NRG Energy Inc (NRG) 2006 Q2 法說會逐字稿

Greetings, ladies and gentlemen.

Thank you for holding.

Welcome to the NRG Energy second-quarter earnings results conference call. (Operator Instructions).

As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Ms. Nahla Azmy, Vice President of Investor Relations for NRG Energy.

Thank you, Ms. Azmy; you may begin.

Thank you, Dan.

Good morning and welcome to our second-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 statements.

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

In addition, please note that the date of this conference call is August 1, 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 our non-GAAP financial information, the most directly comparable GAAP measures and a quantitative reconciliation of those figures, please refer to today's press release and this presentation.

Now, I would like to turn the 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, the Company's Chief Financial Officer, who will be presenting the Company's financial performance for the second quarter and for the first half of the year.

I'm also joined by Kevin Howell, our Executive Vice President for Commercial Operations, who may be called upon to answer or as the case may be not answer some questions that may be posed given the raging commodity environment that we sit in here this week; and also by Tim O'Brien, our General Counsel, who may answer some questions of a legal nature.

As Nahla mentioned, I will be referring during my presentation -- to our presentation, which is on our website.

So turning to -- actually, before I turn to slide 4, let me just make three general points about what I'm going to cover before I turn it over to Bob.

I'm really going to discuss three interrelated areas -- current operations; forward initiatives; and as a segue into Bob's presentation, capital allocation.

Associated with these three areas, there are three takeaway points.

First, all business regions of the Company are executing well against a corporate business strategy, which in my opinion is being increasingly validated by market and industry conditions.

Second, there is more fuel on the tank.

The solid foundation of the existing business provides a springboard for earnings and cash generation growth through the expansion of our FORNRG program and through our repowering and [ECHO] NRG initiatives.

And third, thanks to the cash generated by our solid current performance and the market's near-term focus on issues only tangentially related to the intrinsic value of energy NRG, we have both the means and the opportunity to initiate a sizable share buyback program today with the goal being to take advantage of the Company's low current share price to lever our shareholders more strongly and through the Company's increased earnings power over time.

So now going into more detail starting with slide 4, our second-quarter adjusted EBITDA was $338 million for the entire Company, up 205% year on year.

This increase is of course the result of the acquisition of Texas Genco, which contributed beginning February 3 to the combined Company's results.

On an apples-to-apples basis excluding Texas and other portfolio changes, the adjusted EBITDA result for classic NRG was up by approximately 17%.

Given the very mild winter, which had a significantly negative impact on our first-quarter '06 performance, we believe that our results year-to-date are acceptable, particularly given that they are underpinned by much stronger year-on-year performance in the areas within our control, namely plant and commercial operations.

As we anticipated, the Company's strong financial performance and the shift away from cash collateralization, which began with the Texas Genco acquisition, have in turn fed the Company's robust liquidity position and healthy leverage ratio.

While our execution has been solid, our financial performance continues to be influenced by events beyond our control, most notably energy commodity prices and seasonal weather.

The precipitous decline in 2006 gas prices, even taking into account yesterday's movement, has had a negative impact on both our merchant energy sales in Texas and on our oil-fired peakers in the Northeast.

And as such, has prompted the reduction of our 2006 EBITDA guidance from effectively 1.55 billion to 1.5 billion.

While we, the directors and management of NRG, take this step of reducing guidance for the first time in the new NRG's history neither lightly nor happily, I believe that the fact that we are only reducing guidance by 3% during a period when gas prices have declined over 30% is a validation of both our regional diversification and of the soundness of our portfolio baseload hedging strategies.

Now turning to slide 5 on plant operations, our safety record remains strong at approximately 44% better than the industry average.

Once again, I'm happy to report that there were no life-altering accidents at NRG.

Likewise, our profile with respect to the traditional environmental emissions continues to improve due to the completion of PRB conversions at Huntley and Dunkirk and additional fuel switching on the margin.

We expect that future significant reductions will come during the 2010/2011 time period, as we add back-end controls to comply with environmental regulations tightening under the Clean Air Interstate Rule.

With respective plant operations proper, the second-quarter EFOR performance of our classic NRG coal plants is significantly improved year on year but with quite a bit of room for further improvement under the FORNRG program.

While overall production is up year on year, we realized lower margins on the Texas merchant sales and our Northeast peakers generated significantly fewer megawatt hours in 2006.

Nonetheless from an operational perspective, we're pleased with the performance of both our classic NRG fleet and the NRG Texas plants.

Now turning to slide 6 and 7, which deal with the Company's commercial operations activities.

As we have articulated in the past, our commercial operations group has two basic guiding principles.

One of which is static and the other of which is dynamic.

First, we seek to manage through the dark spread with our baseload capacity by maintaining a matchbook as far out as the commodity markets will permit without surrendering an ill liquidity discount.

This is the static part of the strategy.

The second dynamic part component of the hedging strategy is that we adhere to the proven winner of a strategy known as "buy low, sell high."

For us of course, this translates principally into buying coal low and selling power high.

Over the past couple of months, we have had noteworthy success in adherence to both of these guiding principles.

First, we have significantly added to both the length and volume of our baseload matchbook, and we have well-timed the two sides of the equation on the "buy low, sell high" principle.

First, with respect to coal.

We have taken advantage of recent softness and new-found length in the PRB market to add materially to our coal position in the 2010 to 2012 timeframe.

