NRG Energy Inc (NRG) 2004 Q1 法說會逐字稿

Good morning, ladies and gentlemen and welcome to the NRG Energy first quarter 2004 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 0 on your telephone keypad.

As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host Ms. Kate Sullivan with Investor Relations of NRG Energy.

Thank you Ms. Sullivan, you may begin.

NRGenergy.com, you can access the call and presentation through a link on the Investor Relations page of our website.

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

During the course of this morning's presentation management may make or repeat statements made in today's press release regarding future events and financial performance.

We will attempt to identify these statements by the use of words such as expect, believe, anticipate, intend, and other words that denote future events.

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 to you consider the important risk factors contained in our press release and other filings with the Securities and Exchange Commission that could cause actual results to differ materially from those in the forward-looking statements.

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

For complete information regarding our non-GAAP financial information, the most directly comparable measures, and quantitative comparison please refer to today's press release and certain non-GAAP financial information available on our website.

The press release has been furnished to the SEC as part of the Form 8-K.

We will make this information available on the website for a limited time.

In addition, please note that the date of this conference call is May 11th, 2004, 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.

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

So Ershel Redd, regional President, of the west coast, finally Bob Flexon, our new [inaudible].

In terms of our agenda for today we've really split it into three parts.

The first part we're going to focus on our objective for the first 100 days, NRG post Chapter 11, then Bob is going to walk you through our first quarter financial results, then I'm going to come back and outline our strategy going forward.

We expect this presentation will take about 45 minutes, then we'll have approximately 45 minutes for questions both here in the room and also from the phone.

Now we obviously have had some exceptionally strong first quarter financial results.

Bob is going to provide you with an incredible amount of detail with respect to these numbers.

The only point I'd like to emphasize is this.

While there's been a considerable amount of questions or noise swirling around the company over the past few months what is our strategy, what's going on with the transition, what's happening with the auditor, acquisitions which may or may not be participating in, the important point is that the company has stayed focused on the day-to-day business.

Whatever else is discussed here today, whether you agree with the strategy I'm going to outline a little bit later, or disagree with it, I think everyone should walk away from this presentation with the knowledge that the 3,000 men and women who constitute NRG stay focused during the first quarter of 2004 and took care of the company's business and the proof is in this set of financial results.

Now, when we last met on actually two months ago today on March 11, our last quarterly call, I outlined for you the original 11 management objectives of the company that I set upon my arrival at NRG for the post-emergent period.

At that point we were still in the middle of the first 100 days.

Now that we're at the end I wanted to update you on our progress.

In particular, I'd like to focus on the four operational priorities.

Our operational performance during the first quarter was very strong.

While the numbers in this slide are good they don't tell the whole story.

In particular we were able to keep our plants running during the extraordinarily harsh weather conditions that impacted the northeast in mid-January.

It is obviously easy for us to sit in offices to overlook the fact that our plant personnel are kept running by dedicated plant personnel working their shifts outside, in the case of this winter, dislodging coal from frozen coal trains and breaking up ice, clogging water intake channels, but it's through their efforts that we can post these results.

Contracting-wise we have as previously reported hedged a significant portion of our coal-fired generation for the balance of the year at this point approximately 50% of the output is hedged and more than 80% of our projected coal requirements are already locked in.

This puts us in a good position with respect to down-side protection while enabling us, through our unhedged capacity to take advantage of any price spikes that may occur during the summer peak season.

With respect to asset sales, our efforts to rationalize the portfolio through the sale of nonstrategic assets continues to meet with success.

We have implemented a series of relatively small transaction during the first four months of the year and are now poised to close a sale with respect to Batesville, one of our larger noncore assets from a balance sheet perspective.

And finally with respect to Connecticut, the stage finally has been set for turning Connecticut from being a major negative as it was in 2003 and before as a result of the Connecticut line power contract, into a modest positive.

This result has been achieved through substantial effort on the part of the NRG deal team working in close coordination with the Connecticut authority and with FERC to explain the nature of our position and the position of our plants in the southwest Connecticut sub regional market.

So in summary for the first 100 days we had 11 objectives and from my perspective we have 11 missions accomplished.

I think that between the financial performance we have turned in and what we have accomplished here we have created the right foundation and hopefully have begun to establish the credibility as a management team to have a meaningful discussion of where we intend to take this company from here.

But first for some more detail about these quarterly financial results.

Bob Flexon.

Thank you, David, and good morning.

My objective this morning is to provide information on our first quarter performance, to share our key accomplishments during the quarter, and provide selective information for the remainder of the year.

We will not provide specific earnings guidance at this time, but will provide you with a number of full-year estimates, provide you with information on key earning and cash flow drivers to enable to you better your own assessment of the company's financial prospects.

As a result of adopting Fresh Start accounting and emerging from bankruptcy our historical financial information is not comparable to periods post-bankruptcy.

Accordingly, information on 2003 is limited.

The company's performance during the first quarter was impressive.

Reported net income was $30 million, or 30 cents per share.

Adjusted for reorganization and restructuring charges, discontinued operations, and losses on sales of equity investments, recurring net income was $34 million, or 34 cents per share.

As David has mentioned, favorable market conditions of higher gas prices and colder weather in the northeast during January combined with our excellent operating performance were the underlying factors driving these results.

Cash flow from operations in Q1 was a remarkable $350 million, even when adjusted for the net receipt of the Xcel payment cash flow from operations was $225 million for the quarter.

Net cash flow inclusive of a $31 million pay-down of debt was $280 million.

The company's liquidity increased by $188 million versus December 31st, 2003, and now stands at nearly $1.4 billion of which close to $1 billion is unrestricted cash.

We also improved our medium-term liquidity by cost effectively refinancing $503 million of bank debt with a tack-on issuance of high-yield bond.

This extended maturities from seven years to ten years and reduced our exposure to floating interest rates.

We also put in place two interest rate swaps which reduced interest cash cost by $20 million over the next two years and brings our floating rate debt ratio into our target range of 20 to 30% of total debt.

Operating revenues of $621 million from majority owned facilities were comprised of $392 million of NRG revenues of which 73% were merchant, $150 million of capacity revenue, of which 66% were contracted. $79 million of other revenues primarily thermal and resource recovery, net of nearly $17 million in fresh-start amortization.

