NRG Energy Inc (NRG) 2006 Q1 法說會逐字稿

Greetings, ladies and gentlemen.

Thank you for holding.

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

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

A brief question-and-answer session will follow the formal presentation. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded.

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

Thank you, Ms. Azmy.

You may begin.

Thank you, Dan.

Good morning and welcome to our first-quarter 2006 earnings call.

This call is being broadcast live over the phone and from our website, 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 published 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, 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 and the press release and this conference call.

In addition please note that the date of this conference call, May 9, 2006, and any forward-looking statements 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 these 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.

Let me add my own welcome to everyone participating on the call.

I am joined today as usual by Bob Flexon, the Company's Chief Financial Officer, who will be reporting on the Company's financial results.

And today also we have Chris Jacobs with us, who runs the Company's plant operations who is here to report on our focus on ROIC and NRG program one year since its announcement.

I also have with me here in the room Kevin Howell, who runs our commercial operations function and who is available to answer questions.

As Nahla said, we will be referring to a presentation and to page numbers of the presentation which appears on our website.

So if you turn to page 4, I would really like to begin with the conclusion of this page and that is that 2006 year-to-date for NRG has been about three things, execution, integration, and preparation.

Execution in that we closed and financed the Texas Genco acquisition while at the same time substantially improving the performance, our performance both in terms of plant operations and in terms of commercial operations.

Integration in that we are well on track to achieving all of our integration objectives and timetable with respect to both Texas and the West Coast and I want to remind you that in the case of West Coast, Dynegy had previously been responsible for the joint ventures commercial operations function.

And preparation in that through forceful implementation of an extensive planned outage program and a flexible coal supply management scheme, we will enter the financially critical summer period in a better position than we have in any previous year.

More specifically and still looking at slide 4, we show the adjusted EBITDA number for the entire Company.

The adjusted EBITDA result for Classic NRG contained within that number as further adjusted for mark-to-market changes was generally flat year-on-year.

Flat is not something that most CEOs would wax eloquently about but given the almost unprecedented mildness of the winter in Classic NRG's key Northeast region, flat to me serves as a validation as the baseload hedging strategy that is a fundamental element of our business model.

And as you know is increasingly a key point of differentiation between NRG and the other companies in the merchant generation industry.

Of course this result also is a testament to the portfolio effect of our multiregional platform, as significantly better year-on-year results in South Central helped neutralize the mild weather's impact on the Northeast.

The other part of our first-quarter success was the nimbleness showed by our emissions trading desk in monetizing the additional excess SO2 emissions allowances freed up by the mild weather before the price of SO2 allowances dropped.

I would note that this is a capability which we did not possess a year ago.

I also would note our liquidity statistics as we already are seeing the delevering impact of the Company's cash generation and of the shift of our commercial operations from a dependence on cash collateralization arrangements to the second lien structure.

Our net debt to total cap already is approximately 55% and on the current track will be down an additional 3% to 4% by year-end 2006.

From an operational perspective our safety record improved by 22%, placing as further ahead of the industry average and most importantly we had another quarter with zero fatalities and zero life changing injuries.

With respect to the performance of our baseload units, while I don't want to steal Chris Jacobs' Thunder, the classic NRG baseload plants achieved a substantial improvement both in capacity factor and forced outage rate.

These results were achieved even as we completed the conversion of our New York coal plants to 100% PRB burn.

With respect to our Texas baseload units, in 2006 they improved on their already top quartile 2005 performance.

Particularly noteworthy were the South Texas nuclear plant, which achieved a capacity factor for the quarter in excess of 100% and a forced outage rate of 0.0% across both units; and Limestone, which successfully completed a 99 MW upgrade of one of its units ahead of schedule and in time to support ERCOT during its hot weather event a few weeks ago.

Finally with respect to transactions, the first quarter of 2006 obviously was a momentous quarter from the perspective of reshaping our business.

Obviously most notably in Texas Genco we have added a multifuel across the merit order scale business in one of the most attractive competitive wholesale markets in the United States.

We also during this quarter gained full control of our West Coast portfolio at a reasonable price.

In each case not only have we had integrations which have proceeded smoothly to date, we also have during the course of integration found ways to unlock substantial incremental value.

In Texas in particular we developed a more tax efficient ownership structure with respect to our interest in the South Texas nuclear project.

This more efficient structure is worth $200 million on an NPV basis over and above the tax benefit originally ascribed to this acquisition.

I want to thank the staff at NRG Texas and NRG West who have worked so hard to make the integrations a success.

Also as illustrated by Audrain and Cadillac, we continue our successful program of monetizing at value those assets which do not fit into our multiregional portfolio strategy.

With respect to our Australian business, our process continues on track.

There are not that many specifics I can give you today since final proposals are due next week other than to tell you that there continues to be a tremendous amount of interest from strategic and financial investors in our Australian business.

At this point we anticipate making a decision regarding our Australian business by the end of the second quarter.

Now turning to slide 5, we highlight some of the key commodities involved in our business.

As demonstrated by the table in the upper left, Powder River Basin prices have moderated substantially since the January spike as we predicted that they would at the time.

Since we actually have contracted for Powder River Basin coal modestly in excess of our 2006 needs, we were a net seller during the quarter.

We expect as the summer progresses there may be more opportunity to sell our excess Powder River Basin coal at value.

In the upper right you'll see that we have managed to stockpile for a variety of reasons in excess of our fleet target inventory range.