We have purchased almost 40 million tons of additional PRB coal, spread over those three years, raising our coal hedge levels in those years to above 50%.

These deals were struck a few weeks ago and reflects a decline in PRB prices, which has occurred over the past several months as illustrated in the box in the upper left of the page.

Now, before turning to the electricity side of the equation on slide 6, let me point out that we also applied the "buy low, sell high" philosophy to emissions sales.

Due to our excess emission credit sales effort early in the year followed by our repurchases in recent months after prices dropped, we're now $4 million and 23,000 emission tons better off than we were at the beginning of year.

I would note that the price of SOX credits are on their way back up.

And while we obviously are longer in terms of excess SOX credits than we have ever been, our financial projections and guidance do not contemplate any additional emission credit sales.

Now looking at slide 7 on the electricity side of our baseload hedging strategy, the decline in 2006 gas prices has not been reflected in the back end of the gas curve.

Indeed, the back end of the gas curve remains stronger than it was either at the beginning of 2006 or at the time we executed the Texas Genco acquisition.

We took advantage of the recent strength in gas prices to add significantly to our power hedges in 2009 and beyond.

Indeed, we have hedged some 2011 power for the first time.

While the incremental percentage numbers do not appear large -- 5 to 6% of incremental additions to our power hedges in each of 2009 through 2011 -- in nominal value terms, these trades equate to approximately $1 billion of revenue.

In addition, consistent with our recently-established practice, these additional hedges were executed primarily through option structures.

They give us significant upside opportunity, while putting a floor under our financial return.

Furthermore, we utilized a combination of forward power and gas sales in order to maximize the potential value of any heat rate expansion which occurs in the market.

Now turning to slides 8 and 9 having to do with asset disposition.

As it has been sometime since we reported on our non-core asset value maximization program, we have outlined on these slides both recent developments and the cumulative success of our asset disposal program since its inception.

As you will note, this program's contribution to value creation and balance sheet improvement have been considerable and a material but often overlooked component of our success.

We consider asset management and dispositions a core skill and critical strategic competency.

With respect to the recent announcement of our Australian asset sales, these transactions are expected to generate net after-tax proceeds in excess of $400 million to NRG once fully consummated.

Having said that, we need to caution the market that the Gladstone portion of the sales process remains subject to considerable closing risk due to the consent rights invested in the partners in the project.

Now turning to slide 10 and shifting focus from current execution in the areas of operations, trading and marketing and asset management to the Company's principal initiatives going forward.

In due time, I'm reminded that more than a year ago I was asked during an earnings call whether any fruit remained to be harvested on the NRG tree.

I responded that while we indeed had been successful in harvesting most of the low-hanging fruit during the Company's first post-Chapter 11 year, plenty of fruit remained higher in the tree.

Through the focus on ROIC&NRG initiative, the ECHO NRG program and most recently the Repowering America with NRG plan, we're going after that higher fruit.

In the case of the FORNRG initiative, we are already well into harvesting.

Last year, we achieved a $35 million EBITDA benefit out of the FORNRG initiative against an original objective of 25 million.

Today, we are announcing an expansion of the FORNRG program to NRG Texas and an extension of the now companywide program by one year to 2009 with a recurring EBITDA target contribution of $200 million plus an additional $50 million onetime cash savings associated with more efficient cash management.

Turning to slide 11.

The year-by-year buildup of the FORNRG targets appears on this slide.

And some of the more significant contributors to the program include continued benefits from improved reliability and reduced EFOR, driving an incremental $45 million of value and cost synergies and purchasing-related initiatives which are driving enhanced returns for NRG Texas, adding an incremental $55 million and including the elimination of the duplicative G&A and overhead.

Now on to slide 12.

With the main story today being capital allocation, I don't have a lot of time to delve into the two most recent forward-looking initiatives -- our repowering plan, which was announced on June 21st, and ECHO NRG, which includes our acquisition of Padoma Wind as well as several other elements constituting our multi-pronged effort to be proactive in response to the environmental issues and opportunities which confront our Company and our industry.

These two initiatives will however be the focus of NRG's first analyst conference to be held October 16 to 18.

In the meantime, I want only to draw your attention to two of the five key elements, which provide a foundation for our repowering program.

First, peak supply demand records in all of our forward domestic markets are not only being broken, they're being shattered.

And the new records, which are set forth on this slide -- slide 12 -- are already being eclipsed with new demand records anticipated virtually across the country either today or tomorrow.

These new records and particularly the extent by which many of the old records are being exceeded is a positive development for our repowering initiative, most notably in the psychological impact it will have on wholesale power buyers, their regulators and public policymakers.

It will increase their motivation to secure their long-term wholesale supply and to get more metal put in the ground.

Chronically high natural gas prices in the forward market and dwindling reserve margins have caused states in the tightest regions already to take meaningful steps to get involved in the process to ensure that new capacity gets constructed and that we've done so on the strength of long-term off-take agreements with a state or state-endorsed entity.

We expect several of these request for proposals to be issued, bid and awarded before the end of 2006.

This is a very positive -- indeed essential step for our repowering effort, and we are engaged in an extensive effort to prepare a comprehensive response to these RFPs.

Now turning to slide 13 and summing up what does it all mean.