Operating income of $125 million includes $23 million of fresh-start amortization expense.

Depreciation expense of $59 million should be reflective of the depreciation run rate for 2004.

North America accounted for about 81% of the operating income.

Equity and unconsolidated affiliates of $18 million includes the west coast power contract,Fresh Start amortization expense of $31 million, and the effective tax rate for the first quarter and 2004 forecast is 34%.

The strong financial results were obtained even though North America megawatt hours decreased approximately 5% versus the same period last year.

The decrease reflects higher planned and unplanned outages primarily in base-loaded coal plants during the first quarter 2004 versus 2003, particularly the planned outage of our Big Cajun number two unit at Louisiana generation that was a major overhaul for the entire month of March 2004.

The lower generation reflects slightly milder weather in the northeast and first quarter 2004 versus that in 2003.

As measured by heating degree days the number of heating degree days in the first quarter 2004 was 4% lower than the same period in 2003.

However, in January 2004 alone, the heating degree days were 19% higher than normal and were 6% higher than 2003.

The severe cold in January 2004 increased demand for natural gas thus pushing up prices for this commodity as well as electric power prices while the rise in gas prices may have squeezed spark spread margins for those firms more dependent upon a gas-based generation, NRG's fuel diversity, particularly that of its coal-based capacity, allowed NRG to benefit from the higher electricity prices without a comparable rise in fuel costs.

The spark spread from coal-based generation which we refer to as the dark spread, was $31.23 per megawatt hour which generated $99.8 million in gross margin.

This excludes generation from our Louisiana generation plant.

Oil and dual fuel generation earned a spark spread of $31 million and $39.15 per megawatt hour while gas-based generation spark spread was only $1.5 million or $10.44 per megawatt hour.

The North American power generation by fuel type demonstrates the significant leverage of our coal-fired asset. 72% of megawatt hours generated in the first quarter were from coal-fired plants while coal-fired costs, fuel costs, accounted for only 44% of the total fuel costs while eastern coal prices have been rising, our contract to position and increased usage of PRB coal have limited the year to date cost increase for coal to about 5% versus 2003.

Here are some new information for you which I don't think you've seen before.

EBITDA, earnings before interest, taxes, depreciation, and amortization by segment, reflects how the new company is newly organized and managed.

You will find additional regional segment information in the 10-Q and we will continue to provide you with information according to these business units in the future.

On the NRG website will you find a list of what plants comprise these individual segments.

For instance, included in other North America is Batesville, Rockville, Kendall, and Rocky Road.

As you can see from the numbers the northeast was a big contributor to EBITDA this quarter with Australia also showing strong results.

Corporate unallocated is primarily certain general and administrative costs that are not allocated out for the units.

It does not reflect cost of the headquarters.

As I mentioned in my opening remarks the company had exceptional cash flow in the first quarter.

Cash flow elements are cash interest of $43 million, which includes $15 million of debt retirement costs, $3 million of debt issuance costs and current period interest cost of $25 million.

Interest payments on our corporate secured bonds was paid semiannually, so a source of cash for us this quarter, $35 million, will be reversed next quarter.

Income taxes on a cash flow basis for the quarter are approximately $3 million.

Cash income taxes for the current year are forecasted to be approximately $18 million.

Changes in working capital during the quarter included $21 million decrease in inventory primarily fuel oil, at our Oswego plant which will be replenished during the year. $30 million decrease in prepaid assets reflecting replacement of cash collateral with a letter of credit.

$288 million collection of the Xcel Energy settlement of which $163 million was paid out and reduced the creditor pool obligation.

We expect an additional $25 million to be disbursed to the creditor pool in the third quarter leaving a net cash increase for the company of $100 million.

$2.5 million of asset sale proceeds were received in the first quarter as of May 10th cash proceeds have reached $97 million year to date.

In addition the recently executed Batesville sales agreement will contribute another $27 million in cash and eliminate $292 million in consolidated debt.

Cash from asset sales for full year 2004 are expected to exceed $120 million.

Cap ex for the quarter was $35 million.

Approximately $22 million for maintenance and the balance for environmental.

Full-year cap ex is estimated to be about $130 million for 2004, of which approximately $100 million is maintenance capital.

This is higher than previously discussed as major maintenance continues to be capitalized in 2004 versus expenses previously anticipated.

This slide provides guidance on the potential impact for the remaining nine months of market fluctuation.

For example, if the price of natural gas increases by $1 per million BTU the impact for the remaining nine months, based on our current merchant position, would be an increase to operating income of approximately $39 million.

The average gas price in the first quarter was approximately $5.80 per million BTU.

Liquidity improved by $188 million since December 31st, 2003.

Unrestricted cash balances increased by $291 million.

This improvement was partially offset by the use of the use of the letter of credit facility.

At the end April our liquidity improved a further $77 million net versus March 31st, 2004, as a result of our asset sale.

This slide depicts the uses of the $250 million letter of credit facility as well as collateral use to support our commercial operations commonly called Power Marketing, Inc., or PMI.

We continue to be judicious with our credit usage and still have $137 million available under our letter of credit facility.

Other uses of collateral include guarantees which are [inaudible] note 18 of our 10-Q, pre payments, and margin marked to market collateral.

Near-term corporate level debt maturities are not significant and the company is well within the consolidated interest coverage ratio and the consolidated leverage ratio.

In our prior conferences we introduced the concept of supportable/nonsupportable debt.

Supportable debt defined as corporate level debt, recourse debt and project-level debt, generating and distributing cash, totaled $3.1 billion at March 31st, 2004.

Cash associated with these entities and projects totaled $866 million of which nearly $800 million was unrestricted.

Nonsupportable debt defined as nonrecourse project-level debt for which corporate does not provide cash support totaled $1.4 billion as of March 31st 2004.

Cash associated with these entities aggregated $142 million of which only $36 million was unrestricted.

Of our $266 million of consolidated adjusted EBITDA during the first quarter of 2004, $241 million, or 91%, came from supportable projects.

As you know, the company is relocating the corporate office to New Jersey later this year.

This is no small undertaking, particularly in the first year of compliance under Sarbanes-Oxley 404.

It is, in particular, a challenge for our accounting group given that we expect a very high degree of attrition.

