NRG Energy Inc (NRG) 2004 Q2 法說會逐字稿

Good morning ladies and gentleman and welcome to the NRG Energy second quarter 2004 results conference call.

[OPERATOR INSTRUCTIONS].

It is now my pleasure to introduce your host Ms. Katy Sullivan, Manager of Investor Relations.

Thank you Ms. Sullivan, you may now begin.

Good morning and welcome to our second quarter earnings call.

This call is being broadcast (inaudible) from our Web site at www.nrgenergy.com.

You can access the call and presentation through a link on Investor Relations page of our Web site.

A replay of the call will be available through the Web site as well.

With me in the room today are David Crane, Chief Executive Officer, Bob Flexon, Chief Financial Officer, John Brewster, President South Central Region and Vice President Worldwide Operations, Scott Davido, President North East Region, Ershel Redd President West Coast Region and Vice President Commercial Operations.

They will be available for questions following the prepared remarks.

The prepared remarks will last 20 minutes and will be followed by Q&A with the call ending sharply at 10 a.m.

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.

You will tend to identify these statements by useful words such as expect, belief and anticipate, extend 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 you to consider the risk factors contained in our press release and other filings with the Securities and Exchange Commission that could have caused actual results to differ materially from those in the forward-looking statements in the press release and this call.

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

A complete information regarding our non-GAAP financial information to the most directly comparable measure will probably be a reconciliation of those figures.

These refer to the date of the press release and certain non-GAAP financial information available on our Web site.

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

We will make this information available on the Web cast replay of this conference call on the Web site following this time.

In addition please note that the date of this conference call August 5th 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 obligations to update these statements as a result of future events.

With the formalities underway I would like to turn the call over to David Crane.

Thank you Katy and I would like to add my personal welcome to everyone joining the call today for our second quarter quarterly results announcement.

We have a very brief and straight forward agenda here and I personally like to step out of character a little bit by saying very little using very few slides and then handing it over to our CFO Bob Flexon to provide the real substance of our combined presentation.

As most of you know to-date we have not given any full year '04 financial guidance.

We have repeatedly stated that we would not give any such guidance until myself as the CEO and Bob Flexon as our CFO, both were comfortable that we could provide forecast numbers within appropriate level of confidence.

At our last quarterly announcement with Bob having been on the job only five weeks, we were not yet in a position to have that requisite level of comfort.

Today we will be providing full year guidance in respect of the key financial matrix.

Bob, will be explaining that guidance, I just wanted to provide some preliminary comments before we get to that.

The second quarter as I think all of you know is largely a shoulder season in our business.

And given that we feel that we turned in a solid financial performance for the quarter with $232 million of adjusted EBITDA making 489 million adjusted EBITDA for the year-to-date.

As Bob will go into later, all four-core regions contributed materially to this overall results including Australia, which was a predominant contributor to the $98 million of EBITDA from international year-to-date.

Operations wise, an aspect of our business, which we really talk about externally but focus on relentlessly internally is safety.

We are pleased to report that our record in this regard as measured against a key ultra external benchmark is quite good.

With respect to fleet operating availability we are - I should say about the safety for people who aren't looking at the presentation, 20% lower than the industry average.

With respect to fleet operating availability, we were well on track achieving in-market availability through May of this year of 96%.

Environmentally we remain in full compliance with our obligations and finally in reorganization of the disproportionate spend during the second quarter on major maintenance Capex, I want to note that we completed the major outage season on time and on budget.

Turning to asset sales, we are at page 6 of the presentation.

As you know we remain committed to divestiture of non-supported assets.

We closed out several assets sales during the second quarter and after the quarter ended we closed on McClain.

We made good progress on Batesville and expect to close on it later in the third quarter of this year.

All in all with Batesville accounted we project close to $150 million in net cash proceeds from asset sales and over $500 million in balance sheet debt eliminated.

Now before I hand you over to Bob, I would like to just to give update on our two most significant portfolio management issues.

With respect to California, I mean with the respect to Connecticut, turning to page 8, what we have is - is not really an update, but more of a clarification.

The majority of our assets in Connecticut continue to operate under the RMR awarded earlier this year.

We have in my opinion been a little bit confusing and tasking to explain the financial impact of that RMR and I believe that, that confusion has stemmed larger from our failure to specify which assets we were talking about as not all of our assets that are on - under the new RMR.

So on this page 8, we have outlined the precise current situation with respect to which assets are under the new RMR and the old RMR and also the assets are continue to operate in the market through push bidding.

And finally in terms of California, our commercial position with respect to 2005 and beyond after the CDWR contract expired has not yet changed, but the market and regulatory environment has improved significantly and particular the State government and the CEC and CPUC have made it clear that they recognize the importance of measuring the cost of generation, as being the cost actually delivered to load, in other words transmission constraints have to be factored in and plants like ours which are inside the inside the transmission constraints in the load centers will in effect - should in effect achieve the - realize the economic benefit of not burdening the transmission system.

It remains up to us however to translate in this more favorable environment into commercial arrangements and we continue to evaluate all of our options with respect to our California plan for 2005 and beyond.

And with that I would like to hand it over to Bob for the main portion of the presentation.