If we combine all we have done through improved plant operations, asset dispositions and careful cash management to ensure robust current liquidity with the work done by our commercial operations group to secure baseload hedges for the future NRG, we have the means to embark on a very substantial capital allocation program now with a high degree of confidence about the Company's cash generation capability going forward.

Looking at slide 14.

Just because we have the means to allocate a substantial amount of capital, we still need to answer the question of why.

Why have we chosen to allocate a very substantial amount of capital to an open market repurchase of the Company's shares?

While there are several different motivations for companies to initiate share buyback programs, the motivation for the share buyback program we are initiating today is quite straightforward.

NRG stock is quite simply severely undervalued, and that undervaluation is in our opinion primarily a result of the stock market's unwillingness to look beyond current and next year financial performance.

As we have sought to demonstrate on slide 14, the way we look at the Company's medium-term earnings profile, there is an embedded growth potential of nearly 60% over the next four years.

The important thing is that contrary to popular perception, this growth potential is only partially a result of high forward gas prices impacting the uncontracted portion of our generation portfolio.

Other drivers include more predictable sources, such as existing hedges entered into gas prices substantially higher than 2006.

As the first line on slide 14 reflects, that incremental EBITDA potential for 2010 is $140 million.

And we expect that number to rise dramatically as we hedge further and shift value from the more speculative second line to the more certain first line.

The second, new or increased capacity payments from the three Northeast ISOs.

A very positive regulatory development during 2006 has been the relatively unimpeded progress made towards the introduction of some version of locational capacity markets in all of the Northeast ISOs.

In this regard, I need to point out that while we are confident that California is making progress toward some version of a locational capacity market and we would benefit from the introduction of such a market, we do not assume in the numbers that appear on this page any capacity payment upside from California.

And also on this page, the successful conclusion of FORNRG in 2009 at a recurring EBITDA target of $200 million, which would represent an incremental EBITDA gain of almost $120 million relative to the 2006 FORNRG target of 81 million.

While this embedded growth potential is close to $1 billion is quite attractive on a stand-alone basis, it represents only part of the story in that it represents just the Company's current intrinsic growth potential.

It does not take into account the value that can be created by the Company through successful execution of its intrinsic growth strategies, including successful implementation of a significant portion of the NRG repowering initiative, further development and expansion of the ECHO NRG initiative and disciplined participation in the inevitable trend towards industry consolidation either as a buyer or as a seller.

By buying back a significant amount of our common shares now before the full impact of the medium-term value creation potential of this Company is felt in the market, we leverage our remaining shareholders further into the upside in the Company's stock which we're confident will become increasingly and ultimately fully recognized over time as the market appreciates the full strength of the Company's combined intrinsic and extrinsic earnings growth potential.

Now, I would like to turn the call over to Bob Flexon for his review of the Company's financial results.

Thank you, David, and good morning.

Today, I will cover our second-quarter results, provide an update for our 2006 outlook and review the details surrounding our capital allocation program David just mentioned.

On slide 16 are the second-quarter and year-to-date financial results, the significant factors that affect our performance and the impact of NRG Texas.

Adjusted EBITDA excluding mark-to-market impacts for the quarter increased $227 million, $208 million due to the addition of NRG Texas to our portfolio.

Excluding NRG Texas, the NRG classic portfolio's earnings increased by $19 million or 17%.

Year-to-date, adjusted EBITDA increased by $303 million also due to the addition of NRG Texas with steady classic NRG portfolio earnings year over year.

These quarterly and year-to-date results are despite a drop -- despite an 11% drop in classic NRG domestic generation.

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

Overall year-to-date performance despite an unseasonably mild winter was equal to last year's performance when we experienced more seasonal weather conditions.

Adjusted for asset sales, our performance improved 8% over last year.

Free cash flow for the quarter totaled $199 million compared to $1 million in 2005.

Collateral returns of $42 million were collected this quarter versus $43 million outflow during the second quarter 2005, a net $85 million cash flow increase.

The balance of the quarterly increase, $113 million was primarily related to our Texas operations.

Year-to-date, the story is similar.

Free cash flow increased by $476 million, as cash collateral returned year-to-date totaled $272 million as compared to an outflow $179 million in 2005, a differential of $451 million.

Partially offsetting this increase was $127 million in refinancing expenses compared to $33 million for the same period last year.

Additionally, interest payments increased $29 million due to the refinancing of our debt for the NRG Texas acquisition.

Excluding these financing-related activities, the collateral changes and the 2005 onetime dividend from West Coast Power, cash flow from operations year-to-date increased by $235 million with capital expenditures increasing $37 million quarter-over-quarter.

Slide 17 provides the quarter and year-to-date adjusted EBITDA by region.

The regional numbers include the mark-to-market impacts, which are adjusted below on a consolidated basis.

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

While the Northeast may appear at first glance to have performed better than last year, embedded in the 2006 results is a $5 million forward mark-to-market loss for the quarter and $21 million of gains associated with the reversal of a 2005 $119 million year-end mark-to-market loss.

Adjusting the mark-to-market out for both years reveals the Northeast's second-quarter adjusted EBITDA was $59 million versus $61 million for 2005, relatively steady quarter-over-quarter results.

This is primarily due to increased New York and EFOR capacity payments and stronger EFOR performance from our baseload plants that offset the 11% drop in generation and $8 million of higher major maintenance costs.