This is precisely where we want to be as we enter the summer season.

Equally important to our overall fleet statistic in this regard is that on a plant by plant basis our coal stockpile is relatively evenly distributed with all baseload units carrying in excess of 20 days of coal at a minimum.

We have been able to achieve this objective by shifting two trains from Big Cajun service to Texas in order to enhance the pace and volume of deliveries to both Parish and Limestone.

Of great assistance in this regard are the four extra coal trains which we have pressed into service during the first quarter, the first of 21 train sets that we will take delivery on over the next eleven months.

Now turning to the New York City capacity chart on the lower left, we had previously indicated that our view was that 2006 would be down significantly versus 2005 levels.

However the dynamics of this market have remained robust and spot capacity prices continue to clear at or near 2005 levels.

As a result of this winter and summer auction results, we have increased our outlook for New York City capacity margins which are now factored into our 2006 guidance.

I would also note that capacity margins in the rest of state New York have also shown strength recently.

Finally with respect to the emissions table on the lower right, we sold a substantial number of SO2 allowances during the first quarter in order to take advantage of the high prices prevailing during that quarter.

SO2 prices have declined quite substantially over the past couple of months to the point that they have become in our opinions significantly oversold.

As a result, since the first quarter ended we have in fact bought back virtually the same amount that we sold but at a substantially lower average price.

In this regard I want to reemphasize that we only sell SO2 allowances in excess of our expected generation requirements.

Now turning to slide 6, finally I want to update you on the baseload hedging strategy which is the foundation of our commercial operations.

I want to remind everyone that the objectives of our baseload hedging strategy are threefold.

First to be substantially hedged with respect to our baseload generation as far out as the market will give us without forcing us to sell subject to an ill liquidity discount.

Second, we seek to preserve -- while we seek use effective hedge instruments which preserve as much of the upside as possible.

And third, we seek to be very selective as to when they put on these hedges, recognizing that the high volatility of natural gas prices and their close correlation to power prices in our core markets will give us opportunities over the next few years to fill out our hedge position at times when gas prices are robust.

You will note from the table on the left on page 6 that during the course of the quarter we added incrementally to our power hedges in each of 2007 through 2010.

Almost all these additional hedges were executed through collar or option structures.

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

As the time sequential Henry Hub gas curve on the upper right demonstrates, the back end of the curve has strengthened substantially since we purchased Texas Genco and this is of course the part of the curve into which we are executing our baseload hedging strategy.

Now to update you more fully on our progress with plant operations, I'd like to turn it over to Christine Jacobs.

Good morning.

I'm pleased to be here to update you on the progress we have made in the FOR NRG program.

In the first-quarter call last year we announced a new major effort at NRG focused on improving our return on invested capital or ROIC.

We branded our efforts focused on ROIC at NRG or its short form FOR NRG.

As I described for you then, FOR NRG is not a simple cost reduction effort.

In fact we know that additional investment will continue to be needed in many areas to bring about improved plant performance.

Our focus is on making the right decisions to improve the return on existing assets.

Corporate cost reductions have helped us to fund future operational improvements.

We are happy to report that we are ahead of schedule in meeting our commitments.

FOR NRG has been institutionalized across NRG and our investments in time and energy are paying off.

Our message on page 8 is about corporate and operations initiatives are fundamentals of FOR NRG.

We've previously reported our corporate centered accomplishments led by significant savings in the areas of tax and insurance.

These were savings we could realize almost immediately and did so in 2005.

At the outset we knew that the operational improvements would take more time and in some cases require investment in facilities and well-planned outages.

The biggest drivers of FOR NRG in 2006 through 2008, come from initiatives at the plants and we are starting to see the returns.

Our initiative to reduce our station loads to enable us to increase net megawatts available for sale have already shown rewards.

We saw improvements from Oswego last year and so far this year our West Coast and Norwalk Harbor plants have seen significant reductions in their station load.

Through joint efforts between operations and regional affairs we are starting to be paid for the additional auxiliary services that we provide.

For example in line with our projections the Astoria, Arthur Kill black start system have all been tested and verified by the New York ISO.

Our ability to provide this valuable service to the ISO should mean about $1 million in additional revenues to NRG per year beginning this year.

Our Somerset plant showed a great deal of flexibility in adapting to some different coals which meant that we will show several million dollars in fuel and transportation expense cost reductions.

Our dedicated Somerset plant staff accomplished this without sacrificing performance and in fact they ran for a solid 129 days straight this winter.

FOR NRG is driving improved plant performance.

Much of the improved profitability we projected last year was to come from improved EFOR in our coal plants.

On page 9 we elaborate on both the goals and our performance in meeting those goals at the Classic NRG coal plants.

We benchmarked each of the Classic NRG units against units of like profile and age.

In 2005, 70% of our coal plants megawatts were produced at plants that operated in the bottom half of benchmarked performance.

Through April 2006, that number has gone down to under 50% and we have another 45% of our installed megawatts performing in the top quartile.

This solid performance improvement is based on completing targeted planned maintenance and improving our internal processes.

The largest single cause of forced outages and therefore lost production has been and continues to be boiler tube failures.

In 2005 in Classic NRG coal plants we lost over one million megawatt hours due to these problems.

On a quarter-on-quarter basis in the first quarter 2006 we have had 34% fewer lost megawatt hours due to boiler tube failures.

Although we do recognize the performance improvements, it will have some variation.

