阿莫林 (AEE) 2005 Q1 法說會逐字稿

Good morning, and welcome ladies and gentlemen to the Ameren Corporation first-quarter 2005 earnings conference call. At this time, I would like to inform you that the conference is being recorded, and that all participants are in a listen-only mode. At the request of the Company, we will open the conference up for questions and answers after the presentation. I will now turn the conference over to Mr. Bruce Steinke, Assistant Controller. Please go ahead.

Thank you Joe, and good morning. I am Bruce Steinke, Manager of Investor Relations at Ameren Corporation. Here with me today is our Chairman, Chief Executive Officer and President, Gary Rainwater; our Executive Vice President and CFO, Warner Baxter; our Vice President and Controller, Marty Lyons; and our Vice President and Treasurer, Jerre Birdsong.

Before we begin, let me cover a few administrative details. This hour long call is available by phone for 1 week to anyone who wishes to hear it by dialing a playback number. The announcement you received in our news release carry instructions on replaying the call by telephone. This call is also being broadcast live on the Internet, and a webcast will be available for 1 year on our website, www.Ameren.com.

This call contains time sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated in the forward-looking statements. For additional information concerning these factors, we ask you to read the forward-looking statements section in the news release we issued today and the forward-looking statements and risk factors section in our filings with the SEC.

To assist in our call this morning, we have made a slide presentation available on our website that reconciles our earnings per share for the first quarter of 2004 to our earnings per share for the first quarter of 2005 on a comparable share basis. To access this presentation, you may look in the Investors Section of our website under presentation or follow the links for the webcast.

Gary will begin this call with an overview of our first-quarter 2005 results and some operating matters. And Warner will follow with an update on some pending regulatory matters and a more detailed look at our first-quarter 2005 results. We will then open it up for questions. Here is Gary.

Thanks, Bruce. Good morning, and thank you for joining us. This morning, we reported earnings of $0.62 per share for the first quarter of 2005, as compared to earnings of $0.55 in last year's first quarter. These numbers represent a solid start for 2005. As we indicated in our release this morning, we are reaffirming our guidance of $2.90 to $3.10 per share for 2005. Our net earnings in the first quarter of 2005, as compared to the first quarter of 2004, benefited from higher prices for Interchange power sales as well as the addition of Illinois Power Company and improved availability and capacity factors at our power plants. Milder winter weather reduced emission credit sales and higher fuel costs compared to 2004, partially offset these positive factors.

On the operations side, the availability of our electric generation fleet was 84% in the first quarter of 2005, up from 82% last year. And our capacity factors increased from 75% to over 76%. Our increased generating plants' availability allowed us to take advantage of higher power prices in the Interchange markets. Prices in the power markets continued to be driven by higher prices for natural gas as well as emission credits allowances and coal.

The first quarter 2005, we realized average revenues on Interchange sales of $38 per megawatt hour, up $7 per megawatt hour from the first quarter of 2004. The margins we have earned on these off systems sales as well as the margins on our native load sales have been partially offset by higher coal and related transportation costs this year. We currently have fixed-price coal supply contracts for over 95% of our expected 2005 requirements and over 90% of our 2006 requirements. And our coal transportation requirements are similarly locked up. However, as we have discussed in the past, we have been seeing some pressure on coal and transportation pricing. As a result, we expect coal and transportation cost increases of 3 to 5% in 2005 and again in 2006. And we currently expect our coal and transportation costs to increase at a minimum by 3 to 5% again in 2007.

As I noted, the addition of Illinois Power contributed to our improvement in earnings and earnings per share in the first quarter of 2005. The integration of Illinois Power with the rest of our operations is well underway. Late last year, we had 230 Illinois Power employees except voluntary separation. Those employees will lead the Company throughout 2005.

In addition, we have reorganized all of our Illinois utility operations in the first quarter to leverage the fact that our service territory now covers the entire lower two-thirds of the state. In April, we converted some Illinois Power's key financial systems, and we expect to convert the remaining systems including the customer service systems later this year. As part of our recapitalization of Illinois Power beginning late last year, we contributed equity to Illinois Power and reduced high-cost debt by $770 million.

These actions have resulted in significant interest expense savings and has helped raised Illinois Power's credit ratings to investment-grade categories. We are executing our integration plan very well and remain on track for achieving the expected synergies and the earnings contribution in the range of $0.09 to $0.13 per share in our first 2 years of operations from this acquisition.