Thank you David, good morning.

David has provided you with some of the key highlights for the second quarter.

During the call you will receive further information on our operating results, key drivers and performance on a regional basis.

I will also provide the company's 2004 outlook with respect to two key financial measures we used to manage our performance, EBITDA and free cash flow.

As a result of adopting fresh start accounting and emerging from bankruptcy, our historical financial information is not comparable to periods post bankruptcy.

According information on 2003 is limited.

The first quarter 2004 financial results have been restated for the accounting for the Batesville operation, which was re-classed to discontinued operation during the second quarter.

Included in discontinued operations in the second quarter are the following projects, McClain, PERC, Coby, Hsin Yu and LSP Energy also known as Batesville.

On slide 10, you will see our key financial highlights for the second quarter.

Operating revenue for the second quarter was $574 million net of $9 million of fresh start amortization.

Operating revenue was comprised of $333 million of energy revenues of which 66% were derived from merchant sales included in contract energy is $38.5 million resulting from the settlement of the Connecticut Light & Power contract dispute. $161 million of capacity revenues of which 62% were contracted and $89 million of other revenues primarily from our thermal and resource recovery position.

Growth margin for the quarter totaled $349 million, after total energy cost of $225 million of which fuel cost accounted for $176 million.

Cost of delivered coal for our North American generation fleet was $32.53 per ton for the second quarter while in the Northeast the average cost was $44.93 per ton.

The higher cost in Northeast reflects the blend for delivered PRB of $34.25 and delivered central appellation coal $56.19.

The overall lower costs for North America are due to LaGen's use of 100% PRB coal.

NRG's North American coal plants earned 79% PRB in the second quarter compared to 70% in the first quarter reflecting company's continued progress with converting our Eastern plants to low sulfur Western coal.

The average cost of gas from an SOB supply point earned across North American plants from the second quarter was $6.14 per million BCU versus $6.49 per million BCU in the first quarter.

Now let us turn to net income.

For the second quarter net income was $83 million.

Impacting the quarter's net income was fixed operating expenses increase in the second quarter versus Q1 of $8 million.

Maintenance related expenses fared for the higher demand summer season increased $23 million in the second quarter compared to the first quarter.

This was partially offset by a $12 million property tax credit.

General and administrative expenses also increased in the second quarter and aggregated $45.8 million.

The higher spending in the second quarter reflects increased legal fees associated with asset divestitures higher accounting fees and higher labor cost associated to the increased staff in preparation for our headquarters relocation.

During the three months ended June 30th 2004 NRG incurred $5.6 million of onetime cost related to its corporate relocation activity comprising of employee severance and termination benefit.

We anticipate total cost for corporate relocation activities being incurred through 2005 will be $43 million.

Of the $43 million, $27 million will be classified as relocation and restructuring charges in accordance with FASB 147. $12 million will be included in general, administrative and development cost and the remaining $4 million will be capital.

Cash costs for 2004 are estimated to $30 million.

Earnings from our West Coast operations were higher than expected due to favorable market condition and settlement adjustments.

Equity earnings were also favorably impacted by $10 million unrealized gain related to our Enfield investment.

This gain is associated with changes in the fair value of the national gas supply contract not accounted for as hedge, as a hedge in accordance with FASB 133.

Other income in the second quarter included $8 million, which is primarily interest income.

The effective tax rate for the second quarter is 34.6% and year-to-date 33.6%.

The 2004 forecast is 30.9%.

This is slightly lower than our previous guidance due to the change in the proportion of domestic foreign pre-tax income.

The adjustments to EBITDA mainly include discontinued operations, relocation, reorganization and restructuring charges and the Connecticut Light & Power Settlement.

The full reconciliation is provided within our earnings release.

On slide 11, we have the North American dark spread excluding LaGen in the second quarter amounting to $25.03 per megawatt hour approximately 20% lower than the first quarter and inline with our expectations as prices generally moderate in Q2.

Although the company's average gas price is 5% lower in the second quarter versus the first, the high volatility of gas prices driven by supply concerns and extreme weather event in January particularly in the North East resulted in higher power prices in the first quarter.

The average megawatt hour price realized by our North East coal assets in Q1 was $51.11 as compared to $46.55 in the current quarter.

The gross margin reflects the continuing benefit the company derived from higher gas prices rather than an overall market recovery.

Output generated from these same facilities totaled 2.8 million megawatt hours versus 3.2 million in the first quarter.

Our gas spark spreads in the second quarter was $7.94 per megawatt hour, a decrease of 24%.

This decrease is primarily due to low power prices, partially offset by lower gas costs.

The gas spread margin dollars increased during the second quarter due to higher generation primarily at our Arthur Kill plant.

Absolute dual fuel spread was significantly down from Q1.

This difference is primarily the result of the severe weather noted above in Q1, which increased demand from our intermediate and peaking plant that have largely been idle during the second quarter.

The real life price per megawatt hour from our oil burning plant was $91.75 in the second quarter, a decrease of $5.45 from the first quarter.

This was offset by $9.90 per megawatt hour decrease in oil cost, resulting in a net $4.45 megawatt increase in the spark spread.

The dark spread tells a story for NRG.

