NRG Energy Inc (NRG) 2006 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the NRG Energy fourth-quarter and year-end earnings results conference call. (OPERATOR INSTRUCTIONS).

As a reminder, note that this conference is being recorded today, February 28, 2007.

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

Thank you, Sylvia.

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

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

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

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

This call, including the formal presentation and the question-and-answer session, will be limited to one hour.

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

To 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 and the press release and this conference call.

In addition, please note that the date of this conference call is February 28, 2007 and any forward-looking statements that we make today are based on assumptions that we believe to be reasonable as of this date.

We undertake no obligation to update these statements as a result of future events.

During this morning's call we will refer to both GAAP and non-GAAP financial measures of the Company's operating and financial results.

For complete information regarding our non-GAAP financial information, the most directly comparable GAAP measures and a quantitative reconciliation of those figures, please refer to today's press release and this presentation.

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

Thank you, Nahla, and good morning, everyone.

I am joined today, as usual, by Bob Flexon, our Chief Financial Officer, who will present after me with respect to our 2006 results.

And also joining me today is Kevin Howell, our Head of Commercial Operations, who won't be giving part of the presentation but is available to answer, or, as the case may be, not answer questions that you may ask about the Company's commercial position.

So, turning to the presentation, if you turn to slide 4, I'm pleased to report that for fiscal year 2006 we delivered on our guidance.

And that's notwithstanding the declining gas price environment through much of the year, and notwithstanding the generally mild winter and summer weather during 2006.

Our full-year adjusted EBITDA was $1.5 billion, up 105% year-on-year.

This substantial annual increase was largely driven by the acquisition of Texas Genco and by improved South Central performance, offset to some extent by lower margins and lower generations in the Northeast.

Our fourth-quarter adjusted EBITDA was a healthy $336 million which was particularly noteworthy given the record-breaking mild weather we experienced in December.

Given that December normally accounts for about half of the fourth-quarter results, the fact that we could hit our quarterly financial objectives during the warmest December in recorded history in the states of New York and Connecticut is a testament to how flawlessly the Company performed across all regions and across all functions.

Now turning to cash flow, cash flow generation continued to be strong, with the full-year 2006 result, as adjusted for collateral movements, of $939 million.

With a cash collateral inflow of 534 million during 2006, cash flow from operations during 2006 was $1.5 billion in total.

The reason we have managed this business for cash since we arrived here three years ago, and the reason we will continue to manage this business for cash for so long as we are here, is that robust cash flow is the tide that lifts all boats and makes all things possible.

In our case, our cash flow generation enabled us during 2006 to return $730 million to shareholders through share buybacks, to remove approximately $1.1 billion of debt from our balance sheet, and to substantially increase our spend on regular maintenance, maintenance CapEx and on initiating our repowering program, all the while maintaining our net debt to total capital ratio well within our targeted range, and while ending the year with a liquidity balance of $2.2 billion.

Now moving to slide 5, as you've heard me say before, and will undoubtedly hear me say again if you continue to listen to these quarterly calls, what sets NRG apart from other companies is not only that we have multiple value drivers available to us, but that we are built to execute effectively on many if not all of them simultaneously.

Slide 5 is intended to give you a sense of our ability to capture value on many fronts at the same time.

Many of the accomplishments listed on this slide will be touched upon by Bob or me later in the presentation, so let me just give you my personal view on one important issue, and that issue is the return of capital to our stakeholders.

On this topic, I believe, our track record is second to none.

Most recently, on the debt side, at the end of 2006 we paid back $400 million on our senior debt facilities, which as I mentioned before means that we've removed or avoided a total of 1.1 billion of debt from our balance sheet since the completion of our Texas Genco acquisition financing in January 2006.

In this regard, Bob and my commitment to prudent balance sheet management remains as steadfast as it has been since our inception, and is not in any way swayed by what one headline this week referred to as the easy capital currently being made available by Wall Street to our industry.

At this point I can't help but editorialize a bit by noting that I think that given our track record and given our hedge position, it's high time that one or more of the rating agencies should give serious consideration to removing us from the risk-driven ratings purgatory that they have held us in for the past three years.

Now, with respect to equity, during the course of 2006 we executed two share buybacks with a total value of $732 million.

That means that in the three years since NRG emerged from Chapter 11, we have done a total of four buybacks with an aggregate value of $1.4 billion.

In the course of doing these four buybacks, we have purchased and retired 34 million NRG shares at an average purchase price of $40.65 per share.

Now as we sit here looking forward, we have approximately $270 million remaining to go in the current buyback program, and we expect to complete that program during the first half of 2007, in accordance with our original undertaking.

The question that arises is what do we intend to do at that point?

Clearly, the conditions and timing are evolving in such a way that introducing a dividend merits more serious consideration, alongside our traditional approach of returning capital to shareholders via share buybacks.

But the dividend issue is one that we are not quite yet ready to address.

The most I can tell you at this point is that we as a management team and as a company remain committed to the regular return of capital to our shareholders, and that commitment will not end with the completion of this share buyback program.

Now turning to slide 6, on the operational front, NRG had a very good year.

In terms of our critical operational metrics, the equivalent forced outage rate at our baseload coal plants, we experienced substantial year-on-year improvement, both among the Classic NRG plants and at NRG Texas, with the Texas units as a fleet hovering near the top decile.

Not shown here, but possibly even more impressive, was the performance of the South Texas nuclear project.

Nucleonics Week recently ranked STP Unit 2 as the highest-generating nuclear unit in the United States during 2006, while Unit 1 was number six.

Taken together, STP was the highest-generating two-unit nuclear site in America in 2006.

Now, much has been said by the nuclear utilities about the benefits of nuclear fleet, and undoubtedly there are G&A synergies.