The higher major maintenance expenditures related to the reliability improvements, while our Oswego plant underwent a major outage this quarter.

Texas's quarterly results included $45 million, a mark-to-market gain, caused by the ineffectiveness or correlation breakdown of gas and power prices in the ERCOT market.

The region added another exceptional operating quarter with top quartile EFOR performance continuing from the baseload plants along with strong run time from their gas plants.

This helped offset the impact of the lower than anticipated power prices on the unhedged baseload position.

Year-to-date, the Northeast recorded $25 million of net mark-to-market gains associated with forward sales of electricity.

In addition, in connection with the 2005 mark-to-market loss, $65 million reversed to income during 2006.

After adjusting 2005 for similar impacts, the Northeast year-to-date results were $165 million year-to-date compared to $196 million in 2005.

The decline is due to the unseasonably mild winter during the first quarter.

Year-to-date generation for the Northeast is down 17% with the oil-fired gas and gas-fired generation down 43% and 48% respectively, resulting in $69 million and decreased NRG margins.

Year-to-date, NRG Texas has delivered an extremely strong operating performance, offset by lower than anticipated power prices on the open baseload position.

NRG Texas as noted earlier recorded $43 million of mark-to-market gains in the second quarter.

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

Total generation from the South Central plants increased 14% for the quarter and 12% year-to-date, thereby reducing their purchase energy needs to meet contract requirement.

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

The Australian region now consists of only the Gladstone investment.

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

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

The liquidity this quarter was largely due to higher cash balances, totaling approximately $1 billion or $7.40 per share, offset by increased usage of our [upsea] facility supporting our current hedging activities.

Components of the cash increase included $268 million of cash from operations during the second quarter, excluding collateral returns and interest expenses.

Second-quarter results as with first quarter benefited from the cash accretive impact of the Texas Genco acquisition.

Total collateral returned for the quarter was $42 million.

As of June 30, 2006 total posted collateral was $209 million.

Approximately $135 million of the $209 million balance is expected to be returned during 2006 as the underlying positions settle.

During the quarter, we spent $37 million in CapEx and made $72 million in cash interest payments and $13 million of preferred dividend payments.

Our revised 2006 guidance is shown on slide 19.

Since we first provided guidance during our roadshow in January, gas prices have declined significantly, approximately $3.60 per million BTU across the calendar strip.

At that time, we had estimated our sensitivity to gas prices at $65 million per dollar change in gas or approximately $235 million in margin value.

At our last earnings call with New York capacity pricing steering at prices higher than we had originally anticipated and with the forward curve holding and rising through the third quarter, our peak summer season we maintained our guidance at the original 1.6 billion with the stated provision that gas prices would have to remain at least steady.

As highlighted on the graph since May, the forward gas curve has continued to fall, particularly in the critical months of July, August and September, the months our portfolio is most tightly tied to change in gas prices.

Through improved operating rates, higher generation from our Texas gas-fired assets, capable New York capacity markets and our progress with FORNRG, we have absorbed approximately $190 million of the estimated $235 million impact.

The net difference of $45 million is reflected in our updated guidance.

Our revised guidance also reflects $10 million of increased development costs associated with several repowering RFPs due this fall.

These expenses were not previously included in our guidance.

Finally, the Flinders operation has been classified as a discontinued operation.

Therefore, we have adjusted our guidance to exclude their $45 million of expected contribution.

I'll now shift the presentation to today's announced capital allocation plan.

Before delving into our capital allocation philosophy and mechanics of structure, as outlined on slide 20 are financial principles and a guide to the plan structure.

The most fundamental of these principles is prudent balance sheet management, achieving and maintaining targeted debt to total capital and leverage ratios as well as other financial measures.

In addition, maintaining the appropriate levels of liquidity, which doesn't mean hoarding cash but ensuring we have the sufficient flexibility to meet obligations and be in a position to optimize and support our operations.

We also remain committed to complying with our debt covenants and returning capital to both debt and equity holders when opportunities exist.

Slide 21 lays out our decision tree for capital allocation.

The underlying theme is the balance use of cash between organic growth and investment opportunities that include Repowering America initiative, bolt-on acquisition, other plant investments, managing debt balances to targeted levels and returning capital to shareholders.

Our cash management approach is to ensure we have the proper liquidity to support current operations and fund economically-prudent investment projects.

If cash balances exceed these needs, excess capital is first used to bring debt balances within targeted ranges and second return to equity holders.

Slide 22 highlights the capital allocation transactions we are announcing today.

It will be accomplished in two phases with Phase I providing a return of capital to both shareholders and debt holders, while Phase II provides a further return of capital to shareholders in 2007.

Phase I includes $500 million in common share repurchases and a $400 million reduction in our Term B first lien debt.

Phase II to occur in 2007 is an additional $250 million share repurchase.

As disclosed in our press release today, if market conditions change, we may use this capacity for the initiation of an ongoing dividend.

The anticipated proceeds from the sale of our Australian business segment will be used to pay down the Term B loan in the first quarter of 2007.

In addition to the reduction in the Term B loan, an additional $177 million of consolidated project level debt will be eliminated once the Flinders portion of the sale closes.

We remain confident the Flinders transaction will close on schedule in the third quarter with after-tax cash proceeds in excess of $230 million.

