NRG Energy Inc (NRG) 2005 Q1 法說會逐字稿

Greetings ladies and gentlemen, and welcome to the NRG Energy first-quarter earnings results conference call.

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

A big question-and-answer session will follow the formal presentation. (OPERATOR INSTRUCTIONS).

As a reminder, this conference is being recorded.

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

Thank you Ms. Azmy; you may begin.

Thank you.

Good morning and welcome to our first-quarter 2005 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 1 hour.

In the interest of time, we ask that you please limit yourself to 1 question and 1 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 filings with the SEC that could cause actual results to differ materially from those in the forward-looking statements and the press release and this conference call.

In addition, please note that the date of this conference call, May 10, 2005 and any forward-looking statements that we make today are based on assumptions that we believe to be reasonable and 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 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.

Today as usual, I'm joining giving this presentation by Bob Flexon, our Chief Financial Officer.

Bob and I will follow the same structure of presentation that we've used for the previous 4 quarters.

I will lead off with updates and comments on a few of the first quarter '05 financial operational and transactional highlights.

With Bob following with the more detailed review of the first-quarter numbers.

However, before Bob hands it back to me for concluding remarks and Q&A, as we have done in the past, you will hear from the Head of our Domestic Plant Operations, Christine Jacobs.

Christine will speak to you about our costs and performance improvement program, which we call F.O.R.

NRG, which we are making public today.

By way of background, Christine is a process control expert.

We recruited her away from Aeromark in the fall of 2004, precisely so that she could develop and then implement a comprehensive program and a cost and process improvement across both our fleet of generating assets and our administrative facilities.

Few, if any of you, would have met Christine before because she's been very focused on developing this initiative over the 8 months since her arrival.

While a lot of hard work remains ahead to implement fully and eventually expand this initiative, I'm very pleased in the progress that Christine and her team have made, not only in developing F.O.R.

NRG but also in beginning its implementation.

With that, I'd like to move into a brief discussion of our financial business and operational highlights.

So if you turn to slide 4 in our presentation, our adjusted EBITDA result for the first quarter was $154 million, down from last year's $257 million.

A substantial portion of the year-on-year negative delta was due to the contraction of the portfolio and the loss of the CDWR contract at the end of '04.

However, even on an apples-to-apples basis, we had reduced gross margin on nearly identical total domestic energy sales -- as peak pricing events were neither as deep nor as long during our winter or the southern hemisphere's summer, as they were during the first quarter of 2004.

With respect to cash, our cash flow from operations in the first quarter was $64 million.

This result was affected by higher margin calls associated with our hedging program, which was much more active this year than in the first quarter of 2004, at a time when the Company had just emerged from Chapter 11.

And on the liquidity front, we were able to continue the improvement in our key liquidity metric, net debt to total capital, which we reduced by approximately another 100 basis points during the quarter.

We now face a situation where it might be argued that we are mildly under-levered, which I believe is an extraordinary place for a company like ours to be just 16 months after emergence from Chapter 11.

As a continuation of our focus on cash, we completed a couple of important transactions in the quarter that we have been working on for almost my entire tenure at NRG.

In both cases, the sale of Enfield and the collection of the TermoRio arbitration award, we resisted the desire to sell or settle sooner.

In both cases, by working harder and longer on what proved to be deceptively complex transactions, we achieved better results for our shareholders -- an aggregate contribution of an additional $134 million in cash proceeds.

It was a great effort and an outstanding result led by Bob Henry and his asset management team.

I will leave the discussion of the two capital market exercises listed on this slide to Bob Flexon.

So if you turn to slide 5 of the presentation, and if you just focus on the box in the lower right hand corner -- safety first is a core value at the new NRG.

And while I'm thankful that not one of the 2,600 men and women who work at NRG were badly hurt during the first quarter of '05, our OSHA incident rate for the first quarter crept up above the industry average.

This is not acceptable.

We are taking several measures to reinforce our safety first message, and we will be unrelenting in our focus on this area.

Operationally, we had a good quarter.

For the fifth quarter in a row, we made year-on-year improvement in our equivalent availability factor.

Notwithstanding the capacity d-rates at our Huntley and Dunkirk plants associated with full PRB conversion.

Our PRB conversion program is proceeding at full tilt.

At this point, we are burning 100% PRB coal at both Huntley 67 and Dunkirk 4.

By the end of 2005, we expect to be fully converted to PRB at 5 of the 6 units at Huntley and Dunkirk.

The two units, which are already fully converted, have been partially d-rated to avoid certain operating and maintenance issues.

But our engineers remain cautiously optimistic that most if not all of that d-rate can be recovered.

And that is why the higher value initiatives that constitutes part of the F.O.R.

NRG program.

Arthur Kill in New York's own Jay (ph) and Norwalk Harbor in the Southwest Connecticut zone of NEPOOL also had extremely strong operating results in the quarter.

And we appreciate the contribution they made to the overall group result.

Now turning to slide 6.

We have made reference in the past of our intent to increase the scope and effectiveness of our trading, marketing and hedging operations in our domestic market, particularly in the ISO markets of the Northeast.

This is a topic, which I expect to come back to in greater detail later in the year at future quarterly presentations.

To-date, we continue our very methodical build-up of the pace and breadth of our commercial operation activities.