We have every reason to believe that this overall trend will continue given the amount of work we have accomplished in our facilities this year.

You can also see in this chart that our Texas coal plants are ahead of Classic NRG [instant] improvement process and have set the pace for solid contribution to the bottom line.

Classic NRG however is on track to follow closely behind.

The path will not be smooth and we anticipate some ups and downs, however we remain confident that we'll meet our FOR NRG goals of above-average performance across the fleet for Classic NRG by the end of 2006 and top quartile for the entire NRG fleet by the end of 2008.

Why are we feeling cautiously optimistic?

On page 10 we have detailed some of the 2005 and 2006 outage work that will contribute to meeting our FOR NRG goals and contribute to a strong summer performance.

The Big Cajun II plant led this turnaround effort.

Last year we reported that poor operation of reliability had a negative impact on our Company's financial performance.

Through changes in some operating practices and well-timed targeted outage work, we have seen a major reversal in performance.

The work has included a boiler tube inspection and replacement program and improvements in low NOx burners to reduce our boiler slagging.

We expect to see the effects of the first-quarter outages at the Huntley and Dunkirk facilities in upstate New York in our second quarter performance.

Early indicators for April give us confidence that we are having an impact.

Further we take considerable pride in pointing out that our plant and region teams are simultaneously improving EFOR rates, completing PRB conversion efforts, and revamping our railyards to more efficiently and quickly handle railcar unloading and turnaround.

These things are being accomplished with dramatically lower safety recordable rates.

Again, our Texas plant showed the way with exceptional performance during the recent heat waves.

Classic NRG wants a chance to show that our investments have paid off.

Now what is yet to come for NRG?

We list a few what next steps on page 11.

We're bringing the FOR NRG process to Texas.

Yes, Texas plants are younger and they've certainly set the standard for superior EFOR performance.

Therefore Texas will not have the same magnitude of contribution to FOR NRG as does Classic NRG but we do believe that their contribution will be meaningful.

We also believe that our bottom-up approach to project identification and the fact that investing in our people, our processes, and our equipment brings higher returns will resonate in Texas.

And of course there is always the advantages of scale that we can leverage.

Planning is underway and we will report back to you later this year.

These are all part of what we are doing for NRG.

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

Thank you, Chris, and good morning.

Today I will cover our first-quarter results, update the Company's financial position and liquidity, and provide our 2006 outlook.

In addition since this is our first reporting periods subsequent to the February 2006 acquisition of Texas Genco, I will highlight how the acquisition affected our reported numbers.

Slide 13 highlights our first-quarter financial results.

The significant factors that affected performance and how NRG Texas impacted the numbers.

Gross margin compared to the first quarter of last year was up $338 million.

Driving this increase was several factors. $188 million from the addition of NRG Texas to our portfolio; $57 million of SO2 excess emission allowance sales; $29 million of current year net domestic forward mark-to-market gain versus a $40 million loss in Q1 2005; $44 million of income related to the reversal of a portion of the $119 million mark-to-market loss recorded at year-end versus $42 million of reversals of previously accrued mark-to-market gains; and a $23 million improvement from our South Central region primarily due to higher merchant sales and increased unit availability.

These positive items were partially offset by $84 million in lower margins from our Northeast region due to the mild northeast winter which contributed to weaker power prices and approximately 900,000 megawatt hours or 22% lower generation quarter-over-quarter.

The decline was primarily from the 90% output drop from our oil fired assets, which include peaker assets in the NEEPOOL and Western New York areas.

In regard to the $57 million of SO2 sales, $15 million is related to transactions originally entered into during Q4 2005 and closed during the first quarter of 2006.

The balance is related to the sale of a portion of our forecasted excess position.

Our original forecasted excess emission allowance position increased during the first quarter by approximately 17,800 tons primarily due to the lower-than-expected generation.

The mark-to-market impacts were primarily in the Northeast region and in total accounted for $155 million of the $338 million gross margin variance quarter-over-quarter.

The financial impact of the lower generation was also mitigated in part by the performance of our coal-fired assets and continued focus on managing cost and performance.

Coal-fired generation in the Northeast increased 4% during the quarter, while South Central's generation increased by 10%.

As Chris discussed earlier, Big Cajun II's EFOR derate improved to the top quartile this quarter largely due to the acceleration of the spring 2006 outage to the fall of 2005. [Hunley] experienced an improved EFOR derate this quarter as well.

The Texas coal and nuclear plants continued with their exceptional top quartile performance with STP achieving an EFOR derate of zero.

The PRB conversion has been completed at our western New York plants and has resulted in significantly higher PRB coal blends.

The domestic mix of PRB coal consumed during the current quarter including our South Central and Texas operations reached 80% as compared to 77% in 2005.

Excluding Texas and South Central, PRB coal consumption reached 62% in the Northeast region as compared to 49% during the same period last year.

This improvement was particularly cost-effective as the cost of delivered Eastern coal this quarter was $80.13 per ton versus $69.64 per ton in the first quarter of 2005, a 15% increase.

The overall blended and delivered coal cost for the Northeast region was $53 per ton, as compared to $49.80 per ton for the first quarter of 2005, an increase of just over 6%.

Coal cost on a delivered basis for our South Central region, which consumes 100% PRB coal, was $24.24 per ton versus $25.56 per ton in the first quarter of 2005.

The slight decrease in delivered coal price quarter-over-quarter reflects the benefit of our new coal transportation contract, which became effective April 1, 2005.

