美國電力 (AEP) 2003 Q3 法說會逐字稿

Ladies and gentlemen thank you for standing by and welcome to the third quarter 2003 earnings conference. At this time all lines are in a listen-only mode. Later there will an opportunity for questions. Instructions will given at that time. If you should require assistance during the call please press star, then zero. As a reminder, this conference is being recorded and replay information will be given at the end of the call. I would now like to turn the conference over to our host, Senior Vice President, Armando Pena. Please go ahead.

Thank you and good morning everyone. We're here to discuss AEP’s earnings for the third quarter of 2003 and provide you with our earnings guidance for 2004. I expect you've received the press release earlier today. It's also available on AEP.com. The earnings release and other matters that may be discussed on the call today contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to the SEC filings including the most recent annual reports and our form 10 K and quarter reports on the form 10-Q for a discussion of factors that may cause results to differ from management projections, forecasts estimates and expectations.

Also on the call we will discuss measures about company performance that is ongoing versus reported earnings that differ from those recognized by generally recognized accounting principles or GAAP. You can find reconciliation of these nonGAAP measures on our investor relations Website at WWW.AEP.com.

There are several members of management here. But I am going to turn the proceedings over to Linn Draper, CEO of the company, to lead an opening presentation, and then at the end, there will be time for questions. Linn?

Good morning and thanks, Armondo. I plan to review with you the results of operations for the third quarter and the first nine months, and to give you our current view of the company's earnings forecast for 2004. I'll then ask Susan Tomasky to highlight the current financial profile for the company before we open the call to questions.

Ongoing earnings for the third quarter were 76 cents a share. Reported earnings were 65 cents a share, or about $257 million. The difference is due to an impairment loss of $45 million, or 11 cents, on two independent power production plants. They're part of a group of four IPPs that we're currently in the process of selling. I'm pleased to report that despite the unfavorable weather conditions experienced in a large portion of the company's service territory and severe storms that resulted in unexpected repair expense, our core utility operations performed well, declining only $38 million year over year. However, we continue to be disappointed by the underperformance of our noncore investments and remain committed to divest these assets.

There were four primary drivers leading to the 45 cent year over year decline in ongoing earnings. They were unfavorable weather, accounting for 7 cents a share, share count dilution, accounting for 13 cents a share, the loss at AEP Energy Services accounting for 6 cents a share, and the negative impact of timing differences related to accounting treatment of freight hedges in our UK operations producing a loss of 7 cents a share, about which I'll say more in a few minutes. For the year to date period, ongoing earnings per share were $1.82, compared to $2.37 for the same period last year. Although the third quarter was a challenging one, we believe that our 2003 earnings will be within our previously stated range of $2.20 to $2.40 a share. However, the timing difference is related to the accounting for our freight hedges in the UK business is now pointing us to the lower end of that range. This effect results from the timing differences in accounting treatment for physical versus hedge transactions that must be mark to market.

The cash flows associated with this business are well hedged, and indeed it's this hedging activity that's the cause of this timing difference. This quarter's losses will be offset by corresponding accrual income, overtime predominantly during 2004. And, again, I'll discuss this in more detail in a few minutes.

Let me talk about utility operations for the quarter and year to date first. Then I'll talk about the investment segment before moving on to 2004 guidance. The details for utility operations for the quarter are on page 7 of the earnings release.

2003 net earnings of $394 million for utility operations were almost 9% below last year's $432 million as shown online 16. Total gross margin was down $94 million, or 4.5%, to $2 billion. The decline was mainly driven by the reduced demand associated with mild weather and the reduced margin contribution from our Texas supply business.

Our coal fire generation performed well and was available for higher volume of sales to the wholesale market at higher on-peak prices this year to offset the lower retail sales. $61 million in Ecom earnings was another positive factor for this quarter.

ONM expense declined $15 million despite increased storm costs. Total domestic retail load for the company was down 2.3%. Primarily as a result of lower residential, down about 6%, and industrial, about 1.7%, as shown on page 9 of the press release.