I want you to know that even before I arrived on the scene, the situation was being actively managed.

We have risk management plans in place that include staff retention, programs that extend through March 2005, relocation support, and incentive for those employees transferring to New Jersey, and an extended staff transition time to ensure knowledge transfer from departing employees to new employees.

Training programs for new and existing employees as well.

Already position in the financing and accounting organization have been filled including the vice president and controller, the chief risk officer, the director of internal audit, director of planning analysis, and the treasurer.

The director of internal audit will be performing ongoing audits of department transition plans and progress and activities to ensure transition risks are continually managed.

The search being led by our audit committee to replace PWC as our independent auditor is progressing.

We are working towards having our new auditor in place and expect to be in a position to announce a new independent accounting firm prior to the end of the second quarter.

We continue to work with PWC.

They completed their review of our first quarter and are working with us to complete our S-4 registration statement due later this month.

They have asked us not to comment on their reasons for declining to stand for reelection and we are respecting those wishes.

In conclusion, while I'm only six weeks with the company, although I have much to learn I see a company putting up impressive first quarter numbers. $1.4 billion in liquidity, $350 million in cash from operations, $266 million in adjusted EBITDA.

Furthermore, I don't see the level of legacy cash drag of other industries I've worked in such as environmental, asbestos, and pension liabilities.

As we continue on this year, we'll work at improving our reporting to you to bring more transparency of our performance.

We'll continue to attract, recruit, and retain the talented work force, and although new to the industry I'm excited to be part of it.

In particular, I'm thrilled to be part of an organization with a very talented and dedicated board of directors and employee base.

Thank you.

David.

When I was approached last summer by the NRG creditors committee about the CEO position with NRG they suggested I should consider taking this position because they were intent upon ensuring that NRG would be the first company in the industry out of bankruptcy with a cleaned up balance sheet.

And that was appealing to me, and what we're here to discuss today is what that means in practical terms in terms of real-life strategy to be first out of bankruptcy because I do think it means something that is important and that it is a considerable source of comparative advantage for this company in the content -- context of our industry today, but first understand our strategy.

It's necessary to understand the industry and market environment which we operate.

While the merchant generators vary significantly in terms of nature of their generating portfolios virtually all of their differences stem from where they originated.

In terms of their strategies once they decide to pursue the wholesale power generation business, they have been remarkably homogenous.

The single minded focus on megawatt growth, during the bubble period take [inaudible] directly back to basics strategies forced on these companies upon the collapse of the bubble.

Let me emphasize to you that the beyond back to basic strategy I'm going to outline today is not a return to the breathless acquisition development strategy pursued during the bubble period.

A strategy which I derided on our last quarterly company as MPOM, the mindless pursuit of megawatts.

As we approach the midpoint of 2004 our peer group remains focused on back to basics.

This is logical because as has been frequently pointed out while there has been a great deal of success in rescheduling debt maturities around the industry only NRG has been successful to date in actually restructuring our debt obligation.

As such our peer group needs to maintain its complete focus on repaying its considerable debt.

And since spark spreads currently are insufficient this debt can only be reduced meaningfully through asset sales and reduced spend on G&A.

At NRG we, too, have back to basics at the core of our near-term strategy.

I would say the speed and efficacy with which we are executing on our back to basic strategy is second to none.

Consistent with our commitment to manage the business principally for cash, we already have taken several highly visible steps either to increase our revenues or to reduce our operating costs and overhead burden.

As point out on this slide we have already significantly de-levered our balance sheet through noncore asset sales.

We will de-lever our balance sheet more as we continue to sell non-core assets with consolidated but nonrecourse debt attached, and we will be de-levering at the corporate level through the application of 50% of our excess cash flow through the mandatory offer feature in our senior debt facilities.

But the difference between our back to basics strategy and those of our peer group is that our B-to-B is not is sum total of our strategy.

De-levering our balance sheet is important but by no means the only element of our strategy going forward.

Our position of relative strength and flexibility puts us in a position to exploit the advantage inherent in our portfolio and to address our relative weaknesses all in order to create a company that can consistently generate value for all of our stakeholders but particularly for our equity investors.

As to what our competitive strengths this set of results should make it clear our strengths are our geographically and fuel-diversified portfolio.

Our principal weaknesses are the age and fuel efficiency of our plant, although after the set of results that we have announced today I don't think I'd be overhyping it if I question whether the age of our plant is even a weakness.

Certainly for this quarter at least, our old-timers, something like Roger Clemens, have showed the young seven-heat-rate gas plants a thing or two.

Now, it's also important to understand where we're coming from in terms of looking at the market environment that we operate in, and I'm going to take a little bit of time with this slide to talk about four features of the environment and what we see in terms of the future.

With respect to the reregulation de-regulation question we believe that we are destined for the next few years to continue in the half-in/half-out situation that presently exists.

The five ISO markets have gone too far down the path of deregulation to go back now and we think we'll continue to refine the market environment.

At the same time the regions which have yet to de regulate have little incentive to do so at the present time.

With respect to the overall industry structure the future consolidation of the wholesale power generation industry is inevitable and desirable.

The only question is when and on this question of timing I'm somewhat of a pessimist since I believe that most companies in the industry have, albeit unintentionally, given themselves the ultimate poison pill in the form of excessive debt.

While the debt issue is outstanding, meaningful consolidation will be difficult and slow to occur.

With respect to market fundamentals, as we all know, a cottage industry has developed on Wall Street and elsewhere predicting that timing of the rebalancing of the supply/demand equation for electricity.

Much of that commentary focuses on the rate of electricity demand growth.

Electricity demand growth is nice to have but I don't agree that it is the key determinant.

The history of upward movements in the commodity price cycle in our industry, whether you're talking about Australia in 2001 or U.K. in 2003 as data points, is that those upward movements in the price cycle are invariably supply driven.

And Finally, with respect to fuel, after last winter people finally seemed to understand the close relationship between real-time gas and electricity prices and again there's much debate over what the price of gas will settle at over the long term.

While not addressing that issue directly, what strikes us as beyond question is that the surge in spot gas prices on a delivered basis, particularly in the northeast that we have experienced over the past two winters are likely to become more frequent in the winters and possibly even in the summers to come.

As such, we want to strategy that is responsive to gas price surges that we know are coming but cannot accurately predict in terms of precise timing.