Including the two month's ownership of our Texas coal fleet, the delivered cost of coal consumed by our North American generation fleet for the first quarter was $32.21 per ton or $1.94 per million BTU versus $36.32 per ton or $2.29 per million BTU for the first quarter of 2005.

This improvement in per ton cost is largely due to the inclusion of low-cost PRB and lignite coal consumption at NRG Texas.

Excluding NRG Texas, our coal cost per ton increased to $37.10 or $2.16 per million BTU.

This is largely due to the diesel fuel cost escalator in our existing rail contracts combined with a higher mix of Eastern coal at our Indian River plant.

Operating and maintenance expenses increased $70 million versus the same period last year, $65 million due to the acquisition of NRG Texas.

The balance of the increase was primarily due to the higher major maintenance.

As Chris highlighted, we continue to invest in improving plant performance through our FOR NRG initiatives and scheduled outages.

The general and administrative spend increased by $11 million, all due to NRG Texas.

The $11 million of Texas spend includes approximately $2 million of onetime expenses associated primarily with the retention of key staff during the integration.

G&A at NRG excluding Texas was flat quarter-over-quarter, yet this quarter's results included $1 million related to a bad debt allowance and $2 million related to a Texas integration costs.

Net of these items, G&A spend was slightly lower as compared to last year.

Interest expense, which includes $4 million of non-cash amortization of financing costs, increased $63 million quarter-over-quarter.

This increase is directly related to the acquisition of NRG Texas, which we partially financed with new debt facilities.

While we successfully lowered our overall interest rates, we increased the overall size of our debt facilities, resulting in higher interest expense as compared to the first quarter of last year.

Also included in the quarter's income statement is $178 million of refinancing expenses associated with the acquisition financing.

The refinancing expenses included $127 million for the premium paid to our prior second lien debt holders.

Additionally the $178 million included a number of non-cash items; $33 million for the amortization of the bridge loan commitment fee entered into last year; $31 million for the write-off of deferred financing costs on the prior debt; and offsetting these amounts was a $14 million credit for the write-off of a debt premium.

Our adjusted EBITDA excluding mark-to-market impacts of asset-backed hedges in both periods was $314 million in the first quarter versus $234 million in the same period last year.

NRG Texas contributed $95 million of adjusted EBITDA for the two months of NRG ownership during the quarter.

If changes in the portfolio are taken into account, including NRG Texas and Enfield, our adjusted EBITDA results for Classic NRG were flat compared to last year, despite one of the warmest winters on record.

Cash flow from operations of $366 million this quarter shown on slide 14 was primarily due to the operating results and $230 million in return collateral.

These increases were partially offset by $53 million in cash interest payments primarily for accrued interest paid to NRG's and Texas Genco's former debt holders; $127 million in tender premium payments to NRG's former second lien holders; and a $63 million working capital increase during the first quarter due to a $23 million inventory build; $87 million accounts payable decline; and $20 million of other accrued expenses.

These working capital increases were partially offset by a $65 million decrease in accounts receivable due to normal seasonal movements.

The increase in other assets and liabilities is primarily related to $42 million in proceeds from the sale of two turbines.

The first quarter increase in cash flow from operations was partially offset by $35 million in capital expenditures.

Slide 15 highlights the Company's capital structure at March 31, 2006 versus December 31, 2005.

Post acquisition the Company has no significant near-term debt maturities, not until the senior secured term B matures in 2013.

To reduce interest rate risks, the Company entered into a series of interest rate swaps this past quarter.

The swaps converted a portion of the senior secured facility from floating to fixed-rate interest.

The overall fixed to floating interest rate today is 76% fixed and 24% floating.

The interest rate swaps qualified as a cash flow hedge and approximately $35 million of deferred gains associated with the swaps was recorded during Q1 to other comprehensive income.

We continue to actively manage our capital structure to optimize the debt to equity mix.

Our targeted range of net debt to total capital remains between 45% and 60%.

Net debt to total capital at March 31, 2006 was 55%.

By year-end we expect this ratio to be nearer the midpoint of the targeted range.

Slide 16 updates our February 28, 2006 disclosure for our second lien structure that supports our hedging activities.

Available capacity under the second lien structure represented by the gold area is based on 80% of our baseload capacity going out five years, declining down to 20% by year eight and thereafter.

This equates to approximately 6800 megawatts of baseload capacity for each of the next five years.

Hedges currently under the second lien structure have a net exposure of approximately $1.8 billion, an increase of approximately $500 million since the end of February.

Of this increase, the vast majority is due to the higher forward ERCOT power and gas curves.

Since our last disclosure, additional hedges onto the second lien structure for the 2007 through 2010 time period range from 100 megawatts to 300 megawatts per year.

Letters of credit posted as collateral supporting these hedges remains unchanged since February 28, 2006 at just over $570 million.

For hedges currently under the second lien structure, the maximum incremental LC exposure is $64 million if gas prices should rise from April 30 levels.

NRG's liquidity as of March 31 is presented on slide 17.

The increase in liquidity resulted from higher cash balances totaling approximately $885 million or $6.45 of cash per share on hand, and increase liquidity facilities primarily to support our commercial operations and hedging activities.

Components of the cash increase included $316 million of cash from operations during the first quarter excluding the collateral returns, interest and refinancing expense.

The strong cash flow results includes the cash accretive benefit of the NRG Texas acquisition.

As noted earlier, also contributing to the cash increase was $230 million of returned collateral.