Weather in the east was extremely mild with cooling degree days 13% below normal for the quarter and down 33% from the same period last year. The impact of mild weather is reflected in lower year-to-year gross margin from AEP's regulated integrated utilities line one and the Ohio companies' line two. The Texas wires margin line three was up $19 million primarily driven by $61 million Ecom revenues that in 2002 were not recorded until the fourth quarter. You may recall that these noncash earnings associated with stranded cost recovery reflected difference between the actual price received from the state mandated auction of 15% of our generation capacity and an earlier estimate of market prices derived from the Texas public utility commission's model.

These revenues are regulatory assets recoverable in cash through a process established by the Texas deregulation law. The Texas supply margin line 4 was down $89 million primarily due to the reduced gross margin associated with the sale of the reps that was replaced in part with the Sentrica supply contract which extends through 2004.

The outage at unit one of the STP nuclear plant also contributed to the reduction in the Texas supply margin. STP unit one returned to service on August 12th, following a 19-week outage to repair a reactor vessel instrumentation penetration. You probably recall that AEP owns 25% of the STP plant.

The FERC municipal and co-op margin line 5 was down $22 million, mostly due to FERC contracts being renegotiated at market base rates.

System sales, line six, were an extraordinarily positive contributor to the quarter, helping to offset some of the earnings pressures that I mentioned earlier. The strong performance here was driven by the combination of available low-cost generation made available by lower weather-related retail demand, which was sold to the wholesale market. Our successful optimization efforts and higher on-peak power prices were also helpful. For example, the average on-peak price in the into synergy hub was $38.70 a mega watt hour for the third quarter of 2003, compared to $33.50 a megawatt hour last year.

On the expense side, ONM expense line 11, was down $15 million despite increased storm recovery costs. So earnings per share for the quarter from utility operations were $1, as shown online 16. For the year to date, as seen on page 10 of the earnings release, ongoing earnings from utility operations were $928 million compared to $896 million for last year. The improvement comes from our effort to control costs despite upward pressures.

Ecom revenues in the Texas wires line and impressive success in optimizing our coal fire generation in the east resulted in a 79% increase in system sales, which worked to offset the reduction in gross margin from our retail sales, our Texas supply, and discontinued speculative trading activity outside our physical footprint. I think it's important to note that we are delivering the reduction in O & M costs that we identified for you a year ago.

For our utility operations online 11, you can see that O & M has declined $39 million year to date in 2003. This has been a challenge given that the $31 million storm damage costs which we incurred this year was $20 million over the 2002 year to date. We're also absorbing year on year increases and plant outage and maintenance costs of about $32 million, and increases in pension and post-retirement benefits of $46 million.

Our year on year cost performance reflects a reduction in staffing of roughly 1700 employees as well as savings in overheads and outside services. I expect that our continued focus on O & M expenses will deliver approximately $90 million in cost savings at year end for our utility operations as we originally had predicted.

I'd like to turn to the performance of the investment segment now, beginning with the third quarter performance on page 7 of the press release. Earnings from investments in the third quarter totaled a negative $71 million, down another $52 million from last year. The decline in performance reflects the ongoing challenges at our domestic gas business and timing differences related to freight and hedges at our UK business.

The gas business online 17 includes our domestic gas pipelines and storage operations as well as the transitional trading book for gas. This quarter the gas business produced a loss of $20 million compared to a net income of $5 million last year. The significant decline in attributable to lower margins associated with the scaling back of gas optimization in marketing activities in line with our reduced risk appetite. Lower staffing and financing costs have helped to offset a portion of these thinner margins.

It's important to note that the pipelines produce positive EBITDA, but not enough to overcome allocated overhead and financing costs. As we mentioned during the second quarter earnings call, it's for these reasons that for the year, losses associated with the domestic gas operations will exceed the $15 million originally projected.

The UK business, line 20, posted a loss of $51 million during the third quarter, compared to a loss of $5 million last year. The reported loss is attributable to timing differences associated with the accounting in our fuel procurement operations of physical freight contracts requiring accrual treatment compared to freight hedging contracts requiring mark to market treatment. Reducing -- reduced trading activity from our reduced risk appetite and increased operating costs largely associated with the exit of non-core markets.

