密歇根天然氣 (DTE) 2002 Q3 法說會逐字稿

Welcome to the DTE Energy third earning conference call. After the presentation we will begin the question and answer period. If you would like to ask a question at that time please press star and number one on your touch tone phone. At this time, I would like to turn the call over to David Meador, chief financial officer.

Thank you. Good morning. Thank you for joining us. I'm pleased to host our third quarter earning call. Let me introduce who is with me today. I have Dan Brudzynski, our VP and Controller, Nick Khouri our Treasurer and Peter Pintar, our Director of Investor relations. Peter, is now going to cover the safe harbor statement on page two.

Peter Pintar (ph): During this call we will be making forward looking statements about DTE Energy and its subsidiaries that are based on current beliefs of our management. These statements are subjects to the risks and uncertainties that are discussed in the press release issued this morning and DTE Energy filings with the SEC. These uncertainties can cause our actual results and prospects in 2002 and beyond to be different from those expressed in or implied by these statements.

Thanks, Peter. I'm going to start on page three of our presentation that are on the web. We are pleased to announce earnings of 96 cents per share, which in light of current market conditions is a very strong quarter for DTE. The earning are within our expectations to keep us on track for the year. These results were driven by both energy resources and energy distribution which experienced favorable conditions for the quarter. The drivers for energy resources were higher demand and lower fuel and purchase power expense and this is partially offset by benefits costs which we're seeing start to effect us this year and we'll start more with 2003 in a little bit. The non-regulated portion of this business unit also benefited from higher syn fuel production. Energy distribution experienced higher demand, partially offset by heat related liability costs on the wire side of the business.

The gas business had a loss in the quarter. This is seasonal and is normal for the third quarter in a gas distribution business. The quarter also included a tax rate adjustment. This was caused by the higher syn fuel sales that I talked about earlier that we saw in the energy resources group. This is a timing item that primarily reverses out in the third quarter. Without it, we would have been at 85 cents for the quarter. Previously we had given guidance of 75-85 cents, so without the tax related adjustment, we would have been at the high end of the range for the quarter. Now , let me turn it over to Dan and he'll go over the quarter in more detail.

Good morning. Let's move onto slide four that lays out our third quarter contribution by line of business. Our energy resources line of business contributed 50 cents per share to the third quarter results. Roughly half of this was in their regulated generation business, related to strong summer sales and lower power prices. The other key earnings contributions stem from the energy services business, primarily the coal-based fuels assets. Smaller contributions are made for the quarter service-related business with an approximate break-even within our wholesale trading and marketing facilities.

Realized gains in this business were offset by similar mark to market unrealized losses. In the third quarter , DTE adopted the FASB EITS (ph) issue 02-03 which requires the presentation of gains and losses on energy trading contracts on a net basis. This reduced operating revenues, fuel purchase power and gas expense by 1.4 billion in the quarter, but it had no resulting impact for net income for both the quarter or for the year. Our energy distribution lines of business contributed 49 cents per share to third quarter performance, again demand driven with strong demand sales.

Losses within the energy technology business, our distributor generation subsidiary were 3 cents per share. However, revenues for the third quarter were up 79 percent over 2001 as they continued progress towards their goal of breaking even in 2003.

Our energy gas side of the business contributed a loss in the third quarter, reflecting seasonality. While the non-regulated mid-stream assets contributed 4 cents per share to the third quarter. Corporate and other rounded out the quarter with losses at plug power and the positive effect of the tax rate adjustment at the DTE level as David mentioned earlier, this does not have a permanent earnings impact for the year.

Now let's move onto slide 5 and compare quarter to quarter performance. Our energy resources business were up 16 cents a share over 2001 levels, driven by higher sales in our service territory. Overall sales were up 4.3 percent for the quarter, primarily within the residential sales class. Lower power prices also favorably contributed to the quarters results, which improved overall electric gross margin. Mitigating some of these improvements were higher operating costs due to planned and unplanned reliability and maintenance work done within our fossil generation fleet to improve production and availability. In addition higher employee benefit costs as a result of continuing inflationary pressures and higher fixed costs due to property and other taxes negatively affected third quarter performance.