So into this environment of a bifurcated market structure, fragmented industry structure, persistent overcapacity and volatile fuel inputs we bring our geographically and fuel-diversified portfolio of U.S.-generated assets.

What do we do to improve our competitiveness?

We focus on improving our position in terms of what I call the four emperatives.

The price of our portfolio as reflected on our balance sheet, geographic diversity, sale in our core markets, and improving our route to market.

The first three of these imperatives are quite straightforward and require little explanation.

More over NRG's position with respect to all three is already pretty strong.

The fourth imperative, route to market, requires a little more explanation.

During the bubble period that route to market question was dominate by the Enron vision of a trading driven future while wholesale power generators got no closer to their customers than the other side of the trading screen.

Well, if the Enron vision was the modern era of route to market we are preparing NRG for the post-modern era.

Contractual and other commercial relationships with load-serving entities in our core regions will be critical to our success.

We want to build a business that gives a low serving entities what they want.

What do the load serving entities want?

First they want to see metal in the ground from their suppliers.

The age of synthetic megawatts is not likely to reoccur in the near future.

Second, like in all industries they want suppliers who are price competitive both on a short-run marginal cost and a long-run marginal cost basis.

In particular this means they want a contract with a generator which is able to off-shape load from its own generation across the merit order.

Finally as gas prices continue to surge load-serving entities are going to be increasingly intent upon contracting for wholesale supply which offers at least partial insulation from short-term spikes in the price of delivered gas.

In other words, we expect future off-take arrangements in the wholesale power supply industry to trend toward BGS all requirement contracts that we have successfully bid on in the past few years in the eastern PGA market and also the all requirements contracts with the rural co-ops that we currently serve out of our south-central assets.

What we hope to get out of contracting with load serving entities for NRG is reduced volatility to our own core earnings, a premium to market in terms of price for delivered electricity, and greater freedom in terms of how we operate our own fleet in order to serve our own contractual requirements.

In other words, we want to build a financial foundation upon which we can rest the more opportunistic aspect of being in the of business of selling a commodity which cannot be stored.

Now, in terms of addressing the issue of our aging core fleet this slide shows both the operating age and the chronological age for many of our core units.

The good news is that in many cases the operating age of our units is considerably less than the chronological age.

Nonetheless, many of our units are approaching the traditional age of retirement for a plant.

The fact is, however, that with continuous reinvestment, the life of a coal-fired unit can be extended far beyond its original life expectancy.

Indeed it's much more cost effective to reinvest in an existing coal fired unit than to build a new one the thrust of our cap ex program is to do just this.

To extend the life of our core assets well beyond their original life expectancy.

However, the opportunity we need to consider is how we go beyond just keeping our existing plant afloat to expansion of our multi fuel-fired fleet.

The opportunity we have in this regard is direct result of three factors.

Continuing transmission constraints, limits on fuel transportation infrastructure, recurring gas price volatility.

These three factors in my opinion are going to contribute in the years to come to creating an environment where load serving entities in the state and local politicians that regulate them will recognize that new generation from nongas-fired plants is not only preferable but absolutely necessary and that no one can build such incremental generation cheaper, quicker, cleaner, with less disruption to the local population than us from our existing ground fueled sites.

But the key ingredient that we lack which they can supply is the long-term power purchase agreement because we are not, at NRG, going to repeat the sins of the past by building one or more merchant plants unless we have a long-term PPA for substantial portion of the proposed capacity with a credit worthy load serving entity.

Now finally there is the subject of acquisitions and the question that has been posed to me quite frequently recently is how could a company that acquired its way into Chapter 11 even consider engaging in acquisitions post Chapter 11.

Part of me believes that the best answer to this question is the obvious one, namely that in a capital intensive long lead time commodity industry there is a night and day difference between buying assets at the top of the commodity price cycle as the old NRG did and on the other hand seeking to buy assets at the bottom of the commodity price cycle that we're currently in.

And indeed, in this current price environment acquisition prices potentially attractive rationale for acquisition but there are additional reasons which we might -- why we might contemplate selective investments and the logic of most of those listed on this slide is fairly obvious.

The one I want to draw your attention to ties back to my earlier comments about putting all of our regional portfolios in the strongest possible position to compete for contracts with load serving entities.

Using upstate New York and the Energy zone of FERC, when it comes to being able to sell shape-load efficiently across the merit order, we have gaps in our current lineup.

In particular our portfolios and these in our other markets tend to consist of base load coal plant and high peaking unit.

We tend to be missing the mid-merit seven-heat plant that would allow us to follow a load more effectively as it moves between base to high peaking.

So in essence what are beyond back to basic strategy involves is reshaping what is currently a loose conglomeration of [inaudible] generating assets into three coherent regional business.

Each already with degree of scale in its core market but with plenty of room to grow and, in fact, as I think about about the future course of the wholesale power generation industry I'm constantly trying to draw analogies to other industries that deregulated before ours.

In that regard I am constantly drawn to the course of the retail banking industry.

After it deregulated 20, 30 years ago.

Consolidation took hold relatively quickly but it was pursued along two distinct paths.

Some banks chose the more glamorous approach of expanding in every direction at once in order to become a national player instantly.

Other chose the less glamorous but ultimately far more profitable approach of working towards being a regional, and later a super regional player.

If our industry goes in that direction with some merchant generators aspiring to be truly national while others stay focused on their region.

You can count on NRG trending towards the super regional business model.

So in summary three regions, northeast, south-central, west coast,, sweating the existing asset base, reinvesting in the existing assets, existing core assets, and select acquisitions that enhance the lineup.

The strategy which I am convinced when properly executed will enhance total share holder return for investors in NRG.

So with that I thank you for patiently sitting through this presentation and we'll now take questions.

[inaudible] with respect to the bank facility.

These assets clearly in a region that's probably under a lot more suspect in terms of people's outlooks and perspectives.

What can you say about this region, number one, which would make you more aligned with what Madelyn Patterson is doing?

Number two, if you were to do any type of transaction here with Madelyn Patterson, obviously you are the likely candidate here.

What form or shape would that transaction be?

What is the operator? 50/50 JV?

What would you contemplate?

I realize there's sensitivity to it, but it's something that I think gets people a little concerned.