Let me describe the fuel procurement strategy for the triple F plants. These plants are unscrubbed and have limitations on the amount of sulfur they can emit. In order to maximize generation hours with these emission limits we obtain low-sulfur coal from international sources that require transportation by ship. So there's a coal component and a freight component to our procurement work.

The third quarter has witnessed an unprecedented increase in freight costs driven by a worldwide shortage of vessels. Prices have more than doubled. While physical contracts are accounted for on an accrual basis, freight hedges are mark to market. So when prices go up, as they did in the third quarter, the accounting related to a hedge position reflects a loss in the present period that's offset by a corresponding gain due to settlements occurring over time. Conversely, if prices drop, the gain occurs immediately, and there's a cross funding reduction in the accruals over time.

The dramatic run-up in freight prices has amplified the effect of the timing differences associated with freight hedges. And was a major contributor to the weaker reported earnings this quarter. What's important to know is that the company is well hedged in its freight exposure and will show corresponding gains due to settlements occurring over time, as I said earlier, predominantly during 2004.

Year to date performance of the investments on page 10 of the press release package declined $98 million versus 2002. The reduction is attributable to the $88 million loss posted year to date at our UK operations, and the $58 million of net income posted in 2002 from seaboard operations that were divested last year.

The year to date loss at our UK operations was driven by the deterioration in power markets in the early part of the year, the cost of exiting the Nordic business, reduced trading activity consistent with our lower risk appetite, and the accounting treatment of physical freight versus financial freight on our fuel procurement operations that I just discussed.

We had originally projected a loss of $103 million for the UK business, and we told you at the end of the last quarter that this should improve. However, this new volatility in coal and freight prices will place downward pressure on the results this year.

We continue to look for opportunities to exit both the gas and UK businesses. We plan to divest the HPL assets sometime after the resolution of the ENRON bankruptcy issues. An adviser has been selected for the league disposition, and the information memorandum is about to be circulated. We've selected an adviser for the disposition of the UK business, and are evaluating the market for disposition of these assets prior to our assumed date of year end 2004.

Let me now turn to 2004 guidance. I know you've been very interested in this subject. Our utility operations have performed extremely well in 2003 despite poor weather, and I expect they'll continue to do well next year.

We are looking at numbers that suggest a relatively flat year compared to our 2003 projection. As you read in our press release as you read in our press release this morning, we expect 2004 earnings per share to be in the range of $2.10 to $2.30.

The primary assumptions and earning drivers for our core utility business are as follows. They're normal weather, economic recovery, the discontinueance of Ecom-related earnings, completion of the sale of the Texas central generation assets by September 2004, and elimination of the margin we're enjoying this year associated with the reliability must-run contracts and capacity auctions, the cessation of the Cook restart amortization costs which have amounted to about $77 million a year pretax, and the reduced interest cost. We expect the investments to continue to produce losses next year.

However, we expect the losses to be much smaller based largely on the following factors. The losses around the intex contract that we experienced at HPL in the first quarter of this year should not be repeated. And a full year of lower interest expense and improved market conditions will benefit our UK operations.

It's obvious when you look at the investments that they pose a significant drag on the $1 billion in earnings from our utility operations. Again, the 2004 earnings per share calculation will be impacted by higher average number of shares outstanding, $395 million for 2004, compared to the 2003 count of $385 million. The share count dilution equates to roughly 6 cents a share.

We're preparing a point estimate for 2004 in the format that you are accustomed to seeing. And will have it available at the EEI financial conference and on our Website. Before taking your questions, let me now ask Susan Tomasky, our CFO, to give you a summary of the financial profile of the company at the end of the third quarter. Susan?

Thanks, Linn. In my brief remarks, I'll discuss our current liquidity position, cash flow and cash structure.

At the end of the quarter, our liquidity position remained strong with total available cash and credit facilities at $4.2 billion. We recently reduced the $300 million Euro facility down to $150 million, reflecting lower needs for working capital in our UK operations. And we added a three-year, $200 million letter of credit facility that's going to be used domestically in lieu of posting cash to counterparties.

As of yesterday, our commercial paper outstanding was $358 million, and cash on hand was approximately $1.6 billion. Placing our net liquidity position at $4.1 billion.