Nonregulated earning within this portfolio were up 10 cent as share due to increased production in 2002. Energy distribution improved 6 cent as share driven by higher demand and a stable economic climate. Offsetting some of these gains were increased distribution operating costs due to prolonged periods of above normal temperatures and the related stress placed on the distribution system. In addition higher depreciation due to plant and service. The transmission side of the business was up in 2002 related to higher volumes. Just to remind you that the billing flows through the operating line of the distribution business. The gas side of the business was essentially flat in the third quarter. Holding company and other was favorable due to the effective tax rate adjustment.

As David mentioned the adjustment in 2002 was 11 cents a share. Whereas the third quarter 2001 had a negative effect of tax rate adjustment. These are adjustments that throw up our year to date effective and will reverse themselves in the fourth quarter of 2002 which is a negative 5 million dollar adjustment. So you have a zero impact to earnings for the year.

Overall, performance for the third quarter was 45 cents/share ahead of last year with roughly half, or 22 cents, being operating related. With that, I'll turn it back to Dave with an outlook for the rest of 2002 and into 2003.

Thanks, Dan. Now, I'm going to cover page six of the presentation. Our guidance for the year remains at 3.75 - 3.95 for the total year and that translates to 1.13 - 1.33 per share for the fourth quarter. This has been a good year for DTE in light of the business conditions that we face. The low end of the range for the year is 7.8% above last year's operating earning.

Given the strength of the year, we still believe it's prudent to maintain our guidance for the remainder of the year due to the nature of the economy. Weather is another uncertainty that we face. Including the heating demand impact on the gas side of the business. Always the potential for storm exposure on the electricity side of the business.

Another sensitivity for us is the regulatory treatment for the impact of choice, which is currently under review. Then the last, is regional power prices. On page seven, we're maintaining our guidance that we provided for 2003 of $3.90 - 4.10 per share. As is the case with most companies at this point in time, we are still in the budget process.

The assumptions listed here are very similar to what we showed you in the July 31st update. They include that the non-regulated earnings will grow to 190 million to 210 million. Up from 170-190 this year. We also assume economic growth with GDP in the 2 to 3% range and weather normal for next year. We expect in 2003 a higher penetration of electric choice. However, if we prevail with NPFP (ph) in the treatment of this, most of the impact of this will be offset by recording a regulatory asset for future recovery.

Another item that we talked about, an item that everybody in corporate America is facing we will experience higher pension retiree health, active health and insurance costs in 2003. The pension and retiree health costs are being driven by three factors, : 1. We are all facing market losses, this is the third year of negative real returns in the pension. The second item is the anticipated lowering of the return on asset assumptions. And then the third is the impact of lower interest rates.

Pension and retiree healthcare costs are expected to be in the 50-55 million range pretax, higher in 2003 over 2002. This is after actions that we are taking to reduce that exposure. When you add to that number, active health and insurance costs, we are facing a temporary 90-100 million pretax bubble in costs. These are included in the guidance we provided and because of the variables involved, the total bundle of costs could be higher or lower than what we are anticipating at this point in time. And its something that we will have to give you an update on when we give you the update on 2003 in early next year.

The last item that the industry is facing is the conditions that we see in the marketplace in terms of power prices. This effects what we buy and what we sell. DTE is faced with higher purchases next year in terms of purchases that we have to make in the marketplace because of our scheduled Ferme (ph) outages. We are going to provide an update on all of this and all the factors that I went through when we release our year end earning of next year. Now before we wrap up, let me turn it over to Nick Khouri.

Thank you and good morning. Continuing our long standing practice , DTE's management and board of directors, remains committed to a strong balance sheet and solid investment grade ratings. This translates for us into a targeted leverage ratio of 50 to 55%. Given last summer's well received equity issue, DTE is comfortably within our range with a year end forecast of 52 to 53%. This forecast includes a minimum pension liability of approximately 300 million dollars which will vary of course depending on market conditions. Remember this reduction in reported equity does not effect cash or net income. Generating net cash remain as simple focus for our organization. The compensation of all DTE employees from the CEO on down is partially dependent on achieving our cash target.

We believe we're on tract to reach our 2002 forecast of cash from operations of over a billion dollars, primarily generated from the utilities. Capital spending is projected at approximately 950 million. Including over 200 million for NOx environmental spending. As we have stated in the past , state law provides for the future recovery of certain environmental spending after the rate freeze is lifted. We believe therefore it's prudent to finance the NOx project with debt, matching future cashflows with debt service payments.

