NRG Energy Inc (NRG) 2005 Q4 法說會逐字稿

Greetings ladies and gentlemen and welcome to the NRG Energy fourth quarter earnings results.

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 Nahla Azmy, Director of Investor Relations.

Thank you Ms. Azmy, you may begin.

Thank you, Jen.

Good morning and welcome to our fourth quarter 2005 earnings call.

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

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

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

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

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

And now for the obligatory Safe Harbor Statement.

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

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

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

In addition, please note that the date of this call is March 7, 2006, and any forward-looking statements that we make today are based on assumptions that we believe to be reasonable as of this date.

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

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

For complete information regarding our non-GAAP financial information, the most directly comparable GAAP measures and 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 let me add my own welcome everyone on the phone.

I would particularly like to add a special welcome to any new investors or new bondholders that may be joining this call for the first time as a result of our capital-raising exercise in January.

With me today as usual and speaking is Bob Flexon, our CFO, who will run everyone through our 2005 results.

We also have another guest speaker -- Steve Winn -- who is not as well known as some of the other members of the management team but was the key architect of the Texas Genco transaction and is in fact located in Houston now, running the Texas Genco business.

Now we refer to it as NRG Texas on our behalf.

With me today also are two other members of the management team who don't have presentation roles.

But Kevin Howell, the head of our Commercial Operations, and the newest member of our -- senior member -- senior management team, Curt Morgan, who joined us I think less than a week ago as President of our Northeast Region and I believe adds a considerable amount of depth of experience and expertise which will be very, very helpful to our company, and very glad to welcome him on board.

So now in terms of the approach to this call, we have a lot of material to go through today.

What I would like to do is give you a bit of an overview.

Obviously, we have three objectives for the call -- to review our 2005 operating results, which in their totality we are quite pleased with; to give you a brief update on where we stand on the Texas integration.

But I would make a cautionary note here -- please keep in mind as you ask us questions and think about what we're telling you that we have owned Texas Genco for less than 1000 hours.

We have only owned the Company for five weeks.

And so anything we're going to tell you is a work still in fairly early progress.

And then also, a focus on 2006, and particularly with respect to financial guidance.

The conclusion that I have and I hope you will take away from this conference call is that, in terms of how you should think about NRG in 2005, is that while we are in the process of transforming the Company during the second half of 2005 via the Texas Genco acquisition, we maintained a focus and took care of business in terms of delivering a very solid 2005 financial result.

So, with that, if you're following along with the presentation on the website, I would turn to Page 4.

First, in terms of just my take on some of the financial highlights, and of course our focus is always on the cash metrics.

The 2005 adjusted EBITDA of 722 million versus the 700 million guidance figure as was most recently updated on November 7 of '05.

And I would just note that -- so we exceeded our guidance target for 2005, even though we raised our guidance during the course of the year, and notwithstanding the slippage of the $15 million of emission sales that we referred to occurring in December, but not settling until the first quarter of this year.

In terms of cash flow from operations, $68 million, and this is after the cash collateral outflows of $405 million during 2005.

Obviously, from a liquidity perspective, I am pleased that in a year were the cash requirements of the business rose to extraordinary levels because of the unprecedented volatility of gas prices that we were able to maintain sufficient liquidity to support our hedging position without having to resort to any force or suboptimal asset sales, even though immediately prior to the sharp movement in gas prices, we had bought back $250 million of the Company's common stock.

And during the course of 2005, we had also paid down $645 million of high-yield debt.

Turning to the operational side, first safety.

Our safety record improved during the year 14% on a year-on-year basis.

But obviously, we're not going to be satisfied in the area of safety is long as we have any recordables, either amongst our own staff or among the contractors who work at our sites.

With respect our plant operations, both with respect to total output and availability of our peaking units, we improved year-on-year.

However, the improvement in total output was largely attributable to both a good year from a weather perspective in 2005 and the continuing decline of the excess reserve margin in most of our core regions.

As we talk about operations, I don't want to gloss over the fact that we struggled with the reliability of our coal plants last spring and summer.

Both the conversion of our New York coal plants to 100% Powder River Basin burn and the introduction of additional environmental remediation equipment at Big Cajun had a negative impact on the forced outage rates at our plants.

But this is an issue we feel we have a good handle on, and as such, we consider the improved reliability of our baseload coal plants as a significant area of opportunity for the Company, rather than as a fundamental or a chronic weakness.

As I mentioned in my preliminary comments, my takeaway point, my theme being that in 2005, we took care of business while positioning the Company for sustained future value enhancement.

On slide 5, we've listed some of the ways in which we feel the Company has been strengthened in terms of its positioning.

In the interest of time, I'm only going to focus on a couple of these areas, the first being Commercial Operations.

For those who are not that familiar with our company, the Commercial Operations is the centralized function within NRG which markets our output and ancillary services, procuress and trade our key inputs, manages the logistical arrangements, particularly the transport of our fuels and secures firm transmission rights in respect of our electricity sales; and finally, also seeks to capture the extended value of our overall assets base.

As such, obviously, the Commercial Operations Group performs a key function within our company.

During 2005, we substantially enhanced the capability of our Commercial Operations team from top to bottom, and already the list of what they have achieved is I think quite impressive.

They improved the way we hedge for 2007 and beyond preserving more of the upside from our baseload fleet, while putting a floor on the downside.

They've taken the lead on the second lien structure to reduce the Company's dependence on cash collateralization of hedges.

They are structuring their forward hedges now so as to reduce the risk of mark-to-market accounting treatment.

They have become more savvy and dynamic in how they manage our fuel position and they have developed the capability to actively manage and trade our bank of excess stocks allowances.

All along, extremely confident that the Commercial Operation Group's success to date will continue and the Company will reap a great reward over time on a risk-adjusted total return basis as a result of the enhancement of the capabilities of the Commercial Operations Group.

The other area on this slide that I would like to address is in the area of intrinsic growth.

We continue to believe that the next 24 months will present NRG with a critical window of opportunity to reinvest and enhance generation at many of our locationally advantaged sites in markets where the supply/demand balance is tightening considerably.

You are familiar with our permitted projects previously announced, including the 675 megawatt coal unit at Big Cajun II and the 638 megawatt combined cycle unit at El Segundo in Los Angeles County.

We also expect to be pushing forward aggressively with other developments in the Northeast as the developments in question not only represent an important opportunity for us to revitalize our aging assets base, but also represent a critical obligation of the authorities in the states where we operate to ensure that there is an adequate supply of base intermediate load generation brought online over the next two to four years.

Turning to slide six, I'm focused on (indiscernible) NRG.

As we have previously discussed, most of the FORNRG savings in 2005 came from corporate initiatives, including work on reducing taxes, insurance and financing fees.

One small but important change of the plan has led to an adjustment upward of the ultimate 2008 goal of $100 million of recurring benefit being revised upwards to 105 million.

This is our effort to ensure that there's no backsliding with respect to the 5 million of recurring gain achieved in 2005 in excess of our original $30 million target.

