NRG Energy Inc (NRG) 2004 Q4 法說會逐字稿

Good morning, ladies and gentlemen.

Welcome to the NRG Energy fourth quarter earning results conference call.

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

A brief question and answer session will follow the formal presentation.

If anyone should require operator assistance during the conference please press star zero on your telephone key pad.

As a reminder this conference is being recorded.

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

Thank you, Ms. Azmy, you may begin.

Thank you.

Good morning and welcome to our fourth quarter 2004 earnings call.

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

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

A replay 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.

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 filings with the SEC that could cause actual results to differ materially from those in the forward-looking statements in the press release and this conference call.

In addition please note that the date of this conference call is March 30, 2005, 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 to most directly comparable GAAP measures and a quantitive reconciliation of those figures, please refer to today's press release and this presentation.

With the formalities out of the way, I would like to turn the call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Nahla.

Good morning, everyone, and thank you for participating in the new NRG's first full year financial results.

We apologize for the couple weeks delay in announcing these results and the reasons for those Bob will explain in greater detail during his section, but hopefully you will feel that the wait has been worth it. 2004 was a profoundly busy year for NRG both from a financial and operational perspective.

I can say I am very proud of our people and the results which they achieved.

I am particularly pleased with the way we've achieved it because I feel that throughout the year we told our stakeholders what our plans were going to be and then we went out and successfully executed on our plans.

We set an EBITDA hurdle of $875 million and we did 976 million.

Even if you back out the $60 million mark-to-market gain and apply it to 2005 rather than 2004, as I believe you should, we still exceeded our EBITDA target by $41 million.

We set a net debt to total capital target range of 45 to 55% and we are already well with within that range.

We said that we would be able to lock in our PRB coal supply arrangements for the medium to long-term at or close to our historical cost and we are well on our way to achieving that goal.

And we said that we would return capital to stakeholders when it made sense to do so and in December we both paid down debt and bought back shares.

Today Bob and I are going to talk about the year past but we are also going to discuss our current prospects and our initiatives going forward.

The important point is that what we did, what we achieved in 2004 we are not stopping in 2005.

Our new initiatives are additive to the focus on execution and balance sheet management that were our Company's twin keys to success in 2004.

Before I turn my focus to the present initiatives and future prospects of the Company, I would just like to provide a few comments about the year just concluded.

If you are looking at our presentation and you turn to slide four the story of our fourth quarter is a strong finish to a strong year.

Typically the fourth quarter is a weak quarter for companies in our industry relative to the first and third quarters but in 2004 we achieved a very healthy adjusted EBITDA of 214 million for the quarter.

The big contributor to this good result was the $60 million mark-to-market gain associated with our coal fired generation assets in the northeast.

For those of you who were on our last call in November, you'll recall that at that time I pointed out that the Company had taken advantage of the recent run up in forward electricity prices to increase significantly the hedge position of our northeast coal fired assets for 2005, particularly for the first quarter 2005.

Our timing was indeed very good as dark spread softened over the balance of 2004.

As it turned out, due to the workings of FAS 133 and our written hedging policy at the time, we were obligated to realize the benefit of our timely hedging activity in fiscal year 2004.

Regardless of the fact that this 60 million gain should have been realized in 2005 or that it was realized in 2004 as it was, we are very pleased at the speed and effectiveness demonstrated by our power marketing group in capturing this opportunity.

In terms of net cash flow I'm pleased to report a full year net cash flow of $559 million.

This is perhaps the most important number to Bob and me as we have stated from the beginning of our tenure here that we would be managing this Company for cash.

The $559 million contained some significant nonrecurring elements like the $100 million net payment from Xcel and a significant amount of cash from non-core asset sales.

But it also includes, as a deduction, a sizeable amount of financing fees that the Company has incurred -- or incurred in 2004 in order to achieve a significantly lower cost of interest and a more flexible debt capital structure going forward.

Turning to our debt capital structure.

Our net debt to total cap ratio, which is the principal liquidity ratio which we track, now stands at 49%.

When it comes to net debt to total cap, we include all of our balance sheet debt in that calculation as we made such significant progress in 2004 in removing non-core, nonrecourse debt from our balance sheet that we no longer see the need to distinguish between supported and nonsupported debt as we have in past presentations.

Having said that, our liquidity ratio calculations still includes $500 million of nonrecourse debt associated with our drain and with the peakers that we expect to remove from our balance sheet between now and 2007.

Our strong fourth quarter financial performance was underpinned, as it has been during the previous three quarters, by strong operational performance.

If you turn to slide five, if you are following the slide presentation, some specific highlights include, in terms of our operational performance, in the northeast, Indian River increased its equivalent availability factor to 84% in 2004, up from 77% the previous year.

At our New York City plants we achieved significantly higher capacity factors in '04 compared to '03, allowing us to capture the higher energy prices that were available.

In the south central region, Big Cajun II set a record production year with a capacity factor of 81%, up from 78%, notwithstanding significant major outage time spent on the the installation of low NOx burners for environmental remediation purposes.

And in Australia the refurbishment of our 240 megawatt Playford facility was completed in advance of the Australian peak summer season.