Moving onto environmental matters. As most of you know, the Environmental Protection Agency issued more stringent SO2, NOx and mercury emission limits on all coal-fired power plants in March. Between 2005 and 2015, we expect to be required to spend between 1.4 and $1.9 billion to retrofit our power plants with pollution control equipment. Approximately two-thirds of this investment will be in our regulated interim UE operations.

We continue to evaluate our final strategy for complying with the new rules. Fortunately, with our current bank of emission credits allowances at Ameren, we are in a good position to approach these significant investments in a prudent manner.

As we indicated during our year-end conference call, we expect to reduce the number of allowances we will sell at Ameren UE in 2005. Indeed, in the first quarter, we did not sell any allowances. Over the years, our non-regulated business has been short emission credit allowances, and we have routinely acquired allowances to meet our needs. We now hold 100% of our expected 2005 and 2006 requirements for admission credit allowances. Our needs for admission credit allowances post-2006 will be determined in part by our final environmental compliant strategy. We expect to be able to discuss our strategy on this matter more fully later this year.

On the transmission front, on April 1st, MISO began operating in Day 2 to markets. The Day 2 markets present an opportunity to have greater access for power sales from our low-cost power plants. As you might expect, the transition to a new marketplace is an evolutionary process, and some hiccups are likely to occur. During the first month of Day 2 operations, we've seen what we believe is suboptimal dispatching of plans and some price volatility. We are working closely with MISO to resolve these and other issues. We continue to be optimistic that the market will function as expected. Most importantly, we have not experienced any major issues associated with the reliability of the system.

On another transmission-related matter, we did announce in April that our AmerenUE and AmerenCIPS subsidiaries were withdrawing from Grid America effective November 1st. We believe that our continuing participation in the MISO through Grid America would not have provided us with significant added value over participating directly in the MISO, as AmerenCILCO and AmerenIP are currently doing.

On the regulatory front, we are very focused on preparing for year-end rate freezes in Missouri and Illinois in 2006. Warner will go through our regulatory proceedings in a bit more detail. But in late February, we made initial filings with Illinois Commerce Commission to outline a proposed method for procuring power in 2007 and beyond. Later this year or early next year, we will make filings with the Illinois Commerce Commission that will serve as a basis for adjusting our distribution rates. And by January 1st, 2006, we will provide an update on the service studies from Missouri Public Service Commission staff and others. These are milestone events for the Company, and we look forward to working with regulators and other interested parties in both states.

In summary, I believe we are off to a good start in 2005 with solid first-quarter earnings and operating results. The Illinois Power acquisition is meeting our targets. We are on the verge of completing intercompany asset transfers that have been pending for some time. We are working diligently on the continued improvement of our operations, and we are focused on preparing for our upcoming regulatory proceedings. With that, I will turn this discussion over to Warner.

As Gary noted, we made filings in late February with the Illinois Commerce Commission, outlining our proposed process and framework for retail rate determination and generation procurement after the current Illinois rate freeze ends in 2006. Our filings were consistent in most respects with the framework that had brought support from last year's Commission-sponsored workshops. This framework would have all regulated Illinois electric distribution companies that after native load requirements for generation in an ICC-monitored, New Jersey-type auction process -- and it would provide for recovery from customers of the generation costs resulting from that auction.

Under this structure, we expect that our non-rate-regulated power generation businesses will be allowed to sell the approximately 14 million megawatt hours of power that are currently committed to our AmerenCIPS and AmerenCILCO distribution businesses at the market base clearing price. Prices under our AmerenCIPS and AmerenCILCO power supply contracts that expire at the end of 2006, or $38.50 per megawatt hour and $34.00 per megawatt hour respectively. Market prices today for similar contracts to deliver power in 2005 approximate 48 to $49 per megawatt hour. Of course, these may not be the prevailing market prices at the time of the proposed auctions.

However, I believe the location, mixed and the low-cost of our generation assets, positions Ameren very well to compete in the new Illinois market. As Gary mentioned previously, later this year or early next year, we expect to make filings to establish the distribution portion of our electric rates in Illinois after the rate freeze ends. I should note that electric rates for all our Missouri and Illinois utilities have been frozen or declining for the last 12 to 22 years.