As we move into 2006, the weight of additional improvements falls increasingly into the area of improved plant operations.

The plant-specific initiatives in these areas include of course improved forced outage rates and heat rates at our coal plants, quicker start times at our peakers, reduced parasitic station service and other performance improvements in cost savings.

In every case, we have tailored individual plant objectives towards what gives us the biggest bang for our buck from that plan given the market characteristics impacting that plan.

As we have stated previously, the reason FORNRG benefits are slower to be realized out of the plants relative to corporate is that many of the plant improvements depend upon repairs and enhancements that can only be accomplished during stable outages scheduled outages which always occur during the spring and the fall.

Some of the most -- and in the case of the fall of 2005 outages, if you turn to slide 7, some of the most trouble-plagued units were put into outage last fall and as we've tried to demonstrate here, while it's still very early, and in fact too early to draw any definitive conclusions, we have seen for example excellent performance at Unit II of Big Cajun II so far this year since it returned from outage.

We're confident that the considerable work we're going to perform on the other coal-fired units during the outages in 2006 will also have the desired positive impact.

Now moving to slide 8, we want to address four features of our Commercial Operation activities, and while all four of these features are important, they're not necessarily the most important things that we do in our Commercial Operations, but we are addressing these four areas because these tend to be the areas that we're typically asked about.

First, as we've illustrated in the upper left-hand slide in the upper left-hand quadrant of this slide, with respect to our coal stockpiles, notwithstanding significant disruptions in western rail service, including extended and overlapping declarations of force maejure from both western railroads, plus low water levels on the Mississippi River which constrained barge loading and a fire at the [Hall Street] Terminal in St. Louis which is our principal transshipment point to Big Cajun, we have been able to maintain our coal stocks at acceptable levels at all our coal-fired plants.

We withstood these challenges by taking advantage of the flexibility inherent within our coal fleet, including the continuous redeployment of our railcars in favor of whichever plant was most in need at the time.

We also completed upgrades for the unloading system at [Dunkirk], which has significantly improved the cycle time and the delivery of coal to both of our western New York coal plants.

We anticipate continued coal supply challenges during 2006, but the inherent strength and flexibility of our coal position and our ability to circumvent issues as they arise are both considerably enhanced by the greater scale and resources associated with the combined company's coal fleet.

Now moving to the chart of PRB prices on the upper right of this slide.

Clearly, western coal prices were volatile during 2005 and rose to unprecedented levels in January of 2006.

However, as we stated during the January roadshow, we did not believe that these price levels were sustainable based on the fundamentals.

And given that we actually had contracted Powder River Basin coal for 2006 delivery in excess of our anticipated needs, we have been a modest seller of Powder River Basin coal in recent months.

Even with current Powder River Basin prices now having fallen into the mid-teens, please keep in mind that we have hedged a significant portion of our Powder River Basin coal needs in late 2004 when Powder River Basin prices were in single digits.

And as such, our average coal prices are well below even the current market.

We continue to look for opportunities to hedge additional coal needs longer-term at attractive prices versus the current market and we also continue to be in dialogue with various suppliers in an effort to encourage a supply-side response to the still very high turns coal price environment.

Turning to the SOX emission table on the lower right.

As mentioned our last call, [we're long emissions allowances], or long SOX allowances, well in excess of our generation needs.

Starting in August of last year when SOX allowances first climbed through the $800 per allowance level, we began to sell excess credits.

We have increased the pace of SOX credit sales in early 2006 for two reasons.

First, because we felt the price of vintage credits remained attractive, and second, because the unusually mild winter has much reduced our projected usage of SOX allowances, causing an excess 13,600 allowances year-to-date to accrue to our internal excess allowance account.

While we continue to be active in the SOX emission credit market, our forecasted guidance being reaffirmed today does not anticipate selling any additional SOX credit from our excess allowance account, but does not preclude us from selling additional credits that are freed up because should there be a continuation of unusually moderate weather.

Just emphasize one last time.

We sell only SOX credits in excess of our projected requirements.

We have to date only sold current and vintage credits; we have never sold future year SOX allowances.

Finally, turning to the lower left quadrant in the New York City capacity payments, 2005 was a strong year for the capacity market in New York City as generators cleared their in-city units at the regulated price cap.

For 2006, however, due to the additional 1000 megawatts of in-city generation coming online, we anticipated that prices would drop significantly.

However, recent regulatory developments, specifically the requirement that New York City in-city generation be 83% of total generation rather than 80%, and the revised New York [ISO] load forecast implies higher prices than originally forecasted.

Accordingly, we have increased our original conservative estimates for New York capacity payments, New York City capacity payments, and this increase in our forecast is factored into our reaffirmation of our full-year 2006 guidance.

Turning to slide 9, I want to address directly the question that seems to be preoccupying the market.

What is the impact of falling gas prices on the financial performance of NRG?

The short answer is that, while the Company obviously does better in a rising gas price environment, the impact of the current movement in gas prices, which has been largely felt on the front end of the gas curves, is not nearly as significant for us as it would have been were we not so very substantially hedged for all of 2006.

As the graph on slide 9 shows, as the bottom graph shows, our baseload capacity is not only almost totally hedged for 2006, it is very heavily hedged for 2007 as well, in each case on a matchbook basis.

As those of you follow the Company closely are well aware, our current hedge position makes us most interested in the back end of the gas curve, which actually remains marginally higher beyond 2008 compared to at the time of the announcement of the Texas Genco acquisition.

In the few weeks that have occurred since we closed the acquisition, we have focused on putting the second lien structure in place with multiple counterparties so that we can put on long dated hedges without the need to cash collateralize.

While this initiative is making good progress with some counterparties concluded, more remain to be signed up.

With the counterparties that are presently on board, we have begun the process of adding to our long dated hedge position with 220 megawatts of effective hedges put on for 2010.

We expect to add further to our out year hedge position in the future and we will endeavor to keep you updated in respect our hedge position, so long as to do so does not compromise our ability to implement hedging strategies which are in the process of being implemented.

Turning to slide 10, 2005 and 2006 year-to-date have been very busy on the regulatory front as well.

On slide 10, we show some of the benefits from our proactive and cooperative work with regulators and our constituencies to reach resolutions for fair returns and functioning market design mechanisms.

All of these developments represent potential upside for NRG longer-term as the market design improves and incentives are provided for new investments.

On February 1, 2006, FERC approved the RMR contracts for NRG's Connected planes on the terms that the units will be under our staffs until they are no longer needed for reliability or until a suitable market alternative is implemented.

This settlement is positive longer-term as it removes any uncertainty regarding the continuation of RMR.

With respect to LICAP -- just yesterday, the FERC settlement judge filed a comprehensive settlement of the LICAP case with the commission.

The settlement, if approved by the commission, will provide a transition to a well-designed capacity market.

NRG supports the settlement and the broad consensus of suppliers, state regulators and transmission owners that produced it.

Our Connecticut units (indiscernible) reliability will as I mentioned before continue to be paid under the approved RMR agreement during this transition period to the effective market.