The completion on March 31, 2006 of the West Coast Power, the purchase and Rocky Road sale, the net purchase price of $160 million was offset by the consolidation of the West Coast Power cash balance at March 31 of $180 million.

At April 30, 2006 an additional $15 million of cash collateral had been returned and outstanding cash collateral was $236 million.

Approximately $185 million of the $236 million is expected to be returned during 2006 as the underlying positions settle.

During 2006 we anticipate cash balance will continue to increase through the cash generated by operations, the return of posted collateral, and increased usage of our second lien collateral structure to support hedging collateral requirements in lieu of cash postings.

With our acquisition of Texas Genco, appraisals are currently being performed to finalize the fair value of the assets and liabilities acquired.

Slide 18 is our preliminary allocation of the $6.2 billion purchase price.

As expected, the majority of our preliminary purchase price allocation is property plant and equipment.

This value will be depreciated on a straight line basis over the remaining useful life of the assets.

Our preliminary estimate varies by plant ranging from 15 to 22 years of a weighted average life.

Intangibles include approximately $850 million of SO2 and NOx emission credits and another $400 million of positive fuel contracts.

The SO2 credits with nearer term vintages receiving a higher value are amortized based on the plant's generation while the NOx credits are amortized over the life of the respective plant.

The out of market contact allocation of $2.5 billion is being amortized to income over the life of the underlying contracts.

Included in the $2.5 billion is $1.9 billion of long-term power sales contracts and $472 million of gas swaps.

The net amortization to income for out of market contracts is expected to be approximately $478 million in 2006 and $609 million in 2007.

The third-party appraisal should be completed during the second quarter and will be used to finalize our purchase price allocations.

Our 2006 guidance is shown on slide 19.

We are reaffirming our guidance for both adjusted EBITDA and cash flow from operations.

Although first-quarter Northeast generation and power prices were below expectations, a number of items offset the declines including exceptional operating performance at W. A. Parish, Limestone, the South Texas project, Somerset, and Big Cajun II; stronger capacity markets in both New York City and New York rest of state; commercial operations quick response to monetizing the additional emission credit length caused by mild Northeast weather; and an improved outlook in the ERCOT market through incremental energy and capacity revenues from our gas-fired assets.

Ultimately the peak summer season will influence the achievement of our guidance targets.

As Chris covered, our FOR NRG program and summer readiness actions are positioning us to have successful operations during summer season.

Before turning it back to David, let me summarize where we are for 2006.

First, while the quarter was a challenging environment, favorable market offsets combined with higher operating reliability and commercial operations mitigated much of the downside caused by reduced demand and lower power prices.

Second, the integration of our acquisitions are proceeding and we are seeing a cash accretive impact through higher cash balance.

Third, the compelling investment story remains the cash generating capability of this Company, demonstrated by an expected 2006 free cash flow yield of over 16% from current stockprice trading levels which translates to over $8.00 of cash flow per share.

Finally as stated at our year-end call, our criteria to initiate capital allocation remains advance the integration of NRG Texas into our portfolio; realize the expected accretive cash flow benefits of NRG Texas and the existing NRG portfolio; and manage our balance sheet within our targeted capital structure.

With clear progress on each of these fronts, we expect to be in a position to announce and initiate our capital allocation plans during Q3, 2006.

David?

Thank you, Bob.

Before I turn the call over to the operator for the Q&A session, I just want to draw your attention on our last slide, on page 22, which is our 2006 scorecard.

Most of the goals on this page are full year objectives, but four months into the year I can assure you that we are making measurable and material progress in the accomplishment of all of them.

Bottom line, all of us at NRG are mindful of the fact that this January our stakeholders showed their confidence in our Company by providing us with a very substantial amount of debt and equity capital to fund the Texas Genco acquisition.

We remain committed to and focused on executing the plan that we have laid out during the road show in January.

So with that, operator, we are ready to take questions.

(OPERATOR INSTRUCTIONS) Elizabeth Parrella, Merrill Lynch.

A couple questions on NRG Texas.

First on the $93 million of EBITDA for the two months that you have owned it, how would that compare with your thoughts on your original expectations for I think a little bit less than $1 billion of EBITDA this year for the 11 months you own it?

Elizabeth, basically when you look at Texas and its earnings profile, it is different from the Northeast where you basically have six month shoulder six months peak.

So the first quarter and fourth quarter happen to be the weakest quarters for the Texas portfolio.

If you look at the EBITDA in the first quarter, we were slightly off in order of magnitude range, 10 to $15 million range off on the EBITDA, so not very much.

Again the drivers for the NRG Texas portfolio will be the second and third quarter.

Okay, and my follow-up question on Texas would be I know that originally I think you had built in very, very modest synergies or cost reduction benefits from the management fee going away and maybe $10 million of other, but I think not more than, say, $20 million.

I'm just wondering -- I realize you've only owned it for a little over three months, but can you give us a sense or can you give us a timeframe if you can't give us a sense now as to when you might be able to come back to us and let us know whether that is looking conservative or not?

Elizabeth, in our own budget and forecast, the spend at NRG Texas at the G&A level of about $60 million and you can see from the numbers that we reported, the run rate is exactly that.

We are still sizing it up and our plan is to bring that back to you during our call for the second quarter results.

For the firming up what the future looks like on synergies.

Okay, thank you.

John Kiani, Deutsche Bank.