During the first quarter, our principal focus remained on dynamic hedging of our existing asset fleet, locking down our coal supply and transportation requirements for the medium to long-term and seeking to unlock more of the intrinsic value of our gas supply and transportation needs.

In terms of merchant energy sales, during the first quarter, we hedged a significant portion of our economic generation in PJM at prices above the clearing price for energy at the BGS Auction, which was held this February.

In terms of merchant capacity sales, we hedged our New York City summer capacity at the mitigated price cap of $10.68, which actually is $0.37 higher than the summer '04 mitigated price cap due to adjustments to the capacity demand curve that were recently approved by FERC.

In terms of gas transportation, during the summer season when transport to the Northeast United States is not constrained, we are contracting forward for gas transportation in order to better balance our Northeast fleet and allow us to respond Intraday to spot electric sale opportunities.

Like many of our initiatives implemented to-date in the commercial operations area, this initiative is intended more to take risk out of the commercial operations of our portfolio than it is to increase profit.

Now turning to slide 7.

During the month of March, dark spreads were pushed substantially upward by higher crude oil prices.

Throughout that month, we took advantage of the rising dark spreads to substantially hedge the balance of year '05 and calendar '06 economic generation from our coal-fired fleet.

As the quarter ended with dark spreads at a peak, these new hedges yielded the mark-to-market loss referred to in our press release.

As dark spreads have fallen back during April, much of that mark-to-market loss has already been reversed.

Accounting rules require some of these hedges to be accounted for on a mark-to-market basis.

But it is important to remember that these transactions are executed against generation assets that are not accounted for on a mark-to-market basis.

As the forward market moves up or down, both the value of the generation and the hedges will increase or decrease.

However, the difference in accounting treatment results in earnings swings, as the change in hedge values are recorded in current earnings, while the change and value of the generation assets will be realized at delivery.

I should also note that this graph shown on slide 7 is intended to show trends and does not include all detailed cost for any particular coal-fired generation facility.

Now if you turn to slide 8, you will see the proportion of our coal-fired generation hedge in our Northeast and South Central portfolios and our positions with respect to the associated coal supply and transportation requirements.

As you know, eastern coal prices have softened slightly recently after having increased significantly over the past year, while PRB prices have increased significantly just in the past 2 months.

We have reduced the impact of these coal price movements in four ways.

First, we have reduced our reliance on eastern coal to around 11% of our coal purchases through our PRB conversions underway at the Huntley, Dunkirk, and Indian River stations for calendar '05.

By 2006, we expect our eastern coal burn to be reduced to 6% of our total tonnage.

Second, we have actively hedged much of our commodity risk at attractive prices with a variety of producers and resellers.

In fact, 96% of our coal is hedged this year, 92% next year, and 54% in '07.

We have also hedged 45% of our 2008 and our 2009 coal requirements.

All of these contracts were entered into before the recent surge in PRB coal prices.

Third, we have hedged 100% of our coal transportation through long-term agreements at attractive rates consistent with historic norms.

These transportation agreements range in term from 3 to 10 years.

And fourth and finally, we've entered into long-term railcar leases to ensure that we have the cars necessary to transport coal to our plants.

As you may know, we will take delivery of 1,540 new railcars this year, and we have already received 960 of these cars.

As a result of our efforts to hedge coal, commodity and transport risk, we have very minimal downside potential through '06 and manageable exposure in the '07 through '09 timeframe.

In addition, by working with the railroads and barge companies, we have done an excellent job in rebuilding an adequate supply of coal at our plants.

We have currently have on average approximately 30 days coal stock across all of our coal plants and expect to maintain between 15 and 30 days supply at each plant going forward.

Now turning to slide 9.

As you know, over the past few months, we have added a focus on growth to our continuing focus on operational excellence and our prudent balance sheet management.

To reiterate again, growth at the new NRG is not simply about accumulating megawatts or "bragawatts" as it was once put to me.

Our focus is always on value enhancing growth, as measured by increasing net cash flow, earnings and improved return on investment capital.

We have previously shown this slide 9 to indicate our four drivers for improved financial performance.

At our last quarterly call, which was just 6 weeks ago, we focused on the most headline grabbing and capital intensive of these -- ground fuel development and the potential addition of complementary assets to our portfolio in a variety ways.

Today, we will focus on two of the other growth drivers in the cost control and plant performance areas.

As I mentioned earlier, Christine Jacobs will present on this area in a few minutes.

I don't want to steal her thunder, given that this is an area, which she has worked hard on for several months and has so ably led.

But I do want to make one point.

F.O.R.

NRG is a dynamic, living initiative.

And what we are announcing today will be not the end of it, but it is a very substantial and meaningful start.

Now, turning to slide 10.

There is one other area of potential financial growth, which does not appear on our own growth plan because we can only influence the result indirectly through education and awareness.

What I am speaking about is the absolute essential development of locational (sic) capacity markets in one form or another in the deregulated wholesale generation regions.

There is, in our opinion, an increasing awareness among regulators, energy policy makers and even major energy consumers that certain regions in the United States -- there is a critical growing need for new investment and generation.

This is especially the case in densely populated, difficult to permit areas of New York, New England, California and the mid-Atlantic states.

We're convinced that FERC and the ISOs of these regions are committed to market reforms that will support needed competitive investment with fair returns on those investments.

Increasingly, the trend among stakeholders is evolving towards the adaptation of structures similar to New York's successful LICAP model.

