阿莫林 (AEE) 2004 Q4 法說會逐字稿

Welcome, ladies and gentlemen, to the Ameren Corporation fourth quarter and year-end 2004 conference call. At this time I would like to inform you that this conference is being recorded and that all participants are in a listen-only mode. At the request of the Company, we will open up the call for questions and answers after the presentation.

I would now like to turn the call over to Mr. Bruce Steinke, Manager of Investor Relations. Please go ahead sir.

Thank you, Karen, and good morning everyone. 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 one week to anyone who wishes to hear it by dialing a playback number. The announcement you received and our news release carry instructions on replaying the call by telephone. This call is also being broadcast live on the Internet and the Webcast will be available for one 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 there are various factors that 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 on our call this morning we have made a slide presentation available on our Website that reconciles our earnings per share for 2003 to our earnings per share for 2004 on a comparable share basis. In this presentation, we have also included a slide that reconciles our 2004 earnings to our 2005 earnings guidance range on a comparable share basis. To access this presentation you may look in the investor section of our Website under presentations, or follow the link for the Webcast.

Gary will begin this call with an overview of our 2004 results and some operating and regulatory matters, and Warner will follow with a more detailed review of some of these regulatory matters, our 2004 results and our guidance for 2005. We will then open it up for questions.

Here's Gary.

Thanks Bruce. Good morning and thank you for joining us. This morning we reported earnings of $2.84 per share for 2004 as compared to earnings of 3.25 per share last year. Last year's earnings included unusual gains totaling 30 cents per share related to the settlement of a dispute over certain coal mine reclamation issues and the adoption of a new accounting standard related to the recognition of asset retirement obligations. Excluding these unusual gains, our 2004 earnings of 2.84 per share compared to earnings of 2.95 per share last year.

Our solid earnings performance in 2004 was accomplished despite some of the mildest weather on record and the two-month refueling and maintenance outage at our Callaway nuclear plant. There was no outage in 2003 and the 2004 outage was twice the normal duration for a refueling outage, due to extensive improvements being made.

In addition, we prudently issued common stock to fund the Illinois Power acquisition prior to the September 30 completion of the deal. Since we did not have the benefit of Illinois Power's earnings during this period, our earnings per share were diluted. I'll talk more about the IP acquisition in a moment.

We were able to largely overcome these challenges through effective cost control and through the excellent performance of our low-cost coal-fired plants. In 2004, our generating plants produced a record 75 million MWH, up 3 percent over 2003 levels. The availability of our coal fleet was 87 percent in 2004, up from 85 percent in 2003, and our capacity factors increased from 73 percent to 76 percent. This record-setting operating performance reduced our generating costs on a per MWH basis and allowed us to take advantage of strong power prices in the energy markets through the sales of our excess generation. Simply put, we focused and delivered on the fundamentals of our business -- cost control, efficient operations, and asset optimization. We will continue the sharp focus in the future and I'm confident we can raise our equivalent availability and capacity factors from our 2004 levels, and we're putting in place plans to do so.

During 2004 we were also focused on the completion of our acquisition of Illinois Power and Dynegy's 20 percent interest in Electric Energy Incorporated. As you know, we announced, financed and completed the $2.3 billion acquisition of Illinois Power in only eight months, which I believe is an industry record for this type of transaction.

Completing this acquisition in such a timely manner has allowed us to turn our attention to integrating Illinois Power with Ameren, realizing our expected synergies and related earnings from the acquisition and immediately improving the financial condition of Illinois Power. Our fourth-quarter progress on this front included taking out $700 million of Illinois Power's high-cost debt and having approximately 230 Illinois Power employees accept our offer of voluntary separation. These steps, and ones we'll take in 2005, are intended to put us well on our way to realizing the expected synergies from the transaction.

As Warner will discuss in more detail a bit later, we now expect the IP acquisition to be accretive to earnings per share by 9 to 13 cents per share over our first two years of ownership. That is better than our original expectations of 5 to 10 cents per share.

Moving on to environmental matters. As most of you know, the Environmental Protection Agency has proposed more stringent ESO2, NOx and mercury emission limits on all coal-fired power plants. Between 2005 and 2015, we expect to be required to spend between 1.5 and $1.9 billion to retrofit our power plants with pollution control equipment. Approximately 2/3 of this investment will be in our regulated Ameren UE operations.

