, and the demonstrated ability of our company to act decisively and effectively to capitalize on these value drivers.

The Hedge Reset program itself harnesses several of the value drivers set forth on this page four.

But now, turning to the third-quarter financial highlights, adjusted EBITDA for the quarter was $519 million, up 124% quarter on quarter.

This increase was largely driven by the acquisition of Texas Genco and improved South Central performance, offset by lower margins from the Northeast.

On an apples-to-apples basis, excluding NRG Texas, the adjusted EBITDA result for classic NRG was flat, despite the mild weather and significantly lower natural gas prices.

The quarter's strong financial performance drove solid cash flow generation.

Excluding cash collateral, net outflows in 2005, and net inflows in third quarter 2006, cash flow from operations was up nearly 72% quarter on quarter.

In fact, I would note that this company generates cash so quickly that both our total liquidity increased and our net debt to total capital decreased during the quarter, even though we were well into execution of our third share repurchase program at the quarter end.

The strong financial results that you see depicted on this slide five are, I believe, a testament to three factors.

First, our successful integration of NRG Texas and the outstanding operating performance that they have continued to deliver.

Second, our own success in improving the summer performance of the classic NRG fleet through the reliability initiatives, which are grouped under the FORNRG program.

And third, the benefits of our baseload hedging program, which inoculated NRG financially against the extreme volatility of near-term gas prices.

Now turning to slide six, you can see some of these key operating factors illustrated.

First, with respect to safety, our performance continues to outpace both the industry average and NRG's previous-year performance.

With respect to plant reliability and output, you can see both the higher reliability across our baseload fleet, on the lower left, and the fact that in Texas and in the South Central region, this higher reliability translated into higher megawatt hour sales.

But in the Northeast there was a drop-off in production, notwithstanding the improved reliability.

This is because our significantly-sized fleet of oil-fired peakers were rarely dispatched in the third quarter 2006, as they fell behind gas-fired peakers in the merit order due to the comparative strength of oil prices during the quarter relative to gas prices.

I would note that over the past month, with the rise in gas prices and the drop in prices across the oil complex, the relationship has reverted to oil plants now ranking below gas plants in the merit order.

If this relationship continues into the winter, and of course, assuming we get some winter this year, this could be a significant upside for us as we invariably stay along with our oil peakers and take at least a good portion of them into the short-term market.

Now, this improvement in plant performance did not occur just by happenstance; it was the result of a lot of hard work by NRG personnel across the fleet, with central coordination and planning by our plant operations group through the focus on (indiscernible) NRG initiative.

As slide seven demonstrates, the FORNRG program has two main drivers to achieving the ultimate target of $200 million of annual EBITDA improvement by 2009 -- improved reliability and economies of scale and procurement.

What we show on the bottom left is that our third quarter 2006 EFOR results, which is the second furthest bar to the right in the graph, exceeded our plan.

We are working hard now to ensure that those performance improvements can be consistently replicated and then taken to the next level.

All of us at NRG recognize that one good summer quarter does not automatically constitute a long-term trend.

Turning to slide eight, our business operations group continues to deliver in all areas of asset management, but particularly in the area of non-core asset sales.

During the third quarter we completed the sale of Flinders in accordance with the timetable we outlined to the market last January.

We continue to seek to secure the cooperation of the partners to consent to the sale of our ownership interest in the Gladstone plant, but that transaction has not yet been consummated.

There remain a few small non-core assets for us to sell, but our non-core asset monetization program is at this point almost complete.

I would note that while we have been rumored to be involved in various single asset and small portfolio sales processes over the past few months, and indeed we have participated in some, invariably we find that the price at which single assets are clearing the market is significantly in excess of what we are willing to pay.

And as such, in this market we are more of a single asset seller than a single asset buyer.

Having discussed our plant operations and asset management, I'd like to begin on slide nine with the segue into a discussion of the hedging transaction being announced today.

We have discussed with you from time to time our commercial operations philosophy, and it is repeated on this slide nine for your consideration.

Clearly, our focus is on optimizing the value of our physical assets, while at the same time reducing the inherent risk of being fundamentally long to the commodities markets as a result of our physical asset position.

Our basic approach in this regard has been and continues to be focused on substantial hedging of our baseload, predominantly coal-fired, generation as far out in term as the market will permit.

Thanks to the significant strengthening of our commercial operations capability over the past 18 months, we have increasingly sought to implement this baseload hedging strategy in a manner which preserves some gas price upside through the use of option and swaption structures.

Over the past few months our commercial operations group has been increasingly focused on one additional goal, which is listed as the last bullet in the left column of this slide nine.

That is taking advantage of the relative strength in the back-end of the gas curve to hedge effectively our baseload generation in the out years, while preserving all of our ability to benefit from heat rate expansion.

This hedging objective was a key motivation to the highly-interrelated and coordinated set of transactions illustrated on slide 10.

In order to substantially extend and deepen our medium-term hedges -- and by medium-term I mean 2010 and 2011 -- we reset our nearer-term baseload hedges to market.

By doing the Hedge Reset we accomplished two things.

First, we opened up very substantial counterparty capacity under the second lien structure, some of which we have now put to work through the newly put on medium-term hedges.