NRG is at the forefront of advocating for and helping design capacity markets that recognize the needs of various stakeholders.

Our existing portfolios in these regions is at present under-compensated for in terms of its locational value.

As such, current market structure does not support its making substantial capital investment to ground fuel development at these sites.

However, we're confident that over the next few years, various market structures will be implemented that provide adequate compensation to us for the location of our existing generation and to allow the building of additional generation.

With that update, I would like to turn it over to Bob Flexon.

Thank you, David, and good morning.

I will provide you a review of our first-quarter results and a revised outlook for 2005 adjusted EBITDA and cash flow from operations.

Slide 12 provides a financial summary of our performance for the first quarter of 2005.

Operating revenues for Q1 2005 were $601 million, in line with Q1 2004 revenues.

Energy revenues accounted for $402 million versus $383 million in Q1 '04.

This $19 million increase was primarily due to $29 million increased merchant revenues from our Arthur Kill plant, of which $10 million was from increased prices and $19 million from higher generation -- up for the $12 million increase in merchant revenues from higher generation at Oswego and our NEPOOL assets.

And $5 million higher energy revenues from our domestic coal operations with higher generation at Indian River and South Central, offset by lower generation from our western New York plants.

These increases were offset by $22 million in lower energy merchant revenues from our Australian operation, as unseasonably mild summer weakened power prices to an average $23.26 per megawatt hour, as compared to $40.33 per megawatt hour in the first quarter of last year.

Additional offsets included capacity revenue decrease of $5 million versus last quarter.

While we saw $23.9 million in additional capacity revenues from the Connecticut RMR settlement, we also have made the sale of Kendall and decreased capacity revenues from our assets in western New York.

Revenues were also impacted by the $39.5 million in unrealized mark-to-market losses.

Subsequent to quarter-end, forward prices softened during April, reversing nearly $28 million of the mark-to-market loss recorded in the first quarter of 2005.

Net income for the quarter totaled $22.6 million, as compared to $30.2 million in the first quarter of 2004.

In addition to revenue fluctuations, the largest quarter-over-quarter change is in the cost of majority-owned operation.

Cost of majority-owned operations increased by $71.2 million. $59.5 million was due to increased cost of energy, primarily at our domestic operations.

Higher fuel costs included $20 million in increased coal costs.

The increase in coal cost was driven by Indian River and South Central facilities -- $17 million in higher gas costs due to the increased generation from Arthur Kill, as mentioned.

A $19 million higher fuel oil costs with $12.3 million due to increased generation from our oil generating assets.

In addition to higher fuel costs, our cost of majority-owned operations increased by $11.7 million for planned outages.

Our South Central, western New York and Indian River plants all have scheduled major outages in the first half of 2005.

The delivered cost of coal consumed by our North American generation fleet for the first quarter was $36.32 per ton or $1.94 per million Btu versus $31.39 per ton or $1.75 per million Btu for the first quarter of 2004.

The Company's North American operations consumed 2.9 million tons of coal during the first quarter, of which 77% was PRB.

In Q1 2004, total tonnage was 2.8 million tons, of which 70% was PRB.

The average cost of gas burned across North American plants in the first quarter was $7.32 per million Btu versus $6.49 per million Btu in the first quarter of 2004.

Adjusted EBITDA quarter-on-quarter decreased by $103 million.

The primary drivers of this decrease include $44 million due to the sale of Kendall and the expiration of the West Coast Power CDWR contract. $40 million mark-to-market lost in the Northeast region -- discussed earlier -- $15 million in lower regional margins, primarily due to unseasonably mild weather in the Northeast and Australia and increased fuel costs; $14 million increase in other -- in operating and maintenance expenses excluding Kendall; $14 million increase in general administrative costs, primarily related to increased audit fees;

Sarbanes-Oxley compliance and insurance costs.

These decreases in adjusted EBITDA were partially offset by a $21 million increase in equity earnings, excluding West Coast Power, primarily driven by Enfield a $15 million, including a $12 million mark-to-market gain at Enfield.

These adjusted EBITDA results do not include $13.5 million gained from the TermoRio settlement or the $3.5 million gained related to the Crockett Co-gen Project.

Slide 13 was prepared to illustrate the composition and relative volatility of our variable margins.

Contacted capacity margins provide a stable stream of earnings, 34% of total margins for the first quarter 2005.

These contacted margins are largely from our South Central and NEPOOL operations.

Contacted merchant energy has also provided relatively stable margins.

Our alternatives in thermal operations are the main contributors and provide a 10% of total margins in 2005.

Merchant capacity has also been fairly steady over the course of the past year.

Our New York assets, due to their locational advantage, are able to provide steady merchant capacity revenues with western New York realizing lower prices this quarter due to additional capacity and imports in the region.

Merchant capacity margins accounted for 16% of total margins in the first quarter.

The above components accounted for approximately 60% of the Company's variable margins during the first quarter.

The higher volatility is in our merchant energy margins and the other category, which includes the derivative and financial revenues.

Adjusted EBITDA by segment shown on slide 14 demonstrates the largest change quarter-on-quarter is in our Northeast region.

The $39.5 million mark-to-market loss impacted the Northeast results.

As mentioned a moment ago, higher fuel costs was also a significant factor.

In the Northeast region, as David highlighted, we continued to push to convert to PRB and other western coals.