A strong balance sheet coupled with discretionary non-regulated investment, allows us to invest in non-regulated projects as the opportunities arise. We have developed a rigorous internal capital allocation process. Allowing us to only invest in projects with suitable risk adjusted rates of return. These projects could include generation assets, land fill gas, or gas midstream. If projects meeting our threshold do not materialize, we will return excess cash to shareholders or reduce debt.

Recent developments enhance DTE's balance sheet and liquidity requirement. Last month we closed a credit revolver with a target of 1.2 billion dollars of bank credit availability. We were one of the few recent companies whose base revolvers were oversubscribed. We have approximately 900 million of available excess liquidity. The recent bondmarkets have also been kind to DTE. In October, Detroit Edison refunded nearly 500 million in long term debt at rates and spreads not seen in years.

Finally, consistent with DTE's long term strategic focus, we are currently in negotiations to sell our transmissions system. If successful, the sale will only enhance our liquidity and balance sheet strength. No let me turn it over to David Meador to wrap up.

As I said at the beginning of the call this is another strong quarter. 2003 will be a challenging year but we're maintaining our guidance this time. We'll provide an update when we release our earning next year. We have successfully accessed both the equity and debt markets with great rates and have successfully rolled over our revolver a couple of weeks ago. And as we go forward, we will continue to explorer asset acquisitions. And we'll continue to talk a little more about that in the Q&A. As we've done in the past, we're going to remain disciplined. We're exploring opportunities that meet our strategy and meet our financial objectives. However, we don't have to invest unless we see something that we really like. So we're more than happy to open up for questions at this time.

We will now accept questions at this time. If you would like to ask a question, please press star then the number one on your touch tone phone. If you're in the queue and don't want to ask a question. Please star then nine. Our first question comes from Paul Woodsome (ph) of McDonald's Investment

Paul Woodsome (ph): Wondering if you're thinking more individual assets or perhaps whole companies. Could you give us a sense of how much you've ear-marked for that strategy then the time line as to whether you would rather turn that cash to shareholders or pay down debt if you don't find anything.

Initially. If you'll let me back up and look at our strategy at the non-regulated side of the business. These are energy based or asset based. As we saw the market shift, our original interest was in requiring individual assets or groups of assets. As we explored these asset acquisitions and time is going to have to tell how this is going to play out. The first question is are price is going to rationalize in a range that makes these that are attractive to us from a return basis. As we're going into this, our intent was to get things that were very clean and simple. That would lead you to individual asset acquisitions. Something where the economics were very transparent and you could close transactions quicker. What we're experience in the marketplace is a combination of factors including prices have not completely rationalized or there are financing structures around the assets that bring more complications than you would desire. So we are also seeing situations where there's bundles of assets where you might see one gem in the middle, but they're intertwined with financing that might make it hard to get to the asset.

So the long part of the question is we're going to have to wait and see. This could take six to nine months to play out. So, we are going to continue to monitor and evaluate and where appropriate put in a bid on assets. I would say to the second part of your question, a year from now , if this is not played out and we don't find any opportunities. At that point in time, we're going to have to evaluate our alternatives. We have said consistently, that we are going to invest if it meets our strategy and our return hurdle. If we don't find assets or other opportunities that are attractive, we will use the cash to return to shareholders or pay down debt.

Paul Woodsome (ph): Could you give a rage of what you're looking to spend?

If you look at our July presentation , on average, we would have to invest about 450 million dollars per year in growth capital in order to hit our over all growth objectives. We've also said that on any given year that could range from very low, almost nothing, to $500 million dollars. Over a five year period, we believe we could have the cash available to fund 2.8 billion - 3.5 billion. Now, initially, if there are -- there are very attractive opportunities that show up in the marketplace that that we will have a look at. We are going to have to evaluate, first of all, can we do them organizationally and operationally and how would you financial it. If something showed up initially that is greater than we could finance with debt, we would have to issue equity.

Paul Woodsome (ph): Thank you, very much.

Your next question comes from Terry Shoe (ph) of JP Morgan

Terry Shoe (ph): Just to clarify. For 2002 cashflow, the number that you gave, a billion dollars if you could give the pieces a little bit - the obvious pieces earning, net income, plus depreciation then you have working capital. Is this after common dividends. I would assume so, right? The cash from operations.

I'll start answering that. Then I'll ask Nick to join me. When we refer to cash flow that we show on our charts , net income adjusted for your balance sheet accounts. That is before capital and before dividends. So cash from operations is that's in the one billion to 1.1 billion range. But net income adjusted for working capital primarily.