Despite the fact that final rules have not been issued, we are well into the planning stages for this investment; in fact, this year we expect to spend about $50 million for the expected Clean Air rules. Fortunately, with our current bank of emission credits, we are in good position to approach these significant investments in a prudent manner. Based on our current assessment of proposed environmental rules, our developing thoughts on compliance strategies, and to maintain flexibility around these issues, we anticipate reducing the number of allowances we sell on an annual basis in the future. Warner will discuss in a moment the impact that decision has on our 2005 guidance.

Our organization also continues to prepare for the transition to Day 2 MISO markets. The implementation date was recently removed -- or moved from March 1 to April 1. The 2 Day markets present an opportunity to have greater access for power sales from our low-cost plants. Of course, moving into the MISO Day 2 market also brings its share of market-related and operating risks. We believe we are well prepared for these changes and we look forward to this new marketplace.

On the regulatory front, we have several matters pending that I want to briefly touch on before I turn it over to Warner to go through them in more detail. As most of you know, rate freezes or moratoriums in all our electric distribution businesses expire in 2006. In Illinois that date is December 31 and in Missouri the date is June 30. The process in which rates will be addressed in Illinois and Missouri is somewhat different given the different regulatory structures in these two states. Later this month, we expect to make filings with the Illinois Commerce Commission outlining the process and framework for retail rate determination and generation procurement after the current Illinois rate freeze ends in 2006. Our filings will be consistent in most respects with the framework that had broad-based support in last year's Commission-sponsored workshops.

This framework would have all regulated Illinois electric distribution companies bid out their native load requirements for generation in an ICC-monitored, New Jersey-type auction process, and provide for recovery from customers of the generation costs resulting from that auction. Under this structure, we expect that our unregulated power generation businesses will be allowed to sell in the open market the approximately 14 million MWH of power that are currently committed to our Ameren CIPS and Ameren CILCO distribution businesses.

Prices under our Ameren CIPS and Ameren CILCO power supply contracts that expire at the end of 2006 are $38.50 per MWH and $34 per MWH, respectively. Market prices today for similar contracts to deliver power in 2005 approximate 43 to $44 per MWH. Of course, these may not be the prevailing market prices at the time of the proposed auctions; however, I believe the location and the low cost of our generation assets position Ameren very well to compete in the new Illinois market.

I'd also like to point out that the Illinois legislature will begin hearings today on post-2006 process. In today's hearings, the ICC staff will be discussing the ICC's sponsored workshop process and the conclusions from that process. Future hearings will likely explore the generation procurement auction process, the resetting of energy delivery rates and consumer-related issues. We welcome the opportunity to discuss these important issues with key legislators as Illinois fully transitions to the competitive marketplace. As we have continually done throughout this process, we will promote a fair and balanced approach for all stakeholders in procuring generation and in setting future energy rates for customers.

And finally, turning to Missouri, we will file an updated Cost of Service study with the Missouri Public Service Commission by January 1, 2006. Based on the results of that study, we will determine what course of action should be taken in resetting electric rates for Ameren UE in Missouri.

And with that, I'd like to turn the discussion over to Warner.

Thanks, Gary. First, before I discuss 2004 earnings and our 2005 guidance, I want to add a little more detail on our post-2006 regulatory process, as well as brief you on a few other regulatory matters.

Later this year or early next year, we would expect to make filings that will serve as a basis for determining the future rates for our distribution businesses in Illinois. As Gary mentioned, we will also make a Cost of Service filing in Missouri by January 1, 2006. At this time, it is too early to predict how rates will change in Illinois and Missouri once the moratoriums expire.

We do know that electric rates for all of our Missouri and Illinois utilities have been frozen or declining for the last 12 to 22 years. In addition, we have made significant energy and infrastructure investments during this period, and operating expenses in total have generally risen over the past several years. Of course, the interest rate environment has changed during that time, we have effectively controlled costs, and we have also realized meaningful synergies from our acquisitions. The Illinois Commerce Commission staff, the Missouri Public Service Commission staff, and other stakeholders, will review our filings, and based upon their own analyses, make rate recommendations.

Many issues are often litigated in a rate case, including those surrounding return on equity, weather normalization, joint (ph) generation, dispatch energy pricing, and employee benefits and depreciation expenses, among other things. And, as you know, no one can predict the ultimate outcome of rate cases. We will keep you posted as the rate-setting process moves along in Missouri and Illinois.

In our Illinois Power gas rate case, hearings concluded last month. Prior to the hearing, many of the issues, including the majority of revenue requirements-related issues, were settled with various parties to the case. The only revenue requirement issue addressed during the hearings related to some gas storage field operational matters. These issues arose several years ago and we included indemnification provisions in our IP acquisition agreement with Dynegy for this matter. Should the ICC accept the settlement reached on the issues by all the parties, we would expect IP's gas rates to have an annual increase of 11 million to $14 million. We expect a decision from the ICC by May.

