美國電力 (AEP) 2005 Q4 法說會逐字稿

Welcome to the AEP fourth quarter 2005 earnings call.

[OPERATOR INSTRUCTIONS]

I would now like to turn the call over to the Vice President, Investor Relations, Ms. Julie Sloat. Please go ahead.

Thanks, John.

Good morning and thank you for joining us today to discuss AEP's 2005 fourth quarter earnings and earnings for the full year of 2005. I expect that you've already seen the press release issued earlier today. It is also available at our web page at AEP.com. In addition to the financial schedules included in the press release package, the web cast of this call will include visuals of charts and graphics referred to by AEP management during the call. An investor information packet will be available at AEP.com today at approximately 1:00 p.m. eastern. That will include a consolidated balance sheet and statement of cash flows, as well as full income statements for our Utility Operations, gas operations, investments, and Parent Company.

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 on form 10-K and quarter reports on form 10-Q for discussion of factors that may cause results to differ from management projections, forecasts, estimates, and expectations. Also on the call we will discuss the measures about company performance, that is ongoing earnings versus reported earnings that differ from those recognized from Generally Accepted Accounting Principles, or GAAP. You can find a reconciliation of these non-GAAP measures on our Investor Relations web site at AEP.com.

I'll now turn the proceedings over to Mike Morris, Chairman, President, and CEO of The Company to lead an opening presentation and then we'll have time for questions. Mike?

Julie, thanks a lot, and as usual, I'll join in welcoming you all here. I know this is again a busy day for you and we're encouraged to have all of you with us.

I obviously will share the speaking time with Susan, our Chief Financial Officer and we'll try to give you what we believe is a fair and full review not only of our 2005 performance but some of the issues that are facing us here in 2006, as we go forward. I don't think that there's any way to measure 2005 at American Electric Power other than saying it was a great year. The ongoing earnings performance was well above what we originally thought would be accomplishable in 2005, and I really need to thank all of the team here at home on how much was accomplished. The operating companies all performing as we had hoped that they would relatively comfortable rate treatment and most all jurisdictions, and we'll speak to the Texas issue in a moment. And overall some very solid year-over-year growth in our energy send-out, not only for what we consider to be system sales or issues sold to our retail customers, but an additional increase in the volume of energy that we were able to put into the off -systems sales market as well.

A couple of other very important highlights for us, and we think ultimately for those who own and work for this company, the fully funding of the pension at the end of calendar year 2005, as well as a dividend increase for our shareholders put in place by the board of directors in the fourth quarter. We obviously were very active in a small way in the asset acquisition strategy, as you know we added a couple of very important gas-fired capacity machines to our eastern portfolio with the Waterford and Ceredo purchases, and of course, as I constantly tease most people, we were active in the M&A activity purchasing through negotiations, the 59,000 customers of Mon Power here in Ohio. Not quite as big headline wise as some of my friends, but nonetheless we were able to negotiate an undertaking, with that activity approved by the Ohio commission.

We continue to feel comfortable about 2006. Our range for guidance remains the $2.50 to $2.70 a share, obviously January presents us and all utilities with quite a challenge already early in the year with incredibly warm environment that we've all been experiencing. Important for us in 2006, as before and going forward, will be the overall rate activity that has been teed up and filed in calendar year '05, much of which will be dealt with in '06.

It would be anything short of honest if I didn't say that we were extremely disappointed in the ECOM discussions that have been held by the Texas Commission in the TCC stranded cost true-up case. We believe that the Commission is wrong in the way that they've interpreted what we have done and we believe that that is an unfortunate impact, of course which is, as you know, the driver of the delta between the GAAP earnings and ongoing earnings for us in 2005. We have made the adjustments that we felt were appropriate under the accounting rules on the GAAP earnings forecast, or actual calculation, I should say, for 2005, and we'll continue to pursue our rights presuming that the final order from the Commission follows the discussion from the bench as is the case as you have seen before in Texas. Short of that, we felt that many of the ways that the Commission dealt with the TCC stranded cost case were appropriate. We felt that much of what they viewed was, as their staff had viewed and as we had viewed as filed. We will go through a number of additional proceedings in Texas in '06, much of it directed toward, obviously, the securitization of the final number, whatever that number might be, and Susan will touch on that a bit as we go.

We have very important filings in front of the commissions in West Virginia and in Virginia, Kentucky, and Indiana, and we will continue to pursue as aggressively as we can resolution to those cases when it's available to us. If not, we will continue to pursue those cases through their statutorily defined timeline to ensure that the capital invested on this system, which as you know, not only has been significant, but will be going forward, earns its appropriate rate of return, both for the debt providers as well as equity investors in our company. We feel comfortable about the opportunity to address some of those issues by way of settlement discussions, but as I said, if it doesn't yield the results that we think are reasonable for our shareholders, then we will go forward and continue to process the case.

Very important in Ohio, as you know, we continue to wait for a final resolution on the integrated gas combined cycle filing that was made in 2005, I would hope that we will have something to report on that matter early here in 2006 so that we can stay on our intended 2010 in operation date. As you know, we have made a filing, most recently in West Virginia, seeking the West Virginia Commission's review and approval of another gas combined cycle facility that would be built at our mountaineer station in West Virginia to continue to provide energy to the customers in our eastern footprint.