Can you give a little more color on the $200 million of tax benefits identified through South Texas?

Sure.

And I'll just give you the high level, John, on this, but when we originally did the purchase price allocation and for the tax basis step-up, about 80% of the basis step-up was allocated to the fossil fired plants as compared to, say, 20% in round numbers allocated to the nuke.

The way that the tax structure was -- the way the entities were structured we couldn't take advantage of the 20% basis step-up for the nuclear.

So what we have done is we've been able to move that entity to be directly under NRG Inc. and any income that's generated by the nuke will then be offset by the NRG NOL and that leaves the basis back down at the Texas Genco holding company level and that basis is then fully allocated out to the fossil fuel assets.

So you basically get the piece of your purchase price or the basis step-up that was not going to be able to pass through is now allocated entirely to the fossil assets.

So that is $1.1 billion of additional basis step-ups.

If you multiply that by a 40% statutory tax rate, that is $440 million of after-tax benefit.

And then when we profile that out on exactly how do we expect to use that versus our NOL position in the cash flow, the present value of that is in round numbers about $200 million.

So it is a more efficient structure that supports our business far better than what we had and through the additional digging of the legal and tax groups, we've have been able to restructure it and get quite a sizable benefit of the restructuring.

Okay, great.

Can you give a little update on the Big Cajun unit for RFP process?

The Big -- in terms of the arrangement of the offtake?

For the 675 MW expansion.

The keys at this point are really twofold.

One is in terms of arranging the offtake arrangements and negotiations are underway with several counterparties.

Then also with partners, partners who would take their share of the electricity much the way that unit three at Big Cajun is structured, and that is going on as well.

So I think we expect there to be something that we can announce in this area within the next few months, but it is all going quite well at this point.

Okay, thanks.

[Rudy Tolintino], Prudential Equity Group.

Can you give us an idea of -- you talked about that New York capacity values have increased and how much of the increase have you incorporated into your guidance?

And what is the impact of that to your EBITDA?

Rudy, when we originally came out with our guidance for 2006 and this is going back to January right before we did all the security launch, we had New York City going down year-on-year by about $95 million and about $50 million of that was on the capacity side.

What we're seeing now in terms of the results achieved to date as well as looking at the forward curve and the outlook on the capacity side, we have seen two things.

First we're pretty much clearing near our mitigated price cap.

So on the capacity side, we are pretty much making up all of what we thought we were going to lose or substantially all of it.

The other element on capacity that is also an upside that we had not included in our forecast or we hadn't included when we originally did our forecast was the New York rest of state, which has been particularly stronger than what we thought.

So in terms of what is included in our guidance going forward, it is pretty much getting New York City capacity payments at a level pretty near to what they were last year and then the rest of state benefits coming through, which 15, $20 million from that side of it.

Okay, and have you sold any of your New York City capacity forward for 2007?

How much have you sold roughly?

For 2007 we have sold -- I don't want to get too specific, but we have sold a little bit, a few hundred megawatts in New York City.

And the rest of the state?

Have you sold any of that forward?

Again I would like to be a little bit vague here, but not a lot.

Okay, thank you very much.

Brian Russo, Broadwell Capital.

Can you remind us what the long emission allowance inventory position is?

Again I don't mean -- our aggregate position is -- I guess we are more than 200,000 allowances along.

I think that was in the January presentation, so since we have pre much been in balance so far this year we remained that long.

Okay, thanks.

Secondly, just could you discuss in greater detail the performance of the South Central asset base and the ability to sell excess capacity in the wholesale power markets in more attractive prices than what is embedded in the long-term contracts?

Let me address the second part then I'll turn it to Chris Jacobs to talk about the performance in the units themselves.

But in terms of our ability to sell our excess coal-fired generation into the market, it was a relatively positive quarter from that perspective.

And one of the complaints we have had, we have been very open about the way the transmission system is operated down there.

It is never clear to us why we are able to export our power and when we are not able to, but in this last quarter, we were constrained relatively infrequently compared to the two years that I have been here.

So it was a good quarter from that perspective.

Before we hand to Chris, Kevin, do you have anything to add on that?

No, I guess the one piece of I would say is that with the co-op contracts down there you get this inverse relationship and mild weather, our existing co-op contracts which are below current market levels, their load was down substantially and so what we are able to do particularly in the off peak period is export power out of the NRG zone back over into the Southern zone and we really saw the lift in kind of the off peak hours.

In terms of what made the plants work better, Chris?

I think as David had mentioned or Bob had mentioned, we moved an outage from first quarter of 2006 on Unit II into the fourth quarter of 2005.

So it was an unbudgeted expense for us, but it has had fantastic returns for our organization.

A lot of the work that we did on Unit II we are continuing to do on Units I through III and I think the fact that we've achieved top quartile performance for the first four months of this year at Big Cajun II across all three units is commendable to the organization.

We expect that although we will have some ups and downs we expect to see continued availability in the units for the balance of the year.

Brian, one final point is the gross margin for South Central was up about $23 million from the prior year and slightly more than half of that is due to the market sales if you will and then the slightly less than half would be the performance improvement.

Okay, thank you.

Paul Patterson, Glenrock Associates.

My question at this point is TXU.

Big, huge announcement in terms of building coal plants in Texas and maybe taking their show on the road at PJM.

And you guys are clearly market participants in these markets.

They are talking about a pretty aggressive plan.

I'm wondering what you guys think about it?

How it might impact you, what you think about it in general?