In Missouri, we are working on three related matters -- the transfer of 550 MW of generating capacity from our unregulated Ameren Energy Generating Company subsidiary to Ameren UE, the transfer of Ameren UE's Illinois service territory to Ameren CIPS, and the expansion of our service territory in Southern Missouri in order to serve Noranda (ph) Aluminum.

Noranda is the largest user of energy in the state of Missouri at approximately 470 MW, which equates to approximately 5 percent of UE's load. These matters are related, since without the two transfers, Ameren UE would not have the available generating capacity to serve Noranda, and without the service territory transfer to Ameren CIPS, the generation transfer would require Illinois Commerce Commission approval.

Last December, the Missouri Public Service Commission granted our request to rehear its order approving the service territory transfer. The original order carried conditions that we did not believe were necessary or appropriate for the transfer to be approved. Those conditions related to pre-transfer generation liabilities and the pricing of intercompany generation transfers between Ameren Energy Generating Company and Ameren UE under the joint dispatch agreement. In our filings, we have offered protections to ensure that rate payers will not be adversely affected by these matters in the future. As Gary mentioned earlier, electric rates are frozen until June 30, 2006 in Missouri.

A preliminary hearing on the service territory transfer was held in January. More hearings are scheduled on this matter, as well as the Noranda case, later this month. While there is no deadline by which the Commission must act, the schedule they adopted should result in a decision by the end of March.

The proposed service territory transfer and generation transfers also remain subject to the approval of the SEC under the Public Utility Holding Company Act, and the interconnection agreement by which Ameren UE will serve Noranda is subject to approval by FERC.

Now I would like to refer you to our Website as I provide a more detail discussion of 2004 earnings results, 2005 earnings guidance, and other financial matters.

As Bruce mentioned earlier, we have posted a slide presentation on our Website that reconciles our earnings per share for 2004 to 2003 on a comparable share basis, and a slide that reconciles our 2004 earnings per share to our guidance range for 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 2004, we reported net income of $530 million, or $2.84 per share, compared to 2003 net income of $524 million, or $3.25 per share. As Gary indicated, if you adjust for unusual gains in 2003, earnings were $2.95 per share. As a result, earnings in 2004 were 11 cents per share below 2003 on an ongoing basis.

Extremely mild summer weather, the issuance of new common shares to pre-fund the Illinois Power acquisition, and the Callaway nuclear plant refueling and maintenance outage, significantly reduced 2004 earnings. These items were mitigated by solid organic growth in our service territory, an additional month of CILCORP earnings in 2004, and increased interchange margins, due largely to record plant generation and strong energy prices.

We estimate the mild 2004 weather reduced earnings by an estimated 14 cents per share versus 2003 and 20 cents per share versus normal. Heating degree days were approximately 7 percent below 2003 and 10 percent below normal. In addition, cooling degree days in Ameren's service territory this past summer were approximately 20 percent below 2003 and normal. And according to the National Weather Service, summer weather in Ameren's service territory was the 7th mildest in the past 109 years.

Despite the mild weather, sales margins in 2004 were higher than 2003. Solid sales growth that contributed incremental earnings of approximately 42 cents per share was driven by improved economic activity in our service territory and an additional month of sales margins from CILCORP. Our 2004 sales volumes were also significantly influenced by the acquisition of Illinois Power and the additional month of CILCORP sales when compared to 2003.

Excluding the impact of these acquisitions, residential electric sales were flat in 2004 despite the very mild weather, and commercial and industrial sales increased by approximately 2 percent. In addition, wholesale sales increased approximately 5 percent over 2003.

As I mentioned, electric margins also benefited from strong interchange sales, which boosted earnings by 16 cents per share over 2003 to a total of 71 cents per share in 2004 on a comparable share basis to 2003. Interchange sales in 2004 were almost 17 percent higher than 2003.

On the expense side of the equation, we incurred higher purchased power and maintenance expenses due to the Callaway refueling and maintenance outage, which Gary discussed earlier. That reduced earnings by 22 cents per share. In addition, our employee benefits and depreciation expenses reduced earnings by 11 cents and 6 cents per share, respectively. These expenses were offset in part by a refund from MISO for exit fees paid to that organization several years ago, which reduced expenses by 6 cents per share and lowered labor costs resulting primarily from the voluntary employee retirement program.