The 2% increase in fleet equivalent availability factor referred to on slide five most directly contributed to the Company's bottom line financial performance.

But even more important over the long-term was the Company's substantial improvement in plant safety and our steady and significant year-over-year improvement in SO2 and NOx emissions.

Turning to slide six, we continue to make progress in 2005 with our focus, as always, on operational excellence and cash generation.

Our plant and power marketing personnel have worked in close cooperation with each other during the important winter months to capture the value that was available.

Although it's important to note that neither in the United States nor in Australia did we see in the first quarter '05 the weather driven price spikes that the Company captured during the first quarter of '04.

Around the core portfolio we continued the harvest for cash.

This quarter, after several months of intensive effort, we collected $70 million of an arbitration award which we secured in connection with the old NRG's participation in the TermoRio project in Brazil.

And we continue to make progress in the sale of our three remaining significant non-core assets, Enfield, Saguaro and Itiquira.

Turning to page seven, operational execution, of course, involves aggressive and effective implementation of longer term objectives as well as near-term objectives.

A critical long-term objective for this Company continues to be the commercial operational and technical life extension of our fleet of baseload coal fired plants.

Our path to the accomplishment of this objective is an integrated multi-disciplinary approach.

We have succeeded during the course of our fifteen months here in advancing our strategy across the full spectrum of our core related initiatives.

On the regulatory front we signed a consent decree in January with the State of New York which provides us with regulatory certainty with respect to our coal fired plants there at a cost to us in terms of future environmental CapEx which is commercially sustainable.

In terms of procurement of a commodity itself, just yesterday we signed a five-year deal for 5 million tons per year of PRB coal which we will use to feed Big Cajun II.

In December we signed the ten-year rail and barge agreement to get coal from Wyoming to Big Cajun and now are nearing conclusion of a series of long-term rail arrangements to take the western coal to our eastern coal fired fleet.

And we recently began to take delivery of the 1500 new rail cars which we ordered last summer and which we now have entered into a lease arrangement with respect to with General Electric.

Finally, we are now operating units both at Huntley and Dunkirk on a 100% PRB burn.

Of course the last and ultimate step in our comprehensive coal strategy is the trading and marketing of our coal fired output.

As I noted at the beginning, last fall we took advantage of the fact that forward dark spreads appeared to be very attractive to lock in 98% of our winter forecast generation for the first quarter '05.

Dark spread fell off thereafter giving rise to the 60 million mark-to-market gain that we've already talked about.

As you can see on slide nine, dark spreads have had a strong push upwards again in recent weeks, driven by the high prices of crude and natural gas.

And, again, we have used this opportunity to increase significantly our hedge position for the balance of year '05 and for calendar '06.

We expect that the value of this recent hedging activity, unlike last October's hedging activity, will be accounted for and realized in the year to which it relates.

Now turning to slide ten.

Slide ten is a very useful slide because it, in a nutshell, illustrates NRG's basic hedging strategy.

As those of you who follow this Company already know, our EBITDA is principally generated by three different means, long-term PPAs, capacity payments and energy sales.

With respect to the energy sales portion, which are shown here on page ten for balance of year '05 and full year '06, the steadier and far more significant component derived from these sales are produced by our coal fired fleet.

We have sought, obviously with recent success recently, to hedge forward as much of this production as we can when prices are good.

With respect to our oil and gas fired fleet, we seek the contract later and at lower levels in order to preserve our ability to capture price fights arising out of supply disruptions or weather driven demand.

Of course, as always, I need to caveat that, our current hedge position is not static and can change in either direction depending on our point of view of market fundamentals.

Turning to page 11, I'd like to look forward but before I look forward I just like to spend a few more seconds looking backwards.

During 2004 we pursued single-mindedly a two headed strategy, an unrelenting focus on execution in all phases of our operations and prudent balance sheet management.

As this slide seeks to demonstrate, we feel we achieved a great number of noteworthy successes in both areas.

As we enter 2005 our financial operational focus will continue unabated but will be supplemented by a third focus on value enhancing growth.

Now, when we talk about value enhancing growth the first point that I must make is that at the new NRG value enhancing growth is not measured in megawatts.

It's measured in increased net cash flow, earnings and improved return on invested capital.

Increased megawatts may prove to be part of our growth plan but only to the extent megawatt growth translates into financial growth.

Slide 12 indicates the four types of growth initiatives which we have launched here in recent months -- Improved plant performance initiatives; corporate and plant costs and process control initiatives; enhanced trading, marketing and hedging activity; and expansions and enhancements to our asset portfolios in our core regions.

You will hear more about each of these initiatives in the months to come but today I would like to make just a few comments about our efforts to expand and enhance our existing asset portfolios.

This is the most capital intensive of our growth streams and as such has the greatest potential risk but also the greatest potential reward.

At NRG we consider our existing plant portfolio to be our greatest asset and we are actively seeking ways to invest in and around, in and around our flagship assets in ways that are not only rational capital investments on a standalone basis but also enhance the value of the existing assets in terms of any one or more of a variety of ways.

These ways can include life extension, repowering, supplemental load following peakers, fuel supply security, trading optionality or a portfolio based origination.

Slide thirteen indicates, with various levels of specificity, some of the portfolio enhancement initiatives which we are currently pursuing.