Paul, how much time do you have?

A few things.

I think on the most important thing, we agree I think with the assessment that most of you on the analysts side have also concluded, which is that the potential risk to us that so much coal is built in Texas that gas comes off the margin, that that's just we cannot envision the scenario where that happens.

So I think among the more aggressive elements of the TXU announcement is the idea that it is all going to be built by 2010.

So I think if you take a more realistic view even if you'd don't probability discount us of when they or whether they can build these things I think the timing is more likely to be staged over a 2011 to 2016 timeframe and then the baseload demand growth in Texas is so great that Texas needs 1.5 to 2 new coal plants a year.

So we feel very comfortable on that front.

Secondly, the big cost advantage that John talks about in his announcement, most of it is the benefit of brownfield over greenfield and if you believe that for TXU then you'll believe it for us, because that is also a key to our redevelopment strategy is brownfield over greenfield.

When you see what price like Coleto Creek clears at for well in excess of replacement costs for a plant with back end controls, the idea that one should be building rather than buying makes a lot of sense.

So we agree with John on that.

Just a couple more things.

I think the main point of differentiation for me in terms of the overall strategy is that NRG has always been -- we have always stated our claim is that we want to be a multifuel fire generator and while coal is in fashion today, I would say that gas was in fashion three years ago and I don't know what TXU wants to be, but we don't want to be the Calpine of coal here.

So we are going to stick to a multifuel strategy.

Paul, I guess the thing that I find most worrisome about the TXU announcement was actually the reaction of the sell side analysts to it in the sense that it reminded me very much of -- I don't if it was 1999 or 2000 and Calpine would announce that instead of having 50,000 megawatts they'd put another 30,000 megawatts under development and at that time the sell side analysts would skip all the intermediate steps and say each 1000 megawatts of development is worth $0.50 per share, ignoring the fact that the stuff all needed to be developed, constructed, operated, and sold at a profit.

I think a lot of the bubble period in the power space in 2000/2002 was resulting from Wall Street being enamored with these growth programs.

So I just hope that this does not unleash a torrent of ill-advised projects like in the last round.

I hear you.

Just to circle back with you on brownfield development, are you guys looking at anything like that?

Do you see the same sort of cost advantage?

Are you guys coming up with -- they're coming up with pretty low-cost pretty aggressive cost numbers that they are coming in with.

When you guys look at these plants, your own plants and what have you, do you see those kind of opportunities?

We definitely see opportunities around our fleet and this may just be a question of style, but I think what one analyst referred to is TXU or John Wilder's characteristic grand gesture, we are a bit reluctant to go down that path because the history of this company, again, I had this aversion to the “bragawatt” concept.

So we are working on several different redevelopment opportunities in Texas and other parts of our system and whether or not we ever lump them all to put them together and put them in one sort of grand (indiscernible), we haven't made a decision yet, but this is definitely a good time, the right time I think for the independent power industry to engage in brownfield development and we are putting a lot of effort into this area.

Thanks a lot.

Lsan Johong, Hong, RBC Capital Markets.

Your line is live.

Our next question is coming from Michael Lapides, Goldman Sachs.

A real easy one.

Can you provide a little more clarity regarding the extra hedges that you've put in specifically where you put them in and at what price?

Well, I have a very short answer.

No.

We would rather not give that.

In fact, Kevin, do you want to not answer that question?

I'd be happy to not answer that question.

I think generally we view our baseload portfolio as a portfolio, so when we are putting the hedges on we don't necessarily tag them to specific assets.

And if you look at the way the second lien structure is set up, it really is spread across a that whole baseload portfolio, so when we're in the market we're really executing against the total capacity that is under that second lien structure.

And as far as the prices, I really don't like to talk about the exact execution price.

What I will say is that we use a kind of a combination of instruments.

We'll use some straight out swaps if we've got really attractive levels that we're happy with that outcome and then if we still view there is volatility left in the market that we can monetize, we will put a collar structure in place where we may do a slightly below-market put option and partially finance it with an out of the money call option so that if get the volatility we can still participate in that last piece of the upside.

That helpful.

Let me maybe simplify the question a little bit.

On the deal running into the Texas Genco deal you provided going and going forth back into '05, you provided investors with a lot of insight on what kind of forward power prices hedged were in various regions.

Just real quickly, is that number going up or down?

In general it's going up and in fact if you look at the one slide that was in on the commercial operations you can see that particularly in the back end of the curve there has been a lot of upward movement and interestingly after the first quarter when you started seeing a drop at the front and the curve, what a lot of the market participants did is just roll their positions into the back end, so as you were actually having the front year come off, you saw particularly 2009, 2010 moved up dramatically.

So when we saw that movement we stepped back in and started hedging more off.

Right.

Thanks, guys.

[Ryan Watson], Stanville Capital.

When you look at your guidance on slide 19, being that the New York capacity markets have hung in there and actually probably done better than you thought and the Texas market is, judging by your comments at least remains strong, what are you -- what are the negatives that you've built into your 5 '09, '06 guidance, the May 9th guidance?

It seems like you have been rather constructive in your outlook on the markets.

Ryan, when we originally came out with the guidance again before we did all the securities offerings we were working off gas curves that were -- that existed in the fourth quarter of last year, which were substantially higher even than where they are today.

Gas came off upwards to $3.00 per million BTU and for the forward '06 versus where they were during the fourth quarter of last year.