In Q1 2005, our mix of PRB coal consumed in the Northeast was 49% of the total tonnage versus 37% in Q1 2004.

During the first quarter 2005, coal costs in the Northeast reflected a blend for delivered PRB coal of $28.94 per ton and delivered eastern coal of $69.64 per ton versus $28.02 and $48.62 per ton respectively in the first quarter of 2004.

Cash flow for the first quarter 2005 is shown on slide 15.

Cash flow in the first quarter before debt repayments and other financing activities was $154 million.

Given our robust liquidity, we repaid approximately $500 million in debt during the quarter, resulting in a net cash outflow for the quarter of $347 million.

Notable components of our cash flow in the first quarter included $56 million in cash interest payments.

This included interest paid on our Senior Credit Facility and project debt and $33 million in cash costs associated with debt repurchases over the course of the first quarter. $66 million in other non-cash items was driven primarily by $85 million add-back related to our hedging activity, with forward prices at a high point at quarter-end.

Unrealized losses, both in OCI and the P&L, were recorded.

$8 million add-back in deferred financing costs and debt premium and partially offsetting these add-backs was equity earnings, which exceeded cash distributions for the quarter by $31 million.

In April, we received a $50 million distribution from our 50% investment in West Coast Power partnership.

The working capital increase was mostly attributable to 124.5 million increase in pre-payments and other current assets to support our trading activity.

Collateral requirements will fluctuate throughout the year as forward power prices move.

And since March 31, 2005, approximately $39 million of cash collateral has been returned.

This working capital increase is partly offset by a $30 million net working capital decrease from accounts receivable, inventory accounts payable and other accrued liabilities.

Other cash used by investing provided $104 million of cash this quarter.

This includes the $70.8 million we collected from the TermoRio settlement and $34 million of restricted cash that was reclassified to unrestricted upon the completion of the refinancing of Australia's debt.

Cash used by financing totaled $501 million for the quarter.

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

Additionally, we repurchased $47 million of our Australia project debt, primarily using the restricted cash that had been freed up as part of the refinancing there.

Our liquidity on slide 16 reflects the change in net cash flow just discussed and remains strong at $1.2 billion.

Significant benefits to our liquidity since March 31st included the $63.5 million Enfield sale, the $50 million cash distribution from West Coast Power, and the return of approximately $39 million of collateral.

Cash and capital will be allocated to reinvesting in our existing operations and in growth opportunities that generate economic return, managing our capital structure to the targeted levels, and providing an efficient return of capital to our shareholders.

On the last point, returning capital to shareholders -- for example, share buyback and dividends -- are limited by the restrictive payment basket, as defined under our loan indentures.

This basket had a capacity of approximately $127 million at the end of the first quarter.

And while we project the size of the basket to grow over time, as our net income is realized, we intend always to maintain a cushion within the basket to ensure that we are allowed to service the preferred dividends on our existing shares on a timely basis.

We are actively evaluating our alternatives to increase the capacity of the restricted payment baskets.

As we have stated in the past, our target capital structure, as shown on slide 17, is to maintain a net debt-to-total capital ratio within a 45 to 55% range.

As of March 31st, we achieved a 48% net debt-to-total capital ratio, the lower end of our targeted range.

By year-end 2005, we expect net debt to decline further, possibly below targeted levels, as we generate positive cash flow and complete the sale or transfer of other remaining non-core assets and their associated non-supported debt.

Slide 18 updates our guidance for 2005 in the sensitivity that fuel price and interest rate movement.

We are raising our revised adjusted EBITDA guidance to $600 million from $560 million, as a result of the following. $17 million is due to extending the dates of certain asset sales; $12 million from the Enfield mark-to-market gain in the first quarter, not previously forecasted; and $39.5 million unrealized mark-to-market losses included in the first-quarter results.

As of April 30, 2005 due to market price movement, the unrealized losses decreased by $28 million.

The updated guidance reduces the mark-to-market loss to $12 million as of April 30, 2005.

These increases are partially offset by lower margins, primarily from South Central, bringing our revised adjusted EBITDA guidance to $600 million.

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 recorded in 2004 but are attributable to 2005 transactions.

Guidance from our cash flow from operations is nearly unchanged at $467 million.

While we have included a number of increases in our revised cash flow guidance, including $27 million of additional cash dividends from West Coast Power and the return of $39 million in cash collateral associated with our hedging activity, we have also included the net outflow of cash collateral since December 2004 -- resulting in little change to our cash flow guidance.

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

Using our updated adjusted EBITDA guidance and giving effect for the Enfield sale and the available letter of credit capacity, slide 19 provides a look at our total enterprise value.

Total debt associated with continuing operations is $3.2 billion as of March 31st.

Supported debt, defined as corporate-level debt, recourse debt and project-level debt of entities generating and distributing cash -- total $2.7 billion at March 31, 2005.

Cash associated with these entities and projects total $995 million.

Unsupported debt, defined as non-recourse project-level debt for which corporate does not provide cash support, totaled $582 million with $87 million of cash associated with these entities.

We continue to believe that the equity value of the Company is entirely attributable to supported projects.

Using our adjusted EBITDA guidance of $600 million, our stock is currently trading at an aviated (ph) EBITDA multiple of approximately 8.27 times.