At legislative meetings hearings last month, we stated that average electric rates for our Illinois utilities on a combined basis could increase by 10 to 20% in 2007 over present bundled rate levels with 50 to 70% of this increase resulting from higher power costs. Of course, this estimate was based on a number of assumptions about auction results, rate-making outcomes, and the like. The final results of the auction process and regulatory proceedings could be significantly different from our original assumptions.

Turning to Missouri, as Gary mentioned previously, we will submit an updated cost of electric service study to the Missouri Public Service Commission staff and others by January 1st, 2006. Based on the results of that study, we will determine what course of action we believe should be taken in resetting electric rates for AmerenUE in Missouri. The Missouri Public Service Commission staff and other stakeholders will review our study. And based upon their analyses, may make rate recommendations. Keep in mind that electric rates in Missouri are frozen until June 30, 2006.

Back in Illinois, we currently have a gas rate case pending before the Illinois Commerce Commission for Illinois Power. The administrative law judge in that case has issued a proposed order, which if adopted by the Illinois Commerce Commission, would provide for an approximate $14 million increase in this case. The ICC staff has proposed an approximate $11 million annual increase in natural gas delivery rates. The Illinois Commerce Commission is expected to rule on this case in May. Also in May, we expect to complete three related matters -- the transfer of AmerenUE's Illinois electric and gas utility service territory to AmerenCIPS; the transfer of 550 megawatts of generating capacity from our unregulated Ameren Energy Generating Company's subsidiary to AmerenUE; and beginning on June 1st, the expansion of our service territory in southern Missouri to serve Noranda Aluminum, the largest user of energy in the state of Missouri. At this time, we have received all regulatory approvals necessary to move forward and complete these matters.

On the legislative front in Missouri, yesterday, the Missouri House of Representatives passed Senate Bill 179. This bill was previously passed by the Missouri Senate. In part, this bill, as signed by the Governor, would enable the Missouri Public Service Commission to put in place an environmental cost recovery mechanism for Missouri utilities. In addition, it would enable the Missouri Public Service Commission to allow electric utilities to recover fuel and purchase power costs through a similar recovery mechanism. The legislation also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental recovery mechanism and prudency (sic) reviews, among other things. I should note that these costs have always been recoverable in Missouri under existing regulations.

Now, I would like to refer you to our website, as I provide a more detailed discussion of our first-quarter 2005 earnings. As Bruce mentioned earlier, we have posted a slide presentation on our website that reconciles our earnings per share for the first quarter of 2004 to the first quarter of 2005 on a comparable share basis. In this presentation and throughout our discussion this morning, we will discuss the factors impacting earnings per share.

In the first quarter of 2005, we reported net income of $121 million or $0.62 per share compared to net income in the first quarter of 2004 of $97 million or $0.55 per share. Net earnings benefited from the addition of Illinois Power, which added $21 million to net income in the first quarter of 2005 over 2004. After taking into account the 30 million common shares we issued to finance the acquisition, the transaction was accretive to earnings by about $0.03 per share in the first quarter, consistent with our expectations. In addition, there was a positive variance of $0.03 on 2005 earnings due to the dilutive effect of partially pre-funding the Illinois Power acquisition in the first quarter of 2004. You may recall the acquisition of Illinois Power was accretive by $0.07 per share in the fourth quarter of 2004.

In the addition to the impact of Illinois Power, increased margins for Interchange power sales added $0.07 per share in the first quarter of 2005 versus the prior year. I should note that if you look at our statistics page, it will appear that Interchange sales were down year-over-year. This is due to Interchange sales by Electric Energy, Inc. to Illinois Power, which represents about 20% of EEI sales being eliminated in consolidation in 2005. Excluding the effect of these sales, Interchange sales were up 7% year-over-year.

However, the primary reason for the increase in the contribution of earnings for Interchange sales was the higher power prices then Gary referred to earlier, which averaged approximately $38 per megawatt hour versus approximately $31 per megawatt hour last year.

We did have very mild weather this quarter. We estimate the mild 2005 weather reduced earnings by $0.03 per share versus the mild 2004 first quarter and nearly doubled that versus normal.