Although the Gladstone sale is less certain, once the Flinders sale closes, we're committing to the $400 million reduction by the first quarter of 2007.

Phase II is expected to be initiated after the restricted payment's capacity expands in the first quarter of 2007.

The expected expansion based on the definitions in our credit agreement and indenture is approximately 200 million to $250 million.

Our existing credit agreement and bond indenture contain restricted payments limitations, which by definition include share repurchases.

The statement in the 2006 limit of $250 million -- we will form two wholly-owned consolidated unrestricted subsidiaries common stock funds -- common stock fund 1 and common stock fund 2 -- that will have the necessary capacity to carry out Phase I of our share repurchase plan.

Slide 23 is an overview of this structure and each of the steps necessary to repurchase the shares.

Step one is the funding of two non-recourse bankruptcy remote subs.

NRG Corporate will inject $166 million, while Credit Suisse will provide $344 million comprised of $250 million of non-recourse debt and $84 million of preferred equity.

The NRG Corporate cash injection of $166 million uses a portion of the Company's existing restricted payments capacity, leaving $84 million in available capacity.

Step two is the repurchase of common shares.

The funding in step one occurs on a pro rata basis as shares are repurchased.

Funds from each of the three sources -- NRG Corporate, the Credit Suisse non-recourse debt and preferred shares -- are drawn.

The repurchase shares serve as collateral to the $250 million of non-recourse debt.

Step three, carried out by Credit Suisse is their hedging program initially expected to be for approximately 40% of the repurchase shares.

The hedge position to be established in the open market will decline with the approaching maturity dates of 2008 and 2009, depending on the price of the underlying shares.

The non-recourse substructures essentially serve as a warehousing facility for NRG stock until the Company has sufficient restricted payments capacity to settle out the structure in 2008 and 2009.

In a moment, I will cover how the shares move to the corporate level and the subs are liquidated.

The advantage of the structure, which we created and developed with Credit Suisse, allows us to work within our credit agreement and bond indenture while accelerating otherwise unavailable future restricted payment capacity to today, purchasing a meaningful level of NRG shares at prices we viewed as undervalued, limiting our initial financial commitments of $166 million while providing flexibility for increased capacity and providing a credit and rating agency-friendly structure.

Slide 24 covers how the non-recourse subs are funded, the cost of the facilities and the liquidation of the subs.

As I mentioned earlier, the cash funding of the subs is from NRG Corporate and the Credit Suisse facility and the funding occurs on a pro rata basis as shares are repurchased.

The $66 million of interest and dividends on the Credit Suisse facility are pre-funded at inception -- $50 million for common stock fund 1 and $36 million for common stock fund two, supporting the $400 million accretive value at maturity of the 0 coupon non-recourse debt and preferred facility.

The implied pretax cost of the Credit Suisse facility is a blended rate of approximately 7.6% with an expected after-tax cost of approximately 5.8%.

In addition, Credit Suisse retains the upside and share price appreciation to the extent the share price compound annual growth rate exceeds 20%.

For example, assuming shares are repurchased at an average cost of $50 in 2006, since common stock fund 1 and common stock fund 2 mature in 2008 and 2009, Credit Suisse retains the share price appreciation above $72 and $86.40 respectively.

NRG at this option can settle this difference in either shares or cash.

When these subsidiaries are liquidated in 2008 and 2009, NRG expects to use $220 million and $180 million in cash and restricted payments capacity to repurchase 275 million and 225 million of shares at the 2006 acquisition price.

The difference represents NRG's original contribution excluding the pre-funded interest and dividends.

NRG can elect not to purchase the shares, which in that case results in a prearranged liquidation of the subsidiary.

Our objective in creating this structure was to enable a meaningful capital allocation program while staying within our guiding financial principles as listed on slide 25.

Today's capital allocation announcement also delivers on the commitments we made to both our debt holders and our shareholders.

In summary, we're delevering at the corporate level, complying with our debt agreements, maintaining financial flexibility and providing a meaningful return of capital to our debt holders and shareholders.

David?

Thank you, Bob.

Before I turn the call over to the operator for Q&A, I wanted to end on slide 27 with our 2006 checklist.

We remain on track to achieving all of the near-term objectives that we laid out for this Company in front of the investors at the beginning of 2006.

Notwithstanding the distractions that our Company has been subjected to during the year, our organization has stayed focused on the path that we're convinced will continue to deliver value to NRG stakeholders over the short, medium and long-term.

Today is about capital allocation as we told you it would be five months ago.

And our $750 million capital allocation program is in our opinion a strong reflection of the cash flow generation strength of the combined classic NRG and Texas Genco.

As we go forward from here, we will draw your attention in greater detail to our other value creation initiatives.

With that, I would like to turn it over to Dan to open the lines for Q&A.

(Operator Instructions).

John Kiani, Deutsche Bank.

First question is on slide 19 when you discussed your adjustment to guidance.

What curve date did you use to kind of mark the rest of the year to market?

The last time we provided an update to guidance was at our call in May.

In preparation for that call in May, we were using a gas curve that was in the -- call it the mid-to-late March timeframe.

So on the slide if you looked at the April 1st kind of price level -- that is between the March 1st and the April 1st -- was the level we were using.

So then based on the recent run-up in the NYMEX and the spikes we've seen in market-bearing heat rates, how much of the 45 million -- or can you talk a little bit about just in general what you could potentially make up in 3Q or what you've seen over the last couple of weeks for the quarter?