Obviously, and Susan will talk more directly to this issue, our capital expenditures for 2006 are a bit higher than they were, as we shared data with you on our first look at '06, at the EEI meeting not many weeks ago. Much of it has to do with capital being moved from '07 and '08 into '06, as well as some spill-over of things that didn't get done in calendar year 2005. We are concerned about the capital allocation as we go forward, as I know many of you are, but as we have said before, and Susan will give you a bit more granular detail, we continue to feel that we have the opportunity to manage the capital outflow as we go. As we look at projects and we look at assignments in front of us, we are encouraged by the opportunity to invest, but are mindful of trying to make certain that we have adequate cash on hand to do that, as well as keeping a very strong look at our balance sheet to ensure that we stay at or below our 60% debt -to-equity cap ratio. With a challenge of the ECOM decision, puts us in a bit of a cash-short position compared to where we thought we would be in '06, but again, we'll find a way to deal with those issues as we go.

Lastly, because yesterday was such an important day not only for American Electric Power, let me close my comments by simply saying we have received no end of support for the filing of what we call the I-765 project, a de-bottlenecking PJM, a 765,000 volt transmission line that we think is essential for the well-being of this industry going forward. Ultimately, to be determined by the PJM, by the FERC, and hopefully by the Department of Energy, to be an essential project to be built from our Amos station in West Virginia, to the Dean substation in PSE&G service territory in New Jersey. We are excited to be involved with the project. It has a long timeline on it as these things do, but nonetheless we think it is an appropriate step for American Electric Power to take, a continuing to embrace the notion of an open marketplace where all power plants have a right to compete against each other in that ever-growing competitive wholesale power market.

So with that, I'll turn the discussion over to Susan for her presentation, much more deep into the numbers, but let me again close by simply staying we think 2005 was an excellent year for those invested at American Electric Power, and surely a great year of performance for the 19,000 people who come to work here each and every day on your behalf. Susan?

Thanks, Mike. What I would like to do this morning is talk to you about earnings, first for the quarter and the year, and then we will come back to the cash and capex issues at the end of that discussion.

Let's talk first about the fourth quarter. And as you saw from our press release, reported earnings for the fourth quarter were a negative $0.38 per share, and that of course reflects the $0.67 difference between prior year, that is primarily attributable to the $261 million charge recorded in the fourth quarter of '05. Ongoing earnings for the quarter were $0.29. I'm going to talk in detail about Utility Operations in a few minutes here for the quarter, but I do want to mention a couple of other things with respect to the other lines. The investment segment showed an improvement over last year. It contributed $14 million to earnings versus the $7 million loss we saw last year. There are two factors that issue there. We had a very strong contribution from our MEMCO barge business that was driven by favorable barge rates, and we also saw the non-recurrence of costs that we saw in 2004 associated with the closing down of various investment operations. There was also, you'll note, an improvement of the Parent Company quarter-over-quarter and that really has to do with the fact that in 2004, we entered into some energy marketing settlements that were booked at end of 2004, that's worth about $20 million difference. So virtually all of it.

I want to go into more detail on the next slide, and if you look at a slide labeled Fourth Quarter '05 Utility Operations Performance, slide number six, I want to talk a little bit about where we stand year-to-year. On an ongoing basis, the results of the $0.27 versus $0.51 for the fourth quarter of 2009 for Utility Operations, have a number of differences, but I want to start with the most significant one. If you look at line 14, you will remember that we booked $109 million in TCC carrying costs in the fourth quarter of last year. That compares in '05 fourth quarter in which we booked only $7 million, and that number reflects two things -- the fact that over the course of '05 we booked those TCC carrying charges on a quarterly basis, and we also took an adjustment to that number in the fourth quarter as a result of the Texas-- the TCC true-up proceedings, so that is the single biggest item that accounts for the difference in ongoing earnings for the quarter between the quarter for the two years.

Stepping back from that item and talking a little bit about operational performance, what we saw was that both wholesale and retail sales were strong in the fourth quarter. There was retail growth at the Regulated Utilities of about 5% in Ohio and about 4%. We benefited from better prices, usage and weather. As you see from the slide here, we had a positive weather result against normal of $0.02 and against the prior year of about $0.03. However, you'll also note that the 679 million of gross margin at the Regulated Utilities is down a bit from previous years, and what that reflects is that we have also included in those margins a credit of $40.5 million, which is going to be returned to customers. This is a credit to customers at SWEPCO and PSO, and that is pursuant to the off-system sales sharing agreement that we ended into at the time of the CSW merger. I would note that we filed with FERC to terminate that agreement for 2006, but nevertheless, the very robust performance that we had in off-systems sales in '05 did lead to this result. So that is a key difference between those two lines.

We obviously had a very significant positive in Ohio that was driven largely by weather, obviously. We incorporated and see the benefit of the rate stabilization plan, both in this quarter and across the year in Ohio. You see that the strength in the off-systems sales did continue through the fourth quarter, 57 million in '04, versus the 112 million that we saw in the fourth quarter of '05, and that has really results from continued high prices, and also I think it is worth noting we saw $15 million improvement in transmission, that largely in ECAR.

The last significant-- two significant items of note are Texas Supply, we saw $25 million quarter-over-quarter decline, and as you know, there are several dynamics going on in Texas, the most significant of course is the sale of STP. We did have an outage in [Oakland] Union in the fall, but these negatives were offset by a $30 million, in this quarter, refund that we booked, that's a fuel refund in Texas.

You also note a noticeable increase in O & M on the quarter. That is catch-up. I think we talked to you over the course of the year that we were under running in O & M and then if we found ourselves in a position to spend those dollars, to catch up on tree-trimming, reliability spend, and plant maintenance, we would do so, and those are the dollars that you see in that line.