And secondly, the reset of our nearer-term hedges to the significantly higher current market price substantially increases the Company's near-term cash flow, enabling significant amendments to our debt covenant packages, which in turn we will use to incur the additional indebtedness required to fund the Hedge Reset.

Taking advantage of this additional counterparty capacity, we have over the past few weeks dramatically increased our effective power hedge position for 2010, and particularly for 2011.

As demonstrated on slide 11, our effective power hedge positions in those two years have already increased to 48% and 53%, from 41% and 19%, respectively.

And with these new counterparty arrangements, we will be adding to these medium-term hedge positions as market opportunities arise in the months and years to come.

The dramatic impact of this Hedge Reset program on the Company's commodity earning sensitivity is illustrated on slide 12.

Slide 12 shows the Company's forward earnings sensitivity, both the fluctuations in natural gas prices, and to market heat rates.

In the case of natural gas prices, the left graph shows our sensitivity before and after this latest round of hedging activity.

As you can see, for 2010 and 2011, the reduction in the Company's exposure to gas price volatility is dramatic.

On the other hand, as demonstrated by the heat rate graph on the right, our potential upside from heat rate expansion remains uninhibited.

So you may be asking why we want to stay so long to heat rate exposure?

Well, the potential for heat rate expansion over the next few years has been much commented on by various independent industry research organizations over the past few weeks.

All these reports, and our company's own point of view, assess the impact of one very visible and very certain fact, and that is this.

Notwithstanding the upswing in power projects under development, there are very few power plants under construction in the United States.

And even once a construction pipeline does begin to takes shape, the lengthy construction periods associated with solid fuel-fired plants means that the supply/demand situation will continue to tighten at least into the early years in the next decade, which will in turn result in heat rate expansion.

The second reason for us to stay long to potential heat rate expansion is Texas-specific.

If you look at the graph on slide 13, you will see the dramatic decline in forward heat rates in ERCOT for 2011 and 2012 over just the past few months.

We believe this severe decline in the forward heat rate curve is attributable to the fact that the market appears to be pricing in all the 17 coal-fired newbuilds announced for completion in ERCOT in the 2010 to 2012 timeframe.

As we believe the completion of 17 coal plants in that timeframe is extraordinarily unlikely, we believe forward heat rates in ERCOT have only one way to go, which is up.

And we believe the forward heat rate curve in ERCOT will begin to rise well in advance of the next decade, as the market realizes that the introduction of coal plants into the Texas market will be slower and fewer than is currently anticipated.

If and when that rise in heat rate occurs, we will begin the process of capturing the upside and taking our heat rate exposure off the table.

Finally, looking at slide 14, before I turn it over to Bob to give you further details about both our third-quarter results and the second part of our Hedge Reset program, I want to reiterate our basic message.

NRG is a company that innovates and executes, and we do it across all phases of our business at all times in order to enhance the Company's value to our shareholders, both in the short-term, through initiatives such as this Hedge Reset program, and in the long-term, through initiatives such as the repowering NRG program.

Bob?

Thank you, David, and good morning.

Today I will cover our third-quarter results, provide an update on our 2006 and 2007 outlook, and review the key details on today's announcement of the Hedge Reset, the planned amendments to our first lien credit agreement, and the enhancement of the previously announced Phase II share repurchase plan.

I will begin with a review of the third quarter; however, given the significance of the announcements, I'll spend the greater proportion of my allotted time covering the rationale and impact of these transactions.

On slide 16 are the third-quarter and year-to-date key financial results, the significant factors that affected performance and the impact of NRG Texas.

This quarter's results underscore the benefits of NRG's diversified and hedged portfolio.

In the face of falling gas prices, NRG's third-quarter performance demonstrated the benefits of actively hedging and protecting the cash flow derived from our baseload generation.

In addition, portfolio diversification with the addition of NRG Texas and the solid operating performance from our South Central assets helped offset the softness in the Northeast market.

Adjusted EBITDA excluding mark-to-market impacts for the quarter increased to $519 million -- $304 million due to the addition of NRG Texas to our portfolio.

Excluding NRG Texas and mark-to-market, the NRG classic portfolio's quarterly earnings decreased by $17 million, or over 7% versus the same period last year.

Year-to-date adjusted EBITDA increased to about $1.2 billion, approximately one half this amount due to the addition of NRG Texas.

While the remaining classic NRG portfolio provided results at about the same level as last year's results, these quarterly and year-to-date results were achieved despite a 7% drop in classic NRG year-over-year domestic generation, with most of the decline attributable to decreased generation from the Northeast intermediate and peaking facility.

In a moment I'll walk through some of the large EBITDA impacts included in the results.

Overall year-to-date performance, despite an unseasonably-mild winter and falling gas prices, was in line with last year's performance, when we experienced more seasonal weather conditions during the winter and rising gas prices following Hurricanes Katrina and Rita.

Free cash flow for the quarter totaled $345 million, compared to a $218 million use of cash in 2005.

Collateral receipts totaled $124 million this quarter, compared to $419 million of collateral posted during the third quarter 2005 [of that] $543 million cash flow increase.