But we believe the performance of the STP nuclear operating company, which, by the way, carries an INPO rating of number one, speaks for itself.

Also, I'd like to note the FORNRG achievement at our Huntley and Dunkirk coal units in Western New York in restoring the effective capacity of three of their units to an excess of 190 MW, levels that these 40 to 50-year-old units have not achieved in decades.

In aggregate the capacity improvements underway at Huntley and Dunkirk hold out the promise of an incremental 70-plus MW of coal-fired generation at a cost far below the installed cost of new coal-fired generation.

Keep in mind also that our colleagues at Huntley and Dunkirk are achieving this result while burning 100% Powder River Basin coal, a type of coal that their boilers were never designed to use.

The other critical point I'd like to draw your attention to on this slide has to do with coal inventory.

Our coal plants now have on hand inventory in the high 20sm in terms of number of days at max burn, and our two coal plants in Texas both have 30-plus days of coal on hand.

This is the healthiest inventory position we have been in during my three years at NRG.

Moving to slide 7, as I stated previously, our bedrock principle is prudent balance sheet management, and our objective is to springboard our growth initiatives off a virtuous circle that begins and ends with a robust balance sheet.

On this page we show our multiyear progression on adjusted EBITDA and free cash flow.

After our initial period during 2004 of rationalization through contraction, we have grown robustly in each year since.

I'd like to review with you the main drivers, which as part of this virtuous circle will fuel further growth, while being funded in part by this past growth.

Looking at slide 8.

As you may recall, we had a sub-par operating performance during the second quarter of 2005.

At that time we already had initiated the FORNRG energy cost reduction and performance improvement program.

But our poor performance that quarter galvanized all of us to move faster and harder than we otherwise might.

We did not follow a one-size-fits-all approach, but used a more holistic approach.

We enlisted the support of our Commercial Operations group to ensure that we were solving for the highest value-added operating characteristic at each plant, and then pushing hard on outage planning to ensure that the maximum was done during the planned spring and fall outages to improve the targeted performance.

When Texas Genco joined us early last spring, we were pleasantly surprised to discover that they were ready, willing and able to use the FORNRG template to improve on their already top-quartile performance.

The results have exceeded our expectations and, particularly, our timetable.

Accordingly, the $200 million aggregate adjusted EBITDA goal, which we had originally sought to achieve by 2009, we now expect to achieve this year in 2007.

The 2009 goal, in turn, is being raised today from $200 million to $250 million of recurring EBITDA.

I have so many anecdotes about individuals at NRG who have had a meaningful bottom-line impact on our results through their participation and contribution to the FORNRG initiatives that I simply want to thank the entire NRG staff for their good work in this area, and to commend them to you as the shareholders of this company.

Now turning to slide 9, on the power side, we have added some hedges during the fourth quarter as part of the Hedge Reset program for 2010 to 2012, but for the most part we did not seek to add significantly to our long-term hedge position since our last quarterly report, as gas prices don't yet reflect our fundamental view.

As the graph on the left side of this page shows, the bar chart, we are virtually completely hedged on a matched book basis in 2007 and very heavily hedged in 2008 as well.

On the fuel side, as you can see we are hedged beyond our current needs.

We have done this in an effort to continue to build Powder River Basin inventory levels across our fleet in 2007. [Near-dated] Powder River Basin prices have fallen 26% since November.

And given the increased cost of coal production these days, we don't believe that producers can afford for prices to fall much further.

Thus, it's a good time for us to build up inventory.

Now I'd like to turn your attention to the heat rate curves, specifically the heat rate curve for Texas, which is depicted on the bottom right of this slide.

During our last quarterly call, we advised that, notwithstanding our baseload hedging strategy, we wanted to stay long to Texas heat rate exposure because we did not believe at that time, nor had we ever believed, that coal plants would be built in Texas on the scale or in accordance with the timetable that was then being implied by the heat rate curve.

Indeed, as this graph demonstrates, the heat rate curve has risen substantially and continuously since last October, suggesting that even before this week's announcement, the market had become increasingly skeptical about the prospect for 18 newbuilds.

Now looking at slide 10, we remain very comfortable with the present stance of our portfolio, which is to be quite insensitive to near-term gas volatility as a result of our hedges and forward sales, and still quite long to heat rate exposure.

We fundamentally believe that given the current and projected supply demand dynamics in Texas, heat rates can and will continue to rise.

When they do, it will trigger the new investment in generation resources that Texas requires.

And NRG Texas, with more than 4000 MW of gas, wind, coal and nuclear projects in active development in that state, stands ready to make that investment.

Now turning to slide 11.

When we were on the Texas Genco acquisition roadshow last January, I was often asked whether there might be some hidden value drivers in the acquisition.

My common response was always the same.

While our valuation was driven by the baseload plants, I thought Genco's 5400 MW of gas-fired peakers might provide a pleasant surprise.

In 2006 that indeed turned out to be true, as the output from our Texas peakers rose 16.5% to 7.9 GWh, from 6.8 GWh in the previous year.

As reserve margins continue to tighten across all of our core domestic markets, and as weather events return to our summer and winter peak seasons, I believe our peaker fleets in all of our core regions will contribute increasingly and materially to NRG's financial performance.

Now turning to our Repowering NRG program on slide 12.

There's more information on this slide than you would be interested in, but the basic point is this.

While we have not been immune to setbacks, progress is being made.

We continue to lift our development game.

As a company, while we still have room to improve, but we are much better development today than we were 12 months ago and we're light years better than we were two years ago when we first conceived of this repowering program.