Heating degree days were approximately 4% below 2004 and 8% below normal. Clearly, our electric and gas sales volumes in the first quarter of 2005 were also significantly influenced by the September 2004 acquisition of Illinois Power. Total electric sales were up 15% due to the Illinois Power acquisition. Excluding Illinois Power, weather-sensitive residential and commercial electric megawatt hour sales were down 2% and 1% respectively in the first quarter of 2005 compared to the first quarter of 2004. Again excluding the effect of Illinois Power, industrial electrical megawatt hour sales in the first quarter were down 6% in 2005 versus the year-ago period due primarily to the expiration and non-renewal of low margin power sales contracts in the deregulated Illinois market.

Gas sales in the first quarter of 2005 increased almost 70% due to the Illinois Power acquisition, while gas sales in our pre-acquisition service territory were down 5% in the same period as a result of the mild weather. Weather-adjusted sales growth in the first quarter of 2005 netted a modest $0.01 per share improvement over 2004. Native load sales growth and lower purchase power costs associated with increased availability of our power plants and lower industrial sales were largely offset by increased fuel costs and the net impact of rate reductions. Our decreased sales of emission credit allowances reduced first-quarter 2005 earnings by $0.06 per share, consistent with our expectations.

Non-acquisition related net dilution and financing and increased depreciation and amortization reduced earnings by $0.02 per share each in the first quarter of 2005 over 2004. Net operations and maintenance and other expenses declined and improved earnings by $0.05 per share in the first quarter 2005 over 2004. The favorable resolution of a property tax matter and various cost reductions drove this improvement.

This concludes my comments on first-quarter earnings. This morning, we also announced that we continue to expect our earnings for 2005 to be between $2.90 and $3.10 per share. Our guidance assumes normal weather and is subject to, among other things – climate operations, energy market and economic conditions, unusual or otherwise unexpected gains or losses, and other risks and uncertainties outlined in the forward-looking statements of our news release in the forward-looking statements and risk factors sections in our filings with the SEC.

This concludes our prepared comments. We will now be happy to take your questions.

(OPERATOR INSTRUCTIONS). Ashar Khan, SAC Capital.

You guys mentioned that you were seeing much higher prices, 38 versus 31. Could I ask you what had you budgeted for this year? Warner, if I remember going back to the first year-end, you were expecting Interchange sales to be a negative contribution. I guess it would come from the summer. But are prices running ahead of budgeted levels? And could that delta be based on what you see prices now less '04 or '05?

Clearly with regard to Interchange sales, we have seen some price movement has been favorable since certainly the end of the year. As we went into this year and as we discussed during our year-end conference call, we did expect Interchange margins to go down between $0.10 and $0.20 per share. And at that time, we indicated that was really being driven by volume changes, as -- we obviously take on the Noranda Aluminum contract, we assume normal weather, as well as just normalized growth as well as salary (ph) refueling outage -- all taking place this year.

Having said that, we expected prices to be relatively flattish if not up a little bit year-over-year in the first quarter. I would say that those prices were up maybe about 5%. And so if that trend continues the rest of the year, we would expect prices -- or at least from what our original expectations were -- to be up over what we had originally said.

Warner, can you just tell us the delta between the price and volume that at what price increase would delta -- the negative delta year-over-year go to zero?

I'm sorry, Ashar, say that again please?

At what price increase would that delta -- you had mentioned that there is less volume budgeted for Interchange sales this year, which is driving the negative delta, and you had assumed flat prices. What would prices have to rise by so the delta is flat? Are you with me?

Yes, I understand. Ashar, I really haven't done that calculation. I understand your question, but I really don't have that sort of with me. Obviously, we don't sort of go into the details in particular in terms of how we budget it. But certainly, as we continue to see increased prices or solid prices throughout the year, that would mitigate some of the negative effect -- or excuse me -- the negative change in Interchange sales margins year-over-year.

How much of volume decrease have you budgeted for on Interchange sales this year?

I guess, Ashar, with regard to overall Interchange sales, I don't necessarily that in front of me -- what we had budgeted versus what we had before. We usually do not go into that level of detail.

And you mentioned at the end, there was a property tax item, which helped earnings. Could you quantify how much that was? What was it related to?

Sure, that was about $0.02 per share. And it was at a property tax issue that we had actually been dealing with over several years in our Illinois service territory.

And if can end of -- Warner, now with the Missouri bill passed, what is your strategy in terms of going forward with the provisions that have been provided under the bill?