The leverage of our dark spread is demonstrated further in slide 12.

North American coal fired assets accounted for 34% of our generation capacity.

However in terms of megawatt hours generated coal fire generation accounted for 92% in the second quarter.

The coal fuel costs accounted for 57% of total fuel costs.

While coal costs rose moderately on a per-mega-watt-hour basis in the second quarter, our contracted position and increased usage of ERB coal have limited the cost increases for coal to about 4% versus the first quarter.

On slide 13 we have our EBITDA by business segment.

As you can see that Northeast continues to be the standout in terms of its contribution to our overall results reflecting our strong asset base in that region.

Our international business segment, which has contributed nearly 20% of the year-to-date adjusted EBITDA, had lower earnings in Q2 in part due to an unplanned outage at the Australian Northern power station from mid May to mid June.

During this time we utilize the downtime to perform some maintenance originally scheduled for the fall and early 2005.

For reasons mentioned earlier West Coast's power earnings improved over their first quarter results.

You will find additional regional segment information in the 10Q.

While we had another strong quarter from an EBITDA perspective, it did not translate in the free cash flow for the company during the second quarter for the following reasons.

We paid $66 million in semi-annual interest on our high yields load that scheduled.

We made cash income tax payments of $27 million primarily related to our German operation.

Equity earnings were in excess of cash distribution by $26 million.

Other funds used by operations or non-cash income line on such as gain on fixed assets sales and positive 133 derivative mark-to-market adjustment.

The increase in the working capital of $135 million is primarily due to normal seasonal working capital requirement, for example, our fuel oil inventory was drawn down in our free gulf during the first quarter to prepare for the summer season that stocks are replenished resulting a $32 million fuel oil inventory bill.

The prepayments in other current assets increased $31 million due to margin costs and other deposits with our trading partners as we entered into the peak-cooling season.

Included in the account receivables balance is the $38.5 million settlement from the Connecticut Light and Power contract with fuel, which was received in July.

Account payable decreased by a total $22 million primarily due to settlement of invoices related to major maintenance, which occurred at the end of the first quarter and the settlement of liabilities related to bankruptcy.

On the our liquidity on slide 15 remains at robust $1.34 billion relatively unchanged since the first quarter given the cash flow to the quarter as previously discussed.

We have posted an additional $19 million in letters of credit to support our hedging in contracting activities leaving $113 million on our overseas facility.

At our last years earnings call presentation we discussed our intention to provide more clarity in future calls from the company's earnings and cash flow potentials.

On slide 16 we are providing a full year outlook for two of our key performance measures, EBITDA and cash flow, which we use to manage to our business.

We expect our reported EBITDA for 2004 to be approximately $837 million and adjusted EBITDA to be approximately $850 million.

Our free cash flow on a reported basis is estimated to be approximately $521 million and the adjusted cash flow approximately $304 million.

Our forecast is based on our year-to-date result but still normal weather patterns now on foreseen, on usually event for foreign exchange fluctuations and successful closing of pending asset sale.

Slide 17 provides sensitivities on the impact of market fluctuations for the remainder of the year.

For example of the price of natural gas increases by a dollar per million BTU from the $6.37 million per BTU during the forecast period.

The impact for the remaining six months based on our current merchant position will be an increase to operating income of approximately $36 million.

Again assuming normal weather condition.

This is relatively unchanged from the numbers we disclosed last quarter, this is reflected of the higher volatility associated with the shorter time period combined with projective higher third quarter demand.

Given our hedge position for coal and oil we have limited exposure to the cost of these fuels.

Slide 18 is how we look at our equity in enterprise price value.

Total debt associated with continuing operation declined over $400 million from Q1 primarily due to stored or (inaudible) continued operation.

Supported debt defined as corporate level debt, recourse debt and project level debt of entities generating and distributing cash totaled $3 billion at June 30th 2004.

Cash associated with these entities and projects totaled $879 million up which $790 million was unrestricted.

Unsupported debt defined, as non-reinforce project level debt for which corporate does not provide cash support totaled $1 billion as of June 30th 2004.

The assets associated with this unsupported debt are primarily Kendal, Audrain, Sterlington, Big Cajun I, Bayou Cove and Rockford I and II.

Cash associated with these entities aggregated $94 million of which only $31 million was unrestricted.

Of our $489 million of consolidated adjusted EBITDA during the first sixth of 2004, $438 million or 90% gain from the supported project.

Using a mark -- using a $ 27 market price for our common stock the company's total enterprise value is approximately $5.8 billion.

We believe the equity value of the company is entirely attributable to the supported project as the unsupported projects are leveraged over 9 times.

That being the case and given our adjusted EBITDA outlook for 2004, we believe our stocks currently trade at an enterprise values for EBITDA multiple of approximately 6.47 times.

In closing, we provided a lot of information here today, which we hope helps you better understand NRGs performance.

We will continue to assess and look for disclosures to help you better understand NRG.

I will now turn it back to David for final words on the quarter.

Thank you Bob.

This is a third quarterly announcement and from this disclosure prospective we have here to the plan that we laid out there at the first call.

At that call which was back in March, we focussed on where the company had then.