When we set up our current guidance, we were -- again, we had gone through the work and we do a detailed ground-up look at this.

It goes back to a couple of weeks where the curve was.

And obviously, the curve has moved up since then, so it's given us a little bit of a lift.

But the sensitivity that we provided in the appendix showed that if gas moves up a dollar, you're getting somewhere just under $10 million for each movement.

The key point though is on the gas movement.

Certainly seeing more of it in the summer months, August and September, is more meaningful to us than if it's towards the back end of the year.

So we're getting some upside from that in that order of magnitude.

Because from a hedging standpoint, you are more open in 3Q on a seasonal basis?

The correlation is much tighter in the summer months.

You've got the higher demand.

You've got more generation as well.

Just one more question.

On slide 14, the current hedges and current baseload -- $140 million of incremental EBITDA -- does that also consider the Big Cajun II contract?

Consider the Big Cajun II contract in what sense?

It does include -- I'm not sure I understand the question.

In other words, when you are looking at the incremental EBITDA for 2010, does it include the impact of the Big Cajun II contract?

No.

This is just for the -- this is excluding South Central.

All of the numbers that you basically see here on this slide exclude South Central.

Right.

But I guess what I don't understand is that the Big Cajun II contract of 2010 is essentially the same as it is (multiple speakers) --

Right.

What's the (multiple speakers)?

So it's 0 (multiple speakers) --

0 impact.

And what's the ballpark embedded natural gas price in that contract?

On the hedged price?

Yes, for Big Cajun II.

The Big Cajun II contract is -- the energy portion is largely geared to coal prices actually.

The gas -- the problem with the Big Cajun II contract is the gas price changes with the gas market, but it's a fairly small weighting in the blended energy price.

Brian Taddeo, The Bank of New York.

I just had a question with regards to the amount of access -- the capital allocation program, just curious as to how much more capacity you actually would have if you wanted to the rate you'd have to buy back shares.

I know you are only using a portion of the -- I guess your equity that's under the caps but just in terms of raising new debt or preferreds that's actually buyback shares and put them in this kind of structure.

How much initial room do you have to doing more?

You could answer that question first or we've got $80 million of remaining capacity for this year in round numbers, then you can roughly -- the split in leverage would be the same or you could do it a two-for-one so that $80 you can put another -- you could possibly put another $160 million of combined recourse and non-recourse debt in preferred in addition to the 80 of capacity so that would create 250.

And then next year when our basket expands by 250, you can use anywhere upwards to that amount, depending on the capacity down to the structure.

But you could expand it pretty significantly from where it is now in the same sort of structure you would have the tranches on in the later years.

So for next year if we did it, you've got to tranche for 2010 and 2011.

So you could really upsize it pretty significantly.

I would say you could almost double it.

I assume it's your intent to -- going forward if you're going to do any of these kind of programs, you're going to use the same -- a similar sort of structure than just -- instead of just using cash on hand to do these.

What we like about the structure is it does provide that flexibility.

And if circumstances change for us dramatically in the next several years for whatever reason and if you need to retain some of that financial flexibility, you have it.

Also, we view it as a fairly good cost of capital play.

The cost of these facilities on an after-tax basis are below 6%.

So using that structure now to leverage the baskets, you know we can see using it more in the future.

Elizabeth Parrella, Merrill Lynch.

I wanted to follow up on that last question.

By announcing the capital allocation program in this manner with this 500 for this year and 250 after the liberalization of the restricted payment basket at the end of the first quarter, should we read that to mean that you won't be doing anything additional this year or by Bob's comments about the fact that there's still something left in the restricted payment basket.

It might give you some additional flexibility for example to deal with potential shares that might be sold into the market by the financial sponsors.

I'm disappointed.

We only announced it two hours ago.

You are already ready for the next share buyback.

Currently from our perspective, I think that this is all we would contemplate to do for the course of 2006.

But we know we think this is a significant sum.

As I said, we're committed to then adding to it in April of 2007.

But we haven't discussed and I can't contemplate a circumstance under which we would up the basket now.

Bob, do you have anything to add?

I agree, David.

Unless something dramatically changes, I don't see us changing from the levels we are at now.

You are right in recognizing we do have the flexibility but I don't see us using it this year.

But then, what was the reason for leaving 84 million in the restricted payments basket just because you could use a two-for-one structure?

Just again to leave us some cushion in the restricted payments basket if we should need it.

So we could lever up to the size we wanted and retain some flexibility.

Just as a last follow-up, can we assume that with respect to a dividend, we should not assume to see anything potentially done before the end of the first quarter and is the -- I'm sorry?

We didn't say anything, but that's right.

You shouldn't assume to see anything in this next nine-month timeframe.

Gregg Orrill, Lehman Brothers.

Two questions on the quarter.

First, if you could provide a little color on how much switching you saw from gas to oil in the Northeast.

And what was the EBITDA impact of buying back some of those emission allowances in the quarter?

Bob, why don't you do the EBITDA impact on the emission allowances, and then I will ask Kevin to talk about the gas to oil?

On the EBITDA impact on the emission allowances, it's virtually nil because they are put into inventory.

We did put some options against them to create some option income of a couple million dollars.

But the net effect though is that they're sitting in long-term assets as an intangible.