Of the $60 million of mark-to-market gains booked in 2004, which relates 2005, are included in the calculation, the multiple drops to 7.45 times.

Slide 20 further refines the calculation on the prior slide for our equity investments in our Schkopau operations.

In 2005, we expect total adjusted EBITDA from equity investments to total $79.2 million from West Coast Power, Gladstone, MIBRAG, and a number of smaller investments.

These investments independently carry a certain amount of depreciation interest in taxes that carry through to our adjusted EBITDA calculation.

Adjusted for this and the related project level debt are implied share price for equity investments using the supported EV multiple -- is $6.94 per share.

Schkopau is a lignite coal-fired facility of which we own 41%.

Unlike other businesses, Schkopau's capacity is a long-term totaling arrangement accounted for as a capital lease obligation.

And as a long-term PPA with Vattenfall, which is accounted for as a direct financing lease.

Both the capital lease obligation and the financing lease receivable are recorded on the balance sheet at their present value.

The equity value of $286 million is derived by netting the present value of the asset against the present value of the lease obligation.

This amount divided by our outstanding shares results in a share value of $3.29.

The implied equity value for the remaining supported portfolio is $1.9 billion, which translates into an implied multiple for the remaining supported portfolio of 7.61 times.

If the 60 million mark-to-market gain from 2004 is included, the multiple is 6.69 times.

At the risk of overcomplicating the calculations, this should provide greater clarity around some of the questions we have been receiving of late.

I'll now turn it over to our Vice President of Operations, Christine Jacobs, who will discuss the F.O.R.

NRG initiative.

Thank you, Bob.

As David mentioned, I'm here to talk about F.O.R. NRG.

F.O.R.

NRG focuses on revenue and margin enhancement, not just traditional cost-cutting.

It is comprehensive in that it cuts across the organization to all plants and all departments.

F.O.R.

NRG is dynamic.

The goals are clear, but the project list is growing and changing.

We have taken a real process look at how we want the Company and our generation units to run.

While minimizing costs is always on our minds, performance and return on invested capital are the real keys to the future.

Let me begin with a few comments about the process we used to identify areas of improvement.

Within operations, we started with a unit-by-unit comparison of our major plants against those of our industry peers.

Each unit was judged on both costs and performance as compared to between 5 and 20 similar units run by other companies.

On the cost front, as might be expected for Company that was successful in coming through bankruptcy, we measure up quite well.

On the performance front, where we measure equivalent force outage rate, E4, and equivalent availability factor, EAF, we have lots of room to drive additional revenue and its associated margin.

We developed top-down goals for the plants, and they have responded with solid action plans.

I mentioned that we are comfortable with our overall cost position, but we're not satisfied.

Our program is not driven by simple cuts but rather by process improvements that enable us to maximize our return on invested capital, ROIC.

We have dozens of projects underway, so let me give you some insight into a few of them, including our goals, measurement tools, and general direction.

First, we intend to recapture a high percentage of nameplate capacity, as a way to contribute to bottom line growth.

Over the years, delayed maintenance, fuel changes, and other issues have caused some degradation in performance at our coal units.

For the 4 units at Dunkirk, 2 at Huntley, and units 1 through 3 at Indian River -- we regularly average less than 90% of full load.

We've set a target to consistently achieve 95% of nameplate load in the next 3 years through efficiency improvements.

This would return an additional 15 to $20 million per year in EBITDA by the end of 2008.

An ancillary benefit to this project is that we will also see some improvements to our heat rates through these efforts.

And a reduction in heat rate lowers our fuel costs per megawatt hour.

We expect that reaching full load will cause our average cost per megawatt hour to go down, as the number of megawatt hours generated goes up.

Essentially as we generate more and our fixed costs go down, so does our average cost of generation.

In some cases, we use fuel at a rate, which should get full load.

So without achieving this output, our heat rates are high.

Additional output will have the benefit of driving heat rates down.

Tube leaks are the plague of older power plants, and NRG's coal plants are no exception.

Our strategy for addressing this issue, while avoiding lost time, includes the following steps -- understanding and mapping previous leaks, comparing known problem areas in these units to others within our fleet, conducting nondestructive testing to determine potential problem areas, and finally, replacing targeted sections to the boiler on a schedule more conducive to enhanced efficiency.

Our efforts to map both our boiler repairs and weak spots will lead to smarter outages and less production lost and reduced E4.

Third, we are addressing station service.

When units are running, if we can reduce our own internal electricity usage, we can deliver more net megawatts.

When we are not running, we can conserve and reduce the amount we need to pay the local utilities.

Our Oswego plant has led the charge in this area, and we're continuing this process in our other facilities.

Some of our projects are about working smarter, while driving bottom line value.

This is demonstrated in my next example.

At more than one facility, we have a de facto permanent contractor fleet, and we're examining whether outsourcing this maintenance work makes the most economic sense.

Bringing this work in house will also give us the opportunity to re-power our workforce.

Our 10, 20 and 30-year plant veterans will be instrumental in training these new employees and provide an orderly transition and extension of our highly experienced plant operating teams.

We have launched major efforts in procurement.

Our non-fuel spend level is over $400 million per year.

In order to rationalize this number and drive value to the bottom line, we have developed processes and specific programs for all materials and services, and significant reductions are underway.

We're doing a similar review at corporate headquarters, where we will look at ways to reduce insurance costs, taxes and other corporate expenses.