In general terms, even leaving aside the moral aspect of the issue of global warming, for those of you who don't believe, I think our repowering program -- conceived, again, one to two years ago, with the key objective being substantially reducing the carbon intensity of the NRG fleet -- has been validated by the evolution of the marketplace, and by events currently taking place in the public policy debate.

In that regard, since it's my hunch that most if not all of you on the phone were otherwise occupied on Monday morning listening to a conference call emanating out of Dallas, you may have missed Senator Hillary Clinton's press conference held at exactly the same time at our Huntley power plant near Buffalo, New York.

Senator Clinton chose our plant, the site of our proposed 680 MW IGCC project, which we are developing with the New York Power Authority, to announce her landmark bill creating a Strategic Energy Fund.

This visionary legislation would provide the type and quantum of federal support required to make IGCC with carbon capture and sequestration a commercial, competitive and environmentally-benign reality.

Senator Clinton's bill provides federal support for five working clean coal projects with active carbon sequestration projects.

If enacted, it will jump-start IGCC with carbon capture sequestration, which is, in our opinion, the most promising approach to taking the carbon out of the coal and keeping it out of the atmosphere.

Looking at slide 14, Senator Clinton's bill is so important because it directly addresses the two issues that need to be addressed with respect to IGCC.

The first is the cost issue.

IGCC plants are more expensive than pulverized coal, because every IGCC plant built to date has been custom-designed and custom built on a one-off basis.

IGCC costs will only equalize with traditional coal units when multiple IGCC units are being constructed in parallel with each other.

By sponsoring five IGCC plants, Senator Clinton's legislation will incent the necessary supply chain.

The second issue is that, in order actually to have a positive impact on carbon emissions, IGCC plants need to be designed and built to separate and sequester carbon from very early on in the plant's operation.

Senator Clinton's legislation recognizes this and provides explicit support for carbon separation and sequestration.

The other two myths about IGCC, which have been circulated in recent months by proponents of traditional pulverized coal plants -- that is that it is not -- that IGCC technology is not commercially available, and it doesn't work on Powder River Basin coal -- are both patently false.

Our recently announced Memorandum of Understanding with Mitsubishi Heavy Industries addresses both of these issues, and I want to say it's an honor for our company to work with a company like Mitsubishi, who has developed this technology so deliberately and thoroughly over the past two decades, and who are so committed to ensuring its commercial success.

Now looking at slide 15, one more thing about IGCC.

And I should say for those who weren't there that this slide is the heart of a presentation I delivered a couple weeks ago at the CERA Week conference in Houston.

The Bush administration is a sponsor of the coal-fired zero-omission FutureGen project.

We, through NRG Texas, have been a supporter of the FutureGen project for several years.

Indeed, we have donated the land in Limestone County, Texas, which is the highest technically ranked site of the four finalists to host FutureGen.

However, it is our view that jumping from where we are now straight to zero-omission FutureGen is the equivalent of NASA jumping directly from Alan Shepard to Neil Armstrong with nothing in between.

This is where Senator Clinton's legislation, contemplating five IGCC plants around the country, should be enacted in order to provide the necessary evolutionary steps on the way to FutureGen.

When you consider where these five IGCC plants should be located, given the proximity to enhanced oil recovery possibilities and the ready availability of petcoke, which is an ideal fuel for IGCC, without a doubt, one of the five should be in Texas.

We have identified attractive sites of our own for a Texas IGCC project along the Houston shipping channel, with the necessary interconnections, the ready access to petcoke, and the proximity to enhanced oil recovery possibilities in the shallow waters of the Gulf.

Of all the surprises contained in the announcement at the beginning of this week, one of the most welcome to us was TXU's dramatic change in attitude with respect to IGCC and their willingness to invest in it.

Accordingly, we wish to invite them with their new ownership, and any or all of the other sponsors of traditional coal-fired plants in Texas, to work with us in order to make a Texas IGCC project a reality.

Now finally, with -- turning to slide 16.

With respect to the Texas newbuild situation more generally, again, notwithstanding the announcement earlier this week, there continue to be 10 traditional pulverized coal plants in the permitting queue at the Texas Commission on Environmental Quality.

Indeed, there actually continue to be 18 projects in the queue, unless and until the other eight are finally canceled.

With respect to these plants, our position remains unchanged from last week, last month, last year, namely that Texas does need some traditional coal [plants] to meet its robust baseload demand growth, but that number of plants that Texas needs is less than 18, and indeed, that number is less than 10.

It is important to note that not all of the 18 coal plants in the queue at the TCEQ are created equally from an environmental perspective.

They use different fuels, different amounts of water, and have different abilities to guarantee either current or lower SOx, NOx and mercury emissions at the repowering [sites].

Today the TCEQ processes applications on a first come, first serve basis.

We think it makes better sense to prioritize and sequence the permit applications based on all environmental criteria, including water usage, and would encourage the State of Texas to work towards that goal.

Ultimately our belief, as I articulated at the CERA conference, was that the road to a carbon-free baseload solution in Texas runs through our 2007 MW South Texas expansion project in Matagorda County.

I am personally more bullish on this project then ever.

And while we have no specific announcement to make today, our STP 3 and 4 project remains well on track, and we are convinced the our development strategy for it is the best and most risk-mitigated of any of the new nuclear developments underway around the country.

On slide 17 we give you some sense of what milestones we see in the foreseeable future for our repowering program.

We will be reporting on these as they occur or fail to occur.

In short, progress has been good.

A lot of wood remains to be chopped, but in the near future we believe our shareholders will begin to see the value of this major growth program reflected in our stock price.

With that, I'll turn it over to Bob Flexon.

Thank you, David, and good morning.

Consistent with our prior calls, I'll discuss our fourth-quarter and full-year 2006 results, provide an update on the 2007 outlook and review our 2007 financial objectives.