So they're not in the P&L.

As far as switching from gas to oil, I think the story for this year has actually been the exact opposite.

And it's really if you look at how high oil prices have been with the steep decline over the last few months in the gas price, a lot of the marginal oil plants that we saw a lot of run out of last year have not been running that much this year.

The one caveat I would put on that is particularly in New England where some of the plants are under RMR contracts, then you get recovery of your fuel.

Some of those oil units have been running.

But if you look at the really big merchant facilities, particularly something like Oswego, gas is dispatched well ahead of those facilities for most of the summer.

Oswego is running for the first time this year this week.

So that shows a big change from last year.

Michael Lapides, Goldman Sachs.

One easy one.

On page 7 -- and you may have discussed this a bit;

I just wanted to make sure I caught it -- the hedging of baseload power for 2009 and 2011 that if I look at 2009 that incremental 5%, that's above the 67% already hedged.

Did you provide any guidance about which regions or what implied gas price that was hedged at?

No.

I think those 5, 6 and 6% are subsumed within the green, so it's included within the 67, 41 and 19.

I will see if Kevin wants to answer the question about price.

I think I know the answer to your question, but I will let him be the bad guy.

But I think these trades are mainly put on through gas sales booked in the Texas market.

Is that right, Kevin?

I would say we manage the baseload fleet through the second lien structure against all the regions.

We've heard on the last couple calls people want more clarity about where we are putting these structures in, so we've actually modified this chart to be color coded with the South Central.

We've combined the Texas and Northeast.

And unless the rest open, I think you can assume going forward that the open section will primarily be taken up with the Texas and Northeast.

We've been reluctant to really break that down much beyond that because of the way the second lien structure is set up.

And quite frankly, we are very active in the market constantly in these back years.

I don't want to broadcast to our counterparties specific locations that we're going to be coming out trying to hedge.

You didn't want to answer the price question either, right?

Correct.

Sorry, Michael.

No problem.

Thanks, guys.

[Brian Olsen], Luminous Management.

I just had a quick question looking at the sensitivity of natural gas, looking at the way spark spreads and GAAP are today, I was wondering what kind of run time you assume on peakers for California, in-city New York and other PJM assets for (indiscernible) sensitivities in the appendix.

I think everything is normalized.

Yes, it is.

It's all normalized.

So like on a day like today, would that be able to well increase like that $8 million target?

It would seem like you would be able to bring in a much larger number if you have.

The rule of thumb that we use on that is that when you've got the upside around the peakers and primarily Oswego and the in-city New York, anywhere from 500,000 to 750,000 per day is the kind of benefit that you get.

That's incremental to the sensitivity we gave.

So when you give the sensitivity, that's like a baseload number.

And anything you get out of the peakers is upside?

That's exactly right.

Brian Chin, Citigroup.

Just a follow-up on Lapides's question.

With those additional hedges that you've got on page 7, is it still fair to assume that you're using natural gas future sales as opposed to direct power sales so that way you've maintained your spark spreads and heat rate upside?

You are right in that there is some view implied based on heat rate, spark spread, but there's also a liquidity issue.

I think the further out the curve you go, there's just more liquidity in natural gas, so particularly in the out years where we have more of a bias toward natural gas.

In the prompt years, you have to be careful that some of the correlations can break down as you become very prompt.

So in the prompt years, we're much more biased toward power products.

Can you actually quantify that breakdown or give us some sense of view of how much the prompt years generally are power versus gas versus the back end of the years?

I think the answer is no.

I currently don't have that at my fingertips.

David Silverstein, Merrill Lynch.

I was wondering, Bob, if you could just walk through the structure one more time and just walk me through the unwinding process in terms of NRG buying the shares out of the packet -- out of the vehicle and what type of commitment that represents or doesn't represents as an optional or as an actual financial commitment and then what type of claim that is.

The subsidiaries are structured to really self liquidate in 2008 and 2009.

And say roughly 30 days before the maturity date, we have to provide notice whether or not we're going to buy the shares out of the unrestricted sub.

So if we decide we're going to buy them out, we will be buying those shares out at the original cost.

So in 2008 for example, we'll put $220 million into the subs and take out $275 million worth of shares.

It really represents an option rather than a financial commitment?

Absolutely.

That's what I wanted to clear up.

If we decide not to take the shares then over the last 30 days before the maturity date, Credit Suisse has the opportunity to either sell them in the market or take the shares in full settlement of the obligation.

So, if your share is trading at half the price?

Yes.

If our shares are trading at $20 at the time, we wouldn't exercise that option.

Elizabeth Parrella, Merrill Lynch.

Could you now talk about with the additional hedges you've put on, power hedges you've put on for the out years, what your gas sensitivity kind of a rule of thumb would be say in 2008 or 2010?

I don't have that updated.

I haven't updated that since we disclosed it in January on the roadshow.

Can I ask one follow-up just to clarify something?

Sure.

On the restricted payments basket for next year, that kind of gets trued up after you report your year-end results.

And your expectation now in terms of where that basket would be and is that amount increased by whatever is left at the end of '06 or just how should we think about the size of that basket (multiple speakers)?

Yes, assuming that we end this year with the $80 million that I talked about earlier next year based upon the formulas.

And if you take the credit agreement as an example, the credit agreement is in excess cash flow calculation.