Let me say a few words about cash flow for the first nine months of this year. On our Website, you'll find a table with all of the numbers that I'm going to discuss. For the year to date, cash flow from operations was $1.6 billion and for the third quarter, $754 million.

Let me walk you through the year to date numbers. Cash flow from operations begins with the reported net income of $872 million. Then we add back depreciation, amortization and deferred taxes of $1.3 billion.

And we deduct four items. First, $193 million, which is the sum of the FAS 143, the reversal of previously accrued removal costs for nonregulated plants upon retirement and the cessation of EITF 9810 which is the mark to market of certain energy transactions.

The second deducted item is $83 million in mark to market changes, and the third is $296 million for working capital changes. And fourth, $145 million for changes in other assets and liabilities, which is predominantly attributable to $169 million in noncash Ecom.

The negative change in working capital of $296 million includes $90 million paid in settlement for power and gas transactions, about $60 million in increased fuel inventories, and $75 million in working capital needs at the UK business.

Investing activities year to date consist primarily of capital expenditures in the amount of $941 million. Financing activity so far this year have required cash outlays of $173 million. Sources of cash total $3.35 billion, consisting of our $1.2 billion equity issuance completed earlier this year and net long-term debt issuances.

Uses of cash totaled $3.53 billion including the $225 million paydown of the minority interest financing, $480 million of dividends paid, and $2.8 billion in net short-term debt reduction. That brings us to cash on hand at the end of the quarter of $1.7 billion.

Capital structure within reach of our revised target level of 55 to 60% debt to cap. After implementing reporting changes this quarter. You probably know about the Fin notice 46 which requires certain offbalance sheet arrangements to be reported as debt. We've therefore added $476 million of debt capital, mostly reflecting the lease of scrubbers at our Gavin plant entered into in 1994. Fin 46 also reclassified certain hybrid securities as 100% debt. The steel head financing of our gas assets we've previously labeled minority interest. The trust preferred securities and the equity units have all been reported as long-term debt under the debt category. This revised presentation of capital structure results in 62.6% debt at the end of last quarter.

Let me point out that the steel head financing is eliminated with the sale of our gas assets and the equity units convert to common stock in August 2004. I'm sorry, August 2005.

If I go a step further, and adjust the capital structure as we understand the reigning agency's practices, other offbalance sheet leases for the Rockport plant unit 2 and Dow plant in Louisiana are added to debt, a total of $1.7 billion.

But equity units get 80% equity credit, a reduction in debt of $301 million, and a further debt reduction of $966 million comes from securitization bonds serviced by Texas customers in spent nuclear full trusts that is fully funded with cash that is unavailable to the company. So in the end, the debt ratio is seen by the rating agencies is 62.5%, almost identical now to the point of leverage.

In earlier presentations, we had not included offbalance sheet leases in debt, and we had also credited available cash to the debt balance. Doing so today would result in a debt ratio of about 54%. The available cash by itself can reduce the debt ratio by as much as 3%. This concludes our prepared remarks, and we're now ready for your questions.

Thank you. Ladies and gentlemen, if you'd like to ask a question, press star, then 1 on your touch-tone phone.

If your tone is indicating you've been placed in queue, you may remove yourself from queue at any time by pressing the pound key. If you're using a speaker phone, press pick up your hand set before dealing. And once again, it's star-1 for any questions. Our first question will come from the line of Jeff Peters with Simmons. Please go ahead.

Good morning.

Good morning.

You show your utility margins and your offsystem margins, they were almost offsetting. Can you talk about the gross margin associated with power sales under the regulated environment versus what you're getting in the offsystem environment? And which is more beneficial for you?

Yes. You know, if you look at our sheet, the retail margins include the bundled retail sales. And that includes both the generation component as well as the transmission and distribution, but it is a bundled rate. So you see value in there. In addition, on the Ohio line and in the Texas line, you see Texas supply line, you see a similar charge. And that is essentially the retail component.

You compare that, then, to the system sales line which is where you see the sales into the wholesale market. There is not a one-to-one relationship. Whether or not it shows off as a benefit or a negative vis-a-vis the two will really depend upon market prices and availability of the units at any particular time.