Cash generated by the $304 million of Texas adjusted EBITDA was reduced by a $193 million increase in cash interest and $53 million in increased capital expenditures when compared to the third quarter of 2005.

Year-to-date the story is similar.

Free cash flow increased over $1 billion, as cash collateral returned year-to-date totaled $397 million, as compared to an outflow of $598 million in 2005 -- a difference of $1 billion.

Cash generated, excluding the impact of cash collateral received this year, increased due to the funds generated from the $597 million of Texas EBITDA, reduced by $317 million increase in interest and refinancing expenses, $113 million increase in capital expenditures, and $104 million increase in working capital and other liabilities.

Slide 17 provides bridges from 2005 to 2006 quarter and year-to-date adjusted EBITDA.

The mark-to-market adjustments primarily affect our Northeast and Texas regions.

In 2005, Hurricanes Katrina and Rita disrupted the natural gas production, causing the sharp increases in prices, which drove the mark-to-market losses experienced last year.

This year the mild winter and record level of natural gas inventory led to price decline, driving the mark-to-market gains reflected in the 2006 results.

Also, mark-to-market gains from the expansion of heat rates in ERCOT amounted to a $78 million quarterly gain and a $122 million year-to-date mark-to-market gain since the acquisition of Texas.

Included in the portfolio change bar is NRG Texas.

Throughout 2006, NRG has delivered an extremely strong operating performance, which has been offset by lower-than-anticipated power prices on the open baseload position.

NRG Texas contributed to $304 million in EBITDA for the quarter and $597 million since February 2, 2006.

Texas generation for the quarter was 14 million MWH, an increase of approximately 2 million MWH from the second quarter of 2006.

On-peak market power prices in ERCOT averaged $71 for the first nine months of the year, but prices during the third quarter averaged only $62 per MWH.

Capacity revenues for the 2006 third quarter and nine months totaled $234 million and $624 million, respectively.

A little more than 40% of these revenues were from STP.

Year-to-date results included $67 million in emission allowance sales during the first quarter, primarily in the Northeast region, when we sold our SO2 allowances due to the lack of generation demand.

During last year's third quarter, we sold $25 million of 2005 surplus position.

The South Central portfolio dramatically improved its performance in 2006 as compared to 2005 through improved operating rates.

Total generation sold by the South Central region increased 10% for the quarter and 21% year-to-date.

A reduction in the number of forced outage hours at Big Cajun II plant improved operating performance, thereby reducing purchased energy needs to meet contract load requirement.

A new tolling agreement and increased capacity prices also contributed to the $31 million improvement in quarterly operating margin.

Year-to-date adjusted EBITDA -- adjusted regional EBITDA benefited from $60 million in higher margins versus last year.

Lower results for the Northeast were driven by weaker power prices and reduced generation.

MWH sold during the quarter dropped 23% for the quarter and 19% for the nine-month period.

The decline in gas prices caused nearly a 30% decline in average on-peak power prices, from approximately $112 to $79 per MWH, as well as a nine-month drop of about 15%.

After excluding the mark-to-market emission sales for both quarters, the Northeast EBITDA dropped by $65 million in comparison to the third quarter of 2005.

The 26% quarterly drop in generation from the intermediate and peaking facilities, and lower regional power prices, more than offset increased New York and NEPOOL capacity payments.

Year-to-date, the Northeast oil and gas fire generation is down 70% and 50%, respectively, from the same period last year.

In total, nine-month margins decreased $125 million, again, due to falling energy margins caused by lower generation and the impact of falling gas prices on power.

The Australia region now consists of only the Gladstone investment, the sale of which is expected to be closed in 2007.

Flinders is now reported as a discontinued operation for all periods presented and excluded from our adjusted EBITDA numbers.

NRG's liquidity as of September 30th is presented on slide 18.

The increase in liquidity this quarter was largely due to 240 million -- $242 million in proceeds from the sale of Flinders, $444 million in cash from operations, which includes 226 million of before-tax cash interest payments.

These cash sources were partly offset by $99 million used to purchase stock -- to purchase stock as a part of Phase I of our capital allocation program through September 30th, $62 million in capital expenditures, $35 million in the reduction of outstanding debt, and $14 million in preferred dividend payments.

As I mentioned earlier, a large component of the cash increase from operations is the $124 million of cash from quarterly collateral receipts.

Posted cash collateral remaining as of September 30, 2006 amounts to $132 million.

Assuming a stable power price environment, we do not expect to receive any significant additional returns of collateral for the remainder of this year.

Our updated guidance is shown on slide 19.

We are maintaining the EBITDA guidance provided last quarter, which we adjusted for the sale of Flinders and costs associated with our development activities.

We are making minor adjustments to our free cash flow guidance, primarily for higher interest costs than previously forecasted.

I will now shift the presentation to the Hedge Reset and extension program.

As David mentioned a moment ago, NRG has launched a comprehensive initiative to enhance the Company's strategic hedging program and financial flexibility.

Slide 20 provides the steps of the Hedge Reset program.

But before I launch into the detail, I want to emphasize the reason we are entering into these transactions.