At the second call in May we try to give an accurate financial picture where the company was at that point and now here in the third call, we have tried to work it for to give you a full year picture.

Each of these three points, I think the information we have disclosed is reaffirmed, the initial investment proposition, in NRG, both from an equity and from a fixed income perspective.

And with the respect to latter, on page 18 of the presentation, Bob directly went through the key evaluation metric of fellow enterprise value to adjusted EBITDA, I would like to draw peoples attention using the supported figures to the figures for the ratio -- the key leverage ratio of net debt to EBITDA, $2.15 billion of net debt over $750 million of EBITDA makes for net debt to EBITDA ratio for support assets 2.87, so from our perspective, the company from a leverage position and remains in a healthy situation not withstanding our comparatively low credit rates.

So given that and one last slide to comment beyond the financial measures, the company is going to stay - relentlessly focus on the steady execution of the business strategy that we have outlined today.

And finally in closing I would like to thank all of the dedicated personal at NRG delivered this result and I would like also to thank all of you for your continued interest in our company.

And with that I would like to turn it back to the operator for questions.

Thank you.

[OPERATOR INSTRUCTIONS]

Our first question is coming from Brian Richard (ph) of Atorian Research Group (ph), please proceed with your question.

Good morning.

I was just wondering if you guys could discuss internally the uses for your solid free cash flow position going forward?

It was Brian right?

Yes.

Brian, you know we have discussed and internally quite a bit, what we have said about the use for our free cash is that we have really want to get through this summer because you know we were right in the middle of what supposed to be our half season but as that is not a period occurring, at least in most part of the United States.

You know its nonetheless our highest price season so we want to get through that and focus on where we came out at the end of August before we got in to a sort of detail discussion of capital allocation but it's a complex issue for us because right now under our current arrangement - under our senior loan agreement, its pretty clear how we allocated our capital you know 50% of our free cash flow has to go from mandatory offer of our senior debt.

I think end of March next year, so and most other uses of capital you know any turn of - any type of return of capital to share holders is currently prohibited by the senior loan agreement, so you know there are limits of what can we do right now but we are trying to evaluate all the options, once we know were we have ended up at the end of this summer.

OK, so it is that option would be accelerated debt reduction on top of the mandatory debt reduction or credit payments.

Well all options are open.

I mean the it is just like you know the only downside accelerated debt reduction, I think it has to be done at a premium which you know, so and I doubt that our vendors would waive those payments, but it certainly one of the factors we will consider and I would guess that while we haven't mapped out in great detail what we will talk about in our next quarterly announcement, I think you will - you know we will try and get some insight in our viewpoint and capital allocation.

OK thank you.

Thank you.

Our next question is coming from Elizabeth Parrella of Merrill Lynch.

Please proceed with your question.

Yes.

Thank you.

With respect to your 2004 adjusted EBITDA forecast of 850 million, could you give us a sense as to how much of the contribution is from the CBWR contract that (inaudible)?

How much is from the California?

That is the - within the equity line item.

Right but I am asking the projection.

Yes.

I am just thinking Lis, but I think it is about a - well it is basically going to be the - well in the cash flow it is the 130.

I am sorry, you are saying that it is 130 million cash flow out of the ...

Yes.

The cash flow of course, I got to think through the EBITDA for a second Lis but on the cash flow side of it, it is $130 million.

And that is out of the 440 adjusted operating cash flow?

Yes.

Yes.

OK and could you tell us on the reconciliation you gave us - sorry EBITDA to net income, can you say what the contract amortization is which is related to the fresh start accounting, is that 30.6 million in the second quarter, a decent quarterly number to use or does it vary with respect to the amount of earnings in the quarter, I am just trying to get a handle on what that might look like for the year?

On the revenue side, it is pretty much amortized over the contract strength.

The one that tends to be more variable is the one that is in the gross margin or the cost of goods sold calculation being the admission credits which vary based upon hours generated.

So is there anyway to get a handle on what that 30 - well maybe I could ask you what the six-month equivalent number is if we could look at that?

On which one?

I am sorry, the contract amortization, I am looking at the EBITDA reconciliation table, which reconciles net income to EBITDA and adjusted EBITDA and you are adding back for the second quarter 30.6 million.

What I am wondering is what the six-month number is?

OK.

And if that is going to be in your 10-Q or somewhere else, that is fine, we can get it later, but ...

It is roughly $61 million.

OK thank you.

Thank you.

Our next question is coming from Brian O'dea of Bank of New York, please proceed with your question.

Hi.

Good morning everyone.

Just a couple of quick questions, first, I was wondering if you could just give us a quick as to where you stand with your coal hedging?

I know 2004 is taking care of for maybe 2005, 2006.

What that looks like now?

Well our coal hedging for 2005 and 2006 is a little bit complicated, you know, let me just sort of describe it.

You know we - for 2005 we will be you know we expect to be burning somewhere between 13 and 14 million tons of coal, approximately 10.5 of which would come from the PRB 2.5 rounds from the Eastcoast.

You know the coal from the PRB, the bigger issue is transportation because that's about three-fourths of the cost you know we expected to have a 100% of our coal transportation requirement like in a very short period of time.

You know our rates, which are consistent with historical expenditures.