The development processes for all these initiatives are lengthy and as such they are not well suited to the regular declarations of victory which companies like to make at their quarterly earnings calls.

But we have started to make meaningful progress in these areas.

The El Segundo repowering project was successfully permitted in the past couple of months notwithstanding its location in the difficult to permit Los Angeles basin.

And we are getting very close on the permitting of an additional cold fired unit at Big Cajun.

As we turn to the prospect of putting new metal on the ground, I need to assure you that we will not repeat the greenfield mistakes of the bubble period.

I can assure you that no one at the new NRG has what I refer to as an edifice complex.

We have set forth on slide fourteen many of the criteria that will guide us in evaluating perspective capital intensive investments like El Segundo and the fourth unit at Big Cajun.

The most important, and the one from which many of the others flow, is the requirement of a long-term offtake agreement with a substantial load serving entity.

Without such a commercial underpinning we believe it would be foolish for a company of our size, or any size really, to build a large scale pure merchant generating facility no matter what the location, no matter what the fuel type.

Fortunately, we believe there is considerable interest among various load serving entities and new power generation from our El Segundo site and in an additional nongas fire generation from our Big Cajun site.

Now on slide fifteen I refer back to the timeline on which is showing its full on slide eleven, showing our financial activity over the fifteen months of the new NRG's existance.

I do so to illustrate a simple point.

We are often asked by investors when we are going to announce a capital allocation plan.

The fact is that we've been implementing a capital allocation plan for the past several months as particularly illustrated by our coordinated activities in the high yield debt and equity capital markets in December.

Our capital allocation plan is based on three core principals.

First, we will not disadvantage our equity holders to the benefit of our debt holders or vice versa.

Second, we will use our available capital to reduce negative arbitrage and take advantage of market weakness in our securities whenever and wherever possible.

And, third, all potential applications of our available capital, whether reinvestment in the business or return to shareholders, will compete against each other on an equivalent basis.

Now slide sixteen illustrates a couple of these principals while also highlighting the important caveat that even though we eliminated many of the most restrictive and onerous covenant restraints that hindered us in our original senior debt facility, there continue to be covenant restraints in our indentures which impact both our ability to reinvest in our business and our ability to return capital to our equity and debt stakeholders.

By way of summary, slide seventeen encapsulates on one page much of what I have talked about today and much of what we, as a Company, have sought to accomplish over the past fifteen months.

Since these points are very straight forward I would like to conclude on a more general note.

We, the management team, are very pleased with the Company's 2004 financial results.

And with the operational and organizational performance of the Company that produced those results.

And to be quite blunt about it, I think those of you on the phone who are already stakeholders in the Company should be pleased with these results as well.

I want to assure you that our pleasure does not translate into complacency.

All of us at the new NRG are acutely aware that what we have accomplished during 2004 is the creation of a solid foundation, a foundation built on prudent balance sheet management and on the credibility which we believe that we have earned by setting forth our goals and plans in advance and then by going out and achieving them.

But now is the time for us to expand our focus to building on our solid foundation in a manner that enhances value for all of our stakeholder groups.

With that, I will turn it over to Bob to review in greater detail our 2004 financial results.

Thank you, David, and good morning.

As David mentioned we finished 2004 strong with an outstanding quarter, far exceeding our target.

I'll review with you this morning our fourth quarter and full year financial results.

Additionally, I'll provide an early look for 2005 adjusted EBITDA and cash flow from operations.

As a reminder the fourth quarter 2004 is the last quarter on which comparisons to the prior year will be limited due to fresh start accounting.

Before I move on to the financial review I would like to recap for you several accomplishments in 2004 that are particularly noteworthy.

At the end of the year we engaged in several major financing activities that essentially recapitalized the Company to the benefit of shareholders.

We refinanced our senior debt facility at significantly better terms and rates.

We repurchased 13 million common shares at $31.16 cents per share.

We issued $420 million of 4% convertible preferred shares.

We achieved our target capital structure of approximately 50% net debt to total capital.

Finally we provided outstanding returns to both our debt and equity holders.

All in all it was a spectacular year.

While each one of the above accomplishments is significant there is another accomplishment I would like to highlight that I am particularly proud of.

Over the course of the past year we have redefined and rebuilt the organization and the internal control processes within the Company.

We had an uphill journey and throughout the year the employees of NRG worked countless hours building, strengthening and improving how this Company conducts business on a daily basis.

Our audit committee provided invaluable oversight and guidance every step of the way.

The result of all this work was NRG's receiving an unqualified opinion from our external auditors with regard to compliance with Sarbanes-Oxley.

Although the completion of our Sarbanes-Oxley work delayed our earnings call and 10(K) filing we are extremely proud of the outcome.

I will now move to our financial results.

Slide nineteen provides a financial summary of our 2004 performance for the fourth quarter and the full year.

At our third quarter earnings call we forecasted full year adjusted EBITDA to be approximately $875 million.

Our actual result was $101 million higher with full year adjusted EBITDA totaled $976 million.

I'll explain why the actual result exceeded our guidance.

As David just mentioned, early in the fourth quarter we hedged a portion of our 2005 coal fired generation to take advantage of the run up in power prices driven by escalating gas prices.