So at that time we had a sensitivity that basically said gas goes down $1.00, the impact on the portfolio was around $60 million.

So you could do some of the math there and we had some when we originally did our guidance we had some contingency in there anyway, but that was the downside going into when we announced our year-end earnings.

But we were able to keep our guidance at $1.6 billion because we had some offsets, but it was certainly basically had used up a lot of our cushion at that point in time if you will.

Certainly today I feel the fundamentals are far better than what they were a couple months ago when we last gave guidance, so the certainty around the number I am feeling certainly more confident than I did in the past with the strength in the market.

But fundamentally the downside where we are today versus when we originally came out the guidance still is the forward gas power curve and the impact that it has on the open piece of the business down in Texas.

Okay, so is your guidance now, is it predicated on a specific price in gas?

What we did, Ryan, what we did is when we go through and look at the guidance before each of our calls, we'd look at all the different factors and we were using the market environment in March, so we were using the implied heat rates, the implied gas curve in March.

So we pivoted everything off of March on all of the information that drives the earnings, whether it is capacity markets or forward gas curves or heat rates, so it reflects the March operating environment and what we think then based upon our actual achieved through three months plus what we think the next nine months will look like based upon the fundamentals in the market.

Okay, so your current guidance now, your May 9th guidance is based on gas curves as of March 30?

Well, when we did it, we did the update during the month of March, so it's in the March timeframe.

Thanks.

Dan, I think by our account, there are four more people in the queue.

So we will answer those questions and then we had better call it a day.

Gregg Orrill, Lehman Brothers.

I was just wondering if you could remind us what you're doing or looking at for the proceeds from Australia divestiture?

Gregg, as we go through the process and once we know whether any sales or offers to sell it are meeting our requirements, we do in fact end up monetizing it.

We look at this overall with our capital allocation plans that we are developing now and we have not finalized exactly what we want to do with those proceeds or the build up of cash balances, but our history suggests that we always do a mix of keeping our balance sheet in line so we do something on the equity side, I could see us possibly doing something on the debt side as well.

And the Australia proceeds you could use for advancing some of the -- if you want to reduce some of the debt, you could end up using it for some of that.

But we'll have far more clear and well thought out answer on all of the cash that we have which has obviously gone way up but at $885 million plus with Australia, you've got the $300 million carve out, so we will come back to you in August with really clear plans on all of our capital allocation plans and how it impacts our cash balance.

Great, thanks.

[David Miller], (indiscernible) Associates.

What rates are you seeing in the marketplace for incremental transportation of PRB coal in terms of cents per ton mile?

On the rail transport?

Right.

Flexon: I don't know that we have been in the market that much, have we?

Because we're so heavily contracted.

We contracted for I guess now in the fourth quarter '04, so and we contracted essentially all of our rail needs for five or ten years depending on which part of our business and so I'm sorry I can't answer that question because we haven't actually been dealing with the railroads during the quarter about incremental transport.

Okay, thank you.

Elizabeth Parrella, Merrill Lynch.

Thank you.

I just wanted to go back to the discussion of the second lien structure for a minute.

Can you tell us where you are logistically in terms of being able to maximize the value of that?

Do you still need to get additional counterparties to sign on?

Can it become bigger in a sense than it is now when you've accomplish that or are you pretty much where you want to be?

Elizabeth, we're still looking to add on additional counterparties.

We've increased the number over the course of the year, but the more that we can get in there, the better since there's a lot of hedging that we like to do over the longer term with this structure.

The more counterparties the better for us, so that is a continuous effort for us to get more counterparties into the structure.

And that would help you put on additional hedges rather than freeing up cash collateral around existing hedges?

It can be a combination of both and the key thing with more counterparties, the counterparties each have their own internal limits or credit exposure limits that they want to take, so if you can divide it up, you can get more competition and you can do more hedging.

So I think it is a combination of both.

Thank you.

[Brian Taddeo], Bank of New York.

One thing just following up on the second lien structure question.

If I look at the slide on page 16, I'm just trying -- I wanted to clarify if you have $1.8 billion now, what is the total dollar amount?

What does that translate into in total dollars now and following up how big do you want that to get?

The whole second lien structure is based upon megawatts as capacity, not price.

So what we are looking to do is as they fill out the position going out in the forward years, the actual value of the second lien will fluctuate with prices.

We saw at the end of February the value was $1.3 billion and then at the end of April it was $1.8 billion, so it is sensitive to the gas price movement.

There's the $570 million of LCs that take up a portion of the collateral as well, which are pretty much capped out where we don't have to post any incremental other than maybe upwards of 64 million.

So it is not so much driven on a dollar amount, it is driven on a megawatt and then that translates into dollars that fluctuate with the price of gas.

Is it just correct to look at it and saying that space under that bottom curve looks about one-third of the total lien capacity?

Yes.

Is that about right -- that's a (multiple speakers) looking at it?

Yes, that's a fair way to look at.

Okay.

And how big do you want to expand that?

Well, our goal over time is to hedge out our baseload portfolio and what we have always said consistently on our hedging strategy is we like to protect our baseload generation particularly the peak baseload generation where we will take that into anywhere from 70%, 80% of the capacity which happens to be that same gold area.

So you'd be looking to fill over time to fill that up.

Okay, I appreciate it.

Thanks.

Thank you and operator, I think we're ready to conclude the call.

We appreciate everyone joining us for this call and thank you for your continued interest in NRG.

This concludes today's teleconference.

Thank you for your participation.