Our goal from the start was to find a way to protect the cash flows and economics of the highly-accretive NRG Texas acquisition; the solution, a longer dated hedging program that has the immediate capacity to hedge significant volumes when favorable market conditions arise.

Now for the detail.

Step one was the reset of legacy NRG Texas power and gas hedges at market prices.

This critical first step was required to create the credit capacity in the second lien structure that attracted new and existing counterparties willing to pursue sizable longer-dated hedge agreements.

The mark-to-market value of the underwater hedges at October 31st was approximately $1.35 billion, representing the level of credit exposure that existing counterparties have to [wear].

While the Company -- while the second lien collateral structure can be used to support hedges up to 80% of the baseload capacity of the Company, the more limiting factor in attracting new counterparties has been their credit risk appetite.

By resetting the price of the legacy hedges and paying out the credit exposure, the Company risk embedded in the second lien structure is substantially eliminated, thereby relieving the credit concerns of the potential counterparties.

Step two is executing sizable longer-dated hedges with new and existing counterparties.

At the appropriate price levels, NRG has entered and plans to enter hedges from 2010 to 2012, building on our existing hedge profile.

Although we intended to have all of the target hedges executed by today, the decline in the natural gas curve over the past several weeks caused us to hold back on executing the full complement of hedges.

Instead we have entered into roughly 25% of the targeted hedge position in 2010, 65% of the targeted position in 2011, and await better market conditions for 2012 for targeted hedge positions.

The significant improvement in medium-term cash flow generation and stability created by step one and step two enables NRG to pursue step three, amending NRG's first lien credit agreement.

With $1.4 billion in incremental EBITDA, and $1.3 billion in free cash flow over the next three years, NRG's secured leverage credit metrics dramatically improve.

As a result of this credit-accretive result, NRG is currently seeking significant covenant relief and amendment.

To facilitate this transaction, NRG will seek amendments to allow the incurrence of debt to fund the Hedge Reset, increase the synthetic letter of credit facility capacity by $500 million to provide liquidity support for new hedges in 2010 through 2012, and other related technical amendments to permit the execution of all elements of the proposed transaction.

As part of the amendment process, we also intend to pursue additional covenant amendments designed to enhance our financial flexibility, including expansion of capacity for restricted payment, debt incurrence and repowering investment.

The successful completion of step three will then enable NRG to incur approximately $1.1 billion in unsecured debt.

Step four, which, together with $250 million of NRG cash, will be used to fund the $1.35 billion payment to reset the existing hedges to market as outlined in step one.

Slide 21 highlights the consequences and benefits of the Hedge Reset transaction.

The Company has an effective longer-dated hedging structure able to place sizable hedges in short timeframes, amendments to our first lien credit agreement reduced trap cash, allowing for a more efficient capital structure, the removal of the [near] distortions to the Company's credit metrics, and improve clarity of the Company's cash flow and valuations metrics.

Since David just updated everyone on the current hedge profile and the sensitivity movements in natural gas, I'll cover the last three points.

Slide 22 outlines the impact that the Hedge Reset will have on NRG's cash flow and balance sheet flexibility over the next five years.

Prior to executing this series of transactions, NRG expected to generate $7.9 billion in aggregate cash from operations, excluding current cash balances.

Of this amount, the Company expected to invest up to $3.9 billion in maintenance CapEx, environmental CapEx, and repowering, leaving approximately $4 billion for debt and equity management, as well as other corporate-level initiatives.

As a result of the reset transactions, NRG now expects to generate a total of $9.2 billion in cash from operations over the next five years, and have at least $5.3 billion in cash flow from operations available for balance sheet management and other corporate-level exercises.

These higher-level and near-term cash flows resulting from the Hedge Reset, coupled with the expansion of the restricted payments basket capacity achieved through the first lien amendment process, provides NRG with the opportunity to enhance and upsize the previously-announced 2007 capital allocation plan, as shown on slide 23.

Originally, NRG intended to pay down its term loan B by $400 million, primarily using the proceeds from the sale of the Australian business, and to return $250 million to shareholders through either share repurchases or common stock dividend.

With the significant financial flexibility created by the Hedge Reset, we will upsize both the debt and equity components of the current 2007 capital allocation program by $250 million each, resulting in $650 million in total debt reduction and $500 million in total capital returned to shareholders.

Additionally, NRG originally intended to begin its 2007 return of capital to shareholders at the end of the first quarter, when restricted payments basket capacity expanded through the annual excess cash flow calculation mechanism.

Due to the new capacity created through the first lien debt amendment process, we will begin returning capital to shareholders during the fourth quarter of 2006, with the intention of completing the program well before the end of the second quarter in 2007.

While NRG evaluated various alternatives for reducing debt by the additional $250 million, the Company determined that the most efficient means to effecting this debt repayment was to use the $250 million of existing cash to partially fund the Hedge Reset payments to our existing counterparty.

At the bottom of the page we outline several important elements of NRG amendment package, which will meaningfully impact future capital allocation initiatives.

On the debt side, NRG has included a provision in the first lien debt agreement, which states that 50% of the annual excess cash flow offered to the lenders must be excepted, while the remaining 50% being left to the discretion of the lenders, thereby ensuring a minimal level of debt amortization under the existing first lien debt agreement.