Well, I think I would comment on that. Obviously, in terms of what we had to do in Missouri, we had to provide a cost of service study by the end of the year to Missouri Public Service staff and the other stakeholders. As we have move forward then in determining what sort of the next regulatory steps we would do in Missouri, assuming that the Governor ultimately signs the bill that has been passed by the House and Senate, then we will have I would say two other regulatory frameworks in terms of fuel and environment cost recoverment (sic) mechanisms that we can employ in our next regulatory filings with Missouri.

How we will do that will in part be dictated by some of the proceedings that will likely take place, should the Governor sign the bill, in terms of how an environmental cost recovery mechanism and a fuel cost recovery mechanism should be or can be employed in the state of Missouri. And we would expect those to take place later this summer after -- assuming that the Governor signs the bill. That then will dictate at least in part our regulatory strategy for the recovery of fuel costs and environmental costs going forward, as well as a host of other issues including infrastructure investments and the like.

So we will keep everyone posted, as we continue to move towards that filing, and if there's more clarity around how some of those things will shake out in Missouri.

Greg Gordon, Smith Barney.

2 questions. Did you say that your industrial sales were affected by the expiration of a long-term contract, since your industrial sales were up in the quarter?

Our industrial sales, Greg, were down about 6%. Most of that decrease was due to low margin power sales contracts that we have had from CILCO that were going up into the Commonwealth Edison region and basically our low margin sales because we backed those sales up with purchase power. So we didn't renew many of those contracts. And so while the sales percentages go down in terms of margins, they were very low in terms of how they affected our --

Okay, so that didn't actually re-up generation if they are selling to the Interchange market. It obviated your need to purchase power.

That is exactly right.

Okay and then the second question -- if my model is up-to-date, please correct pick me if I'm wrong -- your CapEx budget for 2005 is just under $900 million?

It's actually the CapEx budget, Greg, is about $930 million for 2005.

Okay. And that CapEx budget obviously doesn't include any environmental expenditures?

Yes, Greg, it does. It includes a small amount -- about $50 million.

Okay. But we are going to essentially get an update on what you think your longer-term spend is going to be in the context of your environmental plan?

Yes.

And it's likely to put upward pressure on CapEx going forward, correct?

Let me comment a couple things on that. In our 5-year forecast -- and in fact we have disclosed that we believe that capital expenditures between now and 2015 based on current technology will range between 1.4 billion to $1.9 million. That obviously --

That's just for environmental?

That is just for environmental. And about 65% or so of that is part of our regulated business, approximately two-thirds. If you look at our Annual Report and our 10-K, we do disclose what we expect our total capital expenditures to be from 2005 all the way through 2009. Those numbers can range, which would include the environmental CapEx that I just spoke to you about, about 5 billion to $6.3 billion.

Is that going to be back-end loaded?

Well in part, I guess certainly with regard to the environmental CapEx. Some of those things will not be on the front end. And they will be more towards the back end, that's true. So that is a lion share of that. But obviously, we have meaningful infrastructure investments that we will continue to make in our regulated operations throughout. And we breakdown in there -- really if you look at the total CapEx and especially in the environment spend and the like -- and most of our CapEx continues to be going forward in the regulated part of our business.

Daniele Seitz, Maxcor Financial.

I just was wondering if you had the estimates to the rate increase you may ask for in distribution rates in Illinois -- just a ballpark figure.

Well, Daniele, what we had said in hearings and legislative hearings in March was that we expected in total -- what I would consider the bundled rate on average for all of our Illinois utilities in Illinois -- would be based upon prices around that March timeframe -- would range between 10 and 20% for all of our customer classes. Not for all -- but on average for those customer classes.

And this includes everything?

Yes, that would include the generation component and the delivery service component.

I was also wondering if the Noranda -- when does the Noranda contract start exactly? And also, will it change somewhat the seasonality of your numbers, or you don't believe that?

The Noranda contract comes into play effective June 1st. So as we discussed before that they will become for all practical purposes like the native load customer for us and then will be really essentially -- after our next rate case -- be treated like any other industrial customer. For 2005 and beyond then, you will see a shift in terms of margins going more -- native load margins from Interchange power sales margins. And that's one of the reasons why, as we went into this year, we saw a difference in Interchange power margins, Interchange sales margin, was due in part due to the fact that some of our excess generation would be able to serve Noranda versus going into off-system sales.