You know the eastern coal is more of an issue we are largely uncontracted for eastern coal from the commodity perspective in 2005 and beyond.

You know but the again the amount of coal that we are burning from the each day on relative basis is dropping almost on a daily basis.

So I think we are only about 20 %, 15 or 20% contracted for eastern coal for 2005 and I am not sure what the numbers for 2006, 17% of 2006 also.

So you know clearly that's the coal that's increasing price and you know we will be out contracting for that but we are always reducing the amount of it that we are burning.

Is that 15 to 20% and the 17% of the 2.5 million ton?

Yes the 2.5 million tons by the way is the maximum amount that we would be burning of the eastern coal and I am not quite sure what the minimum amount would be but it would be probably half that or a little bit less than that.

So that's the range of eastern coal that we need to fulfill and quite frankly you know is the fact that you know we are working to serve covert away from eastern coal you know actually largely for environmental reason is one of the reasons why we haven't contracted forward as we.

Obviously don't want to over contract for coal that is comparatively expensive by historical basis.

What do think in terms of how do you switch to the Western coal and where transportation is now - what is that that, and what do you anticipate that in terms of you know cost savings what with the coal you know kind of given higher transportation cost and have you seen any issues you know the transportation getting from the West you know at your request?

The I am not sure understood the cost element of your- I mean tell me if I don't answer the cost element of your question correctly then you know then push back on me but we think that on an all end delivered the cost of Western coal for us in 2005 and beyond is going to be very consistent with historical levels including both the transportation and the commodity and are we seeing a difficulties in actually getting coal delivered, the answer is yes.

Its like everyone else you know its been a difficult times, a lot of disruptions and particularly in the eastern rail service.

We had not seen nearly number of problems with the western rails but you know obviously western coal to get to plants on the Eastcoast United States has to be handed over to the Eastern shippers somewhere in the Midwest.

So you know it has been a factor this summer, it's been something that has taken up a huge amount of management time.

Is that you have significant -- a sizable inventory level?

That the plan (inaudible) comfortable right now?

Well of course its not our job to feel comfortable about really anything but that's the business procedure, answer is no.

We seek generally have you know 30 days of supply coal of all types of coal at all our plants and no we are not at those levels you know we are not at levels which are you know sort of code red emergency levels but it is a constant struggle because obviously with coal plants which have heavy capacity factors and we have 20 days supply, you know 20 days from now you could be at zero if you don't keep buying the issue everyday.

So, it's an issue that the senior management of this company is working on, on a daily basis.

OK.

Just this one really quick one, can you give an idea of what the capacity factors you saw on your plants, on the coal plants for the second quarter?

John?

Yes.

During the second quarter we have seen year-to-date through the second quarter, we have seen an increase on almost all of our coal plants throughout the country.

If you want those numbers, I can give you those numbers.

That will be great.

OK.

For Cajun II 77.8% that's a net cash impact, Dunkirk it is 67.3%, Huntley is 55.5, Indian River is 48.2%.

You said Dunkirk was 67.3%?

Yes.

OK.

Great, thank you very much.

Thank you John.

Thank you.

Our next question is coming from Robert Howard of Prefectural (ph) Partners.

Please proceed with your question.

Good morning.

Just, I guess, continuing on a little bit with that Powder River Basin coal issue, you are saying that you are kind of moving that way to reduce some or to help you environmentally, I was wondering what kind of impact on environmental Capex would - what the benefit of that would be by going there or how far or you may be possibly differing you know having to make large environmental expenditures?

Well the - I mean the impact in terms of sulfur emissions is quite substantial and John correct me if I am wrong but from the point that the New York plants where we were burning all coal and sulfur emission were 1100 parts per million, you know, with - I think if we are a 100% ERB will be down about 280 or something like that.

So, you know 300% improvement in sulfur emission and I think there was a Capex portion of the, the question was - I am sorry I don't remember exactly the tenure of the question but we are spending about $30 or $40 million a year in Capex on environmental remediation, which targets - associate with this conversion to (inaudible) low-NoX burners and you know certainly it is part of an overall and continuous plan to environmentally remediate the emissions from these plants over time and you know the company is committed to you know doing everything that's technologically available and commercially reasonable to bring down the emission levels from all, whether it will be sulfur, NoX or you know mercury.

And so I guess when this conversion gets completed the running primarily to ERB coal, is there some - in terms of you know how the standards may be changing overtime, is there going to be like around 2012 or something that you still have to have some other big project out there?

Is that pretty much in the --?

Well it is part of our long-term planning (inaudible) you know we expect ultimately to have to put you know scrubbers at some of our plant to take it to next level but you know this is an area that gets into a bit of grayer and because obviously environmental law, environment the you know is always subject to change but you know we are working you know with the state authorities where we had four, five plants.

You know on plants you know consensual plants for environmental, remediation or retirement I think we are making good progress.

So, so it is you know a part of our plant to put in scrubbers but you know in the next decade.

You mention 2012 I am not sure though we been ask specific end I think unlike the environmental requirements in Europe where they still set very specific all today you got have achieved Level X by 2012 and Level Y by 2015 it's a little bit more dynamic here in US.