But what we do find as a general matter is that in circumstances in which our retail margins are lower, either because of weather or because of industrial -- a lack of industrial demand, we are able to offset a substantial portion of that through wholesale sales. How much of that we offset is a function, obviously, of market prices, which are influenced significantly by gas prices as well as by plan availability.

In the third quarter, were you better off selling power offsystem than within your franchise territory?

I doubt it. Although we haven't done that particular calculation. To the extent that it was industrial load that was down, the wholesale prices probably were adequate to cover that to the extent that residential prices were down because of weather, they probably weren't.

That's helpful. Thank you.

Thank you. Our next question is from the line of Dan Eggers with CSFB. Please go ahead.

Good morning.

Good morning Dan.

Not to belabor the business you're hopefully going to sell here in the not so distant future, but looking at the UK, basically last quarter you guys benefited from positive procurement and movement this quarter, it worked against you. I guess first question is, can you strip out what the cost of the MTM hedges would have been on the numbers or what the recurring loss in the UK would have been this quarter?

Yes. With regard -- this is Tom Shockley. And with regard to the freight hedge losses that were reported this quarter, that amounted to about $28 million.

And that is going to cover -- is that covered through '04? Is that what you guys said?

No, these are marked as of September 30th. They'll continue to be marked to market, but they are as a hedge, and so they will come back with the locked in profit margin that was created when we put the hedge on.

And much of it will be '04.

And our year end projection takes into account the expectation that there will be some additional mark, obviously, if there continues to be radical volatility, we may see some further change in those numbers. But this, we think, captures it.

What are you seeing in rates during October? Have they moved further away from you guys?

They have.

Meaningfully?

We have a pretty substantial number in for our expectation for where they will go to because of what we've seen in October.

Okay. Very good. I guess another question, certainly a lot of talk right now coming from the Virginia legislature, at least people who want a push -- to push their opinion. Can you guys give us an update what you're hearing out of the legislature, where you guys stand, and kind of where your thinking would be, or outlook for that market for you guys if the energy bill comes through and extends FERC deadlines?

Let me take those in pieces. Because they overlap but do have differences. With respect to Virginia, the legislature, I think, is quite undecided. There is a lot of opinion being offered to the legislature, particularly around the possibility of an extension of existing rates. Through a very long period of time, perhaps 2010.

That is not an outcome, at least the extension of current rates, that AEP would support. Because we are differently situated from other utilities who may find their current rates more beneficial.

We're a low-cost provider in that area facing some additional costs, continued additional distribution hookup, storm damage as well as environmental costs. And were we to go forward in a regulated environment in Virginia, we would expect those costs to be recovered.

So we would not be advantaged by a flat extension, but we do think that if it is the will of the legislature to move forward with some form of reregulation as long as fair cost recovery is imposed, then AEP can do its service well and still provide adequate return to its shareholders. But that's the basis upon which we would fight.

It does appear that the energy bill is going forward. But the specific language around what's called the Shelby amendment is still held pretty tight. If, indeed, it does end up extending the deadline -- or imposing a deadline on FERC that says that they may not act before a certain date, with respect to voluntary -- others involuntary RTO participation, that certainly would be something that would put cards in the hand of Virginia with respect to the resolution of the RTO issue.

We continue to be working toward a voluntary resolution of this issue even under versions of the Shelby that I'm familiar with if we were able to work out a voluntary outcome, AEP would be permitted to go forward, but we continue to believe that we need Virginia's consent in order to go forward and we're currently operating within the framework of current law which prohibits us from going in before the middle of next year, but would require us to go into an RTO by the middle of the following year. Does that help?

Very good. Thank you, guys.

Sure.

Thank you. We'll now move on to the line of Kit Connelley with Morgan Stanley. Please go ahead.

Good morning:

Morning, Kit.

Morning Kit.

Couple of somewhat related questions. I guess all having to do with asset sales. I think Linn, you mentioned a desire to see if you could sell the UK assets sooner than your stated goal or kind of end date of end '04. Can you give us an update on that? Can you give us an update on the Texas generation and what's going on there? And finally, a separate kind of rate extension issue is one that you face in Ohio, which I think is bigger than Virginia certainly. Can you give us an idea of what you see there as a possible outcome?