Our other New England units -- and here, I'm talking about the Connecticut [Jets] and Somerset -- will be eligible for the transition payments under the terms of the agreement.

Thus, we expect the transition period should be moderately net positive compared to the status quo.

The forward procurement market concept upon which the new market design is based when implemented should provide a competitive market price for all capacity while greatly enhancing opportunities for us to competitively repower and further invest in our New England facilities.

There continue to be many steps to implement this market structure, but we are very encouraged on this front by the progress to date.

Now concluding on slide 11 before I turn it over to Steve Winn -- what we have done on this slide is we have duplicated the 2006 operating priorities which we detailed during the roadshow in January.

As I went through this list so that I could provide an update on the progress we had made on these priorities, I recognized that while we have made good progress in all of these areas, it remains exactly that.

All of them remain exactly this -- works in progress.

It's too early to proclaim ultimate success and detail our achievement.

As I mentioned, it's been only a few short but busy weeks since we began implementation of all of these matters.

We remain highly confident that over the next couple quarters, we can provide more detail and definitive information as to our progress in all of these areas.

With that, I'll turn it over to Steve Winn.

Thank you, David.

I'm now on page 13.

During the roadshow, many of you have heard a great deal about the Texas facilities.

It's clear that the Texas plant managers have done a great job in making their operations some of the safest, cleanest and most efficient in the country.

For example, the W.A.

Parish plant will be celebrating a new record for safety tomorrow.

Employees and contractors at the site have worked over 800,000 hours which is over 13 months without an OSHA recordable event.

While this is a truly heroic achievement, it is not unique.

It is the result of the safety culture that pervades the Texas facilities.

Six facilities qualified for special distinction promotions voluntary participation program in 2005.

We value this commitment to excellence and seek to emulate it throughout our fleet.

Similarly, the plants have maintained an excellent performance record.

The solid fuel-fired facilities have maintained exceptionally high availability throughout the decade.

The gas facilities are incentivized to be available during peak periods when there is a much greater chance that they will be dispatched and have achieved excellent results.

This performance highlights the quality of operations management who have a well-developed preventative maintenance plan, a knowledgeable operating staff and continual focus on process improvement.

The plants are well-designed and have been maintained with appropriate levels of investment.

They're populated with well-trained and motivated staff.

They're supported by a knowledgeable headquarters team.

The prior owners worked hard to set up an appropriate infrastructure and right-size the organization and NRG had no staff or assets in Texas prior to the acquisition.

If you turn to Page 14, I will explain how these facts affected our approach to integrating the portfolio into NRG.

Initial integration activities were focused on maintaining the exceptional operating performance of the facilities, retaining key staff and cutting over the business systems with minimal interruption to day-to-day operations.

Day one activities were not focused on extracting immediate cost savings or eliminating duplicative operations since these were minimal.

From the beginning, we have viewed the retention of NRG Texas key staff as the most important aspects of the integration.

They have a strong work ethic and are deeply committed to the facilities in which they work.

We feel we have been successful because they share our vision of what the company -- the combined company can achieve and that they can be a critical component of a company committed to a long-term, multi-regional approach to power generation.

Our transition has also benefited from the exceptional work of members of the Texas headquarters staff.

The first critical business systems challenge had to do with NRG Texas' key IT interface with ERCOT.

At the time of the acquisition, Reliant Energy provided that critical interface to set NRG Texas under contract.

Notwithstanding the potential distraction of the pending acquisition, our project team successfully transitioned NRG Texas to an independent EMS system a few days before the closing of the transaction and it occurred without any significant issues.

This transition sets NRG Texas up for continued success as a major participant within ERCOT and allows it to separate from its legacy relationships with Reliant for the very first time.

Additional systems activities are making good progress and we expect to be able to transition most major business functions to a common platform in the first and second quarter of 2006.

As 2006 continues, our focus will remain on ensuring the continued success of the people and operations in ERCOT.

Employee commitment and focus are of critical importance to us and we intend to provide the support necessary to maintain the high operational, safety and environmental performance of the fleet.

We will work with commercial operations to continue to reduce risk on the unhedged portions of the portfolio and we will support the regulatory and political initiatives that keep ERCOT a well-designed merchant generation market.

While we did not predicate the acquisition on the achievement of synergies, we believe that our new size creates opportunities to increase the efficiency of the total portfolio through purchasing benefits, improved resource utilization and best practices.

I anticipate recording back in the next couple quarters on the upside to be captured under the four NRG programs from potential synergies and best practices.

Going forward, we believe that there are opportunities for portfolio expansion in Texas.

We're both executing on existing opportunities and analyzing options for increasing the output from existing solid-fuel-fired facilities.

We expect more than 100 megawatts of new capacity to come online in 2006 and expect to execute on similar opportunities at other units in the year 2007 through 2010.

Additionally, ERCOT is an excellent market in which to pursue green and brownfield opportunities.

We believe that we own some of the best sites in Texas for new development and would expect to make progress towards the construction of at least one new facility in 2006.

So in conclusion, as we complete the NRG Texas integration process, what will not change is the region's unparalleled operating and safety standards.

What will change is that we will continually look for additional ways the region can enhance portfolio returns through such programs as FORNRG and through development opportunities.

We look forward to demonstrating this progress in the quarters to come.

I'll turn it over now to Bob Flexon to review financial results.

Thank you, Steve, and good morning.

Today as done in the past, I will present our quarter and full-year results.

I will also expand the balance sheet discussion to cover in addition to the year-end position our current capital structure and liquidity post closing of the Texas Genco acquisition.

I will also provide an updated outlook for 2006.

Slide 16 highlights our fourth-quarter financial results and the significant factors that affected the quarter.

Gross margin compared to the fourth quarter of last year increased by $84 million.

Adjusting the gross margin for asset portfolio changes since 2004, which is primarily [Kendall], the gross margin for the quarter was $93 million higher than that of the fourth quarter of 2004.

Driving this improvement was the performance of our Northeast assets, primarily increased generation and higher power prices resulting in $30 million net of higher NRG margins for our coal- and gas-fired assets.

Partially offsetting the higher power prices were the higher fuel costs with coal cost rising $26 million quarter-over-quarter with generation from our coal assets increasing 4%.

The higher coal expenses were primarily due to the increased cost of delivered coal.

As discussed in previous calls, the Indian River facility consumed primarily compliance coal and to a lesser extent, Eastern bituminous coal.

While both types of coal increased in cost, compliance coal rose 18% quarter-over-quarter.

During the fourth quarter of 2005, the overall blended and delivered coal cost for the Northeast region was $37.0 per ton, as compared to $31.71 per ton for the fourth quarter of 2004, an increase of 17%.

The cost of delivered eastern coal cost this quarter was $77.44 per ton versus $58.20 per ton in the fourth quarter of 2004, a 33% increase.

In the Northeast region, eastern coal accounted for approximately 43% of the coal consumed in the fourth quarter versus 54% during the same period last year.

The decrease reliance on eastern coal quarter-over-quarter was driven by the conversion of our western New York coal facilities to PRB coal.