Beginning with the financials, slide 19 highlights the fourth-quarter and full-year key financial results.

Overall the Company met adjusted EBITDA and free cash flow guidance provided earlier in 2006.

In spite of an extraordinary mild December, in which generation in the Northeast was substantially below our forecast, strong operating results and execution made up the difference, resulting in the achievement of our targets.

The obvious and most significant factor that affected year-over-year performance was the acquisition of NRG Texas.

Quarter-over-quarter results, excluding NRG Texas and the Hedge Reset, were relatively flat in spite of mild weather and the lower generation and power pricing levels in the Northeast.

Generation quarter-over-quarter from Northeast and South Central plants was down 13% and 4%, respectively, leading to a revenue decline of approximately $139 million.

The annual performance, similar to the fourth quarter, experienced declines in generation and power prices.

The lower prices were, to a large extent, countered by our hedging positions and increased capacity pricing complemented by strong plant operations.

Annual results excluding NRG Texas were also relatively flat year-over-year.

Free cash flow, calculated as cash from operations less CapEx and preferred dividends, was $1.3 billion higher than last year, principally attributable to the $939 million positive swing in cash collateral in NRG Texas EBITDA.

Cash interest excluding refinancing expenses almost doubled to $451 million, due primarily to new debt incurred to finance the Texas Genco acquisition.

Capital expenditures were $221 million in 2006, as NRG Texas incurred $108 million in CapEx.

This compares to $106 million in 2005.

Slide 20 highlights the primary variances between 2006 and 2005 for both quarterly and year-over-year adjusted EBITDA.

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

Our longer-dated power price hedges are often accomplished using natural gas contracts.

To the extent movements in gas and power prices are not correlated, the ineffective portion is included in the mark-to-market results.

In the fourth quarter we incurred a $36 million mark-to-market loss on forward asset-backed positions that included a $94 million loss on hedge ineffectiveness in Texas.

Full year 2006 mark-to-market gain on asset-backed positions of $171 million included a $28 million gain on ineffectiveness.

Clearly, the addition of NRG Texas to our portfolio is the largest driver of improved quarterly and annual performance.

NRG Texas contributed $788 million of adjusted EBITDA for the 11 months post-acquisition, and $191 million to the last quarter.

Strong baseload generation from the Texas fleet, with total generation at 45 million MWh, 74% of which sold under long-term agreements, accounts for the bulk of this region's EBITDA.

During the summer, ERCOT set new records for peak demand, which we served using our gas and the open position of our baseload assets.

Merchant on-peak pricing, however, was lower.

Full-year ERCOT pricing was off by 23%, while the fourth quarter was 42% lower than 2005, or $54.06 per MWh.

Merchant generation sales during the fourth quarter were approximately $193 million, or about a third of total revenue.

STP 2006 capacity revenues of $343 million are also a significant contributor to the Texas results.

West Coast Power, acquired at the end of March and integrated during 2006, contributed $11 million of additional adjusted EBITDA and is included in portfolio changes along with NRG Texas.

For the quarter, South Central gross margin was essentially flat, but improved $63 million for the year, primarily due to lower outage rates during the second and third quarter 2006 versus the comparable 2005 periods.

Coal generation at Big Cajun II was 11% higher in 2006 over 2005.

South Central plant reliability improved substantially year-over-year, as the Big Cajun II facility achieved an EFOR of 3.1% in 2006, as compared to 6.6% in 2005.

In addition, South Central capacity revenues increased by $9 million, primarily due to the higher peak summer co-op loads, which is used to set capacity prices.

The region benefited from $14 million in higher contract revenues due to increased contract volumes and improved pricing.

We estimate the tolling contracts executed in South Central saved approximately $10 million to $15 million in purchased power costs.

During the year, the sale of emission allowances contributed $26 million of additional EBITDA over last year.

Allowance revenues were earned primarily during the first quarter of 2006, and were in response to lower-than-expected generation levels from our Northeast facilities during a mild winter.

Unseasonably-mild weather in the Northeast region throughout 2006 resulted in 13% and 18% lower generation for the quarter and full year, respectively, versus the same periods in 2005.

The period-over-period generation decline experienced by our intermediate and peaking oil and gas-fired units was 37% for the quarter and the year.

Falling gas prices pulled down the average power prices in New York, NEPOOL and PGM West by 23% (technical difficulty) and 19%, respectively.

As a result, lower power prices realized in our 2006 sales were 40% and 22% below our fourth-quarter and full-year 2005 realized pricing, respectively.

Approximately $155 million of the annual decline in Northeast margins is due to the slower generation in pricing.

Capacity revenues for the year were $30 million higher than last year.

Higher prices in the New York capacity markets and the introduction of a capacity market in Connecticut drove these increases.

For the fourth quarter, downward pressure on margins due to lower generation and market pricing were almost completely offset by favorable settled positions on hedges.

General and administrative expenses for the fourth quarter include $21 million for development expenses in support of our Repowering NRG activities.

For the year we incurred $36 million in development expenses.

Annual G&A shown in our consolidated statements also includes $14 million of NRG Texas integration expense, along with $6 million in the (indiscernible) defense costs.

Flinders and Resource Recovery have been classified as discontinued ops, and are not included in the results for either year.

The Flinders sale closed on August 30, 2006, and the Resource Recovery sale was completed on November 8, 2006.

The Company's liquidity at December 31 is presented on slide 21.

The decline in liquidity since September 30, 2006 is primarily attributable to a $623 million reduction in cash balance due to various capital allocation initiatives, offset to some extent by a $500 million increase in the Company's synthetic letter of credit facility as part of the Hedge Reset and extension program.