Steve Fleischman, Merrill Lynch.

A couple of questions. First, I will list these questions and then first -- on the O&M savings in the quarter, could you just elaborate what that was and whether those will last?

Secondly, the MISO problems upfront -- is that having any material economic impact to you guys? And then lastly, -- would just like your view on the Illinois process, particularly with respect to some of the comments that Excelon has made about being willing to defer some of the -- potentially some of the extent of rate increase. I know your rates are a lot lower than theirs, but it does create some interesting dynamics -- so, comments on those.

Sure. Let me start with the O&M statements. As I said before, in part $0.02 of that, that $0.05 that you see on our reconciliation side related to the property tax win that we had in the state of Illinois -- that is permanent and that will remain.

The other differences I would say relate to a variety of different items. A portion of which -- if not a good portion of which -- is still timing I would say Steve, between quarter-to-quarter. So again, consistent with our expectations in the year, we would expect some of those expenses that they'll show up a little bit later in the year, relatively speaking. So I wouldn't dial in a $0.05 in terms of the O&M savings for the at this point in time.

Secondly, with regard to the MISO -- at this point in time, as Gary said, we are seeing a few hiccups along the way. But frankly, we expected to see some of those things. Importantly, we didn't see issues in terms of reliability. However, they are dispatching some of the plants, at least we believe, and really not on an economic basis.

Steve, the primary problem is that combustion turbines had been running more than expected. This time of the year, we wouldn't normally -- would not normally expect to run turbines at all. But since we started MISO Day 2, we have been running Grand Tower, which is a combined cycle gas plant everyday and running some of our other peakers almost everyday, which really shouldn't happen this time of the year. So hopefully, MISO will work those bugs out.

As far as the economic impact of that though, it should be minimal. We can't tell you exactly what is because the final settlement doesn't occur until about 55 days after we started Day 2 operations. But it (technical difficulty) should be minimal. We believe that (technical difficulty) at least break even on those -- on running our combustion turbines.

And keep in mind on the MISO framework, the first 2 months into the MISO framework are cost base prices. So we would anticipate being able on the minimum to recover our full costs for some of those high cost peakers, at least in our system that are being run, as well as obviously earn still margins in terms of our low cost generating plants being sold into that market. So we will be able to give you a better sense certainly in the second quarter. But at this point in time, as Gary said, we expect that to be relatively minimal.

I think on your third question in terms of the Illinois process that we're certainly aware that there are service stakeholders. And we are aware that Excelon has talked about the potential for a phase in plan of some sort of some deferral plan. Again, our view is, as we said before, that a phase-in plan is not necessary. As we have said, we believe since our rates have been frozen or declining for the last 10 to 20 years, we believe that again it is warranted to ultimately have a true-up in those rates.

However, we're not naive. We know that the Legislature may and has had hearings around this. And mostly hearings, frankly, with them to get a better understanding of the process. And our view is that they have a much better understanding and an appreciation of the auction process. And I would say more confidence in the overall auction process.

But in terms of the overall end results -- should the legislator pursue a phase-in plan, we will certainly seek to work with them to develop what we would hopefully be a constructive solution to all the stakeholders. And in developing any constructive solution, should a deferral plan be initiated, we would have to ensure that the overall financial integrity of all the operating companies are maintained. We've certainly made quite a bit of progress in showing up the financial integrity of both CILCO and Illinois Power in our acquisitions with them.

So again, nothing has been proposed. Certainly, there's going to continue to be discussions around it. That does not surprise us. And we'll be a meaningful participant no matter what in that process.

Doug Fischer, A.G. Edwards.

A couple of questions -- maybe a little more field -- just because some of the others have been asked. Have you any thoughts as to when in Missouri on a regulated basis you might need to add base load?

Doug, this is Gary Rainwater. We are within probably a year or 2 of making a decision. But our analysis indicates the need for some time in the 2012/2013 range. It's still far enough out that in the short-term, we can meet our requirements by just adding fairly low capital cost peakers. In fact, we are installing about 450 megawatts of peakers this year at our Dennis (ph) Power Plant site. We retired the old plant there a year or so ago. It is an ideal location for us to put peakers.

So short-term, we will continue doing what we have done just low capital investment peakers. You know our gas burn now is still less than 1% of our total energy, so we're relying primarily on the existing coal plants.

Across the whole system, it is 1% or just in Missouri?