All areas of cash outflow are being analyzed as part of F.O.R. NRG.

At NRG, this is not a short-term plan or a quick cost-cutting effort.

We are building these initiatives around long-range sustainability and stability and consistently high performance.

So what do these improvement initiatives mean for NRG?

The bottom line is that we see an annual $100 million run rate improvement in EBITDA by the end of 2008.

While we don't get the full impact over night, by setting goal and by identifying, implementing and tracking specific projects -- we will achieve this kind of improvement over time.

We are comfortable committed to the numbers we have shown you because we have the people, the plans and the determination to make them happen.

We are all doing this for NRG.

I look forward to giving you progress updates along the way.

Now, I would like to turn this call back to David Crane for his closing remarks.

Thank you, Chris.

And before I open the lines for questions, I just want to make one more point.

During this call, we have talked about -- to varying degrees -- the four growth drivers that we have underway here at NRG.

Growth through our own Brownfield development initiatives, growth through changes to our asset portfolios, growth through an increase in our own commercial operations activities -- and now as Chris just outlined -- growth through the F.O.R.

NRG program.

All of these growth drivers share one thing in common.

They're all areas where management and indeed the entire NRG team can have an impact.

These are things that we can control and manage.

And the point I want to leave you with is this -- we at NRG are not sitting around waiting for spark spreads to recover or hoping for extreme weather.

We recognize that our task is to create sustained profitability through all economic cycles -- and for that matter, through all meteorological conditions.

So with that Operator, we will be happy to take any questions that the listeners have.

(OPERATOR INSTRUCTIONS).

Brian Chin, Smith Barney.

Congratulations on a great quarter.

Question for you is -- can you give us a sense of where you are in terms of relaxing the cash restrictions?

Or what sort of decision points you're thinking of right now?

I noticed that you didn't really talk about that too much in your prepared remarks.

If you can give a little sense of color, that would be great.

And let's -- Bob start off.

And then, if I have anything to add, I will jump in.

And Brian, I am assuming you're talking about the restricted payments baskets --

Right.

-- that affects the amount of cash that we can put back to shareholders.

We are actively pursuing and investigating the alternatives around getting amendments and what these amendments would cost and what they would provide us.

In terms of what we think that we might be able to increase the capacity of restricted payments, we think we could add additional, approximately $150 million of capacity to the $50 million that is already in the basket plus again the net income component of that.

So we view that we can increase the capacity.

Now, it comes down to a question of cost.

And we are looking at what the amendment fees for that would be.

And certainly the more difficult one is the high yield notes, as compared to the first lien notes.

And the amendment fees are paid to 100% of the high-yield holders as well.

So if you're talking, 1, 2, 3% whatever. 1% would be a $13 million cost; 3% would be a $39 million cost.

It is somewhere probably somewhere in that range in terms of the cost to do it to get it additional capacity of about 150 million.

John Keane, Credit Suisse First Boston.

I like your "bragawatts" terms.

Yes, I wonder where I got that.

Can you discuss the uplift potential from LICAP pricing in New England coming in higher than the current RMR payments, please?

Right now, they are a range of possibilities being considered.

You know the schedule with the ALJ making recommendation in June.

We have some indications on page 10.

And I think there was a FERC action even yesterday in this regard, which reinforced the notion that -- that on the balance of probabilities, that we think where LICAP will come in relative to what we're currently getting under RMR would be in the base case that we would do a little bit better under LICAP in New England across our New England portfolio than we're currently doing under RMR -- where not all of our plants are under RMR.

Plus under LICAP, we have greater upside potential for actual price -- which would capture price events in the energy market.

So net-net, we are more confident than ever that the result of LICAP will be a little bit better than where we are currently at.

I think the second point that we tried to make is that we see more of a trend towards where we deem the New England LICAP as being very important because we see a bit of a snowball effect -- that if New England follows the New York structure, that it's more likely that PJM in California will adopt capacity structures, which are similar if not identical to New England and New York.

And that's also very important for the Company and its existing portfolio.

And then just one quick follow-up.

Is there any potential uplift from the fuel clause reset in the South Central load following agreement this year?

Say again?

Is there a fuel clause reset in the South Central load following agreement this year that could provide some potential uplift to EBITDA?

Well, I actually have got John Brewster here who runs that region.

And he will answer that question for you.

Please repeat the question -- the fuel price.

Yes, John, in the South Central load following agreement, it is my understanding that there is a fuel clause reset that could provide some type of incremental uplift to EBITDA?

Is that correct?

That is correct.

There was a contract fuel opener that took place on 6 of the co-ops of the 11 that's down there.

And those went into effect this year.

That is correct -- in April.

And John -- this is Bob -- that is embedded in our guidance.

Lasan Johong, RBC Capital Markets.

A couple of questions, first one question and then a follow-up.

First, some 160 -- about $163 million of cash of unrestricted cash in your balance sheet -- is a phenomenal number.

It's nice to see that somebody can make money around this business.

But the question is -- you haven't talked too much today about what kind of optionality (sic) this cash gives you in terms of what it can do for shoulder investments other than potentially share repurchases and dividends.

Could you address that?

And the second question, or the follow-up question is, the F.O.R.

NRG initiative on a $100 million EBITDA run rate seems like it is implying a $6 to $7 share price increase if all of that falls to the bottom line after taxes.