Coal cost on a delivered basis for our South Central region, which consumes 100% PRB coal, was $23.56 per ton versus $24.22 per ton in the fourth quarter of 2004.

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 and efforts to optimize the fuel blend of PRB 8800 and PRB 8400.

Overall, the delivered cost of coal consumed by our North American generation fleet for the fourth quarter was $37.81 per ton, or to $2 per million BTU, versus $33.24 per ton, or $1.82 per million BTU for the fourth quarter of 2004.

We continue to increase our PRB to eastern coal mix in Q4 2005, our domestic mix of PRB coal consumed in the Northeast was 57% of the total tonnage versus 46% in Q4 of 2004.

The domestic mix of PRB coal consumed during the current quarter. including our South Central operations, reached 80% as compared to 78% in 2004.

In addition to increased energy margins, the Northeast earned an incremental $22 million from higher capacity revenues this quarter versus the same period last year -- $13 million due to the reversal of a reserve recorded earlier this year.

South Central margins expanded quarter-over-quarter by $14 million, primarily due to higher contract sales volumes and certain co-op contracts, which include a price adjustment indexed to GAAP.

Other factors influencing the current quarter gross margin result were $6 million of surplus SO2 emission allowance sales, $27 million of mark-to-market gains from trades not tied to specific assets by our Commercial Operations Group.

Partially offsetting these favorable quarter-over-quarter gross margin results was $22 million in lower domestic net mark-to-market gains.

These gains are related to asset-backed hedges that are economically neutral to the company.

Operating and maintenance expenses increased $24 million versus the same period last year, reflecting our continued focus in investment on improving plant performance.

Of the $24 million increase, $17 million was directly related to increased major maintenance with Big Cajun II and Indian River, in particular, undertaking outages dedicated to driving plant reliability and performance.

As David highlighted, a 2006 priority is achieving our 2006 FORNRG targets and investments in major maintenance to improve plant performance is a critical step towards achieving this goal.

The remaining $7 million increase is related to a credit recognized in 2004.

Excluding the higher investment in major maintenance in the 2004 credit, the underlying [O&M] expenses were flat quarter-over-quarter.

Continuing on with our third quarter process progress, the G&A spend improved significantly as compared to the fourth quarter of 2004, decreasing by $26 million.

Reduced third-party consulting costs contributed $14 million to the decrease.

Additionally, we recorded an $8 million bad debt allowance in 2004 related to a note receivable associated with our Northbrook asset.

The remainder of the improvement reflects our full NRG progress to decrease insurance costs and other administrative fees.

Interest expense, including the amortization of financing costs, decreased $27 million quarter-over-quarter.

Approximately $4 million of the decrease is related to the refinancing of the corporate credit facility in December 2004, $13 million for the 2005 repurchases of the high-yield notes and the remainder primarily for the sale of Kendall.

Our adjusted EBITDA, excluding the mark-to-market gains of asset-backed hedges in both periods but including the fourth quarter mark-to-market impact from trades not specifically tied to assets, was $202 million in the fourth quarter versus $155 million in the same period last year, an improvement of over 30%.

If changes in the portfolio are taken into account -- in particular, the sale of Endfield and Kendall, along with the contract expirations at West Coast Power and Rockford -- the improvement was a 130%, or $117 million.

Slide 17 provides the same financial summary for our full-year performance.

The story is similar to the quarter with one exception.

The year-on-year net domestic mark-to-market results were a $119 million loss for 2005 versus a $59 million gain in 2004.

Excluding the mark-to-market losses, gross margin increased $79 million.

Strong demand for power in the second half of the year, coupled with rising prices driven by the volatile natural gas environment, led to increased generation volumes for our oil and gas-fired assets and higher margins for the Northeast region.

Our New York City gas plant finished up the year with generation output 52% higher than 2004, contributing $52 million to the gross margin increase.

The Northeast baseload assets all saw increased margins -- $70 million excluding the mark-to-market impact and capacity revenues.

This improvement reflected expanding margins as generation from our Northeast coal-fired plants decreased year-on-year by 4%.

The decreased generation was due to both planned and unplanned outages.

Northeast capacity revenues increased by $27 million due to the final settlement of the Connecticut RMR agreement net of lower western New York capacity prices.

During the second half of 2005 with the price of SO2 emission allowances crossing $850 per ton in July, we began selling excess allowances and recorded $33 million in revenues for the year.

This does not include the $15 million of previously announced excess allowance sales initiated in December.

Revenues associated with these sales will be recognized in the first quarter of 2006.

Partially offsetting these favorable impacts were the second quarter 2005 unplanned outages at South Central resulting in approximately $40 million of higher purchase energy and the loss of nearly $80 million in gross margins associated with our portfolio changes, primarily Kendall.

Cash flow from operations this quarter, shown on slide 18, increased by $182 million largely due to the $193 million in returned collateral due to lower forward prices at the end of this fourth quarter and cash from operations.

These increases were partially offset by $68 million in cash interest payments, primarily the $44 million in biannual interest payment on the high-yield notes and the $21 million annual interest payment on our peakers financing; $22 million working capital increase during the fourth quarter due to a $57 million increase in inventory due to coal and inventory builds as we prepared for the winter season, and the $39 million increase in prepaid assets.

Partially offsetting the working capital buildup was a $55 million increase in accounts payable partially due to tighter controls employed as part of our FORNRG initiative and a $29 million decrease in accounts receivable.

The fourth quarter increase in cash flow from operations was largely offset by $61 million in capital expenditures and $158 million in financing activities.

During the fourth quarter, we repaid the $80 million on the revolver drawn during the third quarter, made approximately $25 million in principal payments on various debt facilities and the $44 million bridge commitment fee related to the acquisition financing.

In addition to the cash generated from operations, the full-year net cash flow results had three additional significant drivers -- cash collateral cause, debt repayments and the stock buyback.

In connection with the cash collateral cost, the Company actively manages price and volatility risk through its hedging program.

During the first half of 2005, the Company sold the majority of its all-in peak baseload generation capacity for 2006 forward.

During the third quarter, natural gas prices spiked, driving power prices higher which required the Company to post significant amounts of collateral to support the forward sales.

As of December 31, 2005, the Company had $438 million of cash collateral outstanding.

$405 million of cash collateral will be returned in 2006 as the underlying trade contracts settle and power is delivered during the year.

Cash collateral return through March 3 was $271 million.

The second item affecting the year's cash flow was the repurchase of $645 million of 8% high yield notes during 2005.

In the first quarter, approximately $450 million of cash was used to repurchase $416 million of par value, high-yield bonds.

The net proceeds from the fourth quarter of 2004 of 4% preferred stock issuance were used to fund this purchase.

Finally, on August 11, 2005, the Company completed a $250 million accelerated share repurchase of the Company's common stock.

In connection with this transaction, the Company issued in a private transaction $250 million of a new perpetual preferred security.

The proceeds from this offering were used to repurchase an additional $229 million of par value high-yield notes.