Terry Shoe (ph): And shareholder dividends plus your capex of 950, just for 2002 if you can again outline you said it included 200 million of NOx, what part of it is the maintenance capex. If you could take us into 2003 in the outlook of cash flow that you have now and capex.

Let's start with capex. This year is a rough number. The way to look at it is we're going to spend 550 million, of what we call base capex for the utility. Broken very generally into 450 million for Detroit Edison and 100 for MichCon. In addition, you can add 200 million this year for NOx. Now, there's two things that we want to say about the NOx spending. First this is the peak year for that. It phases down over the next years. The second thing as I said, we do have statutory authority to recover NOx spending. Then you can add to that, the non-regulated spending. This will be about 200 million dollars this year.

Terry Shoe (ph): Okay, what is that being spent on?

A variety of projects, notably this year in getting the syn fuels up and running. Moving onto 03 without giving specific numbers. Although we expect the 550 on the base regulated to come down a bit. Then on the nonregulated side just to follow up what Dave said. It's depending on what opportunities are available in the market.

Terry Shoe (ph): I assume that you probably have at the low end just some finish up type stuff on syn fuels. Then on the high end that you see opportunity.

That's essentially what the range is 100 million, of what we'll call base non-regulated.

Terry Shoe (ph): NOx, when you say substantially lower, is it half of next year or like hundred million vs. two hundred million that drop off?

It's about half.

Terry Shoe (ph): Okay, thank you. Then a separate question just on the outlook of 2003. You mentioned one of the uncertainties would be purchase power cost because of the firming outage. How much are you short for next year and how much is hedged, etc., etc.. What is your variability on your outlook in 2003 because of that?

We are short is -- our short is coming down and around 1500MW. The way power price have worked out for us , actually the current update is not too much different from what we talked about in July. With power prices coming down we will actually show about 30 million of favorability in the summer peak, because the purchasing less power and the prices have come down. However in what we described as the shoulder month, the prices have gone up and we're purchasing more power because of Ferme (ph). So net, net we're flat for the year in terms of purchase power next year.

Terry Shoe (ph): Is it locked in or is there still some variability around it?

The summer is locked in we pre-purchased our summer peek. Its really the shoulder months where we have some variability. The variability effects us not only on the purchases to replace power during planned outages but there's also another variability which is Detroit Edison selling its excess power into the marketplace.

Terry Shoe (ph): OK, can we assume it's more or less of a wash but not too much variability as far as impact on financials?

Yes.

Terry Shoe (ph): The other variable I gather would be the over all economy in your region. There for impacting demand etc.. Is that, right or not right?

That's one way to think about it. Actually , right now imbedded in our forecast is assumed GDP growth of 2 to 3%. The other way that I think about this is the utility will experience its normal growth next year however that growth is being offset in many ways by the pension and health care costs. It will end up more flat next year. ?

Terry Shoe (ph): Right, but, again, you're not over exposed. When you look at it, you think that if demand outlook, its reasonably predictable.

Yes.

Terry Shoe (ph): Thank you.

The next question comes from Paul Desblack from ValueLine

Paul Desblack (ph): Hello. Can you update us with anything new of the operating system that was spoken about at the July meeting and anything you're doing to reduce the pressures of health care and pension?

What we talked about in the July meeting is we have a pretty concerted effort in place. This is similar to concepts that for example Toyota has done trying to streamline operations, simplify and drive out waste. We're using this across the organization as one of our levers to offset inflationary pressures and costs. This isn't necessarily a big bang cost-cutting move. Some organizations might step in and say we're tacking out 15% of our costs tomorrow. As much as empowering our employees, to look at every opportunity to take out costs and stop doing things and do things more efficiently. That is one of the things that we're using to offset some of the inflationary pressure that we're seeing, including health care costs.

Paul Desblack (ph): Okay. Thank you.

Your next question comes from Kerry Stephens of Morgan Stanley.

Kerry Stephens (ph): Good morning. I was wondering if you could give us the EPS impact of weather vs. Normal vs. Q3 01.

The weather impact in the third quarter was about a 10 cent positive.

Kerry Stephens (ph): Versus normal?

Yes, that's right.

Kerry Stephens (ph): Great. You would have earned closer to 85 cents without the tax rate adjustment?

Yes.

Kerry Stephens (ph): Then we're getting close to 405? So I was curious as to why the guidance would remain the same, is it expected that the 10 cent sort of reverses out in the 4th quarter?