These forward sales did not qualify for hedge accounting treatment under FASB 133 and, therefore, at December 31st, we mark-to-market the performance of these forward sales.

Approximately $60 million of the adjusted EBITDA increase over our guidance is directly attributable to these unrealized mark-to-market gains.

Approximately 70% of these unrealized gains correspond to first quarter 2005 sales.

Subsequent to year-end we modified our FASB 13 documentation policies and procedures for forward sales.

Accordingly, future forward sales such as those made in the fourth quarter will more likely qualify for hedge accounting treatment.

In addition to the $60 million of mark-to-market gains our financial results were favorably impacted by $12 million in lower property taxes as we successfully qualified for tax credits and the $7 million settlement of a third party dispute for auxiliary utility charges.

These factors contributed to the higher EBITDA performance of $970 million and adjusted EBITDA performance of $976 million.

Slide twenty illustrates our total consolidated adjusted EBITDA by operating segment for the quarter and for the year.

The northeast fourth quarter included the $60 million of mark-to-market gains from the forward electricity sales put in place during the quarter.

Shorter months like the fourth quarter tend to be the strongest for our south central operation.

However, the experience and unforced outage in October, this outage combined with some unseasonably cold weather in December increased its load obligation to co-op customers, thus limiting merchant sale opportunities.

Adjusted EBITDA for the West Coast operations is primarily from the CDWR contract which expired on December 31, 2004.

Additional segment information is included in the 10(K).

On slide 21 is the 2004 cash flow.

As expected cash flow was virtually unchanged from the third quarter, increasing by approximately $5 million.

The primary cash flows during the quarter and year included $81 million in cash interest payments during the quarter as semi-annual interest on high yield notes and annual interest on the peakers financing was paid in December.

Total cash interest payments for 2004 were $295 million, including interest payments related to do our discontinued operations. $5 million and $34 million in cash taxes for the quarter and full year respectively, primarily related to our German operations.

The $72 million increase in other non-cash items was largely driven by our hedging activity.

Working capital increased during the year by approximately $65 million.

This working capital increase was attributable to a $53 million increase in our inventory, $70 million increase in our accounts receivable, $37 million increase in taxes receivable.

These increases were partially offset by an increase in current liabilities.

Asset divestitures of $303 million included $157 million to pay down the McLean(ph) debt leaving net asset built proceeds of approximately $147 million.

Cash used by financing including -- included the just mentioned $157 million in McLean debt pay down, fees associated with refinancing transactions and the normal amortization of a corporate and project debt.

With a strong free cash flow during the year the Company's liquidity grew by approximately $400 million during 2004, reaching nearly $1.6 billion by the end of the year.

Unrestricted cash exceeded $1.1 billion at December 31, 2004.

The December 31, 2004, balance includes the proceeds from the preferred share issue and the use of cash to repurchase 13 million common shares for $405 million.

During the first quarter of 2005 approximately $450 million of cash was used to repurchase $416 million of par value high yield bond.

Of the $416 million of par value repurchases 375 million was associated with the preferred offering call back and the remaining $41 million was through open market purchases which I will discuss in a moment.

During 2004 we established our target capital structure as you can see on the bottom of slide 23.

By year-end we achieved this target largely due to the nearly $1 billion of consolidated debt that was removed from the balance sheet throughout the sales.

As you can see on the upper graph, consolidated debt declined in the first quarter 2005 with the repurchases of the high yield notes and further declines in 2005 are planned as we complete the sale or transfer of other remaining non-core assets.

As noted earlier, during the first quarter of 2005 we repurchased $41 million par value high yield notes at an average all in cost of about 108.

As you can see from the chart on slide 24, at the time of our repurchases bond prices had softened.

We quickly responded by making these open market purchases.

These buybacks will reduce annual cash interest expense by approximately $3 million a year.

We will continue to repurchase our debt and equity as market opportunities arise.

Repurchases of our debt and equity are limited to the available capacity of our restrictive payments basket as governed by our debt indentures.

Before moving to the 2005 guidance discussion, I will briefly provide some additional information on our quarter and full year results.

On slide 25 is the breakdown of operating revenues for the fourth quarter and full year by type and by region.

For the fourth quarter operating revenues were $581 million net of $6 million in fresh start amortization.

For the full year operating revenues totaled $2.4 billion, net of $35.2 million of fresh start amortization.

By region, the northeast had the majority of the operating revenues contributing 56% of the total in the fourth quarter and 53% for the full year.

The northeast and Australia's full year result benefited from extreme weather conditions during the first quarter of 2004.

South central had a strong year operationally with record highs for generation and net capacity factor.

Slide 26 shows the components of the cost of operation.

For the fourth quarter the total cost of operations was $428 million, for full year 2004 $1.7 billion.

Fuel cost was the largest component of the total operating cost.

The delivered cost of coal consumed by our North American generation fleet for the fourth quarter was $33.24 per ton or $1.80 per million BTU.

While in the northeast the average cost was $45.96 per ton or $2.15 per million BTU.

The coal cost in the northeast for the fourth quarter were essentially flat compared with Q3 despite the increasing market prices, particularly of eastern coal.