OK and I guess with coal and other issue with that with the price is being so high recently how much with coal really have to rise to have a substantial impact on your you know profitability these coal plants?

Well I would say if that they you operating all Eastern coal that's the level of pain would decrease significant right now because I would say also correct me if I am wrong you know we see afford prices for Eastern Coal, Central (inaudible) coal right now that being in the low $70 right at the portion.

That 25 bugs about what they were last year?

Yes

Where as PRB might be a $1 though, must be enormous

So I am clearly some of that particularly as peoples all their contracts go through some of that increased cost in Fargo as we have passed through in terms of power process but you know nevertheless that her level of increase on your basic input commodity you know would cost some substantial pain and you know those are efforts to accelerate our conversion to our to West in fall to get to bring the number down to a manageable level.

OK.

My last question just if you were to get some credit rating upgrades I was wondering what that type -- what that might impact for your working capital or anything you have tied in collaterals for purchasing that type of thing is if that would free out much cash or what's sort of lock in?

No, you know these the financial impact of any credit rating upgrade I think would be more felt by people who hold their balance in bios.

Because we don't we have no you know immediate financing needs you know we are less than $ 50 million of debt corporate debt to for project to pay over the next five years and you know in terms of going from you know single B land into in our double B land which is you know quite frankly where I think we belong.

Yes I don't think that there is -- yes I don't think there would be any direct impact we would hope you know we would certainly you know make the arguments in terms of dealing with counter parties that you know that they should give us you know credit without in a cash collateralization in you know royalty support but you and know probably our success neither would be limit having said that and we didn't actually produce the slide for this quarterly announcement because it hasn't changed much but we remain very tightest and conservative with how much credit we actually have support in trading.

At this point I think the actual amount I will see we are supporting trading out still less than a 100 million.

So, 150 million of the overseas facility itself is outstanding if I am right, George.

Well, 137 obviously about 70 is OK.

Yes I don't if you can get 137 million of LLC's outstanding 70 million related to trading, so its not a big debt weight on our balance sheet right now but I don't think it would change materially if we want from single B to double B.

OK, great.

Thanks a lot for the time.

Thank you.

Thank you our next question is coming from Mora Shanathi (ph) of MFS.

Please proceed with your question.

Good morning.

Just a couple of questions, first with regard to the 850 and EBITDA guidance, I was just wondering how does that capture the Batesville sales or McClain sale is that excluding the EBITDA contribution from those entities?

That's in the more that's in the reported column, so when we gets the adjusted, the adjusted takes out the discontinued off.

OK, so that you know OK great.

Then the second point - my question, just in terms of your free cash flow guidances.

I wonder if you could flush out a little bit, the cash taxes I think are little bit higher than expected, the other 50 million used in the EBITDA declined just half of the EBITDA as well as the working capital expectations you know I am just thinking in a more normalized years, this is the company that's going to be draining working capital or not so, may be just flush out a couple of those free cash flow numbers.

Sure.

On the - to the income taxes first, the income tax are again slightly higher, its on the foreign side and its just really a reflective of the higher income and part of that also is that where is the income.

You know obviously you can offset losses in one country verus an another country so its just a higher level of earnings has generated higher cash taxes in those location.

The other cash used by operations fairly big outline is there, I get back to the question what (inaudible) had, that tend to be the difference between the actual cash distribution that you receive from your equity investment as compared to the equity earnings that have reported in the income statement so it backed up with non-cash portion.

On the working capital that $60 million really we went through and analyzed the bills during the quarter and look at the things that we turned around as part of the normal seasonal requirement and what are the ones that wont.

You got a $22 million receivables for taxes debt we don't tax that rose during the second quarter that we won't be collecting until next year and then we had the inventory bill that I mentioned that our free go ware you that way it was purchase for the summer season and as David mentioned earlier summer doesn't seems to be arriving this August so, being cautious there and saying that fuel oil will continue to be there through the year end and then you would probably have a quite uplift in some of the other inventory for example coal.

So if you combine the inventory bill, the tax receivables some slight decreases in payables that also become permanent because of the discontinued off's.

We came up with numbers that $60 million number based upon that.

OK, can I guess there is hedging probably never any totaling normal here but that's life.

Just with regard to the West coast tower situation and you know it's ending in - how many months now - its 5 months.

How should we think about the next 5 months, is this should we have expectations and that is going to go down to the wire or how should we be thinking about these as we see here in August?

Well, if you mean do we tend to come down in the wire and that we won't be announcing something until December 31st or something.

We really, we don't really have any idea when we can tell you what is the outcome for the plans out there or what's it going to be.

You know financially the West Coast can go; it is going to go down from a 130 million.

As for this year it certainly is and how far down?

Does it go down to zero?

Probably not, a fair assumption either so, certainly it would not be acceptable to us that it will go down to zero.

So, we -- sorry I just can't give you anymore guidance and say its going to be somewhere between zero and a 130 million, which I know is useless to you but that's about all we can tell you right now.

OK, well great thanks a lot for your help.

Thank you our next question is coming from David Frank of Demolusive (ph) Partners.

Please proceed with your question.

Yes Hi Good morning.