Our review of guidance for the year -- first of all when you look at last year. We had 40% of our earning in the fourth quarter. There is a large amount of uncertainty of the weather in the gas demand, we're also going to have to see how the economy plays out. Signals are mostly up and down. Mostly down these days.

Kerry Stephens (ph): Is that 10 cents going to reverse out in the third quarter.

Yes, it will. The estimate of $5 million dollars for the adjustment in the third quarter.

Kerry, this is Dan, one thing to be careful with, the tax rate adjustment in the forth quarter of last year was about 20 to 25 cents positive. That plays into if you were to take nine months this is year, add in last year's quarter as sort of a surrogate, you'd need to be careful. You need to take that effective tax rate adjustment out of the equation and look at the quarter.

Kerry Stephens (ph): With forth quarter last year I don't remember, weather was...

It was mild. It was not a strong gas heat heating season.

Kerry Stephens (ph): Also , just noticed industrial and commercial sales for the quarter were down.

That is partially due to the customer choice impact. That's customer classes that are impacted by choice versus residential where there's no choice at all.

Kerry Stephens (ph): Was it in line with expectation?

Yes.

Kerry Stephens (ph): Okay. Thanks.

Your next question comes from Annie Sale (ph) of Alliance Capital.

Annie Sale (ph): Hi. I just have a follow up question. In terms of your talking of a purchase power contract and purchase power costs for next year because of the firming outages and you talk about the summer peek. You have mostly lock ins and can you talk more on your shoulder months. That's the part that you didn't have any part that's lock in, I'm wondering how many risk management you have in that part. Do the prices go against you, would you have negative surprises coming to that?

Let me describe the situation. Detroit Edison is short on power, summer peak primarily and this is something that Detroit's summer peak purchases have been coming down over the past several years. We used to purchase about 1800 megawatts, now, it's down to 1500 megawatts. Our summer positions are 100 percent hedged and those have resulted in 20 to $30 million dollars of favorability. On the shoulder months it's different. Where the shoulder months, the prices have gone up slightly and because Ferme (ph) being out we have to buy about 900 gig watts extra power, for the Ferme (ph) outage, it's a fueling outage. A combination of slight price increase and buying the extra 900 gig watts of electricity offsets the favorability we see in the summer peaks.

Annie Sale (ph): In your 03 guidance can you tell us what prices you assume?

It's basically for the shoulder months? It's we're basically using the forward curve when we do that. You're seeing a 40 to $50 dollar a number for the summer. And a $25 number for the shoulder months. It's nothing that's been very stable. We expect to be stable because of the over supply situation in the region in the country.

Annie Sale (ph): Okay. Thank you.

Your next question comes of Steve Fleishman of Merrill Lynch.

Steve Fleishman (ph): Can you hear me?

Yes.

Steve Fleishman (ph): Can you elaborate on the issue again with respect to utility. Recovery situation on the choice and what is the lingering decision that needs to be made there again?

Two questions or you want me to answer that first? The situation on customer choice is under law, there is a provision is this is going back to the 2000 restructuring law that froze rates and allowed a recovery in Ferme (ph). We are entitled toll the economic harm. This would be customers got a choice the difference in the margin that we would get at bundle rate versus margin at wholesale. Who pays for that, and over what period is subject to a regulatory proceeding. We did our initial position and the staff came out early in the year with a filing. We believe used old data and there were some differences in views of how you calculate this. We're going through this process now, as CMS (ph) is also -- the next step in this is the staff will re-file their testimony later this year. We will also push for this to be resolved hopefully in the first quarter of next year. The net result is that we believe the economic harm for this year is about a 40 to 45 million dollar number, and we anticipate that the regulatory assets offset that.

Steve Fleishman (ph): Ok, the reason...

It won't be resolved until next year. We will continue to defer this amount and post rate will be collected. For some group of customers.

Steve Fleishman (ph): Now, the reason you bring it up in discussion of 02 , -- you're really, you plan to book it and defer it. It's not going to rule next year anyway. I guess this is really an 03 issue either way?

The reason we bring it up in terms of 02 in our guidance we assume that the 40 to 45 million dollar referral. We are working with a staff and waiting for the staff to file their position. There is a question about whether the amount -- we're calculating it within a ballpark of what they would calculate it. As we work with our accountants we don't want to work too large of a regulatory asset only to have that revised and written off in a future date. So we're looking for some indication from a staff so to see how they calculate that to make sure that we are within some bandwidth if we record this. And the reason we keep bringing this up is we're waiting for them to bring some tentative positions. And then the number, maybe it wont be 40 million, even if we believe its 40, maybe its 38, so there might be a slight revision to this regulatory asset we keep talking about because of methodology in particular.