Finally, before I move on to our 2005 guidance, dilution and financing costs net of earnings from Illinois Power reduced earnings by an estimated 19 cents per share in 2004. As you know, we issued 30 million common shares in February and July of 2004 to pre-fund the cash portion of the purchase price and recapitalization of Illinois Power. The acquisition was completed on September 30.

Now on to our 2005 earnings guidance discussion.

This morning, we announced that we expect our earnings for 2005 to be between $2.90 and $3.10 per share. As Bruce and I mentioned earlier, we have a slide on our Website that reconciles full-year 2004 earnings to our 2005 guidance. Our guidance assumes normal weather as subject to, among other things, plant 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 release and the forward-looking statements and risk factors sections in our filings with the SEC.

Our 2005 earnings are projected to increase, principally due to continued solid organic growth in the Company's service territory, earnings accretion resulting from the IP acquisition, and an assumption of normal weather. As you can see on the slide, we expect an increase of sales margins, due to continued solid organic growth, of approximately 2 percent in our service territory. We expect this growth to contribute 15 cents to 30 cents per share in 2005 over 2004.

However, we expect interchange sales margins to be lower than 2004 by approximately 10 to 20 cents per share, due largely to lower excess generation being available for sale resulting from increased sales to native load customers due to growth, the planned Callaway nuclear plant outage, the potential addition of Noranda Aluminum, the startup of MISO Day 2 markets, and a return to normal weather.

In addition, as Gary mentioned earlier, we anticipate lower emission credit sales in 2005 as part of our overall environmental compliance strategy. We estimate that reduced emission credit sales could reduce 2005 earnings by approximately 3 to 5 cents per share.

As I mentioned earlier, our guidance at the beginning of each year assumes a return to normal weather. Should that occur, 2005 earnings should rise approximately 20 cents per share versus 2004.

2005 earnings will also be favorably impacted by our acquisition of IP. The IP acquisition is expected to add to earnings in two ways. First, the dilution to 2004 earnings of approximately 18 cents per share that was caused by issuing common shares in advance of the acquisition will be covered by Illinois Power's earnings this year. Second, we expect Illinois Power to be accretive by an addition of 2 to 6 cents per share over the 7 cents per share accretion it provided in the fourth quarter of 2004. As Gary mentioned earlier, we now expect the IP acquisition to be accretive to earnings over our first two years of ownership by 9 to 13 cents per share.

As discussed previously, our Callaway nuclear plant is scheduled for a 70 to 75-day outage in the fall of 2005 for refueling, replacement of the steam generators and steam turbines, and to perform other maintenance. The 2004 outage lasted 64 days. Despite the longer duration, the Callaway outage is not expected to have a significant net impact year-over-year on operating expenses and purchased power, due to more of the work being capital in nature.

We also expect 2005 earnings to decrease due to greater levels of common shares outstanding and higher financing costs. First, we expect to realize incremental dilution of 4 cents per share associated with the issuance of shares under our DRIP Plus (ph) and employee benefit plans, and, in May 2005, dilution of 4 cents per share for the issuance of shares on our currently outstanding adjustable conversion rate equity security (indiscernible). In addition, we expect incremental financing costs of approximately 2 cents per share. We also expect to see higher employee benefit and depreciation expenses in 2005. And finally, in 2005 we will also not benefit from the refund of our MISO exit fee that we received last year, which added 6 cents to 2004 earnings per share.

From a free cash flow perspective, we expect to be cash flow negative by approximately 100 million to $150 million this year as we begin to incur even higher levels of regulated capital expenditures while rates are frozen. I don't plan to discuss our capital plan in any detail, but you can see that the majority of our expenditures are in our regulated businesses and the majority of our increase this year over 2004 is due to Illinois Power.

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

(OPERATOR INSTRUCTIONS). Paul Ridzon, Key McDonald.

What quarter did you realize that MISO refund in?

This is Warner Baxter. That was in the second quarter of last year.

Doug Fischer, AG Edwards.

Just a couple of questions. In terms of financing the needed cash for the year, how much would come from stock plans and how much might be debt? And any other comments on how you might finance that?

I'll let Jerre Birdsong handle a little bit more of that here in a minute, but I think generally from our stock plans we generated about $100 million a year from our DRIP Plus and employee benefit plans. And I'll let Jerre comment a little bit more on some of our other financing strategies.

In addition to that amount of equity, increase the bases we'll convert into equity of (technical difficulty) million of that will occur in May. And beyond that, the amount of debt would be less than the amount of new equity. So, potentially about half the amount of (indiscernible) be issuing in debt.

So roughly 50 million in debt would be the expectation at this point, in terms of new net debt?