Okay.

There are a lot of elements to that.

There's the regional element, there's the Madelyn Patterson element.

Let me start with the Madelyn Patterson element first.

Why would we file an 8-K saying we'd like to do a related party transactions.

I think it's clear to everyone a lot of the opportunities that have come up in the industry over the last year and will be coming up in the industry because of the nature of the industry is coming up through distressed debt world.

This is something I realize when I was at International Power when we looked after the -- went after the [inaudible] asset in the U.K. and I would have liked to have known a lot more about the distressed debt world than I knew at that time.

So, the fact that we have a major shareholder that's quite familiar in that area I see as an advantage to us.

We want to have the flexibility to do transactions with -- as to what type of transaction that would it involve, I mean, all things that you've contemplated we would consider.

I mean, the one thing we wouldn't consider is we don't really want to own assets that we don't do the commercial operation with.

We're currently in that situation with the west coast with -- where Dynegy did the commercial operation and we did the plant operation.

That's not something we want to do in the future.

In terms of equity ownership and service provider we would consider all other alternatives.

In terms of the SERC region, you're right, the SERC region I think I've referred to in the past as the most slighted region in the country.

I'm make a couple comments.

That's the conventional wisdom and prices reflect the conventional wisdom so there is that element to it, but I think the other thing, and this gets back to the slide that was near the end, as things go in the south-central area we have a fairly good situation right now in that we have a contractual arrangement with, virtually as close to the customer as we ultimately get.

That's an all-service requirement where we're now to the point where we're serving up to 1900 megawatts of load in terms of rural co-ops.

We have 1300 megawatts of base load generation.

We're in an unusual position, a position that's not obvious to most people, that we're a generation short in the south-central.

We have to buy in power during the peak summer season.

Because they're mostly residential.

That's right.

It's a cyclical -- I mean, it's a seasonal load.

Right now buying in that 600 megawatts shortage is quite easy to do because the capacity in south-central is virtually free right now because of the extraordinary overcapacity but if we have a position and we have a situation, without commenting on Madelyn Patterson's situation with Duke, but if we have a situation because there a lot of [inaudible] plant down there were we can fill out that middle part of our lineup and fill that 600-megawatt gap.

I think it's a way for strengthening our position, and so, you know, that gets into what the south-central strategy will be going forward to.

But I guess it gives you a sense of what our thought process would be.

Again, without commenting specifically on their deal with Duke.

One more follow-up for Bob.

With respect to the LC facility, cash collateralized, of the amount that's utilized under that what percentage of that actually is expected to get funded, and should we look at that really as -- actually cash and maybe one day get a new LC facility that will come back to you?

The $250 million funded LC in long-term assets, the cash is posted.

To the extent that we utilize that full LC we'll post additional cash for additional requirements in the future.

With respect to the accountant, I understand that you plan to announce by the end of the second quarter would.

That mean that that accounting firm would be expected to audit the second quarter and would they do so within the normal SEC-required filing time?

Yeah what we would have Price Waterhouse Coopers would do the S-4 registration statement with us which is due I think third week in May but the next requirement to have an independent accounting firm review our results would be for the second quarter.

So we would want to get a firm in during June to gear up, then obviously we've got the quarterly filing that will be due around August 10th which they would be on board to review.

Do you think they will be able to do that?

Yeah.

That's our expectation.

Can you -- I understand you wanting to respect the accounting firm's wish that you not discuss, but from our point of view I hope you can understand that given this industry, given the accounting issues that we've had to deal with have an accounting firm come out and say, we don't want to work here is kind of a very unusual thing.

And I'm not clear why we need to bend over backwards to protect the accounting firm as opposed to give the investors the straight story.

If it's not a problem, tell us.

And why won't they let you do that, given what that means to investors?

Well, I understand your concern and appreciate your concern.

We continue to work with Price Waterhouse Coopers to complete the first quarter 10-Q which we did as of yesterday.

We still need to work with them for filing our S-4 registration statement.

We had no disagreements with Price Waterhouse Coopers on disclosing estimates, the relationship is strong.

As to why they resigned they haven't issued a comment on that and you'd have to ask Price Waterhouse Cooper if they'd give you any more information.

At this point we're focused on moving forward, we've got a good relationship with them, we're looking to replace them and we're looking to get all of our filings done on time.

[inaudible] Merrill Lynch is it possible to give us a handle on what the EBITDA for the west coast power assets for '04 looks like, and can you also update us on the status of efforts to extend or renew the DWR contract or some variation of that?

Let say on the west coast, just for the first quarter, the west coast, I believe the cash distribution on the west coast power business was $30 million.

At this point I'm not going to give a full-year forecast for west coast.

I'll respond to the second part of that, Elizabeth.

We did make an offer to the CDWR to extend that contract.

We've since pulled back that offer because they do not have any contracting authority beyond '04.

All that being said we're looking at a lot of different option out there.

We certainly won't sit around and watch cash vaporize.

We're talking to all the load serving entities out there.

We are responding currently, in fact, I think yesterday we responded to a large RFP.

We're hopeful on that.

We're looking at the possibility of wet or dry layup if the market don't materialize.

We're also considering the development value of that property.

We've got a lot of ocean front property that's very valuable out there so we've talked to a few real-estate developers.

We're also considering RMR agreements.

We're talking to Cal ISO about those RMR agreements but rest assured we're not going to sit around and watch that cash vaporize.

Quick follow-up on this contract.

Had some real price movement in California this summer.

Do you benefit at all from that?

Is there some piece of that contract that's not really being sold?

There is some upside.

We haven't realized a whole lot of it so far, but, yes, there has been.

California has had a couple of condition 1 alerts which meant that there reserve margin got down to 7% or below.

That's real good for us because bear in mind these plants are located in load pockets, San Diego and Los Angeles so they've got a lot of value, both on repowering and on an ongoing basis, not just for load support but also for transmission support.

Elizabeth, we're not giving a sense of magnitude.

Just to make it clear these are basically fully contracted assets.

An extraordinary summer in California we have limited upside.

David Frank.

Can you talk a little bit about hedging for this year, both for power output and coal.

Could you talk a little bit about what next year looks like as far as coal and for output?

Do you have hedging in place beyond '04 and where do you see coal costs going for the company?