Steve Fleishman (ph): So the key thing to watch is what the FASB says in their updated testimony.

yes.

Steve Fleishman (ph): My other question. I apologize for this one. If you could run through on the pension side. I believe you said the higher cost is 90 million in 03?

That is for more than pension. If you look at the components of costs, we have pension and retiree health care. They actually work very similar. The calculations and are impacted by return on assets and discount rates. Those two items together are in the 50 to 55 million dollar range. Then when you add in active health care and security costs and insurance costs you put all of them together it's in the 90 million dollar range. Pre-tax.

Steve Fleishman (ph): Then you mentioned 350 million dollar equity at your end?

Right.

Steve Fleishman (ph): Is there any plan to infuse cash?

Well, first of all, let me back up, the hit to equity is something called the minimum pension liability. This is something where you credit the pension liability and the debit goes to equity and other comprehensive income. We believe it's a temporary item that eventually turns around. We talked to the rating agencies about this an we believe it will be included when you compute leverage. Now, on cash, we do not believe that we have to put in cash until 2004. However, one of the ways we're look looking at everything we can to reduce pension expenses YOY and one of the options is to prefund our 2004 obligations in January of 2003, it's something we're considering right now. We're going to talk to our board later this month.

Steve Fleishman (ph): That will reduce the income statement costs?

Yes.

Steve Fleishman (ph): Does that include the prefunding?

The cost that I'm giving you is net of a variety of actions including the prefunding.

Steve Fleishman (ph): Okay. Thank you.

Your next question comes from Zach Shriver of Ducane Capital.

Can you hear me. We're just wondering how much you would be thinking of prefunding on the pension in 2003 if you worked out the over all capex budget.

On pension funding. We are not required to put in any cash. There are two triggers that could cause you to put in cash to your plan, one is a PBTC (ph) requirement and another one is an ARISA requirement. We believe in 2004, at the PBTC (ph) threshhold we'd have to put in about $200 million dollars. That is the number that we are evaluating and the way I think of it is if I had to put it in 2004, can I prefund it in '03 and reduce my pension expense. At this time we're not considering putting in anything beyond that and I still have the option to not putting it in so we are evaluating that cash versus our other use of cash.

Zach Shriver (ph): I'm sorry, that number was 200 million?

Yes.

Zach Shriver (ph): As far as the transition sale goes, the NBV of that asset is 300-400 million?

375 roughly. The sale now the process is well under way. We'll be selling this for a multiple of book. Not at book.

Zach Shriver (ph): What's the tax basis of that asset?

The tax basis?

Zach Shriver (ph): Yes, sir.

The tax gain -- I'm not sure I even. The tax base is about 250 the book base is 375.

Zach Shriver (ph): Is that preferable sort of FERC rate making regime around that still exists for the seller and do you still earn your 11percent ROE on the asset?

As we know it will provide incentives for independent owners. We don't believe it's in our interest to be a passive owners. We continue to look at divesting the transmissions systems under the right conditions.

Zach Shriver (ph): Great. On syn fuels. What annual run rate is under production right now? Is the market per on the under the $12 per on the range after tax? Even the restructuring from below the line tax benefit or from operating income given that they are wealthy trust structures?

Just to give you a sense when that business gets fully up and running , we expect the run rate to be 11 million tons of cold process. So obviously this year has been one in which we've been putting those plans into introduction. Now, they all are but not all running up to that level of annual run rate yet.

Zach Shriver (ph): What production do you expect and should we expect an increase in 03 over 02 from getting a full year run rate from having all the plants in service?

I think roughly the 02 number is going to be around 9 million and next year is going to be 11 million. There ought to be a bit of an uptick there.

Zach Shriver (ph): Is that output contracted at all? Or is it at spot coal prices or some discount thereof?

Of all that capacity is contracted by the host, whether it be a power plant or a [ inaudible ]

Zach Shriver (ph): As far as the economy goes, you talk about a modest recovery in 2003, I think it's the same kind of language you've been using over the last year and half. What exactly do you define as a modest economic recovery?

It would be roughly a GDP of 2-3% of analyzed basis that would allow our utilities to grow at about 1-2% something like that.