To talk for a moment about year-to-date, let's go to the next slide which is entitled 12 Months Year-to-Date Earnings Performance and Ongoing. I should note that, as Mike alluded to earlier , the GAAP results for this year were $2.09 as compared to the $2.73 in ongoing that we have for the year. That, although there are some other small items that are reflected in the difference between GAAP and ongoing, the key one is of course the item that we saw in the fourth quarter which is a $384 million pretax, 261 million after-tax charge resulting from the deliberations of the Texas Commission in the TCC true-up case.

Obviously, we've had a very significant improvement year-to-date in Utility Operations on a year-to-year basis. $2.80 in '05 versus $2.65 in '04. And the investment segment also reflects the trend I alluded to in the quarter. We had a positive contribution from that line of $24 million, or $0.06, versus the loss we saw in the previous year. This, in addition to being fueled by improved MEMCO results, was also affected by the sale of HPL and the gas operations, which did suffer a loss in the prior year. The Parent Company expenses were down year-over-year, reflecting about a 5% improvement. Again, the major item was the fourth quarter item of the settlement costs that occurred in 2004.

So if we turn to the next slide, the 12 Month Year-to-Date Utility Operations Performance, there is a great deal of detail here, and I'm not going to go over all of it. I Would Be Happy To Entertain Questions On This Item. But I think that it's appropriate to observe that what you see this year and ongoing performance is a continuation of the trends that you saw in the first three quarters of very strong performance in off-systems sales, continued growth, benefit significantly by favorable weather. The increased margins in Ohio offset somewhat by lower fuel margins, which of course affected both the Regulated Utilities and the Ohio Companies, as well. We did see an increase year-to-year in operations and maintenance expenses, and that has a little bit to do with changes in geography, but also has to do with the items that I mentioned earlier, which is a desire to take full advantage of the earnings opportunities we had this year and get some tree-trimming and other plant maintenance activity done as well. That leads us, of course, to our excellent results of $2.80 on an ongoing basis for Utility Operations.

I'd like to turn next to the cash flow page, and talk about a couple of items there. We did end the year with a little positive o cash flow basis, while accomplishing a great deal through the utilization of cash for this year. Our cash flow from operations totaled 1.8 billion, which was composed of 787 of cash from continuing earnings, and it's adjusted for the typical items that you see there enumerated in your slide. I'll note in particular the use of $626 million in '05 to fully fund our pension.

I would also note that there were other investment activities. Mike mentioned that, and you see that it required cash outlays of 929 million in 2005. That includes the capital investment of 2.4 billion, which was about 200 million less than we had forecast, and that was offset by some asset sales and some sales-related proceeds. We did receive a total of $1.6 billion this year from the combined sale of HPL, the South Texas Project, the Centrica sharing, and the sale of Pacific Hydro, and then we had the purchase of the Waterford plant for $218 million, the Ceredo plant for 100 million and then the Mon Power purchase of 44 million, which did require cash outlays for the year, as well. The financing activities involved cash outlays of 785 million, and this was primarily driven by the dividend, which totaled $554 million for the year.

Let me talk a little bit about where we ended up on our capitalization. We ended the quarter at 57.2% debt to cap on a GAAP basis and 58% on a credit-adjusted basis. As Mike said, our goals is continue to maintain debt-to-cap on an adjusted basis in the 60% range and we're very pleased to be well within that number, going into the coming year.

If we could, now, I'd like to turn for a minute back to the slide which appears on page four, called Revised Capital Investment Forecast. And I'm going to speak to that and the increase that Mike talked about. As Mike suggested, what we have done, in reviewing the capital forecast, between our meeting and presentation at EEI to today, is look at the timing of capital spend and made a couple of business decisions. The first was to continue to catch up with some underspend according to last year's budget, that occurred--that did not occur in '05 but that's appropriate to do in '06. And we also made a decision to at least plan to roll forward certain additional costs from 2007 and '08 into 2006.

There is some incremental increase over that three-year period. The total for all three years is $116 million. That includes $75 million spread equally over three years in-- at PSO. We have, at the encouragement of staff, agreed that we are going to attempt and undertake a project to convert overhead lines to underground lines. We have what we think is a very satisfactory rate arrangement for recovering those costs as we go, and so that the overage then would be the difference between the 75 and the 116. We continue to believe very strongly in our ability to move this capital around and it is something that you should expect to see in the coming years.

We also believe, as this chart shows you, that we have $1.5 million of what we call throttle flexibility, the ability to move dollars ahead to future years if we believe that is necessary given regulatory outcomes. We obviously have very significant regulatory outcomes that we will be having an opportunity to look at in the-- certainly in the first half of this year, and throughout the course of this year, Mike discussed several of those, and those will be influential as we manage this capital spend over the course of this year. But we have, as a business matter, decided that the optimum spend schedule is one that does take advantage of outages, takes advantage of contracting opportunities that we have, in order to get the spend done this year. We also believe that the improved reliability that we get from some of this capital spend will improve significantly our opportunities in our states going forward.

The last point I want to make is on paying for that additional increment of $400 million, and if you go to page 14 of your slides, what you'll see is a revised chart called Capital Investment Funding, and rather than take you through all these numbers, what I want to do is point to you some differences and the major sources of additional funding for this year over the last time that you should have seen this chart. As I mentioned, of course, the major difference is the capex spend of 3.7 billion through the year versus 3.3. You will also see the change in debt increased by about $300 million. It is $2.4 billion that's the last line under cash sources, as opposed to the 2.1 we saw in prior years. We also, as a result of this spend, would expect to reduce the ending cash balance by $240 million, we had originally projected about $566 million, and we're going to see an ending cash balance under this plan of $326 million.

So I think I probably talked enough, but obviously this is year-end and there is a lot of detail to talk about, so I'll turn it back to Mike and we can take some questions.

John, we're ready for questions.