While NRG generated $425 million in cash from operations, including collateral receipts, the Company used approximately $1.1 billion in cash for various capital allocation initiatives, including debt reduction, share repurchases, and the Hedge Reset program.

During the fourth quarter of 2006, NRG repaid $431 million in debt, including $400 million of the Term Loan B facility as part of the previously announced Capital Allocation program.

Also during the quarter, NRG used $435 million in cash to repurchase common stock in the open market.

The Company's $500 million Phase I share repurchase program was completed in October 2006 with the purchase of $203 million in stock, which the Company financed with $67 million in cash and $136 million in nonrecourse debt and preferred shares.

After completion of the Phase I program, NRG initiated its $500 million Phase II repurchase program by acquiring $232 million in common shares during November 2006 from the Blackstone Group in a privately negotiated transaction at $55 a share.

In addition to debt reduction and stock buybacks, NRG used $273 million of cash to fund a portion of the payments made as part of the November Hedge Reset transaction.

Other cash uses during the quarter included $62 million in CapEx and $13 million in preferred dividends.

For the year, the Company generated $1.5 billion in cash from operations, including cash collateral receipts of $534 million and excluding the Hedge Reset.

We realized $466 million in proceeds from the sale of Flinders, Resource Recovery and other noncore assets, and utilized $221 million in cash for capital expenditures.

Cash collateral collected during 2006 totaled $534 million, versus the $400 million included in our previous guidance.

Collateral receipts were greater than expected, as the Company received $81 million in counterparty cash collateral due to power price declines.

Of this amount, $75 million is expected to be returned to the counterparties in 2007 as these positions unwind.

The balance of the increase is primarily attributable to NRG replacing cash collateral previously posted with counterparties with letters of credit.

Our 2007 guidance is shown on slide 23.

We have not changed the $2.05 billion in adjusted EBITDA guidance provided last quarter.

Consistent with our practice, the first planned re-forecast of adjusted EBITDA and free cash flow will be done in preparation for our first quarter 2007 call.

We have, however, updated the cash flow guidance for the expected $166 million of cash outflows, primarily related to the fourth quarter 2006 collection of cash collateral, which will be repaid in 2007, and $73 million in growth capital for our Long Beach repowering project.

With these two changes, the free cash flow guidance for 2007 is $879 million, providing a free cash flow yield of nearly 11%.

The Long Beach growth CapEx impacts the free cash flow yield by approximately 100 basis points.

Excluding collateral movements, free cash flow in 2007 is over $250 million higher than 2006, mostly due to the $650 million impact of the Hedge Reset, partially offset by the increased repowering CapEx, and $177 million for environmental CapEx.

Slide 23 provides sensitivities to our 2007 pre-tax earnings and cash flow.

Portfolio sensitivities to natural gas, heat rates and coal pertain to our baseload generation.

Since baseload generation is highly hedged for 2007, movements in the commodity markets are unlikely to have a significant impact on our 2007 earnings.

In addition, since the majority of our near-term hedges are accomplished through power, the portfolio also has limited exposure to heat rate fluctuations during 2007.

Our ratio of fixed to floating debt is approximately 87% fixed and 13% floating, before considering the impact of cash on hand.

Slide 24 provides a history of our capital allocation actions.

During 2006, capital allocation included $732 million in common share repurchases, or 14.8 million common shares at a weighted average price of $49.43; $1.1 billion in aggregate debt repayment, debt elimination and [voided] borrowings; and $36 million of development spend in connection with the repowering program, which, in part, led to the Long Beach contract award and the conditional award for the Huntley IGCC plant.

Plans for 2007 include -- complete by June 2007 the existing $500 million Phase II share repurchase plan. $232 million has been completed to date; provide capital for repowering projects and development for -- for repowering projects and development and for environmental CapEx; manage the debt equity balance to targeted levels; and define and communicate to our stakeholders the longer-term capital allocation plan.

Before turning it back to David, I summarize several of the key financial accomplishments and objectives on slide 25 that contributed to shareholder value over the course of the year.

During 2006 we acquired, financed and integrated NRG Texas and West Coast Power.

We developed and implemented a balanced capital allocation program.

We created substantial hedging capacity under the second lien structure to support and protect the value of our baseload assets in a very collateral-efficient structure.

We delivered our FORNRG targets, and we initiated value-added transactions such as the Hedge Reset and extension.

As we begin 2007, we'll continue our pursuit to successfully repower NRG, seeking economic projects structured in an appropriate manner.

We'll complete our current capital allocation commitments and define the next stage.

And finally, we'll continue to focus on our existing portfolio, delivering improvements through strong execution, FORNRG and our actively managed hedging program.

I'll turn it back to David for concluding remarks.

Thank you, Bob.

There is one concluding slide on 27, and a lot of it goes back through what -- the way Bob just ended.

As we normally do, we end with our own self-assessment of our performance in 2006 against our highest priorities, and give you a sense of what we consider to be our highest priorities as we move forward into 2007.

The basic theme here is that, notwithstanding the external distractions that always seem to be occurring in this industry, we at NRG are going to stay focused on executing our business plan, which has been successful to date, and which we believe is the right one for success in the future.

So with that, Sylvia, I'd like to open the floor to some questions.

(OPERATOR INSTRUCTIONS).

Elizabeth Parrella, Merrill Lynch.

A couple of questions for Bob.

Just turning back to the guidance slide, slide 22, you did update the cash flow for a couple of known items, but didn't revisit the EBITDA.

I just wanted to clarify, particularly since you're doing the spend for Long Beach out of cash flow, is the EBITDA for Long Beach in the guidance?

And I guess a somewhat related question, maybe more meaningful because you took the FORNRG program up a lot, is the incremental EBITDA benefit from ramping up FORNRG in the current guidance?