Zach Shriver (ph): Thanks so much. Great quarter.

Your next question comes from David Frank of Simmer Lucas.

David Frank (ph): Just wanted to verify a couple things you talked about. Could you give a break down of the higher pension and medical benefits expenses by the utilities or business lines within DTE?

I would rather not at this point at time. I'd be willing to do at our year-end call. All the components are moving right now. Our actual returns to date for example as the market moves every day is a big component of this. The discount rate which is another big factor of this. We'll see what the fed does this week. All the pieces are moving, and I'd rather hold off and give it to you at our year end update.

David Frank (ph): Could you say that DTE the electric utility typically accounts for 50% of pension expenses and corporate etc. is there some allocation?

It's primarily in the utilities. Our non-regulated businesses do not have a defined benefit pension plan or do they provide retiree health plan. It's in the utilities. I don't have the break down now between Detroit Edison and MichCon. We could follow up and give that to you.

David Frank (ph): Okay. Your 02 guidance includes or excludes 40-45 million dollars of margin loss from customer shopping?

It includes the assumption that we're going to book the regulatory asset and recover that 40-45 million regulatory asset

David Frank (ph): So you're not penalizing yourself for that hurt to earning then?

Right. We're assuming that our estimate of the economic harm from choice this year which we think is about 40 to 45 million dollars will be recovered this year.

David Frank (ph): The same goes for 03 then obviously in your guidance?

Right.

David Frank (ph): I also wanted to check the 300 to 350 million dollar write down what you could take to equity as a result of growing pension liability? That's net of any prefunding contributions you would make or other mitigation efforts?

Yes.

David Frank (ph): Okay. That could be offset if you do sell the transmission assets for a gain. That would go to offset that?

Actually they are independent calculations, this minimum pension liability, the way it works is you look at year-end. So we will look at December 31, the fair market value of the assets in the plan versus the liability. And in this case we believe we will book a debit to equity. As the fair market value of the assets. This is more driven of the asset side versus the liability side. As the market returns over time, the debit reverses out. This is a deferred charge and I believe it's nothing more than an indicator that at some point in time you have to put in cash, beyond what, it's not very meaningful.

So we will book that debit to equity and over time as the value of our asset increases I believe they will , that that debit reverses out of as equity and eventually will go away. The estimated leverage of year end of 52-53 percent incorporates a 300 million dollars reduction in recorded equity.

David Frank (ph): Okay. Thank you very much.

Your next question comes from Phyllis Gray of Dwight Asset Management.

Phyllis Gray (ph): Good morning. Could you provide a little more detail about your liquidity at the end of September. In terms of the credit revolver and the timing for that, any drawdowns currently in place?

Let's start from where we're at now. As I said in my comments we successfully renegotiated our bank's revolver. Taking a cursory look at our liquidity, we have a 1.2 billion dollars of bank backstop for our CP program. We have not, since I've been here ever drawn on the bank backstop. But, it does support our commercial paper. In addition, there's another 200 million dollars in liquidity, that's backed by trade and receivables and again it's just backed up for additional commercial paper. That extends out to 04. We have 1.4 million dollars of available liquidity. And as of just a few days ago, we have about 500 million of CP outstanding. So you take 1.2 billion of bank backstop to the additional 200 million of receivables, subtract the CP balances and you get about 900 million of available liquidity.

Phyllis Gray (ph): What about cash?

Again, we're a borrower now. Some minor cash on hand. Through the coarse of the year, in terms of working capital we are a net borrower.

We also demonstrated this year the ability to issue in the equity and debt markets. The equity issuance earlier this year was three times oversubscribed at a very favorable and it was something that we played into a story of strength. In terms of that the debt, the Detroit Edison refinancing that we did in the last couple of weeks is an indication to our ability to access debt market. We issued 10 year paper at 5.25 and 30 year at 6.3%. Both were 3 times oversubscribed.

Phyllis Gray (ph): Thank you. Do you have a break out similar to your earning per share break up of your cash from operations expected from the different segments for 02?

Let me give you this at least. As I said, cash from ops will be over a billion dollars. About 200 million of it will come from the nonregulated side and the remaining coming from the utilities.

Phyllis Gray (ph): And finally, what do you expect your total interest expenses to be for 2002?

By don't know that I have that handy. We could follow up with you.

Phyllis Gray (ph): That would be fine. Thank you.