Well, we, in terms of our hedged electricity position beyond 2004, I mean, it's probably where we have a long-term, very heavily contract in terms of Louisiana assets for several years, through a series of different contracts.

Beyond that we have -- we are relatively uncontracted into 2005 and beyond.

I think we have one 100-megawatt three-year tranche from the BGS auction and a little bit of contracted coal-fired portfolio in terms of New York state but generally, you know, almost completely uncontracted outside of Louisiana past 2004.

In terms of coal, every year we are increasing the proportion of western coal burned in our plant verse eastern coal.

I think we're now at the point where we're burning about 13 million tons of coal a year, about 75% of which is western coal.

The price of western coal rose a little bit in sympathy with the eastern coal price spikes a few months ago but I think has dropped back.

And, you know, as we evaluate the fundamentals of western coal we don't see the same sort of supply-demand dynamic playing on western coal that we see on eastern coal, so we're relatively confident that the price of western coal is going to stay fairly static.

Jeff Stein, Asset Management.

Can you comment on your asset disposition strategy specifically with respect to the $1.4 billion of nonsupportable/nonrecourse debt?

First of all does that include the debt on the Batesville plant?

Does it.

So that is included.

Let's assume you have a little bit more than $1 billion remaining, based on the comment Bob made a very limited amount of EBITDA contribution from those assets, evidence to all of here that some financial engineering could dramatically enhance equity values by de-leveraging the balance sheet.

Are you targeting the remaining $1 billion to that effect and any other comments you have on those assets.

I would make a couple comments.

One of the reasons we're trying to lead people towards this idea of what's supportable, what's not, is because, you know, there are those assets, you know, Batesville, everyone knows which they are, Batesville, Kendall, and the speakers are the main assets.

Would we look to dispose of those assets?

We would certainly consider it.

One of the things that people have to keep in mind is that -- and it was on my sort of four fundamentals of this industry, selling assets in this industry is not that easy.

Even the Batesville transaction which we've announced, because there was a press release on it, there are off-take agreements on both Batesville and Kendall and they're not particularly happy off-takers.

Getting these transactions done require a series of consents which we cannot guarantee are coming.

From our point of view, the way we look at continues and manage it, though, is the way we looked at it these assets, they basically off off-take agreements that service the debt and they don't really provide any near-term cash to management -- I mean, to the company, and since we're managing the business on a cash basis that's why we're looking to sell them, and feel free to quote unquote, disregard them when looking at our capital structure.

Should, we'll look at trying to sell them but I can't guarantee success or any particular time frame in achieving the results.

So that's as best I can do for you.

Thank you.

Are there any other questions or should we open the --.

Gary Katenache from Principal Capital.

Two questions.

First your income statement for the first quarter shows $14 million of tax expense and cash flow statement shows $12 million flowing back.

What is your cash tax position now in going forward with respect to NOLs, et cetera, then your maintenance capital for the year, what do you think your maintenance capital for the year will be?

Cash tax for the first quarter was about $3 million, and it's about $18 million for the full year.

We have about -- over a billion dollars in tax NOLs, so the cash portion of our taxes primarily foreign related.

There will be some domestic to the extent that you have alternative minimum tax, but that's the cash position.

Regarding the maintenance question, John?

The capital for this year is estimated to be about $130 million.

One follow-up.

Your comment earlier regarding California real estate, can you just elaborate a little bit on that?

Have you seen the location of these plants?

They're right on the beach, for the most part.

The real-estate values are quite high out there, as you are probably aware, so we're looking at all the options.

Thank you.

Are those zoned for residential development?

Not presently but I've been assured that it can be rezoned.

It would create a pretty big tax base for the cities they're located in.

I think the important point about California and the alternative use value is that people like us with plants in urban areas we talk about alternative use value a lot, but, you know, I think there's a lot more work we can do to actually study whether there is the sort of considerable value, the numbers that people sort of throw around.

So we're at a fairly early stage looking at alternative use value but one of the ideas that we're trying to impart is that within the company wholesale power generation is definitely our core business but at the end of the day we need maximize the value of these assets in whatever way is the best way.

So, you know this is something we're going to be looking at going forward.

Ladies and gentlemen, we will now be taking questions from the phone lines.

For participants on the phone lines if you do have a question, you may press star 1 on your telephone keypad.

A confirmation tone will indicate your line is in the question queue.

You may press star 2 if you would like to remove your question from the queue.

For participants using speaker equipment it may be necessary to pick up your handset before pressing the star key.

Our first question is coming from Michael Lipski of Deutsche Bank.

Good morning, gentlemen.

Congratulations on a great quarter.

My question is, well, I have two questions, the first one is an easy one.

What is EBITDA contribution from Batesville?

The EBITDA contribution for Batesville is around $30 million.

My second question, someone in the room asked the question about the Madelyn Patterson acquisition of the CERC assets.

Given your strategy on page 35 to fill gaps in your economic dispatch and you put on here the Energy NERC region.

Isn't at foregone conclusion that at some point you'll either operate these assets or own them outright?

I'm talking specifically about the 5300 megawatts that Madelyn Patterson purchased.

I don't think I would call that a foregoing conclusion by any stretch.

No, I would not agree with that characterization.

One follow-up question.

You mentioned you have $130 million of maintenance cap ex, or $100 million is maintenance, $30 million is environmental.

Over the next three years looking at the age of your assets like Huntley and DunnKirk is there incremental cap ex that is going to be required at those facilities in particular, and if so what would the incremental cap ex be?

Michael, I would say that our -- the general trend in our maintenance cap ex as we look for it for the next few years baring we don't anticipate would be that would be fairly consistent with what you're seeing this year.

We don't see anything in the next three years, you know, in the current environment that would cause that number to increase dramatically or quite frankly decrease dramatically.

Super.

Again, congrats on a great quarter.

Our next question is coming from of Ladamere Golobasic with Long Acre Capital Partners.

Good morning, gentlemen.

Just a question regarding your Connecticut plants.

It was disclosed, I believe, on page 37 of the queue that you're currently earning approximately $7 million of RMR revenues per month on the Connecticut facilities.

Would you just elaborate on, you know, exactly which plant those relate to and why you are able to negotiate those favorable payments?

This is Scott Davido.

Let me answer that.