On slide 19, NRG's liquidity at December 31, 2005 and 2004 is presented, as well as a more current post-acquisition closing balances as of February 28, 2006.

The year-over-year decline in cash is primarily due to collateral postings during the year, the first quarter 2005 high-yield note repurchase and the third quarter 2005 share repurchase.

Cash balances at February 28, 2006 have increased by approximately $257 million since year end, reflecting the return of cash collateral, cash from operations and partially offset by cash used at the Texas Genco closing.

Under our new first lien facility, the Company has $2 billion of liquidity facilities comprised of a $1 billion synthetic letter of credit facility and a $1 billion revolving credit facility.

The term synthetic LC facility is used since this is an off-balance sheet instrument with the LCs backed by $1 billion of cash collateral owed by a third party.

LCs under this facility are available to support our obligations under commodity hedging and power purchase agreements.

The balance of February 28, 2006 reflects $594 million of LCs to support NRG Texas hedges with the remainder supporting the hedges of the NRG portfolio.

Under the revolving credit facility, if the $300 million of unfunded LCs can be used for working capital needs and other corporate purposes, approximately $155 million of non-trade LCs were outstanding at February 28, 2006.

Post-transaction, we have over $1.9 billion of liquidity at February 28, 2006.

This, combined with our second lien capacity, provides ample liquidity to support our hedging activity.

Slide 20 provides a look at the year-end capital structure and the estimated balances at February 28, 2006.

The first lien debt and second lien high-yield notes outstanding at year-end have been extinguished and replaced with new first lien debt and unsecured high-yield notes.

The first lien Term B loan is a seven-year note with interest at LIBOR plus 200 basis points.

In January of 2006, we entered into a series of interest rate swaps with a notional amount of approximately $2 billion that effectively converts this floating-rate interest to fixed at a rate of approximately 6.8%.

The unsecured high-yield notes are comprised of a $1.2 billion tranche of 8-year notes with a fixed rate of interest of 7.25% and a $2.4 billion 10-year tranche at a fixed rate of 7-3/8%.

The preferred stock and booked equity reflect the February 2, 2006 public issuance of the 5.75% mandatory convertible preferred stock, the January 31, 2006 public issuance of 20.9 million common shares at $48.75 and the issuance of 35.4 million common shares to the former shareholders of Texas Genco to be recorded at $47.76 per share.

The 15% overall allotment of preferred and common shares, also known as Greenshoe, was not exercised by the underwriters.

Post-closing and consistent with our previous guidance, we were at the upper end of our targeted debt to total capital range.

With the expected strong free cash flow of the newly combined company, our capital allocation plans include managing and lowering the debt and overall leverage of the Company.

Slide 21 provides an update for the second lien structure being used to support the collateral requirements of our longer-term strategic hedges.

Not being an investment-grade company, NRG can use the second lien structure to provide non-cash collateral support for our hedging activity.

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

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

Hedges currently under the second lien structure have a net exposure of approximately $1.3 billion.

LCs posted as collateral for the same underlying hedges aggregate at $572 million at February 28, 2006.

Our updated 2006 guidance is shown on slide 22.

In early January, we announced our 2006 adjusted EBITDA guidance of $1.6 billion.

Immediately after issuing this guidance, the Northeast region experienced one of the warmest winters ever recorded.

Even with the record warm winter temperatures, we are able to reaffirm our adjusted EBITDA guidance at $1.6 billion.

On the next slide, I will just cover several of the underlying fundamentals supporting our current forecast.

In addition to maintaining our adjusted EBITDA forecast, we are increasing our cash flow from operations guidance by $140 million.

This is largely due to secure lower interest rates that originally anticipated on the high-yield notes and the replacement of the plan's sponsored preferred shares which carried an interest rate of all 11% with higher borrowings under the lower cost Term B facility.

Additionally, we will only have to make one of the $130 million biannual interest payments in 2006 required under the unsecured notes indenture.

Slide 23 highlights the current environment influencing our earnings guidance and sensitivities to the presented guidance.

As discussed earlier, the 2006 winter has been unseasonably warm, affecting both generation hours and power prices.

In spite of these unfavorable factors, we were able to maintain our full-year adjusted EBITDA target of $1.6 billion for the following reasons.

First, the NRG Texas gas plant had a conservative earnings forecast.

Current forecasted energy and capacity margins are higher than previously forecasted.

Second, New York City capacity revenues are being realized at higher levels than previously forecasted.

Third, lower than expected generation as linked to excess emission allowances which have been monetized.

Fourth, we continue to build momentum and success in our FORNRG efforts since the additional opportunities for the Company post-acquisition.

And finally, as we consistently stated during the financing roadshow, although our guidance was developed in the higher gas environment of the fourth quarter, we took a conservative outlook in order to absorb if needed some level of natural gas price decline.

While these factors are sufficient to offset the unfavorable variances of the first quarter's unseasonable weather and declining gas prices, a further decline in natural gas prices or another extended period of unseasonably mild weather would likely result in a lower 2006 outlook.

The sensitivities shown on slide 23 represent the 12-month impact of the indicated change.

Slide 24 summarizes our 2006 financial objectives.

As we have done in the past, we will continue our active management of the balance sheet to the defined targeted level.

We continue to believe that managing down to the lower range provides us with the flexibility to pursue meaningful capital allocation alternatives.

Our near-term focus is the successful integration of NRG Texas and West Coast Power and to deliver our cash flow and earnings targets.

Later this year, we will provide more clarity surrounding forward capital allocation plans.

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

Thanks, Bob.

There is a one more slide on slide 26, which is a slide which we typically use to tell you how great we are and how well-positioned we are, which I will dispense with.

But before I hand it over to Jen for questions, I just wanted to make one point.

Obviously, we as a company and as a management team take very seriously our commitment to achieving the financial targets of the Company.

I think over the eight quarters that we have been in existence, we have a very good record of achieving what we set out to do.

So as I said, we take it very seriously.

But there's one thing we even take more seriously than our financial targets, and that is our commitment to safety.

So I would just like to back up something that Steve Winn said a little earlier.

The NRG Texas plant at Parish, 800,000 hours, more than a full year without a recordable incident is a phenomenal achievement and we're all going to be down there tomorrow to acknowledge that achievement.

And so that is a job very well done and one that we can hope to emulate at our other plants.

So, with that, Jen, I will turn it over to you so we can take some questions.

(OPERATOR INSTRUCTIONS).

John Kiani, Credit Suisse.

Good morning.

When you reaffirmed your guidance, in the press release, you cited the risk of continued mild winter weather or an unusually mild summer.

I guess there are really only a few weeks of winter left, so is really the big impact in the summer months -- meaning, is your guidance more predicated or meeting your guidance more predicated on just normal summer weather?

And therefore, March doesn't necessarily have a very big impact?

Yes.

John, I know you're not used to such a terse answer, but keep in mind, we started writing the press release three or four weeks ago when it was still relatively early in February.

And there was more winter then, but the latter half of winter has not been the issue.

It was the deep winter where there was no weather.