[OPERATOR INSTRUCTIONS]

First we'll go to the line of Elizabeth Parrella with Merrill Lynch. Please go ahead.

Thank you. Can you talk about the impact of the TCC decision in terms if what's kind of built into your '06 guidance? I think, just trying to remember the specifics of the regulatory treatment, but I think you had not been booking like a deferred equity return, and now I think you get to, or once this is all finalized you do, and you get a smaller recoverable balance. How does that kind of affect what is built into the '06 numbers?

Well, in the terms of the '06 numbers, what we did was take a pretty conservative view and we basically said that we would assume about a 1.2, 1.3 cash influx in the fourth quarter. That's an adjustment that would assume, Elizabeth, that what we would do is to securitize everything that we got, including that which we had previously expected to be in the CTC.

Now, if--so you recall that there are two pieces. There is the stranded generation cost piece and then there are the true-up amounts that would ordinarily be collected through the CTC. Our 8-K tells you the adjustments that were made to get to the current stranded cost book balance which is 1.275. And I would recommend that a safe thing to do would be to move forward on the basis of that number as a securitizable amount, but it is not exactly correct.

As you note, there are pluses and minuses, and a lot of that will turn on the view of the Commission as to whether or not we're to securitize everything, or whether we securitize the stranded generation cost balance and continue to collect what would effect be a negative CTC over the coming years. If we were to collect negative CTC, we-- what we would have is somewhere, and we're still thinking this through, but it is somewhere between a $0.02, $0.03, $0.04 difference on earnings and that would-- that varies dependent upon how the Commission chooses to compute that prospectively. As you know, they're considering a change on how they compute carrying costs going forward and so it's kind of difficult to tell, but that-- those are sort of the basic parameters I would use in looking at it. We could end up securitizing substantially more if we were not required to show adjustments for the amounts in the CTC.

We do have, if we were permitted to get the equity return, that's $153 million that would be added to the 1.275, there we would still have to address the add-fit issue in some way or the other, that is 276 negative. There are other positives in there as well. So there are a bunch of numbers moving around which is the reason why I recommend you toward the framework that I discussed before. I don't believe there is downside from that framework. There may be upside.

Okay. Thank you. Just a question on coal costs, where did you come in for the year in terms of coal cost increases, and maybe you can kind of update us on what you expect in terms of coal cost increases for '06, and where you are from a hedging perspective, if you can look at maybe '06 or '07, if possible.

Let me talk a little bit about '05 and Mike can talk about '06. With respect to '05, we ended the year with a price per ton-- average price per ton of $32.50. So that represents about a 14% increase year-over-year. The-- in terms of the reflect-- the effect on margins, we're talking about $63 million in the negative effect reduced margins in the Regulated Utilities at about 44 million in Ohio. We also-- that's basically the picture with respect to '05. Mike, you want to talk you '06?

Well when we looked at '06, Elizabeth, to the questions that you've asked, obviously we're covered for our coal requirements in '06. We're seeing better delivery from the Powder River Basin in the month of January, but continue to see pressure not only on volume deliveries, but what we might see in '06 for spot coal buyers with increased rightful attention on mine safety in the eastern coal-producing states in country. So we watch that with a great deal of interest. As to '07, we're in the 70 to 75% already covered for our needs going into the year and feel comfortable about that. As you know, we continue to address the issue of fuel adjustment clauses, that is a principal part of the filing in West Virginia. We believe that we will begin to be recovering in an accounting and current sense in West Virginia by mid-year, that is part of our filing as we made it there. That will take us to our schedule that we have shown you before of 70% covered either by rate proceedings and/or market realization, that will take us into the 75 to 80% range covered versus 20% still being addressed here in Ohio.

As you know, the Ohio rates did adjust under the rate stabilization plan in calendar year '06 at both the operating companies, that cash of course will go against those endeavors. Yet, we continue to see fuel price increases, we're forecasting that same mid to low double-digit increases for the '06 price versus '05. All of that still translates into, like $1.50 or less per million BTUs and when you are selling, particularly in the off-sale marketplace frequently against $7, $8, and $9 per million BTU gas, that puts us in a pretty comfortable range. But, we watch it; we do the best we can do. I constantly maintain, as you heard me say ad nauseum, that there is no one better than buying coal than this outfit and I think Chuck Zebula and his team continue to demonstrate that year-over-year. The console contract being an important indication of that, with a lot of mine mouth coal that is delivered by conveyor belt and/or truck to our facility. So we still-- we see those issues, but we feel comfortable about the way we're handling them.

Alright, just a very quick follow-up and let other people ask questions. Just on your comments on TRB, just because another company this morning talked about the fact they're still seeing some pressures on deliveries. That they had not seen as much improvement as they had expected coming into the winter here. Sounds like you're seeing some improvement in terms of rail delivery side of TRB in January?

We are indeed. We are a little concerned for the rest of the year as we understand it. It's a suspension of some of the ongoing required maintenance on the tracks, but we have been seeing contract deliveries come back as they should. So someone is getting shorted; it is not us.

Thank you.

You bet.

Our next question is from the line of Paul Rizdon with KeyBanc, please go ahead.

What kind of opportunity are you seeing presented by mild weather and that kind of lessening your regulated load? Is there a sufficient margin to make up the shortfall that weather is costing you?

Well, we managed the overall generation fleet, obviously as best we can. Clearly less retail does provide more energy to be sold in the off-system marketplace. It also gives us an ongoing opportunity to continue to optimize the fuel as well as the emission credits. We continue to balance the overall generation portfolio, as you would expect us to do.

And then just looking forward, what kind of rate-making treatment do you expect on this line that you announced yesterday?