This is due to our increasing reliance and thus higher mix of PRB coal as PRB coal's prices show less price volatility versus eastern coal prices.

During the fourth quarter coal cost in the northeast reflected a blend of delivered PRB coal of $31.71 and delivered eastern coal of $58.20.

The overall lower cost for North America are due to large ends use of 100% PRB coal and the increased blends of PRB coal at our eastern facility.

The Company's North American operations consumed 2.7 million tons of coal during the fourth quarter of which 77% was PRB.

For the full year 2004 coal consumption was 11.7 million tons of which 74% was PRB.

The average cost of gas FOB supply point burned across North American plants in the fourth quarter was $8.06 per million BTU and $7.14 per million BTU for the full year.

Maintenance and other operating expenses for the fourth quarter and full year were 175 million and $696 million respectively.

During this shorter quarter increased maintenance is typically performed at plants and resulted in an additional $17 million in maintenance related expenses compared to the third quarter.

Other operating expenses benefited from the previously mentioned $12 million in property tax credits and the $7 million settlement with a third party for auxiliary power costs.

For the year other operating expenses benefit from nearly $35 million in property tax credits.

G&A expenses on slide 27 show the fourth quarter expenses were $75 million bringing the full year G&A expense total to $211 million.

G&A expenses increased over the course of the year due to the staff build up for the corporate relocation, $12 million in bad debt provision related to notes receivable, costs associated with our Sarbanes-Oxley work and the external audit, and outside legal costs associated with international litigation and international tax planning.

Non-recurring charges included FAS 146 costs, reorganization items and restructuring and impairment charges.

Further disclosure related to these items are included in our 10(K).

We expect our total G&A to decline from $211 million to $181 million in 2005.

The decline results from the lower bad debt expense, completion of the relocation and reduced staffing.

On slide 28 there's additional detail on our equity earnings.

Fourth quarter equity earnings were driven by West Coast Power, our partnership with Dynegy.

West Coast Power, net of $26 million in CDWR contract amortization, had fourth quarter earnings of $24 million.

For the full year West Coast Power's results totaled $69 million net of $116 million in CDWR contract amortization.

Equity earnings from our Enfield investment for the year totaled $28.5 million including $23 million of unrealized gains.

These unrealized gains resulted from changes in the fair value of this project's natural gas supply contract which does not qualify for hedge accounting under FASB 133.

As we have mentioned in the past our Enfield investment is being marketed for sale in 2005.

I don't have slides on the remainder of the P&L.

However I will cover a few other key points.

Other income for 2004 included approximately $72 million of refinancing charges associated with the first and fourth quarter refinancing transactions.

The first quarter refinancing charges of $30 million include a 15 million of prepayment penalties and $15 million of write-offs of previously deferred financing costs.

The fourth quarter included $42 million refinancing charges.

Prepayment penalties were 14 million the remaining balance was the write-off of previously deferred financing costs.

Cash interest savings in 2005 resulted from the December, 2004 refinancing, will exceed $13 million.

The effective tax rate for the fourth quarter was 1.4% due to the low domestic earnings and the taxes associated with the foreign equity earnings.

The 2004 full year rate was 27.8%.

At this point I would like to shift the discussion to 2005 guidance.

Slide 29 provides a bridge between the actual 2004 adjusted EBITDA and the 2005 guidance.

Most of these items have been discussed with you on previous calls.

Key year to year changes include the expiration of West Coast Power CDWR contract, the sale of certain assets in 2004 and 2005, a conservative view on property tax credits in 2005, an increase in operating expenses mainly due to increase in scheduled outages and the continuing PRB conversion.

Finally, as noted during the call, $60 million of 2005 sales have been recognized in 2004 results.

Sensitivities to our 2005 guidance for adjusted EBITDA are set forth on slide 30.

Our adjusted EBITDA guidance excludes unusual or nonrecurring events and assumes northern weather patterns in our core market.

Adjusted EBITDA excludes the favorable impact of the collection of the TermoRio note receivable during February of 2005.

It also excludes the $60 million mark-to-market gains realized in 2004 but attributable to 2005 sales.

As you can see the Company has substantially hedged the downside risk to the 2005 gross margin.

Slide 31 is our guidance for 2005 cash flow from operations.

Our cash flow from operations will again be substantial in 2005, $463 million including the collection of the TermoRio note.

In summary, 2004 was a year of significant achievement for NRG shareholders and employees.

The foundation has been set which this Company can build upon.

With continued and relentless focus on the balance sheet, the operations, the business profits and prudent investments, we look forward to a successful future.

I will now turn it back to David for final thoughts on the year and the Q&A session.

Thank you, Bob.

I am going to open the lines for questions in just a couple of minutes but I would just like to make one more point and it's not the type of point that a CEO normally concludes a presentation on.

I tell you, these investor calls are somewhat frustrating to Bob and myself in that we only have the time to give you a small glimpse of the workings of this Company.

And that glimpse by tradition is overwhelmingly focused on our near-term financial performance.

What we have trouble getting you a sense of is what the Company has actually been through.

During 2004 all levels and all divisions of NRG were engaged in our Herculean change management exercise.