First of all, the specific plants to which that figure relates are Montville, Middletown, and Devon units 11 through 14.

Those reflect the RMR payments that were the subject of a FERC order entered in March that relates back to the middle of January.

The reason we were able to put forth that request to FERC and receive its approval is that those plants are all designated as necessary for reliability by New England iso, the grid operator.

As a result of being needed for reliability generally the system will support us covering our costs to operate those plants and in essence that's what's that said $7.1 million represents, are the costs necessary to keep those plants in operation for reliability.

Understood.

And how do those payments work?

Are they effectively tolls?

Do you not pay, you know, fuel?

Are the plants tolled?

No.

The way it typically works is these are payments that are received through the New England ISO monthly settlement process.

So essentially just pure, you know, incremental payments and you just continue to operate the plants as you normally would?

That's correct, although I would point out that under the RMR agreements, any revenues that are earned in excess of the amount to which we're entitled under the RMR agreements are paid back to rate payers.

So you're capped at that 7 million month.

So would you say that $7 million, is it analogous to EBITDA, or is it analogous to free cash flow?

It's actually analogous almost directly to gross margin.

Gross margin.

Understood.

And any, you know, on a similar topic, any developments with the LICAP payments?

Do you expect those to go through, and if so, when?

The original expectation was that FERC would act on the New England ISOs proposal with respect to LICAP by June 1st.

FERC did not.

We expect, however, that FERC will act on implementing the New England ISO LICAP proposal largely as put forth by the New England ISO sometime this summer or fall.

Understood, and just a quick digression on coal.

I believe you mentioned previously, if I'm not mistaken, that you're considering supplying some of your east coast plants with Powder River coal, is that correct, door I get that wrong?

Yes, that's correct.

Which plant is being supplied by TRP.

Both Huntley and DunnKirk.

Isn't it prohibitively expensive to transport the coal all the way from, you know, PRB regions in Wyoming and Montana all the way to western New York?

Well, it is true that with coal, particularly western coal, that you're buying transportation, but because the price of the coal as mined is significantly less than your eastern coals, even with transportation the PRB coal does provide some cost advantage.

So it provides a cost advantage.

Understood.

One final question on your road shows you mentioned some of the projections in the out years related to Canadian nuclear and at least one coal plant in Ontario.

Either being decommissioned or being out for an extended period of time that would results in some of the Canadian province becoming net importers of power from the United States.

Can you give us any further insight into that view?

Ladamer, you and I had a discussion about this at one point.

Right.

Our projections in terms of capacity market in New York are not predicate on there being retirement of any nuclear plants in Canada.

The -- I think the important thing, though, without getting into the specificity of what's happening with imports into New York from Canada we do in general terms see reduction in imports over time into New York from Canada, particularly from Quebec where they historically have come from and probably an increase in exports from New York into Ontario.

That dynamic, whether it is because of the situation in Canada with increasing demand or their decision to retire their coal-fired units, or what's happening with their nuclear units, I mean that is a discernible trend.

If you look at the imports into New York from Canada on a month-to-month basis over the past, what, 18 months or -- 18 months, there's been a month-on-month decline with one exception in February this year where they had higher hydro production out there which they dumped onto New York state.

So I think, you know, to us, you know, we're monitoring that, but, you know, we do think that's a dynamic that's being proved out that New York will have less power from Canada to rely upon in the future.

Understood.

Thank you.

Our next question is coming from Mora Shaunasee of NFS.

Couple of questions.

First, on the Connecticut RMR deal, just other fellow was talking about $7 million month in revenues.

As per your slide I think that's -- is it around a $30 million per quarter or what is the actual number expected there?

Because I know it was retroactive to January 17th but on an ongoing basis it's expected to be what on a revenue basis?

This is Scott Davido.

Let me reconcile for you the $7.1 million that you see in the 10-Q to the $30 million that you see in our news release because they're not quite comparable numbers.

They're reflective of slightly different things.

In the news release you're seeing an expectation of an average of $30 million per quarter in RMR revenues.

That is reflective of the entire Connecticut fleet.

Devon 7 and 8 have a separate RMR order from the one I was speaking to a moment ago.

In addition, there's yet a third RMR-type order called a cost tracker which is simply an RMR that focuses on certain specific O&M and capital costs that relates to these plants as well.

So if you will the all-in RMR number including cost tracker and all the Connecticut plants subject to RMR is closer to the $30 million per quarter versus the $7.1 referenced in the 10-Q which only relates to a subset of that.

Okay.

Now, my numbers may be incorrect, but please correct them.

If I'm wrong.

But last year, Connecticut, I think the cash flow loss was around $183 million, and obviously with this deal, there's quite a swing.

What is the comparable swing if the basis that I'm using off of '03 is correct?

Well, you've got a couple of things going on.

The number you referenced from last year, of course, is largely reflective of the extremely unfavorable long-term contract that we had with Connecticut light and power which expired on December 31st, '03.

What you're seeing as a general expectation for -- to give you a sense as David mentioned, we're taking our Connecticut plants and going from a forecasted -- and actually budgeted negative EBITDA, if you will, to a positive, and now I'm speaking EBITDA, not gross margin, but a positive EBITDA of approximately $15 million.

50 or 15?

I'm sorry, that's positive EBITDA $15 million derived from the RMR agreements at cost tracker.

Is the 15 million is that an annualized number?

That is an annualized number but I must caution you it doesn't include things like merchant energy revenue and other figures for the balance of the fleet.

As Bob mentioned earlier we're really not prepared to give you annualized figures on any of the --.

Okay.

I mean, just to clarify, because this whole Connecticut situation is very complicated, and just to clarify Scott's last comment relative to one of his early comments, while we're under the RMR arrangement, any additional energy revenues we get from the plant subject to the RMR have to be rebated, but once we're into the LICAP then we get to keep -- we get to keep the energy revenues over and above the LICAP payment.

Okay.

Thank you.

Second question is just any balance sheet goals that we can think about?

You talked about using a lot of the cash to pay down debt et cetera, de-lever.

Any specific goals over the next year or two where you -- any metrics that you'd be going for?

Well, if you're -- I mean, Mora, if you mean -- right now if you look at the supportable debt, not even -- the supportable debt that Bob was talking about, $3.1 billion you don't take out any net cash but leave it at that over the -- our equity value you're looking at about 60% debt to total capital.