Well, the most important determinant of the rate design and the rate recovery of that facility will be coming through two very important agencies. One will be the PJM regional transmission need analysis, which we have asked them to consider this under that, puts it in a very comfortable rate recovery in that it's the cost of the activity are spread over the literally millions and millions of customers who would receive benefit from it. We run back to the envelope numbers, that would take someone's overall kilowatt hour rate by about a mill or so, which is really inconsequential, and surely we hope the PJM sees it as a regionally beneficial transmission undertaking. And then of course, in front of the Federal Regulatory Energy Commission, we asked in our declaratory request to them for the appropriate return on equity in the upper reaches of the range of reasonableness, as well as incentives that are laid out for people who take these kinds of endeavors and would hope that they would consider it that way.

An equally important determination for the investors in this company and the ultimate resolution of this facility and its opportunity to get built will have a lot to do with the DOE's characterization of this as a corridor under the Energy Policy Act of '05 authority granted to the DOE for the issue of ultimate eminent domain coming at the federal level. Because I would expect we will have challenges along the right-of-way, for we know we need the power, we surely enjoy the lack of congestion charges coming in our electric bill. We're encouraged by the opportunity to see new power production facilities come on line. We're encouraged by the renewable potential aspect that a line like this offers. We just don't want to see the line anywhere near our house. So we know we will have those issues.

And most of this capex is well after the environmental capex has rolled off?

It surely is.

Thank you.

You bet.

Our next question's from Ashar Kahn with SAC Capita, please go ahead.

Good morning. Could you just mention a little bit about Ohio situation, IGCC post-2008, anything in the legislature, in the commission, as you look at this year going into next year?

Well, as I said in my comments, Ashar, we're looking forward to a commission decision; we would have hoped to receive it in calendar year '05 but we are patient. We believe that the commission will find in their process that the things that we have asked for are reasonable and we'll go ahead and approve it and, again, we await that decision. As you know, it is clear from the growth that we see in our integrated resource plan not notwithstanding renewables, demand-side management, energy efficiency, and all of the things that are so important to our customers, that we need to have some central generation built on the eastern footprint of AEP. We believe, as I mentioned, that the commission will support us in that regard.

As to the post-'08 timeline, Dayton has taken an approach that the stretched out their rate stabilization undertaking for two more calendar years, being 2009 and 2010, there is no move afoot in the legislature other than that, I think the chair of the Ohio commission in his annual update on the market conditions in Ohio, mentioned to the commission that they continue to look at options and opportunities to ensure that all that can be done by the utilities and the regulator, as well as the legislature, is directed towards seeing to it that there is not an economic disruption caused by a flash-over market day switch, whether that would have been, as you know, calendar year '06 or whether that turns out to be calendar year '09. I expect you'll see the Ohio utilities continuing to dialog on that issue and working on that issue and I know that there are other views about that going forward, but we continue to occupy the space that we have, which is to find an answer in calendar year '09 and 2010 which would allow us to move closer to market and yet not trying to put any economic impact on the overall Ohio economy at that time.

Mike, do you think like the last plan was, I guess, done nearly a year before the implementation date of '06, so do you think all of these discussions and if there is a another rate stabilization these are all '07 events, that is how we should look at them?

That's a great question. As you know from listening or at least reading something about the state of the union message, not only is '06 a pivotal electoral year nationally, it is an extremely important electoral year in Ohio in that Governor Taft is term limited and we will be facing a political season here that may not lend itself to those kinds of discussions. So what you might see is that calendar year '07 would be a better time, a new governor and the leadership in the House and Senate I would expect to stay the same here in Ohio. But nonetheless we'll see how that unfolds. I just don't know how we'll go in '06. If the commission believes that a rate stabilization endeavor addressing those two years should be filed in '06, we would surely follow that lead.

Mike, could you just share your optimism in the West Virginia and in Kentucky in terms of-- I know you filed the cases, sometimes that it might be little bit early in one versus the other, but your-- regarding some recommendation in terms of your regulatory team and the optimism in terms of getting a good result?

I don't think there's any question that we feel very comfortable about the filings that were made in those two jurisdictions and we continue to have constructive discussions, particularly in Kentucky with other parties, meaning the Kentucky industrials, the Attorney General's office and the commission's staff. And in West Virginia, we continue to have an opportunity to provide additional data to those who are involved in the case, and I would expect there will be some time in the hopefully not too distant future to engage in settlement activities there as well. But, please, remember the filing in West Virginia is greatly driven by the environmental capital additions on terribly important power plants for the economy in West Virginia, let alone the electric customers in Appalachia Power, but equally important for the mining industry and overall economy of West Virginia. We feel very comfortable about that and clearly being the optimist that I am, I am very encouraged by the way that those cases will unfold as the year goes on. I don't feel as bullish about the, what we call the E&R case in Virginia, however we do continue to have dialog with commission staff and others in Virginia and will try to seek resolution to that matter if we can find it.

Sorry if I can just, Mike, when you increase the dividend, you had mentioned I guess going in, that when an increase in dividend takes place, you want to be comfortable that we can see growth going forward and it's not just like a one time-event and then we are kind of flat for a period of time. Can we-- is that still the thinking? We had increase in dividend but increase in dividend was done at a level where we could expect to see future increases in dividends going forward?