Your next question comes from Greg Oral from Lehman Brothers.

Greg Oral (ph): Good morning. Could you go over the 02- 03 implementation that meets standard. Again, I did not catch what you said.

You're talking about the EITS (ph) on trading companies. There's several components of the FASB standard that just came out. The first one was the netting of revenues on trading companies which as Dan indicated that we have done. It's something what we welcome. Because in our trading operation we never focused on our revenue. As a matter of fact if you had asked recently our revenue for our trading operations, I don't think most people here could tell you. Because we always look at net margin and net income. We've adopted that portion of the accounting standard and that's in our revenue line that we just disclosed. There's a couple other components of this accounting standard, and one is the elimination of first day gains. Because of the short tenor of our trading operations, we've said this before the majority of our trading operations are transactions that have a tenor of two years or less. That's something that we are looking at right now.

The one area where we are looking at evaluating is the accounting implications on gas storage and gas pipelines. It's premature to say the impact on us. And its something that we think is going to work out good for us because in the gas storage as we've indicated before, we had this phenomena where we are marking the forward sale to a forward curve and we're marking gas and storage to spot price and if they didn't move in tandem we could have a mark to market gain or loss. And what this accounting standard is saying is that your inventory you are now going to count at cost, not at market. So the question is, how do you do that. What is cost? It's something that we have to do and update you on later.

Your next question comes from Terry Shoe of JP Morgan.

Terry Shoe (ph): I have another question. Going back to the transmission sale. I didn't catch what you said as terms of the likely proceeding. I think you said multiples of book value which you said the book value was at around 375 million. Did I hear that correctly , Dave?

Yes.

Terry Shoe (ph): So if you sell at multiples of book, that means it will be close to a billion, what does that mean?

No, one way to think about it is if you just do the math on an NPV basis. Just to replace earnings from that business. You need to sell that at about 1.2 times book. That's going to be our threshold. We are not going to do something unless we expect it to be above that.

Terry Shoe (ph): When you say replace earning. If you don't have anywhere else to put it, it's that retirement and you calculate it what way. Is that the way you're looking at it in terms of how to replace the lost earning? Wouldn't you have initially probably a drag from the sale? Unless you can quickly deploy it because I assume the earlier question said earning around 11% or something like that.

You're right. We also have several irons in the fire that we've been talking about in the terns of potential asset acquisitions, for example Biomass acquisition would be an example of redoploying that cashflow.

Terry Shoe (ph): How near term is this thing? Is it within months , quarters? Who are the potential buyers there?

We anticipate being able to announce a transaction before year-end. This will likely close within the first quarter of next year.

Terry Shoe (ph): Okay. You already have concrete plans in mind. They wouldn't be an initial drag, correct?

Well , it's part of the variable depends on these asset acquisitions that we're looking at. There could be a possibility that we don't find opportunities to invest capitals. Then we're just paying down debt.

Terry Shoe (ph): The other question is this choice recovery. Is it a matter of just how you calculate it. Maybe you in the commission with like in any rate case argue about details but in terms of your right to recover its legislatively dictated.

It's how you computes it and who pays and over what period is how I look at it. We start with a very strong position of having legislation behind us.

Terry Shoe (ph): As far as the number the 40-45 million that you booked. I forget, the annualized number is what, for 2003, for example. Potential loss of revenues?

The 40-45 million is our estimate of the economic impact of economic loss due to choice when our assumption is you have will 8-10%. Our estimate next year is we will have 10-15% of customers going to choice.

Terry Shoe (ph): So the larger is 40-45 million?

Yes, the number will go up.

Terry Shoe (ph): So it would be 50- 60 million.

Yes.

Terry Shoe (ph): As far as arguing about what the exact computation is, I suppose it's surrounding that number. Not the whole thing. There's never a question of that being at risk?

Right, its an issue of methodology, timing and mechanism.

Terry Shoe (ph): Right, post rate freeze, the on going drag will still be there.

What do you mean the ongoing drag?

This will be swept up in the comprehensive discussions that we will have in what happens post rate freeze. If the states don't want us to have a customer choice program it would be compensated for that.

Terry Shoe (ph): Thank you.

Tracy. Since we seem to be going around the horn again in terms of the questions, I think we are going to have to make that the last one. We an internal call in about two minutes. That will be our last call.

That's fine there were no further questions in queue.

Thank you everybody. We look forward to talking to you again at the first of the year.