Just continuing a little on the subject of California, I was wondering if you could comment on some of the California Energy Commission's recent orders or decisions as it relates to permitting in California.

I think that they made some changes to give the coastal commissions some power on approvals of re-powering and so forth.

And then there is some talk in some of the News Wires that California sees a lot of these older plants being retired over that next few years.

Can you just address basically how if at all these issues might affect you plants?

Well they really both affect us indirectly I mean on the second.

And first I think that maybe the News Wires, your point, I think the aging power plants report came out yesterday and I think it was just in my sense it was just a recognition by all the government authorities in California that California has a lot of old power plants in the load centres, which if historically come off the system are going to put the entire power generation and transmission system under an extraordinary amount of strain and that, it will not lead to an acceptable result.

So, for our plant, which are included a month of span in our inside the load centers in a state where relieving transmission constraint is an extremely difficult proposition.

It doesn't trying to -- going to Mora just asked us, it doesn't translate into dollar and cents for us newly but certainly it's recognition that they need our plan, which you know we appreciate.

The California Energy Commission and the Coastal Authorities giving more -- believing that the Coastal Authority should have more power to over these coastal matters, I am not sure we agree with that and that's going to impact our -- that would may require us to study the re-powering of our El Segundo plant, which we feel that we have been operating at the El Segundo site or that plant has been operating there for 50 years and we have studied the impact of that plant and what are emission to date.

And so, we actually don't favor anything that would require us to do what another study, which we would considered to be as a privilege with respect to the impact of another plant at that site.

So, but I think there is more chapters to be written in that portfolio as a final conclusion.

Right and again the article the mentioned something about studies taking a couple of years, is that accurate or did they really get that wrong?

Well the studies themselves can take any period of time.

You know and I am not saying that anyone has (inaudible) motive but you know you can be required by people who don't want you to you know repower to study something you know perpetually.

You know so I mean that is the sort of conventional wisdom I think that if you know if they required another study, we would just say that we would take that amount of time to do.

OK.

Very well.

Thank you.

Thank you.

Our next question is coming from Kevin Rock of Stark Investments, please proceed with your question.

Good morning.

Just a quick question on the bankruptcy settlement payment, is that - the 221 million, is that the contingent payment that is expected to be made in September or October?

Yes.

Are you referring to what is on the balance sheet?

Correct.

Yes.

That is the - that is separate, that is the Audrain Peakers project, that is not going to be settled, I mean we are running these assets for a third party and that is something - that is different from the disputed claimers there.

OK.

Where in the balance sheet is that accounted for then, that payment?

Which payment are you talking about, the 221?

No the contingent payments in September or October?

You mean the 25 million.

Yes.

Back on the bankruptcy, OK well that is on the balance sheet.

OK I see.

Yes.

OK thank you.

Thank you.

Our next question is coming from Mitchell Sieder of Credit Suisse First Boston, please proceed with your question.

Great.

Two questions, first could you just repeat the non-supportable projects that make up the billion dollars of debt?

And then my second question, if you guys could comment on the language in the press release where you are talking about the wholesale environment and you think the - you don't really see any sort of improvement in the wholesale electricity market and if you could just kind of give us your thoughts on how you see things progressing over the next couple of years, that would be helpful?

I will do the first one?

Do the first one on what is included in the (inaudible) debt of Kendall, Audrain, Sterlington, Big Cajun and one in Peakers, Bayou Cove and Rockford I and II.

Thank you.

Well on the wholesale environment, I mean the point we are making because there seems to be a fair amount of enthusiasm for the sector from you know funds from outside the industry at this point and you know the only point that we are trying to make in the earnings release is that you know there is no reason for that enthusiasm, if we continue in the basic sparks spread environment or in you know the basic supply demand.

You know we still see over supply and almost all regions obviously varying dramatically region to region.

You know from our perspective, you know structural you know change in the industry you know would help you know correct that you know with the degree of consolidation but as I said in the past I am somewhat pessimistic if that happens in the near term, because you know consolidation is I think difficult when you know most companies excluding ourselves you know are still struggling with excessive debt burden, you know I think the introduction of new money and maybe new entities into the industry is you know is a complicating factor, which you know its very early days yet.

So, I was try and shy away from predictions on where we will be in that regard two years from now.

But from what you said, I mean you know, you hear different management team speak and you in the management will be talking about two different markets, from what you said and I am not putting words in your mouth you don't see an improvement in the pricing which sparks that environment over the near term?

Do you see any improvement in the high demand?

I don't know who else you are referring to and certainly I hope that you see the world the way that it works, all right is going.

I mean this company is doing well, you know, we think we are announcing robust EBITDA you know forecast, you know its largely driven as you know by high gas prices and you know we are not making any money to speak that offer our gas plant we are making money of our coal and our duel fuel fire plant.

But you know the market you know in terms of, you know if you are doing snapshot of this market, you still talk about spark spreads you know for seven to eight gas plants and while you know we certainly do see improvement in the demand side.

I mean the demand has picked up, you know on reserved weather adjusted basis this year.

Yes they are still you know I have always said that you know natural demand growth in the mature economy it takes a lot of years to absorb the effect of over capacity that we have in the market.

Right.