We had a new CEO and a new board of directors which began at the beginning of 2004, a new CFO in March.

A complete reorganization of senior management responsibilities in April; a new auditor in May; and a corporate relocation that began in August and was completed in December with a 30% reduction in corporate staffing and an 80% changeover in headquarters personnel.

This entire exercise in corporate change management was carried out under the unrelenting and unforgiving glare of Sarbanes-Oxley 404.

Judging from the absence of inquiries which we have received through our Investor Relations group, our corporate change management exercise has been of only moderate interest to our investors and our struggles with Sarbanes-Oxley have been of no interest whatsoever.

But the fact is that the new NRG, under the extraordinary circumstances of 2004, received a clean Sarbanes opinion should be important to you.

Because not only is it a testament to the extraordinary effort and effectiveness of the NRG professionals who led our Sarbanes compliance effort, and those people were Jim Ingoldsby, Barrat(ph) Shaw and Patty Helper.

But it's also a testament to the other 2,641 men and women who work at NRG and who were involved in Sarbanes compliance.

And that is the part that I think should be important to you.

Invest in NRG not because we comply with Sarbanes-Oxley but because our Sarbanes-Oxley success in the face of almost insurmountable odds demonstrates what our Company can accomplish when we work together openly and candidly all as one team.

And with that I would like to turn it back to you, Diego, to open the lines for questions.

Thank you. [Caller Instructions].

Our first question comes from Brian Chin with Smith Barney.

Please state your question.

Hi, David and Bob.

A question for you, Bob.

Has the recent change in interest rates changed your thinking on what to do with regards with covenant debt and your balancing the low rates on that debt versus the covenant?

Can you talk about that a little bit?

Well, our debt structure at this point in time, we've got the senior refinancing that we put in place at the end of the year, obviously significantly lowered the cost but it is floating rate debt.

The high yield debt which we recently had some repurchases of, is more -- is obviously is fixed.

But I think where we are on our debt is pretty much where we are going to be in the near-term a while.

If we see some real softness in the high yield sector we may pull some more back in.

For the time being we are going to stick with the capital structure because we are right in our sweet spot at the moment.

I really don't see changing much of anything on the debt side at this point.

And then you -- David, you mentioned -- you outlined a couple of potential uses for cash in your chart that showed cash out at El Segundo, brownfield over at Big Cajun.

Can you discuss a little bit how you would be financing any West Coast Power investments, especially El Segundo?

Some clarity maybe on your relationship with Dynegy, how they may be playing in a part of the picture?

On the West Coast Power specifically, our relationship with Dynegy remains as strong as ever.

We are working on the El Segundo repowering with them.

Actually, quite frankly, under their leadership since we are the operator and they are the commercial window of the partnership and there's really no daylight between us and what our objectives are.

The El Segundo repowering, which would not be a cheap plant to build being in the Los Angeles basin, it's going to require a long-term offtake agreement which basically reflects the value that that generation would have coming with high efficiency from that site.

So we would expect that a substantial portion of the capital for El Segundo powering or for the fourth unit, the occasion would come from this traditional type of nonrecourse project financing associated with long-term offtake agreements with credit worthy entities.

So I guess when we are talking about the long-term offtake agreements, can you also just segue on to RMR contract status with Edison out there or any other players out there?

That will be my last question.

I'm sorry, Brian, could I segue to what?

The status of any RMR contracts with Edison or any of the other players out there?

I think we are still waiting for the status of contracts on the West Coast Power

For the existing units at El Segundo we signed a short-term agreement with Southern California Edison for the last seven months of this year, which causes the RMR status to revert from condition two to condition one and gives them dispatch rights with respect to the plant.

But that's only a seven-month contract.

Gotcha.

Thanks a lot, guys.

Thank you, Brian.

Thank you.

Our next question comes from Brian Taddeo with Bank of New York.

Please state your question.

Good morning.

Congrats on a good year.

I've just got a couple of things.

First, you talked about capacity factors at the coal plants, can you give us an idea for 2004 for the fourth quarter what those capacity factors were on each of the facilities?

Yes, Brian, at Indian River the capacity factor in Q4 was 35%, Huntley 42, Dunkirk 61, Somerville 63, and Big Cajun II was at 78 for the fourth quarter.

Do you have it by chance for the full year?

I do.

Indian River 46, Huntley 51, Dunkirk 67, Somerville 71, Big Cajun II 81.

Great.

Just a couple other clarifications.

Can you confirm how much in the fourth quarter of the West Coast Power EBITDA was cash?

I think there's always some non-cash items in there.

There is. [Inaudible] it will be clearer.

In the fourth quarter the equity earnings of 24 there is amortization of 26.

So the EBITDA for the fourth quarter for West Coast Power is 50.

The EBITDA for full year West Coast Power, 185.

The cash for West Coast Power comes in pretty much evenly over the course of the year.

And the cash that came in during 2004 was just under 120.

Okay.

Perfect.

One last thing.

Just to confirm for the 2005 adjusted EBITDA number you gave, the 560 does include 70 million for the first quarter settlement, is that true, did I hear that correctly?

The 560 we excluded any impact of the TermoRio collection.

There is $56 million on our balance sheet as a receivable.