Well, that will continue to be our plan. As you know from the comments that Susan shared with you on the capital side of issues, we look at our obligation to the shareholders in an extremely important and longer-term view. One, we would always love to have a reasonable yield and be in the general yield category for electric utilities. We find ourselves there for the most part now, we feel comfortable that going forward, a 60 to 65% payout ratio is a good place to go and we intend to continue moving in that direction. Yet, we also believe very strongly in the notion that investors in our space, particularly those who are there for the longer term, will be highly rewarded by the capital being deployed on the operating company's, of course with the adequate rates of return, as granted by the various commission that those capital projects are in front of. And that's why when we talk about our flexibility on capital, when you look at the 3.7 billion, you know, fully 1.5 of it is in a category that we could say let's not spend this money in 2006, in fact, let's delay these projects for some indeterminate period of time until we get a clear capital signal from the rate regulator, and of course that would allow us, I would hope to be in a position to address something like a dividend increase. So, you'll see us look into those things and weigh them. But you started out with the right approach, that we do want to continue to have some small, yet steady dividend increase for our customers. It is all about capital allocation and capital availability.

Thank you very much.

Our next question is from Craig Shere with Calyon Securities, please go ahead.

Hi, kind of a follow up on Ashar's last couple of questions. Trying to think over the next three, four years, in light of the ECOM disappointment, if a couple of other things don't go well, kind of a worst case expectation, not that that is what we'd necessarily look for, would your cash-flow response be first to slightly increase your debt levels to a degree that doesn't hurt your credit? Second, defer the capex costs into the future, you know, even beyond three years, and then you wouldn't expect at any time to totally eliminate annual dividend increases or be considering an equity issue to specifically fund the capex? Is that a fair statement?

I think you've got them lined up appropriately. Clearly we will watch this with great interest and stay very, very close to it. Increasing the debt level beyond what we're comfortable with is our least likely option. I would imagine that project delay would be much more the release valve if we thought it was needed. Stopping the constant view of the potential for dividend increase would be our least likely endeavor, then, to take as well. We feel strongly about that going forward. The equity issuance issue is something that we have continued to look at. We don't see a need for it and don't feel that there's any requirement for it, and that's where we'll keep that, as well as we go forward.

Great. I appreciate it.

We have a question from David Frank with Pequot Capital. Please go ahead.

Yes, hi, good morning.

Good morning, David.

Susan, I had a question on slide 13, line 5. I wanted to know if the majority of those sales are from the Ohio Companies.

Just one second, David. Well, they're from the East, I can't really distinguish among Ohio versus other companies.

Okay.

But they are from the East.

When we make those kinds of off-systems sales, it is from the fleet.

Okay. I was just trying to get a feel for, if Ohio is two-thirds or 50%, if you had a ballpark on the figure?

We really don't look at it that way, David, I can't help you. I'm sorry.

Okay. Do you know what the average realized price was for those sales in the East in 2005?

I don't know that I have that number at the top of my head, David. We'll search around and share some of that with you. If you divide the megawatt hours and off-system sales by the revenue they generated, that will give you a per-megawatt hour price, and then you can do the same on some of the cost structures and get a per-megawatt hour production, and you can back yourself into a number that, on average won't be wrong, but remember, the 1300-megawatt plants generate energy for something short of $20 a megawatt hour. The 600-megawatt plants generate energy for something north of $20 a megawatt hour, so different plants with different performance characteristics, with different coal feedings, with different landfill requirements, you can get a nice average, but it would be hard for us to share with you more granular detail on which plant at what price into the marketplace.

The additional information we can provide is that about 70% of the off-systems sales last year were on peak, as opposed to post-off.

So 70% were on peak and they were all at 32 terawatt hours, that is all in the East?

Yes.

Okay. And I was also hoping, Susan, if you could maybe itemize.

David, let me correct that. It is really closer to 86% in the East. There was some off-systems sales activity in the West as well.

Okay, that's really what I was trying to get at. And then I was also hoping, maybe you could itemize for us that $6 billion of discretionary capex you have budgeted in in '06, '07, '08. Could you just kind of put that in buckets for us?

Yes, I think it would-- let me do '06 and then we can provide a detail for the other years, if that's okay with you.

Sure.

If you go to slide four, if you go to page six, you'll see how we look at it. Let's look at slide four, and let's look at 2006. If you look at the bottom block, that's in orange, or ochre, as my mother the art teacher would say, what you see is an environmental compliance spend of $1.5 billion. And that we consider to be really essential capital spend. That's not to say that we could not move an outage, but we would be very unlikely to, because the compliance plan that we have designed really is optimized around this spend at this point in time. So we really would not want to do that unless we absolutely had to. Mandated T&D is a combination of two things -- it is the completion of the Wyoming-Jackson Ferry Line, which we certainly want to do, as well as customer connections, and basic service issues that are anything that would not be O& M and that, too, we consider essential.

It is the next two categories that we would consider to be flexible. The ongoing infrastructure replacement, and what we call economically justified through our internal analyses, these are basic improvements and that would include both generation and transmission and distribution. We have coming forward, as you might imagine, any number of projects that make sense for the system that either improve the reliability, that improve the functioning, improve the generation reliability, capability reduction in E4 rates, all those sorts of activities are in the 1.3 billion. In addition we have $191 million in new build and that I would consider to be the most flexible and really the most uncertain of all. What we have done through our integrated resource planning is included the development costs that we have for the IGCC plus, assuming that we are responsible for build activities in the West, as you know, we have two RFPs out there to address additional generation needs of those companies in the West, PSO and SWEPCO, and so there would be, if both of those bids went to AEP for new build activity, then you might see that spend level at that level. That is very much an estimate. So what you really need to do is look at that top two box, the blue and the green, and take that over the next two years, David, and you see the same issues. Okay?