On the equity side, NRG's minimum restricted payments capacity for the credit agreement will be reset to $500 million, from the current level of $84 million.

Additional capacity of 225 to $250 million will be available at the end of the first quarter 2007, when the annual excess cash flow calculation for 2006 is completed and the 25% basket expansion becomes available to the Company.

Finally, as part of the first lien debt amendment process, NRG will be increasing the debt-to-EBITDA target at which the annual addition to restricted payments rises, from 25% of excess cash flow to 50% of excess cash flow.

The target, which now stands at 3.5 debt to EBITDA, will be raised to 4.25 debt to EBITDA.

Based on current estimates, NRG anticipates achieving the new leverage target by the end of 2007.

As previously discussed, the out-of-the-money hedges inherent in the NRG Texas acquisition depress EBITDA and cash flow over the next three years, and distort the true natural leverage profile of the Company.

As a result of the hedges, the Company appears more leveraged and is unable to achieve its targeted leverage profile in the near-term.

To illustrate this point, we have outlined NRG's debt levels and projected 2007 year-end leverage statistics on slide 24, both before the proposed transactions and after.

Pre-transaction, NRG estimated that its year-end debt balance will be just over $7.5 billion, after reducing the term loan B by the previously announced $400 million during the first quarter of the year.

Once the Hedge Reset is completed, NRG's estimated year-end 2007 total debt will be $8.6 billion, an increase of $1.1 billion as a result of the incurrence of unsecured debt for this transaction.

While the net debt to total capital ratio increases to 53%, the midpoint of NRG's target range, both the debt to EBITDA and FFO to debt ratios are significantly improved due to the immediate and substantial increase in cash flow related to resetting the existing hedges to current market prices.

By removing the credit metric distortion, NRG is able to demonstrate its true leverage profile and more quickly achieve its targeted leverage statistics.

While the two most tangible benefits of the Hedge Reset program are the longer-dated hedges and the comprehensive credit agreement amendment package, as with the credit statistics, the Hedge Reset has ancillary benefits on cash flow equity valuation metric as well.

One such benefit is the removal of EBITDA and cash flow distortions caused by the legacy underwater hedges.

Selected EBITDA, cash flow, and equity valuation measures are shown on slide 25.

By marking the legacy hedges to market, a much clearer and indicative picture of the Company's current and longer-term earnings and cash flow profile is apparent.

Combined with the longer-dated hedges, the existing businesses' recurring adjusted EBITDA and free cash flow is in excess of $2 billion and $1 billion, respectively.

Using 2007 as the example, free cash flow per share is in excess of $8 per share.

Free cash flow yield at current prices is greater than 17%.

The [EV] to EBITDA multiple is under seven times, including non-recourse debt not supported by NRG.

While the marketplace will decide the Company's value, post the Hedge Reset, NRG's valuation measures will be much clearer.

Slide 26 provides 2007 guidance, bringing into account the impact of the Hedge Reset on 2007 guidance.

The 2007 guidance was last provided in January of 2006 during the NRG Texas financing roadshow.

The revised EBITDA guidance reflects the benefit of the reset and makes adjustments for the portfolio changes since January guidance.

[2007] guidance is now set for $2.05 billion, reflecting the $650 million in 2007 annual cash EBITDA from the Hedge Reset.

Cash from operations has been increased to $1.45 billion, now inclusive of development expenditures to support repowering initiatives, increased interest payments on the debt raised to finance the Hedge Reset, and the preferred securities issued in support of the capital allocation plan, and the increasing capital expenditures necessary to maintain compliance with environmental regulations.

Before turning it back to David, I've summarized the key takeaway points on slide 27.

First on the quarter, in the face of the challenging market conditions, the Company delivered solid financial results, largely driven by the plant operating performance of our operations group.

This, combined with the commercial operations group's implementation of the Company's hedging strategy, offset the lower generation demand and declining power prices.

In regard to the multifaceted Hedge Reset transactions, we successfully leveraged each leg of the transaction with the other.

As a result, the whole of the transaction is greater than the sum of the parts.

Through this effort we are able to put in place sizable longer-dated hedges above the NRG Texas bid model, the comprehensive bank amendment package that reduces trapped cash, an accelerated and expanded Phase II share repurchase plan, and recurring adjusted EBITDA in excess of $2 billion, and free cash flow in excess of $1 billion.

I'll turn it back to David.

Thank you, Bob.

Before we open the telephone lines to questions, I'd like to draw your attention to slide 29, and just note that the earnings strength of this company, which has been unleashed and made transparent by this Hedge Reset program, is by no means the end of the NRG growth story.

Many value drivers remain, which with proper execution by us can take this company from being roughly a $2 billion annual EBITDA Company after this Hedge Reset, to a $3 billion annual EBITDA Company over the next three to five years.

If this seems like an ambitious growth goal to you, keep in mind that the team we have here at NRG has already taken this company from being a $600 million EBITDA Company to a $2 billion EBITDA Company in our first three years.

Finally, looking at slide 30, focusing on the nearer term, I want to end by bringing you back to the scorecard that we articulated at the beginning of 2006.