Well, Lasan, why don't I answer the first part of that question and turn it to Bob to answer the second part.

On the first part, I think it's a very good question.

And that is one of the challenges we face is that -- first of all, just doing a cost benefit analysis on how much it would cost us to put ourselves in a position where we had freedom to allocate our capital.

That is relatively opaque itself in terms of how much it would cost to get our bond indenture amended and what we would achieve in terms of loosening up the basket.

But the other side of the point -- and I'd say the more important other side of the coin is -- right now, it's still not clear to us because we basically just kick started in the last few months efforts to reinvest in our own business -- whether we have better opportunities to enhance shareholder value by reinvesting in the business either in terms of our existing assets or in terms of complementary assets to the portfolio.

And we've got the Brownfield developments.

We've got also El Segundo re-powering in Big Cajun and the fourth unit at Big Cajun, which are both in the final permitting processes and are now basically I would say involved in commercial structuring.

And just what the probability of success for those projects and other projects, including some of the projects in the F.O.R.

NRG program -- there's just not as much clarity today as there will be later in the year.

And so that's one of the reasons why we're moving very deliberately.

We want to make sure that we don't push the cash -- spend a lot of money to push all the cash back to the shareholders and find out that we would be in a better position to reinvest a good portion of it in the business.

Thank you for the question on the second part as well.

The $100 million of run rate of EBITDA improvements that I agree with your calculation, that certainly should generate that type of share price increase, all of the things being equal.

I'll even be more specific -- in 2005, as you may have noticed from the slide that Chris presented that we do have $30 million of EBITDA target planned to come in the 2005 timeframe.

Now that has been excluded from our $600 million guidance number that we put out a moment ago.

So we view that we've got some upside already in this year once we achieve that $30 million target.

I'm sorry.

So you are saying that if you achieve that $30 million target, EBITDA would be increased to 630 million?

That's correct.

Very nice.

Nice quarter, gentlemen.

Ryan Watson, Stanfield Capital.

: Can you talk a little bit more about your outlook or what you're seeing for the summer period in the Northeast?

I guess more in the Northeast and less so on the West Coast and South Central for the forward spreads and heat rates to the extent that you're open in those markets?

It continues to be a market, particularly in the Northeast, which of course is driven by the underlying fuel prices.

Yes, there has been some softening, but gas still seems to be following the direction of crude, which has a bit of this gravity defying -- on both the fuel areas, there's a bit of gravity-defying act going on here in that the sort of the normal fundamentals in terms of the amount of gas and storage and all would suggest that prices should be softer than they are.

But I think it is over laid with the geo-political concerns that have kept the prices high.

So I'm not sure that we have seen anything particularly out of the ordinary in that regard.

But in this regard, in a high gas price environment, prices for us in the Northeast look very healthy.

And the sort of restless state, New York Zone A, we are talking about quarter three pricing of in the mid 60s range.

In the South Central area, the prices are also driven by gas prices.

The high gas priced environment is more a mixed bag for us.

Because in the peak summer period, we have to buy in some power.

As I have said before, it continues to be in our industry, a situation where electricity price is derivative of the underlying fuel price.

So I think that's pretty much the situation we face now.

So you are not seeing any -- are you seeing any market improvement though year-over-year in the summer period in terms of market heat rate at all?

I wouldn't say market heat rates in this -- are we seeing a fundamental shift in supply/demand balances?

I would say that we haven't seen much sign of that yet.

I have said before that is not really what we are about.

It is claiming an early reversal of basic market supply and demand.

For us, it is more about supply and demand for gas and crude oil.

And I do not think that we see anything that suggests that the electricity itself has reached an inflection point in terms of the change in summer pricing.

But quite frankly, Ryan, part of that could be because there was virtually no summer last summer.

And one of the things I have seen in the past is when you have an absent summer like we had last summer -- if the new heat demand set this year off normally hot weather, what you will see that there was pent-up demand that grew last year but never was realized because of the cool summer.

I think this summer will be very -- if it's a normal heat summer, it could be very instructive in terms of what the next couple years would hold.

Terran Miller, UBS.

I was wondering if you could go through the bridge again between the 560 of previous EBITDA guidance and the $600 million of current EBITDA guidance?

I pretty much just broke it down to really a few simple parts.

The first thing is that when we originally came out with the 560 guidance, we had forecasted asset sales to happen at certain points during the course of the year.

We've updated our view on that timing and two assets in particular, one in Brazil and one here in the U.S. -- has been really pushed out through the end of this year.

So that increased the EBITDA guidance by 17 million.

In addition to that, the Enfield project had a mark-to-market gain that was recorded at the end of the first quarter.

When we originally came out with our guidance, we had not done the mark-to-market evaluation of that.

So that created $12 million of upside.

So that takes you up to $29 million.

And then the third element is around that mark-to-market loss.

Included in our first-quarter results was that $40 million loss in the Northeast.

That we know at the end of April, when we do the re-evaluation of those mark-to-market losses, 28 million has reversed.

So we've added that net 28 million, which takes you over 600, and I'm looking at the updated forecast for cost and margins across the portfolio and in particular South Central, it offsets some of those increases that brought us back to the $600 million.

So effectively on an ongoing recurring basis, we really don't have that much additional uplift in terms of EBITDA?

For the remainder of this year, the uplift would be certainly some of the off-peak assets run.