Yeah, I'll take a quick shot at it. Then there are probably others here who can embellish on what I have to say. We still, for planning purposes, are assuming that we would sell the UK generation at the end of next year. But we think there is some opportunity to accelerate that. As you know, we have seen somewhat higher prices in the UK recently. That seems to have whet the appetite of people. So we'll explore that.

With respect to the Texas generation, we had a lot of interest in that generation. As you know, it's a mix of plants, some gas plants, some coal and a piece of a nuclear plant. There were a lot of people interested in various parts of it. Some interested in the whole thing. We have extended the time for them to finalize their bids.

Now, we expect that to occur during the month of November and then it will proceed as certain rights of refusal by co-owners to the coal plants -- or one of the coal plants and the nuclear plant. So we think that's on track, doing fine.

With respect to Ohio, we do have a situation in Ohio where it would appear that the commission is ameanable to extending rate freezes of various types perhaps with the opportunity for us to amend the rate to include certain other costs such as environmental things. We will be working to see if we can achieve that. But there's certainly nothing much to report at this stage.

Okay. Thank you.

Thanks. Bye.

Thank you. Our next question comes from Elizabeth Parrella with Merrill Lynch. Please go ahead.

Yes, a couple of questions. With respect to the freight costs, I think you mentioned it was $28 million in the quarter. Is that on the same basis as the triple F loss, or is that $28 million meant to be pretax?

It's the same basis.

Okay. And also, on Ecom, you're at $169 million year to date, I believe. How did the third quarter number kind of compare with your expectations, and for the year, do you think now that it would tend to exceed $180 million, which I think had been your previous estimate?

Elizabeth, that number came in a bit higher by virtue of the calculation that we go through for that. And we would expect it to end the year higher than the $169 million that we had estimated a year ago.

But would it be higher than the $180 million that you had estimated a year ago?

Right, right.

We would.

It's in the neighborhood of $205 million.

Okay. And then on your '04 guidance, does that assume that any of the nonregulated assets are sold or divested before the end of the year or at some point during the year?

Go ahead.

Yes, it does. We have a schedule of all of the activity that we have ongoing. And we pick up a number of those in the process.

I can give you --

Have you got the --

Specifics here. With respect to Lig, the assumption is it's gone at the end of June. HPL is in the forecast though December, as is Fiddlers Ferry. We see AEP Coal coming out at the end of the first quarter. The IPPs by mid-year. And some of the other smaller ones by mid-year.

Okay. Is it possible to take that 210 to 230 range for next year and tell us what the utility EPS estimate would be as part of that?

We will be providing all that detail on Monday.

Okay. Thank you.

You're welcome.

Thank you. Our next question comes from Paul Rizdon with McDonald Investments. Go ahead, please.

Actually, that was my question on the disk ops. Does that include any disk ops, treatment of assets, actually?

No.

Is that all, Mr. Ridzonn?

Yes, it is. Thank you.

Thank you. We'll move on to the line of Paul Patterson with Glenrock Associates.

Those were pretty much my questions as well. Let me follow up on Paul's last question, though. Why don't you hold them for sale in terms of reporting 2004?

That's a fair thing to evaluate, and we're doing that, Paul.

Okay. Great. Thanks a lot.

Thank you. Our next question is from Lee Anderson with Alliance Capital. Please go ahead.

Yeah, good morning. Just a quick question on the system sales line. Is that represent pretty much just your eastern fleet, or is there some Texas sales in there?

Pretty much the eastern fleet.

Okay. And so when you say you lost supply -- or you lost margin at Texas supply, were those -- did you actually sell less volume at those facilities, or did you just sell same volume, lower price?

It was mostly the latter, the volume didn't change that much. The price was lower, and we had the impact of the outage of STP.

So would some of those volumes show up in the systems sales line, which is a separate line?

No, they would be in the Texas supply line.

Okay. All right. Great. Thanks.

And if there are any further questions, please press star-1 at this time. We'll now move on to the line of Wen Wen Chen.with ABN AMRO Please go ahead.