For the adjusted EBITDA, we have a disciplined way of re-forecasting here.

And I think our re-forecasting processes have shown to be fairly reliable.

And we like to do this on a quarterly basis, so I have not touched the adjusted EBITDA guidance for any of these items.

I'm waiting for our normal March re-forecasting process.

So, I know we've got upside on FORNRG.

I know we've got outside on Long Beach.

Long Beach should generate $8 million to $10 million of EBITDA this year alone.

And then I also know January was an okay month;

February, don't have the results yet, but I expect it to be better than what we had forecasted, given the generation.

So we'll go through the re-forecasting process in March when we do our first-quarter call at the beginning of May.

We'll incorporate those things and adjust the number at that point in time.

It's just that we haven't gone through the full re-forecasting process, so I was uncomfortable changing the number at this point in time.

Understood.

If I could just ask one follow-up on that.

How is the development spending for the Repowering NRG program looking like for '07, relative to what you told us it might be in October?

When we revised our guidance for -- when we came out with guidance for 2007 in November, we had built in there development spend for 2007 of, I think, $36 million.

We are still holding to that number.

The thing that we would expect to experience during the course of the year is that the expense would be coming in more towards the front portion of the year.

And then what we're looking for is some substantial reimbursements once we get our nuclear partners on board to offset some of the costs.

So we're still on target to meet the development spend that we came out with in November of $36 million.

John Kiani, Deutsche Bank.

David, can you give us your outlook for the joint venture partners and that process on the South Texas Project expansion, and then maybe also give us a little bit of color on that Mitsubishi IGCC wrap?

On the first one, John, there really hasn't been any change in terms of our timetable with the cities;

San Antonio in particular is the major partner, and also the City of Austin, which is that we have a general understanding with them that we will look to try and conclude something one way or the other in the first half of the year.

Quite frankly, if they take a little bit more time than that, which I would have no reason to believe they're contemplating, we're not going to be too fussed about it.

As municipal utilities, they operate to a little bit of a different timetable than we do.

But that really hasn't changed.

And they have been very -- they're not participating in the development right now, but both partners have been extremely cooperative and supportive so far.

So I am very comfortable with where things stand on that.

But that's really all I can tell you on that front at this point.

The situation with Mitsubishi Heavy Industries, it is -- on the IGCC plant, it is at this point just at the Memorandum of Understanding stage.

But the important thing for us was to ensure before we spent a lot of development money on -- on the IGCC projects, or committed irrevocably to one manufacturer's technology, to make sure that that manufacturer was going to stand behind the technology in terms of the type of guarantees backed by the type of liquidated damages that would be required in order to finance the projects.

So we've had extensive discussions with Mitsubishi Heavy on that front.

And of course they're very familiar with what it takes to get plants limited recourse project financed in terms of the mitigation of the construction risk.

And they have made the undertakings in terms of the type of guarantees that would be required on the type of fuels that we expect to use at that site.

That's very helpful.

One question.

Thanks, David.

One question for Bob.

On slide 22, when you were walking through free cash flow, I guess -- excluding other development capital in 2008, we would have a full-year contribution of Long Beach, the Long Beach rebuild as you discussed, of about, sounds like, between 20 million and 25 million of EBITDA.

But then, excluding other development, about 73 million less of CapEx, because the Long Beach rebuild spending would be completed.

So can we think in terms of at least 100 million of incremental free cash flow, excluding all other '07 to '08 growth drivers and changes, just from that alone?

The only thing I would add to that, John -- and everything you said is correct.

The point that is different in 2008 versus 2007 will be the environmental CapEx spend, which is about $100 million and change higher than 2007, as we go through and do the environmental compliance, which you'll see later today on our 10-K where we lay it out for the next five years what that spend is.

So that's the only point that I would add to that.

Great.

That's helpful.

Thanks, Bob.

Maura Shaughnessy, MFS.

A couple of questions.

First, can you just give us an update as to what's going on in Delaware?

Looks like all the three projects were initially turned down.

And then, obviously, the environmental legislation was going in a tough direction.

Can you just give us an overall update there?

It's very much a work in process in Delaware.

I would say one of the things that we see as the biggest challenges to success of all elements of our -- or most -- many of the elements of our repowering program is that when these requests for proposals are administered by the distribution utility that also has some skin in the game on the generation side, we're not always sure that the assessment is the way it should be.

In Delaware there have been assessments by Delmarva Power and Light and by the Public Utility Commission, looking at the expense of the projects.

The factors that are weighted, we're assessing them right now.

But clearly, what factor is given on the carbon front [unclear] -- the assessment that our plant, which would be based on coal, represents more price variability on the fuel side than the alternative being offered on gas is a conclusion that we find very surprising.

So, we are assessing the review.

It's 110 pages of detailed review, and it just came out, I think, late last week.

So we have a little ways to go, but we are continuing to assess the situation down there.

The fact that IGCC is a little bit more expensive than some of the other alternatives, certainly, more than a gas-fired combined cycle plant at certain gas price assumptions, that doesn't surprise us.

We recognize that.

The New York IGCC project recognizes that.

And again, that's why it's important that the federal government comes in with the type of legislation that we're talking about to close that price gap.

Thanks.

Just in terms of getting back to John's question on STP, when are you expecting to actually file with the NRC?

We certainly expect to file with the NRC sometime in the later part of this year.

The precise date, I'd rather not be tied to.

But we are well on track.

And actually, one thing, Maura, as I'm sure you know, the filings with the NRC are extremely voluminous.

But it's not done in one big bang.

Actually, I think it consists of something like 32 different chapters.

There's actually an iterative process that goes on with many of the chapters, and there's already a dialogue going on between STP and the NRC.