At this point we are very close to achieving complete success across the board against our principal 2006 objectives.

This pattern of setting goals, articulating them to the market, and then going out and achieving or exceeding them, is the type of successful execution that we want you to be able to depend on from NRG.

With that I'd like to turn this -- the line back over to the operator for the Q&A portion of the call.

(OPERATOR INSTRUCTIONS).

Elizabeth Parrella, Merrill Lynch.

A couple of questions.

Can you talk a little bit about, in terms of the reset, what type of hedges you put in place?

Historically, I think, those Texas Genco hedges were mostly fixed-price hedges, fixed power price hedges.

What did you do in terms of redoing them?

And has that all been done?

And effectively at what point in time was it done at?

I'm going to ask Kevin to answer that question.

So, he can tell you what he wants to tell you, and what he doesn't want to.

I guess I'm going to try to and answer it as -- I think there's two embedded aspects to your question.

One is the existing hedges, and anything that was already on the books pretty much got rolled up in the same format that it was.

So, if it was the gas hedge, it got reset as a gas hedge.

If it was a power hedge, it got reset as a power hedge.

As far as the incremental hedges that we put on in 2010 and 2011, I think we've said before that, clearly, on the back-end of the curve there's much more liquidity in gas than there is in power.

But more importantly, on this program I think we really took a strong view on the heat rates, that we actually like the gas a lot better at this point than we like the power.

So the bulk of the incremental stuff we've done is in the gas markets.

When you indicate that you've preserved a lot of heat rate open position, it's really more on the new hedges.

Whereas on the old hedges, aside from the gas hedges, you didn't have heat rate; you weren't open to the heat rate in the power hedges, if I remember correctly.

If you look at the chart that David had, I believe it was on slide 13, really the decline in the market view of heat rates has occurred more on the back-end anyway, and that's -- again, it's got embedded into it.

I think every plant that's even been [notionally] mentioned has somehow or another ended up in that market curve, and we just fundamentally don't believe that's going to play out that way.

(multiple speakers)

In terms of the older hedges that were fixed-price, you basically redid them as fixed-price, and the ones that were gas swaps you redid as gas swaps.

Am I reading you correctly on that?

You're correct.

On October 31st, all we did was we took the existing hedges that are in place, and we just reset them to market.

So they maintain their current shape, form, quantity.

So, all of it is exactly the same.

And the incremental hedges were put on it around the same time, end of October?

The incremental hedges happened during the month of October.

One other accounting question related to this.

Bob, does this now eliminate that non-cash amortization of the liabilities that were created related to these contracts when you bought Genco?

It does.

It really converts it to cash.

John Kiani, Deutsche Bank.

Did you see an attractive cost of capital opportunity, I guess, in the idea to buy back stock when the implied price of gas is in your stock prices well below the back-end of the curve that you're hedging into?

Was that sort of the thought on the hedge extension and increased buyback?

Second question is regards to South Central, so maybe I'll let you go with the first.

When we looked at it, certainly as I mentioned in the comments, the first thing we wanted to do was protect the economics of the Genco acquisition.

Certainly, as we did that, in looking at each leg that we had to do to protect the economics of the Genco acquisition, it led us down a path where we could actually get sizable increase to our restricted payments basket, and really take our capacity that were basically out at the end of this year, taking it immediately up to 500 million; an additional 250 million is available in just the next several months as well, so you've dramatically increased the ability to accelerate your share buyback.

And as you see, with metrics -- valuation metrics of less than seven times EV to EBITDA, free cash flow per share around $10 -- and we see those types of numbers going out for -- into the near-term and longer-term future -- we fundamentally believe our equity is undervalued.

So, it was a real nice complement to the transaction to be able to dramatically increase our ability to buy back shares in a larger quantity and on a quicker timeframe.

So, that was a great benefit that developed as we were setting out to solve a different problem; we saw the ability to solve an additional problem at the same time and take advantage of an opportunity.

Great; that certainly makes a lot of sense.

Another question.

On South Central, because the existing PPA was signed back when the NYMEX was around $3 an MMBTU, can we assume that the returns on capital and the overall level of profitability on the South Central 912 MW expansion project would be greater than the existing asset base with the existing PPA?

It's going to have to be, or else it doesn't move forward.

So the existing profitability of the South Central project we can look at in context of being a lot higher in the expansion.

Okay.

One last question.

As far as '07 guidance is concerned, if we look at the current forward strip in cal '07, is it possible or safe to say that there's some level of conservatism in the 2.05 billion guidance for '07?

(indiscernible) like January of '06, earlier this year when we did the guidance.

We take a view of a recent curve environment.

And for this updated guidance it's over the past few weeks.

But from there we take a fundamental look at the numbers and put it through, but we always make sure we have some headroom to absorb things like, again, we experienced exactly this year, with gas being so volatile.

So we've left ourselves a little bit of room.

That makes a lot of sense.

Thanks, and congratulations on all the hard work.

Dan Eggers, Credit Suisse First Boston.

On the -- when (indiscernible) you guys -- the basket of payment structure, is that going to work the same this way around, just the 50% ratio is the only material change we should be aware of?

There's really two changes.