So in our P&L for the first quarter 2005 you will have a favorable impact of about $13 million pretax on earnings and then a $70 million benefit in your cash flow.

And again we excluded that benefit of the difference between the 56 and the 70, we excluded that in the adjusted EBITDA number.

Perfect.

Thank you very much.

Thank you.

Our next question comes from Ryan Watson with Stanfield Capital.

Please state your question.

Can you give some guidance for CapEx for '05 by any chance?

And I guess additionally just looking at your guidance, being that you were able to refinance the debt at Flinders and MIBRAG, do you think that from looking at your EBITDA is that just sort of like a whole co EBITDA so that if you refinance the debt and you're getting more dividends up from those two entities wouldn't that actually boost your year-over-year levels in '05.

Let's take the CapEx question first and I will go back to the MIBRAG and Flinders.

On CapEx our spend would be about $130 million.

Of that 130, approximately $50 million of that is for environmental.

The remainder is primarily for maintenance spending.

On the question regarding MIBRAG and Flinders, we had the EBITDA as kind of -- as kind of the whole Company EBITDA look and you could have cash distributions that actual exceed that.

So, you're right, we might be understating it a little bit from a cash flow standpoint.

Take Flinders as an example.

With the refinancing it took $50 million of cash from restricted to unrestricted.

And at MIBRAG by doing the refinancing we could now do a distribution in 2005 of about 11 million Euro.

So we will be getting cash benefits from these refinancings.

Okay.

And thank you.

On page sixteen the capital allocation, I just wanted to understand this a little better.

If you do cash flow from operations of -- if you take your guidance and then you kind of less out CapEx, it's sort of like a rough free cash flow number, as I see it.

What are you looking at, with 16, is 130 to 150 of that free cash going to debt and equity holders and then 200 going to reinvestment?

Is that right?

No, that's what David illustrated on that slide is the basket -- any time we want to take cash and distribute it back to shareholders or repurchase debt or make any other type of restrictive payment, like our preferred dividends, it comes out of a restricted payments basket which in simple terms is $50 million plus 50% of retained earnings plus any issuances of equity.

So what David is saying there is that we have a basket range based upon third quarter numbers at that time of 130 to 150.

At year-end we went really deep into the calculation as we have to.

And where we put in the adjustments for cash distributions you can add back things like extinguishment of debt.

Our actual basket size at the end of December was $165 million.

Now, in the first quarter 2005 we have used about $45 million of that basket that would be available for future uses for restrictive payments.

Again, examples are repurchases of debt, purchases of stock, dividends, preferred dividends and the like.

So it recharges over time with net income.

But that basket, what David had on that slide on page sixteen, was to give you an approximate size of what that basket is.

It's important to note that we have not earmarked 130 to 150 million to return to debt holders or equity holders or 200 million to reinvest in the business.

Those are just the constraints that we currently have.

Okay.

Now if you look at the free cash flow, cash flow from operations less CapEx, there is a free cash flow sweep I believe for your term loan, right?

So you can use some of that cash to just pay down the term loan.

Is that not correct?

The first time that the cash sweep comes into play is in March of 2006 and the cash sweep is at the options of the banks, that does not go against this basket.

Would you be looking to reduce that though, through free cash flow?

We would consider it, I mean we will constantly look at the balance between our capital structure, where our debt is trading at, where our equity is trading at, or depending on the movement of interest rates, does it make any sense to pay down some of the senior facility.

We would look at that and consider it as part of the overall capital allocation.

Okay, thank you.

Thank you.

Our next question comes from Eric Beaumont with Copia Capital.

Please state your question.

First, to reiterate in the earnings step through for West Power you obviously don't have a CDWR contract but it king of looks like you're really not assuming anything for West Coast, is that accurate, and what prospects do you see on the West Coast this year?

Well, on the financials as you saw on the bridge year-over-year, I think we had the difference of being 177, that was on the slide.

And the actual EBITDA for 2004 was 185.

So we've included about $8 million of EBITDA for the West Coast in 2005.

As far as upsides I don't think we see much upside in that in terms of the -- David mentioned that we've got the contract we entered into with Southern Cal.

We maintain a condition one RMR for El Segundo.

The upside, I think, in 2005 will be the cash distributions that we get from West Coast Power.

They will exceed the EBITDA and included in our guidance we had targeted $30 million in cash distributions during 2005 which we are looking and reviewing that now but we feel pretty confident that we will be getting at least that 30.

Eric, I think it's fair to say that we don't -- we are pretty sanguine about the prospects of West Coast for 2005 but more bullish for 2006 and beyond in part just because of the supply demand fundamentals out there but also we think the constant move towards changing the market design and the introduction of the resource adequacy requirement that comes into effect, I think, on June 1, 2006.

So we are not expecting great things from West Coast in '05 but more bullish for subsequent years.

One more thing.

On slide 27 you talked about the G&A declining by 31 million then going over to slide 29 where you are doing the bridge.

Is that showing up in the increase in gross margin or where does that show up?

I was also curious about the gross margin increase being only 10 million given the -- some of the hedges and elsewhere after you outlined your coal thoughts.

Could you go through that quickly?