So, we want to make sure that we -- when we file it, the quality is of the type that the NRC is expecting.

And again, so far, everything seems very much on track.

Last question.

Obviously, the events of this week, with TXU, the implied value for assets in the ground were a lot higher than what most people were thinking about.

What's just overall views there, David?

On values?

Yes.

You don't want me to say I told you so or anything like that.

We think that, clearly, to some extent, the valuation that's being given to TXU -- we've done the numbers as it applies to our own portfolio, and you're right.

And I think it just goes back to support our position that we've had, is that even though the stock market has been quite good to NRG over the last three years in terms of recognizing value, there's still a lot of value still to be recognized on that front.

So, certainly I'm not going to cast doubt on the way KKR and Texas Pacific Group, some of the smartest people I've ever met, are valuing assets in Texas.

I like to think they're right on.

Lasan Johong, RBC Capital Markets.

A couple questions -- [ask them now].

One for David and one for Bob.

David, my understanding is that the availability on currently installed IGCC plants are about 60% or less.

And if you do the math on five or six different components that go into an IGCC, with a 90 to 95% [reliability] factor, that seems to make sense to me.

Do you think there is a reason to believe that it should be higher than that on these latest generation machines?

And Bob, what I thought I heard you say, not directly but indirectly, is that NRG is short natural gas in Texas before the curve in Texas, and that's how you're capturing the upside heat rate expansion potential. [Do I have that understanding] correct?

On the second part, for 2007 we're pretty much hedged out across the portfolio with power.

Long-term, where we've hedged out, we're still exposed to heat rate movements, because the hedges have been done with gas.

That's what I thought.

Okay.

I'm going to try and answer your first question.

But if I don't answer it precisely right, feel free to ask for a clarification.

You're right that in terms of the past generation of IGCC plants, as people say, the problem was in the I in IGCC, in the integration.

But even the previous generation, the generation that's now operating, like the Shell project in the Netherlands and all, they've all brought their reliability up from, as you say, the 60% level up into the 85% level.

The new generation of IGCC is going to be designed with actually a little bit less I so that it's more robust on the reliability front.

And we've gotten to be very comfortable with that.

And the reliability runs, actually, that Mitsubishi is planning around their clean coal plant in Nakoso, Japan is really extraordinarily highly reliable.

And I would also say that as part of the commercial guarantees that we expect and they expect to step up to, this is an area where we expect to get some robust support for the project from Mitsubishi itself.

Understood.

Perfect.

Thank you.

Dan Eggers, Credit Suisse.

Bob, you talked about the idea of the next wave of returning capital to shareholders after this program is complete.

Can you just give us an update as far as conversations with bondholders looking at covenants, etcetera, as far as ways to free up more cash?

We haven't had any conversations with bondholders on that.

But as you know that we've continually evaluated different ways to create capacity for capital allocation, we've come up with some innovative ways over the past, and we continue to develop new ideas.

So, not only do we have some of the past tools at our disposal, but we're working on things now that I think hold promise, which I'm hoping that [in the] relative near-term we'll be able to give more clarity to the market on it.

So I think we have some ideas to give us more capacity longer-term, which we're going to need when you look at the free cash flow generation of -- call it $1 billion or so.

If we don't do something, cash could end up getting trapped on the balance sheet, which we have no interest in doing.

So, we'll give more clarity on that probably within the next couple of months.

Great.

On the Texas markets, with the eight plants not coming, 10 still out there, some allocation down to what should be built, how are you guys going to approach or think about when you make a go-ahead decision on building new coal in Texas?

That was maybe one of the major consequences of Monday's announcement for us, was to go back to the drawing board and look again at our development program, which, again, based on fuel mix and timing of when we could bring plants to market, we think it's the right one.

One thing that apparently has come up in discussions in Austin over the last 24, 48 hours is a little bit of concern about resource adequacy.

One of the things that I think is very important is that we believe that Texas has absolutely no concerns about resource adequacy in 2009, 2010 and 2011.

I know that TXU is trying to allay concerns on that front by saying they have 1500 MW in mothball.

We have over 1000 MW in mothball.

As we're showing at the Long Beach project out in California, we've brought that plant out of mothball, and we'll have it back online in nine months time.

So I don't think Texas has any concern.

But in terms of our plants and, particularly, one or two gas units that can sort of plug that gap that one might be seeing in the 2009 to 2011 range, we're looking very hard at that right now.

Michael Lapides, Goldman Sachs.

David, will you talk a little bit about rail costs for PRB coal, what you're seeing, how that would impact you kind of longer-term, meaning kind of post-2009 timeframe?

As usual, you've asked a question that falls directly into Kevin Howell's sweet spot.

So you're going to be subjected to his answer.

As I look at the rail, first I look at our current situation, where we're heavily contracted for rail already through 2009, and substantially contracted for rail for several years after that.

So, some of the near-term congestion issues in the rail system have affected us more on cycle times than cost.

I do think that the railroads have gotten more sophisticated on how they look at their cost structure as it relates to exposure to the oil complex.

And new rail contracts typically recognize fuel surcharges, those type things, that we're going to have to come to grips with, as railroads [are].

I think the real wild card on rail usage in the U.S. is kind of the different sectors that compete for rail capacity.

Clearly, with the intermodal traffic where it's at for the last couple of years, with the strong import markets, if that continues to cause a lot of congestion on the system, there will be a lot of competition for that rail capacity as our contracts roll off.

It's safe for us to assume that your rail hedges are in lock step with your hedges on the physical coal itself?

Generally, I would say that's true.

It's not one for one.

But as a general rule of thumb, that is true.

Anthony Crowdell, Jefferies.

Just looking for some color on potential dividend.