One, the base level of funding gets juiced up to 500 million as soon as the amendments are done.

And then the other is you've raised the threshold getting to for a quarter leverage ratio, where the [outer] now becomes 50% rather than 25%.

So before, we had to get leverage ratios down to 3.5 to 1 in order to get that benefit; that's been relaxed.

So we would expect faster expansion of the basket as well.

Do you have any -- are you interested in talking about the cost of restructuring of all this sort of stuff?

On the bank side, it's not that significant.

Overall we view this as growth (indiscernible) [NPV]-neutral type of transaction.

When we look at the bank deals, they're very rather low-cost items.

I don't necessarily [want to] get into specific numbers, but it's not significant.

I would say also on the reset of the hedges, it was a negotiated settlement between us and the counterparties that reflects the PV nature of the trade.

So, the interest expense you're occurring to a large extent has been offset by the fact that you discounted the payment made to the counterparties.

David, just one question.

Now that the cash flows are up and the Genco hedges aren't there anymore, (indiscernible) with more certainty on cash flows, them being bigger?

Is there any thought about implementing a dividend at this point?

I'd just go back to the way I answered this question during the analyst day, which is, at this point, with the stock price being grossly-undervalued from our perspective, there's not a huge amount of discussion of that.

If the stock re-rates, then we'll go back.

Clearly, ultimately this type of transaction sets the stage for a dividend, in that it is greater cash flow and it is further hedged, further out in the future.

And obviously, when someone introduces a dividend, they want to make sure they can pay it with great visibility for several years.

So it sets the foundation, but I don't want to leave the impression at this point that that's where our near-term priority is.

At this point our near-term priority in almost everything we've done over the past few months has been designed to allow us to buy back as much stock as we can when it's as cheap as it is now.

Terran Miller, UBS.

Bob, I think you commented that the amendments are not quite done.

So, we have to complete the amendments on the bank facility, and then you have to issue the $1.1 billion of new, unsecured debt.

Is that how we're supposed to think about this?

First of all, on the bank amendment process, that will be -- that will be coming in the near future.

But I would say that it is an underwritten bank amendment process.

That's why we're comfortable talking about it today.

So that's going to happen.

And then, more information on how we will raise the 1.1 billion, or incur the $1.1 billion of debt will be forthcoming in just the next few days.

The second question is if the hedges get underwater, do you now have the flexibility to do this again in the future, sort of swap unsecured indebtedness for expansion?

I would say, based upon my experience with this, I never want to do it again.

That's not in our thinking.

Gregg Orrill, Lehman Brothers.

Congratulations.

Most of my questions have been asked and answered.

Maybe just a question on the repowering.

Is there -- are there any updates on any of the New York RFPs that are out?

I would say the update on the -- only update on the New York RFP is that the bid due date was October 31st, and we did submit a baseload IGCC proposal at our Huntley plant.

And we think it's an attractive proposal for New York, and we look forward to working with the New York Power Authority and the State of New York to make it a reality.

Michael Lapides, Goldman Sachs.

Congratulations on a strong day and strong announcement.

Really two questions, one related to the development projects.

Can you talk a little bit about what you're just seeing in Texas, in terms of development of new baseload facilities from other folks?

And specifically, kind of talk about the permitting and environmental permit and zoning processes.

That's a tough question.

I can't really say.

There's obviously been a lot of noise in the market, a lot of resistance from various sources with respect to the environmental impact of the 17 coal plants.

I wouldn't say that we've seen yet that that's influenced the basic permitting environment that the Texas Department of Environmental Quality or the political support that is -- that supports the addition of all those coal plants in Texas.

But I would say that I think the situation is likely to -- I just think a lot may happen after the election.

Our general view is on environmental issues in general, and on carbon specific, certainly we want to make sure that the issue is not politicized.

Because I think if this country is going to do anything about carbon, for it to get stuck into bipartisan politics would be a bad thing.

So we'll see.

I think a lot people don't want it to be an election issue, but want it to be a public policy issue.

So I think the next few months are going to be very revealing, but it's hard to say which way it goes right now.

Brian Chin, Citigroup.

Just back on the heat rate question, I noticed that on slide 13 you give out a forward heat rate curve for Texas.

But can you give a little bit of color on what your heat rate assumptions are for the consolidated entity just overall, so that we know where your heat rate assumptions are that we can apply on page 12?

Brian, we use -- in our planning we're in 7500 to 8000.

And that's around the clock.

Paul Fremont, Jefferies.

If you basically back into heat rates using your gas price sensitivities, it looks like for the unhedged portion, the range of heat rates that you'd come out with would be somewhere starting at 11,500, working their way down to about 8000 in 2012.

What essentially accounts for that decline for the unhedged volumes when you back into the heat rate?

It seems to be significantly more of a decline than what you would get just by looking at your Texas chart on slide 13.

We're not following the question, the assumption in the decline in heat rate.

Can you go through that with us again?

I think we're assuming baseload generation somewhere in the 62 million MWH range for Texas and NRG classic combined.

So if we take your hedging numbers, the inverse of your hedging numbers, and apply that against roughly 62 million MWH, and then take the sensitivity and divide by that number, you could basically back into an implied heat rate assumed for the merchant sales.