Yes, the other operating costs imbedded in that $18 million in that bridge is the impact of the G&A.

So that's mixed in with total other operating costs for the Company.

So it's imbedded in that number.

And the increases in gross margin is only $10 million shown on that slide but remember you have $60 million that had come out of that number because of the mark-to-market adjustment that we had.

Okay.

Thank you.

Thank you.

Our next question comes from Ben Gamble with Trafela Company.

Please state your question.

Good morning, guys.

Just a question, kind of get on kind of looking at the Company as a whole and given the past history of the Company with several operating groups and numerous kind of independently run facilities, would like to see if you guys could comment a little on the opportunities you guys see in paying increased attention to running the facilities as a combined entity in terms of procurement and things like that.

And if you would just talk a little bit about what you guys are working on on that front and the opportunities you see right now.

Ben, I think -- in a lot of way you've described the opportunity.

You're right, I think that the old energy was -- the acquisitions were done so quickly and the sort of ethos to the Company was to move on to the next acquisition.

We do still see a fair amount of ability to get cost savings and really performance improvements by working more as -- operating a Company more as one, as one portfolio.

In terms of how much we think we can achieve in that regard it's really a little bit premature because we've just launched that effort within the last couple of months and we've got a team in our operations group that are going through and we hope to be able to provide more considerable amount in more detail when we next -- at our first quarter announcement which I believe is May 11.

So I would rather just leave it that we've started up, I really would rather not get into quantification or specifying what exactly is it that we would be doing because we are still developing it.

Okay.

Great.

Is it fair to say that the numbers on page 29 may change substantially, particularly the numbers lower than the gross margin line?

I guess that's totaling about $100 million at least now that that would obviously have a large effect on that number?

Sorry, Ben.

Could you repeat that, Ben?

I was just seeing if any of that is included in your guidance on page 29?

No, Ben.

The opportunities that we see there while we were early -- we are still formulating how to go after the different opportunities that David just discussed.

We had in there only to the extent that we have things already in place.

Like for example PRB conversion where that brings some cost advantages built in but the more integration type of benefits that we have is an upside.

Okay, great.

Thank you.

And I just had one additional question on this quarter on the interest expense.

How much of that was duplicative, I guess, would be the word in terms of the 73 million in interest this quarter.

The 73 million in interest charges?

Right.

The prepayment premiums?

We had $42 million of , I'll call it interest expense that is non-recurring because of prepayment penalties and write-off of the deferred financing costs and the like so on an ongoing pure cash basis 42 won't have been there.

Okay, great.

Thank you.

Ben, can I go -- just to make clear for everyone sort of referring back to your previous question and if people look at the slide that sort of shows the growth initiatives that I referred to, there is no -- there is no quantification of what those initiatives might achieve in our guidance for 2005 in any of the four areas which I outline.

Got it.

Thank you.

Thank you.

Your next question comes from Daniele Seitz with Maxcor Financial.

Please state your question.

Thank you, good morning.

I just was wondering do you have any estimates for the Big Cajun II unit four, total cost and when do you anticipate that the, assuming you [inaudible] this project, when would you say the construction would start in ernest?

Well, Daniele, the total cost estimate is still being worked out but it's fair to say with the cost of commodities these days, steel and the like, the cost of a super critical coal fired unit, even one of scale with all best available control technologies is extremely expensive these days.

Between 1500 and $2000 per KW on a total cost basis, hard cost, and soft cost including interest during construction.

That's still a fairly wide range and I can't really give you a more specific number yet.

As to when we would be willing to be able to break ground.

Well that's going to depend on the pace of getting the commercial offtake arrangements in place and the non-recourse debt financing.

I would say certainly not before the end of 2005 and certainly the window that we are shooting for is end of 2005 to first half of 2006.

Great.

Thanks a lot.

Thank you.

Our final question comes from Mitchell Spiegel with Credit Suisse First Boston.

Please state your question.

Just looking at the '04 segment breakout in EBITDA, looking from Australia to the right of that slide.

When you look at '05 is it reasonable to assume that the EBITDA contribution from those segments should be essentially flat year-over-year and that the Delta really in -- the biggest Deltas obviously occur in West Coast Power and northeast in '05?

Australia is heavily contracted in '05 and the difference year-over-year, although you do have more generation capacity in '05 than '04, but in our planning and our guidance numbers the difference between the two years is pretty small.

What about in the other international nongen segments?

The other North America really goes down because Kendall had $42 million of EBITDA in 2004 results.

Also included -- other international also included Enfield which had $28 million of EBITDA in 2004.

And that could go away somewhere in the first half of 2005.

Okay.

And then my last question is on the 350 million LC facility, that's cash back, is that on balance sheet or off balance sheet?

On the portion of the term loan?

You are talking about the $300 million?

350 cash collateralized LC that was funded off the term loan are you showing that on or off balance sheet.

It's on balance sheet.

Okay.

Thank you.

Okay.

Thank you.

Mr. Crane, I will now turn the conference back over to you to conclude.

I would like to thank everyone for joining us and for your continued interest in NRG and we look forward to speaking to you at our next earnings call on May 10.

Thank you very much.

Thank you.

This concludes today's conference.

Thank you all for your participation.