Is it a reasonable assumption that a dividend may be introduced in the 2008 timeframe, with a payout ratio similar to the average for maybe a merchant generator or something?

I would say, Anthony, that one of the things about dividend is that that's something that all board members have a personal point of view on.

I could give my personal point of view, but that would be one of 11 or 12.

We have previously talked about that sort of timetable.

I don't really have any reason to believe -- I certainly don't have any excuse to make it later than that.

And so, I can't argue with what you're talking about in terms of timetable.

In terms of amount, again, we've previously said -- and I have no reason to believe we would change our position on this -- is that when we do introduce a dividend, it would not be to portray ourselves as a yield play like a traditional utility.

So, the type of average dividend that you see from the S&P 500 is certainly more like what you would expect to see from us.

Paul Patterson, Glenrock Associates.

I wanted to just touch base with you on this market power Texas legislation. (A) does it have any impact on you?

But also, more specifically, it does look like it may, if it does get passed, have an impact on TXU.

Would that -- would you be interested in any of their assets potentially?

I know it's a little hypothetical.

But if you were, what kind of assets would you want -- just what your thought process might be.

Would there be synergies if you were to buy something else in Texas?

I know it would be another zone, so to speak.

But, if you could just maybe elaborate a little bit on that.

I'm interested in all the coal and nuclear fire generation I can get in Texas at less than $200 per KW in installed capacity.

No -- just on the legislation, we have the highest respect for Senator Frazier and Representative King, and we believe that they're truly interested in creating competitive marketplaces.

And we think there is a competitive marketplace in ERCOT, and we look forward to working with them on any type of legislation that they want to consider.

Having said that, given the demand growth in Texas, I have to say that I think it's important that Texas have a couple of scale players in there.

We're developing this nuclear project down there.

And that's not for the faint of heart. 2700 MW.

Tens of millions of development spend. $6 billion or $7 billion of total spend, even if it's limited recourse project financed.

So, having some scale players in the Texas market, I think, is good for power reliability.

Whether their specific legislation as introduced a week or two ago would impact us; quite frankly, Paul, it depends on exactly how it's written.

It might -- it might impact us, but to what degree?

If it's not modified, it's really hard to say.

Quite frankly, we haven't really looked very closely at TXU assets or a TXU breakup situation.

Quite frankly, I didn't think that if we called TXU they would be returning our call until recently.

So this is sort of a change in the situation.

But, you know, never say never.

Okay.

So it's just too early, I guess.

But let me ask you this.

Finally, with Clinton's -- and I saw her press release -- that $3.5 billion tax incentive, is that --- for clean coal technology -- is that technology-specific, or is that for -- just how -- is that specifically for IGCC, or is that more widespread?

I can't really answer that.

I haven't read the actual bill.

We saw a draft of the bill, but I can't recall whether it said IGCC.

I know that normally, public policy makers, they tend to adhere to this thing that says they're not in the business of picking technology.

So I'm not sure it refers to IGCC by name.

But one of the points I made is that when, actually, the Bush administration started down the FutureGen path, and wanted to build a clean coal plant, it did not take them long at all to settle upon IGCC as the basic technological platform for that.

So, I think there's a lot of support in the federal government, as there should be, for the fact that, based on current developments of pre-combustion and post-combustion carbon capture, IGCC is the real deal when it comes to clean coal technology.

[Brian Tadeo], Bank of New York.

Just a quick question on a comment you made earlier about building your coal inventories.

Obviously, you mentioned you're already at very high levels from where you've seen in the past.

How high do you want to take these, I guess?

And also, just kind of given your comment about -- it's obviously pretty -- you're making a bullish comment here on coal.

Is it just in the PRB regions, or are you seeing that sort of across all coal regions at this point?

I'm sorry, Brian; the last part was about -- what about other regions?

(multiple speakers) in terms of -- what you're seeing in terms of the other coal regions as well.

I know you burn mainly PRB.

But in the other regions as well, are you stockpiling other types of coal beyond your normal levels?

Or are you basically as bullish in those areas as what you're sort of indicating in PRB?

The first part of your question I'm going to turn to Kevin, but the last part is quite easy.

At this point, apart from the mine-mouth [lignot] operations at limestone, virtually all the coal we consume everywhere is Powder River Basin.

So the question about stockpiling other coals is a bit moot for us.

But in terms of how far we want to go, I'm going to turn it to Kevin Howell.

I guess it's a little bit of a -- there's a cyclical nature to that question.

Typically we do try and build inventory going into the summer heating season.

It's hard to forecast what's going to happen with rail performance over the year.

We've gotten some unpleasant surprises out of the railroads the last couple of years.

I guess notionally, the way I think about our bigger plants, we'd, clearly, like to have somewhere in the neighborhood of 25 to 30 days on the ground as we go into kind of the peak generating season.

We'll use kind of a combination of coal purchases and the outage schedule here in the spring to try and get to those targets.

And then it's always our expectation we'll come out of the summer peak season at substantially lower levels than that, and then use the fall outage season to try and build again before we get into the winter.

It sounds like it's almost more normal levels, though.

I guess I took your earlier comment (indiscernible) you wanted to get well above, because you thought prices would be going up.

It's kind of a plant-by-plant issue.

If you look at our average inventory across the fleet, it's kind of dwarfed by the fact that we've got good inventory in Texas right now.

That really weight averages our whole position up.

But there are some -- there's a couple other locations we would like to continue to build inventory.

Thank you, Brian.

And Sylvia, I thank you.

We appreciate all of you joining us for this call and for your continued interest in NRG.

Thank you.

Thank you.

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

It has been our pleasure working with you.

Once again, thank you for participating, and we ask that you please disconnect your line.