Yes, I guess what I was trying to figure out, because the 6 billion, it seems like a huge number and it probably scares a lot of people, and what I'm trying to figure out is how much is really discretionary versus just maybe discretionary from a timing standpoint? And that is what I was kind of getting at. So it sounds like 3.5 billion of your 3.7 billion of capex for '06 is not discretionary; it's maybe a little gets moved because of timing? Is that a fair assessment?

No, I don't think so. The way Susan broke the boxes down for you, David, is that the 2.2 billion in the bottom two boxes is already under way. The billion and a half on environmental spend in '06 is well under way. It is projects that were begun in '04 and '05. What we believe mandated T&D we need to finish Jackson's ferry, it is 3/4 or 4/5 done. It will be energized on June the 30th. We need to obviously complete that project.

The distribution, you have no choice in our world, and this is true of every utility in the country, when customer growth comes, you need to hook them up. And we have obviously years and years and years of data over what that is. When you get to the blocks that say ongoing infrastructure replacement, economically justified, we either the can or can't do that based on how we feel about the return on the capital invested by the regulator, as well as whether we do or don't have enough capital to put to work in those activities. And then new build generation will have everything to do with regulatory orders that are supportive of that activity. As Susan mentioned, some of the purple box, as you look at '07 and '08, is dedicated not only to integrated gas project, but dedicated to projects that need to be built in Louisiana and in Oklahoma to serve SWEPCO as well as Public Service of Oklahoma. We are in front of those commissions today, as so many other utilities do in the country, seeking proposals from others who would build power plants, and we have submitted what we would build if we were the one chosen by the utility regulators. So those top boxes are extremely flexible.

Okay. So I guess it's going to be the economically justified pieces we're going to have to kind of make an assumption on and assign a return to it if we give it to you?

Right.

I think that's right.

I think that is very fair. So when you look at the 6 billion, it is just there in the math, it's 1.5 in '06, it's 2.0 in '07, and it's 2.5 in '08.

Okay. Alright, well, thanks a lot. I appreciate that.

Sure.

Sure.

Our next question is from Greg Gordon with Citigroup. Please go ahead.

Thanks. Building a little bit on that. As I look at your capital investment funding page on page 14. I don't see the assumption of securitization bond proceeds anywhere in this three-year plan. Am I right in doing that math?

It is in the debt.

It is in the net debt?

Yes.

Okay. So you're presuming $1.2 to $1.3 billion in cash proceeds in that net-- that number in '06?

For purposes of this plan, yes.

Okay. Great. Mike, as I look-- as we sit here and we roll through fiscal year 2006 and we think about that-- those-- the labor discussion you just had with David on the will we or won't we spend the money. Which regulatory proceedings and actions should we be focussed on that will make the drive your decision to spend versus not spend? Where should we be focused and when will those decisions be made by the regulator that will in turn cause you to tell Susan it is okay to open the wallet?

Clearly on the new build lines it will have everything to do with Ohio integrated gas filing. The others will be activities billed into the infrastructure upgrade for reliability. Some of that actually might be in Ohio, as well as we go forward in the 4% opportunity that is in front of us for calendar year '07 and '08, as well as the determination in West Virginia where we continue to have a reliability investments. And, as Susan mentioned, some of that comes from the ongoing endeavors in Oklahoma by the regulator in Oklahoma to improve reliability and accessibility in an electric sense for our customers in the greater Tulsa area, moving to undergrounding from overheading. So we'll watch those filings. But the principal ones, for the chunky dollars are clearly in Ohio and West Virginia.

So in Ohio it is a function of two things then, the getting an approval to move forward with IGCC, but also managing your cost profile so you have headroom under that 4% cap to get a return on the capital? Is that right?

That is clearly true in '07 and '08. For '06, remember much of the headroom has been taken up by the way that we have proposed to recover the existing cost of the ongoing engineering activity associated with integrated gas combined cycle. So it is not a project that you get to the end and the commission says no and then we have to turn around and say, well we need to expense 20 million or 40 million that we spent on the way to approval for the project, because the way we have filed those pieces will be covered and we've had tremendous support in the application on those activities so we're not troubled by that at all. But again, Greg, you're right with the way you characterized it, that is what you need to watch for.

Thank you, Mike.

You bet.

We have a question from Gordon Howald, with Natexis, please go ahead.

Great, thank you, hi, Mike, hi Susan.

Hi, there.

Could you talk a little bit about how the installation of your scrubbers at this point is going, and any issues you see at this point impacting that technical vendor's costs, et cetera?

We couldn't tell you how pleased we are with Mike Rencheck and the team that are responsible for the implementation of those projects. I would tell you that in almost every instance, and Mike just gave me an update on these things, we are a bit ahead of schedule, reasonably under budget or at budget, and comfortable with our tie-in dates and our operational aspects. We had an opportunity to do this, and it was a bit in jest at the last-- at the EEI financial meeting where you may remember, John Wilder mentioned that utilities ought not build chicken coops if they don't know how, I couldn't agree with that more. But I am terribly impressed with the ability of this company to do these projects on time under budget.

We're getting pressure, as you would expect, going forward, the cost of steel has gone up, the cost of concrete has gone up. However, any of our contracts were fixed price activities, and that is being consumed by the margin to the supplier rather than by us and/or our investors or customers long-term. So this is one more time when American Electric Power distinguished itself among the utilities. We have a corner on the manufacturers and that we were the first mover in the space. I would argue we have a corner on the engineering talent, because we were the first mover in the space. And I think we're seeing the benefit of that as we go forward.

That was an aggressive strategy and seems like it's working out fine for you. You also mentioned, Mike, briefly earlier SO2 allowances. Could you give us an update on, you know, maybe your strategy from that regard, if it's changed, versus last year and maybe an update on your emissions book overall?