And then the other is, again we mentioned a moment ago in the F.O.R.

NRG program, we see some upside there.

It is the off-peak.

We've got room to contract in the off-peak.

But also the dual fuel-fired plant and peak periods would also be a potential upside.

So that would be Oswego basically in a big way?

Oswego can make a lot of money very quickly.

That's right.

There are others in the portfolio, but that's the biggest.

David Silverstein, Merrill Lynch.

Could you talk a little bit, David, about the reinvestment of cash into the business?

I have always gotten a sense that you are looking to do tuck-in type acquisitions.

Let's say borrowing some assets to complement the co-op contracts that you have in South Central.

Can you talk a little bit about any discussions you might have had with certain parties, whether it be Emurint (ph), whatnot.

Are you at all the mindset of making a major acquisition?

Or maybe just buying certain assets on a piecemeal basis?

And then also maybe comment on what you think about a company like Dynegy after it cleans up its balance sheet with a midstream sale that is pending.

David, we had a little bit trouble hearing -- I just want to make sure I get your question.

First, you said, talk a little bit about reinvestment in the business and I think you referred to like the re-powering initiatives we have.

Then you sort of talked about major transactions.

And then you said something -- and maybe it was just repeating what you said about major --

I apologize.

Can you hear me better now?

I think so.

What was the last thing you said about Dynegy?

Well you've got certain parties like Dynegy that are cleaning up the balance sheet now that are pending sales at mid-stream business.

They'll have a de-leveraging process.

So it might be a little bit easier net for you to swallow in terms of a lot of the legacy issues having been dealt with possibly with that transaction.

There was an article in the paper that you guys had been talking with Marint (ph).

I am just wondering if you're still thinking about smaller Brownfield re-powerings, tuck-in acquisitions to complement certain assets?

Let's say in the South Central region.

Or if you are thinking larger, more strategic initiatives at this point?

Okay, well on that part -- the idea of major transactions, what has been generally lumped in the consolidation basket -- I have stated in the past that I see the same logic behind consolidation that others have talked about more extensively than I have.

That I have also said that I think that as you said in the case of Dynegy -- but I think it applies to several people -- that I think a lot of people in the industry have made great progress.

But obviously, we don't comment on who we are discussing what with.

But as you yourself said in the question, just in the course of 1 or 2 weeks, we can be associated with several different people.

And when I heard about the Duke/Synergy transaction yesterday, I sort of -- I breathed a sigh of relief and said, well, maybe the rumors about us and Dyna will stop at least for a couple of weeks.

So we look at everything.

But everything is a question of price and structure and when we look at things like that, we stay true to our fundamental principles, David, which is something that is near and dear to your own heart -- which is prudent balance sheet management.

There are certain things we would not change.

Now that is the consolidation basket.

We do think that there is a lot of opportunity to sort of add to our individual regional portfolios.

We are still working on the reverse RFP that we announced in January in terms of the South Central region.

And there were a lot of expressions of interest, and we're having discussions with a few of the parties that participated in that.

So the short answer to your question is that we are open to both types of transactions, but we are going to stay disciplined in whatever we do.

And what do you think the right leverage is?

You mentioned that you think you are under-levered right now, David?

Whether it is going forward or even with the transaction -- what do you think the appropriate leverage is for a company in your space?

Well of course, the precise level of leverage depends on the volatility of your earning stream and all.

But I don't think, Bob, we changed anything from our 45 to 55% as being sort of the target zone.

If you want to comment?

That is correct.

David, we are shooting to maintain that ratio, the 45 to 55.

We built that around being a DD company, and that is where we think our ratings should be.

And that's what the profile we want us to have.

I mean David, being the perceptive person that you are, you may have noticed that there was a slight difference between Bob and myself.

In that, he said we were at I think 48%, which is within our 45 to 55% range.

And I suggested that we might be closer, underneath our range.

And that maybe because I tend to look at things calculating on the supported debt basis, while Bob I think when he did that calculation was (multiple speakers)

Consolidated.

Yes.

Ben Gamble (ph), Trapp Lite (ph) & Co.

Great quarter.

Thank you for all the helpful disclosures.

Just a quick clarification on page 20, just looking at your enterprise value calculation there -- are you including the West Coast Power in the collateral there?

Are you taking that out of the enterprise value or--?

We just had the West Coast Power EBITDA in there.

We don't have any collateral.

So I guess if I am -- as you said, redoing this and adding back the mark-to-market gained for last year that was for this year as well -- and then adding potentially the 30 million from this year -- and then taking out the collateral gains, etc., since the quarter, then is it reasonable to say that that number could be kind of around 6.1, 6.2 times if you include all those numbers?

Well Ben, I'd have to quickly do the math.

But the way you're suggesting, it makes sense.

And I think that is probably right.

I am sure you did the calculation correctly.

And the other quick verification I had just on this quarter.

If this quarter -- at the quarter would have ended obviously today instead of March 31st, then the adjusted EBITDA would have been 182 million versus 154 million, is that about correct?

Yes.

You are adjusting for the mark-to-market.

For the mark-to-market.

Right.

Great.

Okay, well we want to thank everyone for participating in the call.

And we look forward to speaking with you again next quarter.

Thank you.

Ladies and gentlemen, this concludes today's teleconference.

You may disconnect your lines at this time.

Thank you for your participation.