And so there is not -- you're right, there is not much that can be done to us in March.

What our guidance is predicated on is a normal summer, which means that it actually gets hot at some point during the summer.

Okay, thank you for that.

As far as the Texas Genco synergies are concerned, I mean I know the deal wasn't predicated on any synergies, but you've mentioned now potential cost savings from purchasing benefits.

Can you give us an order of magnitude of what you are talking about there?

And is that in any guidance numbers?

John, at this point, it's not included in the guidance.

We're framing out the size of the opportunity right now.

And we've talked about on the roadshows that we have a cash spend of the combined company of about $3 to $3.3 billion annually.

Some of that you can compress, some of it you can't.

So we're sizing that up now and we plan to come back to the markets probably at our next call to provide more clarity around that.

But that remains -- anything that we achieve this year on that would be upside to the guidance that we put out.

Okay great, and then one last question.

Can you give us a little bit of color on how the gas plant capacity sales on the Texas Genco assets have materialized so far in '06, relative to your original plan?

Well, I think that, relative to our original plans, which we were very, very conservative in terms of what we expected that they would sell, and sales have just been stronger, in excess of what we anticipated.

You know we have built that into the model.

And our origination people with respect to the gas plants I think have been very good at structuring products that people who serve load in Texas want to have in terms of virtual powerplants or models around the characteristics of the plants because the plants obviously, they not only can sell capacity, but they can sell ancillary services.

So I think it's just a job of good execution.

And, again, we were so focused during the acquisition phase on the valuation creation by the principal of solid fuel-fired plants that we did as we normally do; we think that we hadn't had -- we were just quite conservative on what could be achieved.

Terran Miller, UBS.

Good morning, a couple of quick questions.

Number one is, in your 2006 revised EBITDA guidance, are there any planned gains from the sale of emission allowances baked into those numbers?

Terran, what we have got built in is, and you saw it on David's slide, is $54 million of emission allowance revenues that we have realized through the end of February, and that is the only thing that we concluded in the guidance.

So as David mentioned, while we may have additional length during the year, we have not contemplated doing anything with that, and that remains -- that would be upside to the number.

So it's only what has been achieved through February, which is on the slide that David covered.

Okay, thank you.

Any update you could give us in terms of asset disposals in Australia or the strategy that we should view for 2006 for Australia?

Terran, I would tell you about Australia, there is not really any update.

What we said on the roadshow is that we would have greater clarity by -- possibly something done by the end of the first half of this year.

The process is underway and actually there are several would-be -- there's several parties interested in the portfolio and the first round of dates are due within the next couple of weeks.

So it's something that we [can] give you greater clarity on.

The one thing I would emphasize about Australia is, this is not a for-sale situation from our perspective.

And obviously, if we don't feel that the bids we get are reflective of the full value of the assets, then we will continue to operate the portfolio and have it as an EBITDA contributor as it has been in the past.

Okay, and a quick yes or no question, which is -- should we expect to get year-end 2005 Texas Genco-only numbers?

No.

Jeff Rosenbaum, [Fir Tree].

Good morning.

I was just wondering if you could review for us the limitations that you have on buying back your stock and when you think you may enter the market to do so?

I mean, I think it would be a pretty good sign of confidence, given that this stock has dropped a meaningful amount since your secondary.

Jeff, there's no restrictions on us under the share transactions we just did in terms of going out and buying the restrictions would be limited to what the credit agreement and the unsecured indentures have.

And there, you have a limitation under the first lien, which is the more restrictive of $250 million that you could use today to buy back shares using $250 million of available capacity under the first lien note.

That grows each year based upon your free cash flow.

If we monetize Australia, or any other foreign asset for that matter, the first $300 million of equity proceeds that the Company receives is carved out of the debt agreements [that] indenture.

So that would be in addition to the 250 million that you have today.

So the limitation today is that $250 million under the credit agreement.

It just seems like there would be no greater investment, given your free cash flow yields in 2006 are 15% plus going to over 20% based on the current (MULTIPLE SPEAKERS).

You know, I agree, Jeff, and we're looking at our capital allocation plans for the year.

What we have always said as we went through the roadshow is to get Texas Genco integrated, stabilized, to start generating, demonstrating it has the cash flow, and then we will move to our capital allocation plan.

Jeff, we have been pretty clear.

We look at the question capital allocation, which obviously is a Board question in a very methodical way, and that we have suggested that it's something that people should be focusing on in terms of something that we have an obligation to get back to the market.

I think if not, the next quarter call or actually the call after that during the summer so we have had a couple of quarters with Texas Genco.

Michael Lapides, Goldman Sachs.

Thinking about powerplant development and long-term growth.

You talk frequently about the Cajun.

I wanted to know if there is the possibility of kind of changing the focus and looking more towards new coal plants, either a new unit at Limestone or a new unit somewhere in the Northeast where the market fundamentals may be a little bit more attractive then in the energy service territory.

Michael, I would say that we, in terms of the things you're talking about, we don't find those things to be mutually exclusive.

In fact, we would like to actually find commonalities between those things, between new coal development in Louisiana, Texas.

A little bit more difficult with the Northeast.

I think more a creature unto itself in terms of solid fuel fire development.

In terms of the market fundamentals in the Entergy zone, obviously if you look at the market fundamentals in the absence of contemplating fuel price, they look very bad.

But it is -- Louisiana is the second most dependent market in United States on gas-fired generation.

So coal-fired generation is quite attractive down there.

As we have said all long, we -- with any type of coal-fired generation, whether it be in the Northeast, Texas or Louisiana, we will only proceed if a very substantial proportion of the offtake is contracted for the very long-term.

So we have limited appetite for market risk really in any of our core regions when it comes to billion-dollar capital investments in new plants.

So, I guess that's my long-winded way of saying you may be more -- find Northeast Texas more attractive than we.

We would like to do all three, but off the strength of long-term contracts.

Is there any thought at all still of possibly being a buyer of distressed combined cycle assets in Louisiana to kind of cover the short position there maybe as a substitute for potentially doing new coal there?

Well, to me, again, it would be more complementary in the fact that if we for years now, I think almost as long as I've been here, we've talked about our desire to own a combined cycle plant, a modern combined cycle plant in the South Central region and always been somewhat perplexed that we could not buy one at value given how many there are down there.

But, and the purpose for it would be complementary to our caseload and would help so we didn't have to cycle the big Cajun II coal unit so much.

But I have to say that probably my confidence level that we could buy one at value is at an all-time low because there's just so much money from outside the strategic side of the industry chasing individual asset deals.

And with a lot of the combined cycle plants in South Central, the transmission situation is so uncertain that it's very difficult to come at a value that you think you can actually realize upon.

So, we continue to look, but we are really no closer on that front today than we where the first time I started to talk about this two years ago.

Ryan Watson, Stanfield.

Hi.

On slide 23, can you talk about on the sensitivities what the base that we are starting with is on natural gas and coal?

You know the plus --

Ryan, we have never given out exactly where we started.

When we did our original forecast, we were using prices that existed in October.