It is actually less than 1% across the whole system.

And then, Warner, I'm not sure I understood what you said, I think it was Ashar's question, about first-quarter prices were up about 5%. Are you saying for the whole year? What you were seeing in the forward price curve was up about 5% versus the prior year? I don't understand what you said or maybe I misunderstood.

Okay, Doug, let me clear as to what that is. In terms of our realized Interchange prices for this quarter versus the last quarter, they in fact were up.

Yes, hugely.

They were up about 20 to 25% year-over-year. Ashar's question was -- well then, given these prices compared to the guidance that we started at the beginning of the year where we have said that Interchange sales margins may be down $0.10 to $0.20 compared to last year -- where our prices compared to what you were expecting?

And my comment on that was that we had seen prices slightly north of our expectations here in the first quarter. And should those prices continue or certainly becomes stronger as the year moves on, then that would indeed have the effect of mitigating, at least in part, the potential loss in Interchange margins that we discussed in our year-end conference call.

Okay, but there was no quantification there?

I said, not for the rest of the year, no. I did not quantify that.

Okay. I think that covers it for now.

Dan Jenkins (ph), State of Wisconsin Investments.

Looking at your power supply and it looks like you had about 20% was from purchased versus 9.8% last year -- and I was curious, was that due to outages or just opportunity or what was driving that?

The major contributor to that is Illinois Power. We closed the acquisition with Illinois Power in September of last year. And remember when we acquired Illinois Power, we just acquired the transmission and distribution businesses. So we entered into power supply agreements with counterparties to provide that 3500 megawatt load. So the vast majority of any increase in purchase cost is being driven by Illinois Power.

Okay, so that would probably persist then going forward, those type of ratios?

Yes, that's right. And the fact of the matter is -- then, those Illinois Power purchases -- when we talked about the accretion for Illinois Power of $0.03 this quarter over the prior quarter -- that factors in those purchase power costs for Illinois Power, as well as the sales that go with them.

Then you mentioned that the industrial sales in the first quarter were down about 6%. And I think you mentioned that is due to expiration of some power sales contracts. But just generally, what is the industrial demand looking like in your service territory?

For the quarter, if you exclude those low margin contracts, industrial sales contracts frankly were up 5% or 2 compared to that last year. So that is consistent with our expectations.

Last year, we saw solid sales growth closer to probably 3% off all of our categories, including some of our industrial customers. And if you compare that on a year-to-year basis, again, the economy was probably a little bit softer in 2003 to 2004. So with a little bit better economy in 2004, where we would expect the overall sales growth for those industrial customers to come down to more normal levels, which has historically been somewhere around 2 to 3%.

Okay. Then you also mentioned the IP debt reduction. And I was wondering, have you basically completed what you intend to do regarding their high cost debt, as far as reducing that?

What I had discussed was that we had basically recapitalized Illinois Power and reduced debt to the tune of about $770 million. That is the equity contribution. That is consistent with our expectations. And I would say that the vast, vast majority of our debt repair or balance sheet repair has been completed, consistent with our commitments to do so. If we do anymore, it will just be things around the edge but nothing as significant as what we have done so far.

Okay. And then -- when do you plan to convert the customer service system over? You mentioned that was one of the areas still needed to be integrated.

The customer service system will be converted this fall, consistent with our integration plan.

In the fall, okay. And then the last thing I was wondering on the $7.00 increase in Interchange -- you mentioned that part that the Interchange showed up the volume, and it showed up being down because of the intercompany between EEI and IP. Did that have any impact on that increase of $7 as well, or was that totally independent of that?

That calculation is independent of that sales method I was discussing.

(OPERATOR INSTRUCTIONS). Zack Schreiber, Duquesne Capital.

Actually, Warner, my questions have been asked and answered.

(OPERATOR INSTRUCTIONS). And at this time, there appear to be no further questions. Gentlemen, I will turn the call back to you.

Great. And thank you all for participating in this call. Let me remind you again that this call is available through May 5th on playback and for 1 year through the Internet. The announcement carries instructions on listening to the playback. You can also call the contacts listed on our news release. For those on the call who are financial analysts, please call Bruce Steinke. Media should call Tim Fox. Numbers for both are on the news release. Again, thanks for dialing in.

This does conclude today's conference. Thank you for your participation. You may disconnect at this time.