Hi. I have a couple of questions. Then I think Vicki Jones has a couple. First, do you still expect working mutual capital for the year, or is that now negative?

I'm sorry, I couldn't hear you, Wen Wen. Could you say that again?

Yeah. Are you still expecting mutual working capital for the year?

Yes.

Okay. And what is your operating cash flow projection for '03?

It's about $2 billion.

Okay. Could you review what happened to the gas business this quarter? I just would like to know a little more specific, please.

Sure. I think we’ll get Tom Shockley to talk about that a bit.

The gas pipeline business continues to produce positive EBITDA, but we have a significant amount of financing costs based on the acquisition of those pipelines. And we also have been working to reduce the fixed allocations, corporate allocations, in line with the reduced activities, and that's an ongoing process.

Okay.

So if those two items are greater than the positive EBITDA.

Okay. What does reducing fixed allocations mean, exactly?

The corporation allocates its costs around to its business units. Based on different factors.

Okay. Also, could you give an update on the situation with finding a new CEO?

Yeah. I think there's really not a whole lot to report. As I've told people before, this may be repetitious for some, the human resources committee of the board is seeking applicants by using a search firm both internal applicants and external ones. They have contacted a number of people, and there's some yet to be contacted.

It's my expectation that the number of people who have been talked to would be reduced to a smaller pool that would be interviewed by the full board sometime before the end of the year, and it would be hope that a decision would be made sometime early next year. But that depends on a lot of things, including the specific circumstances of the candidate the board is interested in. But I think it's all on track for the sort of time scale that we laid out some six or eight months ago now which would conclude with my departure sometime around the annual meeting in April.

Okay. Thanks, Linn. And I just wanted to ask -- I'm sorry if I missed this -- are you planning on approaching the Ohio commission with a filing pretty soon? To extend your rate freeze?

This is Henry Fayne. We are in the process of trying to develop a framework, as you know, dayton has already filed something, and I believe first energy has filed something. We will be working in terms of trying to coming up, as indicated earlier, with a process that will allow us to cover any increased costs as we go forward. For that market stablization period.

Okay. Thanks. Those are my questions. I think Peggy Jones maybe had a question.

I just jumped on the call. Did you provide an update of the plant sale efforts in Texas?

We did.

Okay. Please don't repeat it.

Okay.

Peggy Jones Thank you.

Thank you. Our next question is from Lori Woodland with Schroders Investment Management. Please go ahead.

Hi. I believe you mentioned that on your '4 guidance, you're including an economic recovery. Could you give some insight as to if you're currently seeing an increase in industrial demand despite the mild weather, and give us a little more insight on the economic recovery metrics that you're using? The other thing I was wondering relates to the UK generation. To what extent that might be, EBITDA positive at this point? Thank you.

I'll take the first question. We do expect an economic recovery that will positively affect industrial loads next year. We really don't have for you today that kind of granularity, but we do expect to be able to give you some color around that next week. Tom, do you want to --

Sure. I'm not sure exactly where we stand on it being positive with regard to the UK. At the $100 million level, we were very comfortable that we would be EBITDA positive. As that moves around on us from a cash basis, the number that we're looking at has not changed that much because the losses were noncash losses. I would expect that would still be the case.

Okay. Thank you.

Thank you. And that does conclude our Q&A session for today. Please go ahead with your closing remarks.

Thank you very much, everyone for participating. There will be a large number of us at the EEI financial conference next week. So I'm sure that we'll be talking to many of you there. And you can also expect, in our web page on Monday, our presentation at the EEI which will take place on Tuesday morning and which will include a detailed forecast for 2004 in the format that we normally have presented before. So have a good day. And you will hear now some remarks about how to listen to the replay of this call.

Ladies and gentlemen this conference will be available for replay after 1:00 P.M. today through midnight Tuesday, October 28th. You may access the AT&T executive playback service at any time by dialing 1-800-475-6701. And entering the access code 699969. International callers dial 320-365-3844, using the same access code, 699969. That does conclude our conference for today. Thank you for your participation and for using AT&T executive teleconference. You may now disconnect.--- 0