And what I have not disclose before but I will provide it here is that we shaved slightly over a dollar off of the forward curve at the time.

You can back into it towards that, but the sensitivity is meant to be driven around whatever you are selecting in your model.

If you move gas prices out, this is what the impact should be on the portfolio.

So you shaved a dollar off the forward curve as of October?

We shaved slightly more than that.

Okay.

As far as the west goes, you spoke about your El Segundo plans on the CCGT.

Do you have any other plans to expand your presence in that region through acquiring assets?

Well, I think El Segundo, what I said about the coal plant [that supplies] that of course, as well we would need an offtake agreement there, particularly given the lack of a capacity market in California.

I would say that if a plant expands through acquisition in California, again, we would be opportunistic about that, but I wouldn't say that that is our highest priority where we're thinking about what we would like to strengthen, where we would like to strengthen our position.

We expect to close the transaction with Dynegy this month, which will give us full control of the assets out there and our first priority is creating value from those asset sites before we talk about building a bigger business.

Daniele Seitz, Dahlman Rose.

Thank you.

I was wondering if you could quantify the benefit from the above normal weather in 2005 summer?

Was there -- is there a number I can use?

Well, off the top of my head, what happened in the third quarter is that we went through -- going into the quarter, we had guidance out for the year of about 630.

And then as we went through the third quarter and did our third-quarter close and final call, we increased our guidance from 630 to 700.

I would say the majority of that increase was due to the above-normal weather.

Great.

The other question -- you mentioned that you still expect challenges in terms of coal supply.

Could you elaborate on that in 2006?

Well, I can't elaborate on that, Daniele, more than saying it always seems to be something when it comes to railroads.

I mean, in 2004, we had a big issue with eastern railroads.

In 2005, the problem shifted to the west.

And now I can't predict where they're going to have a derailment or where they're going to have a brush fire in Kansas, but it just seems that the rail system in the U.S. sort of stretched to the capacity.

So any sort of bump in the road and it seems to upset the system.

Obviously, we track it very closely and sometimes it gets a little bit better, but it's never good.

So from a prudent management perspective, it just always makes sense for us to be more conservative and move away from what was once the trend, which was to put the coal piles down to the smallest amount.

Better to have a little bit more cushion, and that's what we are trying to achieve.

Great.

I was just wondering if you mentioned -- if that is related to the transportation problem in the west, but it's a variety of disturbance, right?

That's right.

And keep in mind, we are moving Wyoming coal to Delaware, so there are fewer people in the country that are moving coal further than we are.

So really, there's almost anywhere in the system that a problem could occur that could affect us, and that's why we -- why Kevin's group is, having done such a great job to figure out various flexible forms of delivery through barges and as well as rail, has been a big plus for us over the last year.

And (indiscernible) continue doing it next year.

Lasan Johong, RBC Capital Markets.

Good morning, a couple of questions.

Did I hear correctly that in the fourth quarter, there was proprietary trading process of about 27 million.

And how much should we expect in '06?

And what kind of VAR do you have in risk management system do you have around that proprietary trading system?

And just following up on some of these coal questions.

If coal supplies because of choke points at railroads and what not become an issue or a problem, when does NRG make the decision to install environmental control equipment as opposed to burning PRB coal?

Thank you.

Lasan, actually could you elaborate on your second question?

Just so I understand, if there was a connection between the transport issues and the environmental control equipment?

Like, you were saying, you were commenting I think that at this point, because of recurring unforeseen problems, plus difficulty of supplies generally, that analyzing costs implied I assume, that NRG is looking to potentially increase its coal supply more than what you would normally see.

I think the 20- to 25-day target is what you have.

And at some point then, it does makes sense to take that, the risk profile out of the equation to convert some of these plants into or install retrofits environmental equipment.

When is it smart to do that versus continuing to burn PRB coal?

On that question first, a couple of answers.

First is, we don't really equate -- I mean, since we don't, apart from Limestone, which obviously has lignite right at site, since we don't really have any mine mouth plants, coal plants in the United States, coal transport is always an issue for us.

And even though, as Daniele alluded to in her question, the problems have been out with the Western rails during 2005.

In 2004, our biggest issue was getting coal from Eastern Pennsylvania into Delaware.

And in fact, the cycle times for coal coming from Central Appalachian was longer for us than it was from getting it from Wyoming to the east.

So, I don't think changing away from our commitment to Powder River Basin coal will solve our coal supply issues.

So we don't really look at it in that context.

Having said that, the fact that emission prices are so high certainly makes one look at whether one should be adding control equipment sooner rather than later, and that is an analysis that we are doing all the time.

One of the things that has impeded us from considering that too seriously is that, if you were going to on a voluntary basis put in expensive emission equipment earlier than you have to based on what our emission prices are now, they have only been high for a short period of time.

Could you actually lock in the gain by selling the benefit three or four years out?

It's doubtful to me that you could actually achieve that.

But certainly, the rise in emission prices I think has everyone looking at the pace at which they put on further back-end controls, and that includes us at the plants that we own 100% in, it includes us at the plants where we own a small interest in Pennsylvania.

To the first part of your question, the proprietary trading or speculative trading, we have said for a year or two that with the asset base and we have had, that we want to strengthen Kevin's group to do more trading around the assets and to capture the extrinsic value.

And at the same time, we have said during the roadshow that, in terms of what drives this company's financials, that's going to be the tail on the dog.

And certainly, we would like Kevin's group to earn their keep, but we're not looking for them to become the principal profit center of the Company.

And Kevin, I don't know if you have anything that you want to add to that?

Well, you know I would say that any of the trading results we turn in, I look at our base budget results and say, that is monetizing still we own.

Any of the incremental trading we do I say is monetizing the information we get off that steel.

And David's exactly right -- we're very focused on making sure we don't end up in the situation where the tail is wagging the dog.

Well, that's great and I think that's the right approach, but how much of the trading classes are built into the '06 guidance?

And what kind of VAR are you operating under?

Lasan, in the guidance of 1.6 billion, the trading-related EBITDA, if you will, is very insignificant of that 1.6 billion.

It is well below (technical difficulty) 5%, and I will just leave it at that.

And the VAR assumptions?

I don't think we [essentially] make that information public.

Two more questions, Jen, we are a little bit over time.

Since we took so much time, we'd like to answer two more and then call it a day.

Paul Patterson, Glenrock Associates.

I wanted to sort of follow-up on your opportunities outside of El Segundo and Big Cajun, and just how you look at that.

You mentioned the stock buyback as well and I'm just trying to get an idea as to where you might be actually planning to build new plants a little bit more specifically.

You mentioned no solid fuel in the northeast, but I thought that there was some opportunity earlier on that you mentioned.

And also, in Texas, you saw some opportunity, and how that fits in with the buyback that you might be contemplating?

Paul, let me take crack at this and I will turn it to Bob to see.

I think you may have misinterpreted something I said, but I'm glad you brought it up in case I was confusing it.

If I said that we don't think we have solid fuel opportunity in the northeast, that was not what I intended to say.