And so and you know there are certain elements for the market that may continue to add supply in terms of renewable and you know in there at least new coal fire plants.

So, you know I would still - let me put this way, I have never been a big fan of blaming the weather for things and I had never been a big fan of just saying general economic recovery will be the tide that lifts our boat but you know obviously its general economic recovery lifts our boat we will benefit a long side everyone else.

I am not going to you know I am not going to you know turn it back.

OK thank you very much.

Thank you.

We have showing time for one last question today.

Our last question will be coming from Ryan Watson of Dansith (ph) Capital.

Please proceed with your question.

Hello.

More house keeping stuff, I am just trying to back into your EBITDA number base and looking income statement, you guys includes some of those amortization, where do those won through the amortization power credits, power contracts and emission credits and debt issuance cost?

Where do those run through on the income statement?

Well the run through in different parts.

You have got the power contracts run through the revenues line, the emission credits run through the cost of goods sold and then the ones related to West Coast Power run through the equity line item.

So, they are all in different part.

OK and then debt issuance cost as well?

Debt issuance cost will be part of the interest expense.

OK I mean isn't the interest expense always a --?

Was an add back, yes.

OK.

Right and looking at this various amortization, are these good run rate numbers to use?

I mean that annualizing, I mean is this good like, are this competitive numbers this quarter?

Or how do this vary, I mean just kind of --?

This one that varies that I am seeing varies the most is the credit.

The other one tend to be amortized over their life on a fairly straight-line basis.

The others thing that comes into play here is that as we utilize NOLs for our domestic taxes, which in 2003, I am sorry 2004, we expect to utilize $42 million of NOL.

What happens rather than that going through the income statement under fresh start accounting that realization of those NOLs serves to reduce the basis in the intangibles that the fresh start accounting put up.

So, it would lower the amount of amortization going forward.

As you go forward to the extent we utilize NOLs it will impact with on the balance sheet of those adjustments, which will in effect lower the amortization.

So, it does get confusing, which is why we cannot despair people towards that income so much because of the uncertainty around it in how that amortization flows through but if you just look at where we were today the only one that's really variable is the emission credit.

OK and then I guess so then on you EBITDA and free cash flow outlook on slide 16, the income tax of 36 million, I mean those would be 42 million higher if you had no NOLs to that cash?

Yes well probably you are close to in right.

We have most of that is for -- we are subject to alternative minimum tax, so there's some US taxes there but we have -- we do expect to utilize 42 million.

So, that's probably a fair assumption and a fair statement.

OK now do you have additional NOLs that you could use to make that 36, zero if you felt like it?

No because again note that 36 is international.

I am sorry OK, international OK.

And then if I was to look at -- I am not asking for '05 guidance but well OK if I take 850 as a steady state EBITDA generation number and then I say that the WCP contract doesn't get renewed or nothing happens and its zero as David said, could be between zero, 130 and say zero.

Would that mean EBITDA is 850 less 130 or would it be 440 less 130?

Just trying to feel like back out the WCP that never happens again and you guys do the same.

You should take it out of the top line and then its just go through.

Like that -- I will take that off from what you are saying and I will take it off the EBITDA number.

OK because I thought you said that 130 is included in the CFO not the EBITDA?

Well 130, is the cash.

What happens as you march through the statement is that the EBITDA has the full amount of equity pickup so, some of that is non-cash.

So, by the time it gets downs to the cash portion of the statement it's just the 130 that are left in there.

OK.

That if you backed it off the bottom line.

You know that's again going to the question asked earlier by both Moore and Elizabeth on the other cash use by operation, that's where the true up occurs.

OK so we essentially then could see 440 less 130 and your free cash flow is going to be...

On that statement, yes.

Would be lower by like amount, OK.

I mean there was an article out today regarding just indulgent Newswire, just sit out talk about old plants maybe shut down.

I don't know you touched on this, I think I logged on a couple of minutes late, but you just talk about your Long Beach plant probably being shut down, does that factor into this West Coast power?

Do you use that to service the West Coast power contract?

Well its part of the West Coast power contract now.

OK.

Do you guys have any comment on that I mean are you intending on shutting that plant then, the Long Beach plant?

Well I mean quite frankly again its, we are not going to sit around with the plant if the plants aren't earning their keep.

Its more than Long Beach that we will shut down, I would say that Long Beach is the one that's probably most on above all but I mean like I said we are evaluating all options for all plants in California and we don't intend to sit around and just carry the cost those plant if they can achieve an economic return.

OK.

One of the comment back to your question is that thing we do want to stay away from here it's free to draw any conclusions regarding for 2005 from the 2004 figures what we put forward here.

Its all deal '04 and has no connection, we are making no connection to '05.

OK understood.

And have you guys any further developments on possibly you know selling the real estate that makes up these California plants you know just extracting real estate value out of it well you know if you decide to shut them down.

No I mean I was in what I just said before that you know we are looking at all options and as we said before you know the Californian plants are you know to a greater degree is located in so attractive places from our real estate prospective but we still only don't have any you know update in that area.

Thank you.

Thank you and I think operator - I think we are out of time and I just want to thank everyone for participating in the call and look forward to talking to you in the next quarter for the next quarterly announcement.