We may have to take it off-line and work with you to understand exactly what -- because first, the 62 million MWH we would tend to split into the baseload and the peaking, in terms of the MWH (indiscernible).

I'm not sure that we're going to be able to respond to that.

We don't project the type of declining heat rates that you're talking about.

Let me just say the numbers that you came out with are not familiar (multiple speakers) in the room.

So, we probably should work with you to try and understand your calculations and make sure.

Feel free to give us a call and we'll work that out.

We will do that after the call.

Thank you.

Brian Taddeo, Bank of New York.

First, I know you're still working out the details, but can you give us kind of your initial thoughts on how you see that 1.1 billion being raised?

Is that all going to be through unsecured bonds, any portion of that could be term loans, or anything of that nature?

While I would like to, I've been strongly advised by counsel that we can't talk about it.

I apologize for not being able to, but we'll have details out on that very early next week.

One other question.

If I'm looking at the cash flows for the hedging transaction, it seems like you're paying 1.35 billion now, and over -- according to slide 22, getting about 1.3 billion back in.

That's a net number.

The numbers are -- it's really like 1.45 coming in and (multiple speakers)

From the hedges being reset.

Right.

That's what I was trying to understand.

The net difference was probably the interest impact of the additional debt.

Craig Shere, Calyon Securities.

Congratulations on the new hedging program.

A couple questions.

One simple one.

The depreciation in the quarter, can I assume that that's a good ongoing recurring number?

I was going to bring this up since we had the conversation in Houston and the question there.

We're finalizing still some purchase price accounting.

I think my best advice right now that I'd give on the depreciation run rate for 2007, I would work with a number of $600 million.

And that -- there will still be some variability around that number, but 600 million is one that, I think, would be a good one to do your modeling with.

So, Bob, it's a little higher, maybe 50, than we were talking before?

Yes.

I apologize;

I may not fully understand all the implications here.

As I understand it, because of these new arrangements you entered into, the annual discretionary cash bucket is immediately increasing to 500 million from 250 million.

Now, that's an annual limit, subject still to a percentage of operating cash flow calculation.

But when you reach the improved debt to EBITDA metrics in '07, are you saying that maximum bucket will increase again from 500 million?

No.

The way it works is right now there's a base level funding of the basket.

And that base level funding that currently exists is 84.

With the amendment process, that 84 immediately gets raised to 500 million.

And then each year -- and there's an adder calculation.

Actually there's also a change with that that I should mention.

We're actually going to go to a quarterly adder mechanism, which will allow it to build in a more -- in a faster timeframe.

Rather than waiting for the next year to do the calculation, it's now going to build each quarter.

So you take your quarterly results, calculate your excess cash flow, and the basket expands by 25% of that.

Once you hit your targeted leverage ratio of 4.25 to 1, it will go up by 50% of your excess cash flow.

So, that has the ongoing adder to the basket.

So, 500 million is the initial funding, and then the adder calculation is the thing that drives the basket forward in the future.

And again, that moves from an annual calculation to a quarterly calculation.

So then, when you get to the 50% number, and I'm assuming at that point that the other covenants regarding percentage of net income aren't more restrictive -- but when you get to the 50% figure on excess cash flow, that's just an absolute number?

There is no ceiling of 500 million?

Right.

Correct.

To your other point, the way we have designed these covenants, the most restrictive covenant now of giving cash back to shareholders is in the unsecured bonds.

It's no longer going to be the first lien.

So the unsecureds were off the net income?

That's correct.

The unsecureds were always less restrictive than the first lien.

We've now been able to create the situation where the first lien is now -- are now less restrictive than the unsecureds.

Can you give some sense for what kind of cash flow bucket restriction the percentage of net income covenant would imply?

Basically (indiscernible) when you come up with your net income estimates, it's just 50% of it.

It grows by 50% of it on the bond.

So, say for year-to-date for the first nine months of this year, I think, our net income is around $600 million, I believe.

So -- in round numbers.

So that grows it at $300 million, as the example.

So, when you do your modeling, your modeling for '07, literally it should take your net income number and hit it by 50%.

The net income through nine months is 614.

Okay.

I think we have time for one more question.

Elizabeth Parrella, Merrill Lynch.

Thanks for allowing me to follow up.

Just a quick question on your '07 guidance.

Does that incorporate anything for PJM, RPM capacity payments?

It does.

It does not have a very significant amount; it's pretty low what's in there.

It's order of magnitude, I think, 15, 20 million that's in there.

So it's a minor assumption.

Thank you, Elizabeth.

Thank you, Jennifer.

Before we conclude, I just want to say this Hedge Reset program was conceived of and implemented by our treasury team and our commercial operations team working together, and, I think, have done an outstanding job, all under Bob Flexon's leadership.

So it was a great effort.

But I also want to thank the investment banks that have helped us with this.

And also -- we also depended on some strong cooperation from our primary counterparties.

So, we appreciate all of that.

Finally, we appreciate you joining us for this call, and for your continued interest in NRG.

And we look forward to seeing many of you at EEI next week.

So thank you very much.

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

Thank you for your participation.

Disconnect your line.