What I was alluding to in my previous comment was that the type of technology that we might put in in Louisiana and Texas in terms of solid fuel, new solid fuel plants, we don't think that could ever be permitted in the northeast.

So you would have to have more of a clean -- an IGCC technology in the northeast or something very closely equivalent.

Having said that, we do see big opportunities, because obviously the northeast is suffering as well from its dependence on natural-gas-fired power generation.

So, we see that as a big opportunity, but it's obviously a big challenge.

To your question about how do we look at investment in brownfield development, vis-a-vis stock buyback?

In terms of the specific hurdle rates and things like that, I'll turn it over to Bob.

But I (indiscernible) point out, as we did point out during the roadshow, that even if we look at our most ambitious possible thing that we might do on the Brownfield development front, which, say, looking at our entire fleet of Louisiana, Texas and the northeast and in California, we could get somewhere between four to six plants into construction, let's say at a total project cost in the 7 to $8 billion range.

Since we would be doing it largely based on offtake agreements, there would be a lot of nonrecourse debt involved in that.

You get the equity commitment down to I'd say maybe 3 million over a five- to six-year period.

And then with all of the developments that we're contemplating in all of our regions, we actually can't contemplate doing anything totally ourselves.

We would do almost everything with partners.

So you get the potential commitment again over multiple years from our company down 1 billion to 1.5 billion.

If you look at the free cash flow generation of the Company, NRG together with Texas Genco over several years, it's far in excess of what we could possibly see as investing in brownfield development.

So this is my way of saying, I don't think that they are mutually exclusive.

And, Bob, if you care to add how we evaluate them against each other.

I would say actually the same thing you did, Dave, that it's not mutually exclusive.

Our first 20 months after the Chapter 11 experience, we bought back 20% of our shares at the same time we were reducing debt acquiring Texas Genco and acquiring West Coast Power.

As David said, the cash flow from the combined entity is more than sufficient for capital allocation and we'll look at the highest use of it.

We view our stock as a compelling investment as we have demonstrated in the past, and we will continue to do so.

The key thing for us on the stock buyback is get the capacity to build up in the restricted payments basket, if you will, to have the opportunity to do it.

And it would not be an and/or -- it wouldn't be a nor proposition, it's an an proposition to the other investments.

Just to follow-up on that thought, the IGCC technology, that would indicate as you mentioned as well, you had a limited appetite for market risk.

Is the LICAP agreement out there; is that enough to sort of take care of that, or would you need to have a contract, a more substantial form of contracting, to make an investment with the IGCC kind of thing.

And just in general, what is the hurdle rate?

I guess I mean what kind of return are you expecting for any new (technical difficulty) might be making?

What should we assume would be what your return hurdle would be associated with this?

I would say that each project is different, but generally speaking, we have got to get a double-digit return.

If you're getting just your cost of capital (technical difficulty), obviously it's a breakeven scenario when you've got your stock yielding in the teens [over] free cash flow yield.

That's a pretty compelling investment.

So it has to be greater than that, right?

Yes, we're going to have to weigh the two against each other.

Like what we've talked about internally, the free cash flow yield is a compelling investment for us alone, so the project has not only the cost of capital hurdles competing against, but also looking at the alternative use when we measure buyback versus investment.

Paul, on the first part of your question, obviously that's one of the reasons why I said this is the ideal window because to get that type of return, it seems that you should be able to get that type of return in this environment where coal is competing in markets where gas is [saying] the price of electricity.

On the question of -- we are a big supporter of the introduction of locational capacity markets in all of the competitive markets, but we've also equally said that there is just not going to be enough history with those capacity markets while there being developed to get people to put metal in the ground, and that we believe there needs to be another wave of bilateral long-term contracts to get really any type of based intermediate load plant done, but particularly with IGCC and the specific challenges of that.

So we support the LICAP in New England, but for us to build an IGCC in New England, we would be seeking a long-term bilateral contract.

And I think that if these plants get built, one way or another, it's going to be basically a public/private partnership with the involvement of state entities.

And you see in the northeast various states, the various governors of various states being very interested in these ideas.

So that's the dialogue that we need to push forward in the year to come.

So I think one last question, Jen.

Elizabeth Parella, Merrill Lynch.

Thank you.

You mentioned that you put on to 220 megawatts of additional hedges for 2010.

It also looks like you're hedging percentages maybe went up a bit more in the earlier in years, and I'm just wondering if you could talk about where you have done that hedging?

Have you done more for example in some of the base load plants at Genco for 2010, or some of the northeast coal plants?

If you could give us a little bit more of a flavor for that?

Again, I'm always very hesitant of getting on the wrong side of our Commercial Operations team and telling the market more than they want the market to know, so I'll turn it over to Kevin and ask him to answer that question.

Yes, I think the other piece you will see that's increased in our hedge book is some of the near-term years -- some of the load options that occurred in PJM.

We've participated in some of those and picked up some modest load out of the auction process.

In the 2010 year, is that Genco or NRG Texas or is that more northeast stuff or?

I'm sorry, you said in 2010, are you asking where was the 220 megawatts put on against which assets?

Yes.

You want to answer that, Kevin?

Clearly, I think we view our whole portfolio -- when we're doing a hedge program, we look at all of our baseload capacity than units than we will based on what location; it will be slightly biased towards one region or another.

But we don't manage it, the hedge program, by region; we manage it against the whole baseload portfolio.

It sounds like I'm not going to get a specific answer on that one.

Elizabeth, you're very quick on the uptake, as always.

Let me ask one follow-up for Bob.

The interest savings, or not savings, but kind of the cash benefit from lower interest payments in 2006, 140 million, did I interpret you correctly in saying that 130 of that is just the timing that gets switched into 2007?

And the rest is kind of the lower interest rate and the [mix] of debt?

Elizabeth, that's right.

The smaller piece of it is the fact that we didn't issue the preferred shares and we used the Term B, and that gives you a benefit of 10, 15 million or so.

But the real benefit is just the timing of the interest payment on the unsecured you pay in August and February of each year.

So this year, we didn't have obviously a February payment, so $130 million is just timing into February, rolls out of this year.

When we originally did our forecast, we assumed we had 11 months of interest, cash interest.

One last question for Bob.

I realize it doesn't affect EBITDA, but I wanted to ask you in terms of how you are going to account for the acquisition of Genco, the amount that is being written up for the low market contracts where you made an estimate at the time of the acquisition.

Does that get adjusted down because gas prices have come in some at the time of closing?

It will, yes, it will be marked -- basically marked to market at your opening balance sheet, so it will be less than what we talked.

That difference then gets marked up in the form of higher asset values that you need to depreciate?

I think the difference is, we're working through the purchase price accounting now -- the difference typical typically would be in offset and goodwill.

You would have lower goodwill.

There are no further questions in queue at this time.

Thank you Jen, and thanks all of you.

We apologize for taking so much of your time this morning, but we appreciate your interest in the Company and we look forward to talking to you next quarter.

Thank you.

This concludes today's conference.

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