The emissions book is flat, not long, not short. But the strategy remains the same, and that is that we are optimistic, or opportunistic, I should say, optimizers of those credits as we go forward. When you look at a period, as you have seen in early '06, you're clearly not using the credits that you had allocated to your generation fleet, and there are some in the marketplace who went in bear and they find themselves needing to put credits in their bank. So we're taking the opportunity to monetize some of those as we go. It has never been, nor will it ever be an earnings driver for us. We just think it is the appropriate way to manage an extremely valuable asset opportunity that on occasion presents itself to us. I would love to find somebody in a coal short situation right now, as we find our piles building as days go on and generators don't run at full capacity, because it is always good to be a seller when somebody else is in a pinch.

Gotcha. Understood. Appreciate it.

You bet.

Next we go to Daniele Seitz with Dahlman Rose. Please go ahead.

I just was wondering, in most cases when you recover the environmental cost expenditures, there is a net effect in the allowances as well, basically, the fuel adjustment clause goes down. Is that what happens to customers?

Yes, ma'am.

Or do you keep some of those benefits?

Well, it all depends how current your fuel adjustment clause is, Daniele, in those jurisdictions. Many of the areas where that happens we keep the benefits, as you know ,much of that also flows through in the overall activity for off-systems sales, as the coal price goes down, the margin then goes up as you buy a higher sulfur rather than lower sulfur coal. And as you also well know, we do share some of those revenues with our customers. So the implementation of these activities not only benefits the communities where the plants are located for the environmental improvement, a benefit the investors because of the return on equity capital invested in the equipment itself, but also benefit the customers in the fact that they get some of the flow-back, realizing lower fuel costs and as we go forward, the opportunity to continue to optimize what to do with credits that are no longer needed and we share much of that between the shareholders and the customers. So again, as again you've heard me say many, many times, everybody seems to benefit from this and that is what we're seeing in the arena as we go forward.

Basically, the earnings--the rates would not go up as much as what the construction expenditures seem to show. And-- but you will get a return on the investment?

That's true, but I don't want to negotiate with you like you're a rate-maker. We would rather see the rates go up to a reasonable rate of return and keep those other benefits for our shareholders. But I am a firm believer that the regulator is in the business of balancing the benefits to customers and investors and they've been very good about that in our jurisdiction.

Also, I was wondering, your participation in the PJM, do you sense that you are getting now the full effect, or is there still more benefits expected in that area?

I would--as you know, we have talked about this through almost all of calendar year '05, and again I think the AEP team and commercial operations has distinguished themselves. We fully understand it, we take full opportunity of it, and we're very satisfied with the results that we see from it.

So it's almost-- you almost got the full benefit in the first year?

I believe that to be the case. Little slow off the start as you heard, but we were moving along in dog years you might remember, and the graduate degree diplomas were granted at the end of the year.

I just was wondering, I remember that there were some transmission rates that had been adjusted. Are they now completely stabilized?

No, we have had some very important transmission rate activities go forward in calendar year '05, but we continue to still look at the regionalization of rates throughout the PJM, and the Seams Elimination Charge, as you know. Every time we hear any of the FERC Commissioners talk about this issue, we hear their conversations coming more to the way that we see it, which is those who receive a benefit from using what we consider to be the interstate highway, paying for that as they go, rather than customers in the retail region who are not taking advantage, in a day-to-day sense, of electrons moving from Chicago to Newark. So we believe that when we get to the conclusion of this rate activities at the FERC, we have potential for upside there as well.

Do you anticipate this to be relatively soon, or it could be dragging for a while?

Well, It is clearly an '06 event. In my world, soon is now and in the regulators world soon is not now. But it is an '06 event.

Thanks a lot.

You bet. Thanks for your questions.

We have a question from line of Michael Lapides from Goldman Sachs, please go ahead.

Hi, real easy one. On annual basis going forward for the next few years, what are you expecting as either the increase or decrease in off-system megawatt hours sold?

Well, we will probably begin to see slight decrease in off-systems sales simply because we continue to see although slow, pretty steady growth of our retail demand. And remember how the fleet works; it is all power to the retail customer, first from the bottom of the price stack, moving up to off-systems sales, then when available, into the marketplace. That's part of what, of course, we see going forward in the 2010 and beyond time frame that our actual retail load will have grown beyond what our generation fleet can do, and that's why we feel so strongly that the commissions need to give us the authority to build additional base-load power generation facilities of the clean coal variety that you heard us speak about.

Okay. Thank you.

You bet.

Our final question will come from the line of Tom O'Neill with Citadel Investments. Please go ahead.

Good morning. Just curious on Texas, kind of given the process and treatment that you saw, if you have any change in view with regard to the long-term remaining in the state?

Tom, I would argue that we were treated better than others. I would tell you, however, that we are very disappointed in the ECOM deliberations. I think that Commissioner [Smithaman] had it exactly right as it pertains to that, and that will be part of, if in fact the final decision is along the lines of the final discussion, that would be the one issue that we would carry forward with strong feelings about our appeal and our appellate opportunities. Short of that, we continue to have reasonable dialogs with the Texas Commission, as you know we feel comfortable with the ERCOT transmission rate recovery process and continue to feel strong about being a participant in the Texas marketplace as we go forward. One of my favorite bumper stickers in life was, "I wasn't born in Texas, but I moved here as soon as I heard about it," The fact remains, we're happy to do business there, and we'll continue to try to improve the relationship with that regulator both at PUCT as well as with the ERCOT regulator.

Great, thanks.

You bet. Thanks for your questions. Julie?

Thank you for joining us today. The IR staff will be available for you, and have a good day. Thanks.

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