If the question is, are we trying to get our debt to total capital down to 50% or 40%, the answer is we haven't set that goal yet, and that's going to be, you know, again, Bob's six weeks on the job and learning the industry and, you know, it's something we'll be discussing further as to how far we want to take it.

In a sense, I'm a bit fatalistic about it because our main mechanisms for repaying debt are preordained for us in the fact that 50% of our excess cash flow is swept under the terms of our senior loan agreement.

So from my perspective the best way for to us reduce debt is to keep generating as much excess cash flow as possible, then whether or not it happens will depend on whether our lenders accept the mandatory offer.

And any cash interest expectations for '04?

For your modeling purposes I would assume that our cash interest is about 260 for the year.

Great.

Thanks a lot.

Recurring cash interest.

Consolidated.

Yeah.

Thanks a lot.

Our next question is coming from Steven Smart of A. B. and Amro

Since you said your maintenance cap ex wasn't likely to change for three years, but your also going to reinvest it in your long term plan to reinvest in your coal plants.

I'm wondering, some of the, I guess what concerns me is the possibility of the free cash flow changing dramatically if you need to invest in these coal plants, but then in addition, I read the bush administration for the first time has made some statements about penalizing metro areas that would -- that are currently not in compliance with the air pollution, and it sounded a little bit tougher than they usually are, plus the Kerry plan, I think the coal industry dumped all over it as being very restrictive.

I'm wondering, do you care, or do you wait for these things to proceed farther before you analyze what the long-term future of some of these older coal plants might be?

Well, I think the -- just a couple.

First, the $130 million sort of run rate for major cap ex, that's the sort of spend level we expect to sort of life-extend these assets, because then, just to make clear, I then get into the part about repowering our coal plants which would be a different level of capital investment and probably beyond, you know, what our current free cash flow could throw off.

And that's one of the reasons why I emphasize the importance of long-term power purchase agreements because we would not be building plants on spec as was done in the past.

We would be looking to leverage those off the strength of the contract with off-takers.

In terms of the future course of environmental regulation, there is a lot of focus on whether, you know, a lot of politicized discussion on whether the current Republican administration in Washington enforces the clean air act and whether they don't or whether senator Kerry would change that if he came in.

From our perspective, you know, we have a very active environmental enforcement regulatory oversight at the state level, so almost without regard to what happens at the EPA, I mean, we have coal-fired plant in upstate New York with a very assertive attorney general in the state of New York and also in other states around the northeast, so we are dealing with environmental remediation all the time, and we think that we have put forward a plan in close coordination with the state authorities in all of our states which shows continuous environmental remediation improvement, and I think one of the things that people have to keep in mind when they think about us burning western coal, the first company we believe to be burning western coal east of the Ohio river valley is that this has a very, very substantial impact on our sulfur emissions.

When I was up at DunnKirk recently I was watching how they track their emissions and they were showing how they had gone from 1100 parts per million of SO 2 down towards 280 as they went towards 100% western coal, so we have a continuous environmental remediation program underway which we think basically solves for society's desire for cleaner air while recognizing the fact that this country cannot become -- cannot do away with its coal-fired generation.

It's only domestic source of fossil fuel.

Thank you very much.

I'm sorry, relatively unlimited source of domestic follow sill fuel.

So you're saying you might continue to accelerate the process to burn what we might call low-sulfur coal even if the cost savings wasn't as much as today?

Whether there is a cost savings, the whole program of PRB conversion was driven by environmental bases.

One of the previous callers said isn't western coal not cost-effective on a delivered basis in the east.

I think historically it was about same price as eastern coal in the east, with transportation cost included.

So the main reason we started down this path was environmental remediation.

If eastern prices realign with western prices we will continue down this path for environmental remediation purposes.

Very good.

Our next question is coming from Tim Shaler of Pimco.

What kind of return on capital do you all look for when you look at participating in the cerc assets or maybe New York assets?

Tim, I think, I don't think there's one financial metric that we would look at.

We'd look at, but certainly in terms of asset DCF valuation we'd be looking to outearn our weighted average cost of capital by at least 300 basis points, but beyond that, given that the long-term future, you know, is very hard to determine, we'd look at near-term accretion/dilution, near-term impact on cash flow, and so we would look at relatively wide set of financial metrics, including the most basic one which, you know, is just what is the dollar per K W of capacity relative to replacement cost.

But with dollar per K W so much lower than replacement cost now, can you just share with us what you think your weighted average cost of capital is now?

When we do our project evaluation we use a level that's greater than 10 to 12% that.

Would be the base level in terms of a break-even type of scenario.

As David said we'll want to outearn that by 300 base points at least.

Thank you.

That, in essence, is a fairly conservative view on what our [inaudible] is.

That's helpful.

Thank you.

Due to time constraints our next question will be the last one which is coming from Ryan Watson of Banfield Capital.

Hi.

When you guys came out of bankruptcy you offered some projections to the bank group and I wanted to know if you were sticking by those or if there was any reason to revise those numbers upward.

Secondly, I logged on a little late but can you tell me what your average cost of coal is for '05 and how much you're hedged on that input, please?

Thank you.

The -- regarding the plan of reorganization forecast that was originally done I think those numbers were done -- basically about a year old at this point in time, so they are out of date.

We said early on in the call that we weren't going to give any specific guidance regarding earnings per share or EBITDA for the full year but I would at this point time sunset the plan of reorganization for the forecast.

It's over a year old.

I was actually referring more to the presentation you made to the bank group when you did your bank loan in, I believe it was November.

That was in the fourth quarter that.

Is not public data, so I cannot comment on that piece.

And on the coal side, please?

On the coal side comment on the volume hedged, we have, in '05, acquired about 43% of our projected requirements.

In '06 about 30%.

That's all PRB.

And those prices are all locked in but I don't want to comment on the prices.

Okay.

So are Huntley and what portion of Huntley and DunnKirk are burning PRB verse eastern coal?

About 70% of PR B blend at Huntley and DunnKirk.

30% eastern?

Okay.

Thank you.

Okay.

Well, I want to thank everyone on the phone and here in person for participating in this meeting and have a good day.

Thank you.

This concludes today's conference.

Thank you for your participation.