Based upon our cash flow calculation, we see it expanding by $250 million.

So you take the 250 plus the 80, we will have 330.

The indenture is calculated slightly differently, so you will come up with a slightly different number under the indenture.

But the lower would essentially govern?

Yes.

What you're saying is whatever that number is, whether it's 250 or it's 330 million, you have the potential to kind of repeat this structure and lever up the stock repurchase incapability of the Company?

Yes.

You'd use the same type structure, same type funding mechanism.

Lasan Johong, RBC Capital Markets.

Did I hear correctly, Bob, that if there is an increase in share price above 20% that CSFB would completely take that upside?

That's annual growth rate.

So in year 2, it would have to be up 44% from the repurchase price before they get any upside.

I see.

Okay.

That's one of the things we like about the structure is that the share price has to be much higher before someone shares in the upside as compared to the structures we've done in the past, which had a much lower strike price for them.

Then, could you tell us how much it costs on the options to hedge out in 2011 -- 2010 to 2012 I think you said it was?

On the gas?

You said NRG had hedged an additional -- yes, I think it was on the gas -- you had hedged an additional amount going forward.

I think what we've talked about in the past that we use collar structures where we're buying the put to put a floor on.

But we're also selling it out of the money collar.

So we largely finance those structures with the out of money collars.

But there is a little incremental cash spend.

But it's not overly material.

Just I assume that the weather impacting the last month during the third quarter has been very positive.

Hot weather is positive.

Can you give us a quantification of that by any chance?

I think it's a little too early.

I mean we don't -- the July numbers we don't really even have yet.

I mean we really noticed a difference this quarter announcing on August 1 versus August 10.

But we have seen in some of our weekly reports that the generation is up and the July results are probably a little better than what we had originally thought.

So June was softer;

July looks like it will be a little bit better than what we thought.

And I assume most of that benefit is coming from your peaker assets?

The peaker -- yes, I mean that is the most immediate place.

But the rise across the curve is helping the merchant portion of the baseload suite as well.

Mitchell Spiegel, Credit Suisse.

Two questions.

First, what is the second lien capacity currently utilized?

It's $2.3 billion and that includes [health fees] that are posted in round numbers of about $600 million.

So if you back them off, you get to 1.7 billion.

My second question is last year's summer was -- I think summer's account is unusually warm -- 20% warmer or so than the prior year.

When you look out this summer, given you're comparing against a relatively warm season notwithstanding the spike in price -- the temperatures the last two weeks, how do you think about the outlook for the year?

What I look at, the thing I've been focusing on the most is just the impact of the declining gas prices relative to where they were earlier in the year.

And that's quite -- that's been quite leveraging to us.

To the extent it starts climbing back, we've given you the sensitivity.

Plus, as we also talked about if you get some extreme weather events in an order of magnitude whether you can expect to pick up from that too on a per-day basis.

So I think the overall -- the overriding story though for us has been the gas prices.

Dan, I think we have time for one more question.

[Andrew Shirley], Ivory Capital.

On slide 14, you show potential incremental EBITDA buckets.

And I was wondering whether one should assume that there might be meaningful offsets on the expense side or is this as you see it all incremental upside?

Meaningful offsets on the -- in terms of sort of maintenance CapEx, I mean there's always a possibility for some movement or some bringing forward of the scrubber program, which we've outlined in previous slides.

But it is mainly a bigger spend in the 2010 to 2012 timeframe.

But if there are offsets, I would think that they would be comparatively modest relative to the size of this.

I would add that the fixed cost base is subject to inflation obviously.

But there are no unusual large-scale expenses that would be going against these numbers for the portfolio that exist today.

Repowering is obviously another.

But there's a 720 to 960 range -- doesn't necessarily capture increasing coal prices going forward that will be creeping up over time.

Is that the way to look at those numbers?

We're pretty well hedged out.

And we're hedged out at levels that are in the same neighborhood as where we are now.

But to the extent there is some movement up or down, that will affect the numbers.

You commented about hedging PRB coal in 2010 and 2012.

Can you comment on whether 2010 to 2012 prices are in line with the 2008 price you show in the chart on slide 6?

We would except for one technicality.

The chart on page 6 shows the price for 8,800 coal.

And when I had mentioned that we had bought close to 40 million tons because of the requirements of our plants, we were actually buying $8,400 coal and the price for $8,400 tracked 8,800 coal at a 2 to $3 discount.

And I think it's fair to say in general terms that it's probably flat on the curve that you're seeing there on page 6 going forward.

Our view as a company is not that it is basically that PRB prices will be flat in nominal terms over this timeframe; they won't be contango.

Last question.

In terms of some of the incremental hedging you put on in 2009 through 2011, were those hedges put on at clearing heat rates that are in line with the current clearing heat rate?

Or is there any implied higher or lower heat rates in those out-year hedges?

We always assume kind of current heat rates when we put the structures on.

If we have a bias on the heat rates that we want to preserve, we may execute it as a gas component if we want to keep the upside from the heat rate.

But when we execute hedges, we always assume kind of what's available in the market.

Operator, I think that concludes this call.

I want to thank everyone for participating, and we look forward to talking to you at a variety of investor conferences during the month of September and also at our analyst conference in October.

So thank you very much.

Ladies and gentlemen, this does conclude today's teleconference.

You may disconnect your lines at this time.

Thank you for your participation.