No. You would need to add the aces (ph) to that. So it would be half of the total of the (indiscernible) the 100 million.

In looking at the interchange sales, how much of the expected decline is price and how much is volume? Any color you can give on that? It sounded like most of the things you were talking about were volume.

This is Warner again. I think that is an accurate assessment. We really don't see prices moving significantly, certainly in a downward direction. We see them to be flattish, if not maybe a tad better in 2005. So we don't -- at this point in time we down see it being a price issue, it's more of a volume. And again, as we said before, that is due largely to the fact that we're going towards normal weather, which will have used up some of the excess low-cost generation. We expect, obviously, organic growth. And as we have talked about before, should we end up having Noranda Aluminum as one of our customers, that, too, will have larger native load requirements to use our low-cost generation.

Remind me how many MWH the aluminum plant might absorb?

I believe it's 470 MW, and it's probably closer to 4 million MWH.

Is that a net positive by selling to them versus into the wholesale market, from a margin standpoint?

I think as you step back -- and, obviously, it depends upon where you see the ultimate prices rising in the market -- but we think it's generally kind of a breakeven prospect, frankly.

Paul Patterson, Glenrock Associates.

I was wondering if you could go over your jurisdictional ROE, you know, the ROE on rate-based equity for your three companies on a regulated basis -- for the utilities, excuse me.

Let me try and answer that by giving you really what the financial ROEs are for our Illinois utilities, as well as Missouri.

When you look at the reported financial results, our ROEs for our Illinois utilities -- that would be CIPS, CILCO and IP -- range from 5 to 10 percent in 2004. In Missouri the financial ROE was probably 12 to 13 percent in 2004. And as you know, the financial ROEs are not necessarily the same ROEs that would be utilized in the rate-making process. They don't simply pick up those numbers off the face of the financial statements.

Things that are normally adjusted in, say, an Illinois would be things like -- well, really for both jurisdictions -- would be things like weather normalization, unusual income or expense items -- things like, for instance, the MISO refund -- things in terms of capital structure -- we have some intercompany notes that have to be factored into it -- as well as some pieces of the generation operations that still reside in CILCORP.

And in Missouri, you have to look at things like the Callaway refueling outage. Those things have to be normalized. So there are a host of things besides all the other issues that are normally litigated in a rate case. A long-winded answer to sort of make sure that the financial ROE I gave you -- kind of understand the basis upon which that is calculated and how that might be utilized in a rate-making process.

Right. So would it be higher or lower, would you generally say, with these adjustments? I mean, could you give us -- you gave 5 to 10 percent (indiscernible). I don't want to put you on the spot, but I'm just wondering, if you have the information, just if there's any idea about what on a regulated basis you think it would -- the ROE would translate into.

Two things -- one with regard to the Illinois utilities. Let me try and just be more explicit. I gave you the range, but let me just tell you -- in general, CIPS' financial ROE is 6 percent as of the end of the year, CILCO is 9 percent, and IP approximately around 10 percent. With regard to the regulatory ROE, I think because of all the inherent adjustments that you may have to make in terms of what may be an appropriate regulatory ROE -- because we'd have to make assumptions assuming (indiscernible) I said before -- weather normalization, cost allocations between the jurisdictions, and depreciation. We don't think it's appropriate and we're not prepared at this time to give the specific regulatory ROEs from any of our jurisdictions.

Fair enough. Let me ask you this. When you mentioned the House subcommittee -- Electric Oversight Committee, the special committee looking into the post-2006 issues, what do you think is driving that? Is there any concern about the increase in prices that you guys are looking at in terms of market prices and how that might affect customers? Can you give us any feel for what might happen with that, or do you just simply expect to get whatever the auction gives you, and simply put it through to customers?

Paul, this is Gary Rainwater, just to give you a little feel for that. My view is what is driving it is that the Legislature is concerned that there could be a California-kind of disaster as we transition from the rate freeze into the fully unregulated market, and they want to be sure that doesn't happen here. I think that as they look at the processes that we set up, which are primarily the New Jersey style auction, that we have done everything that is possible to prevent that kind of disaster. It's a much different market than we have in California; it's a market that has proven to work in the East. So at this point we're very confident, the Illinois Commerce Commission is very confident, all the interveners who have been a part of this process are very confident that the market will work. But the Legislature just hasn't been a part of that process, so we need to bring them up to the same level of understanding. And I think when we do that, they're going to be satisfied that the market will work, and I think that will be the end of it.

Are you expecting legislation for them? It looked like the ICC white paper suggested that that wasn't necessary. Is there any discussion about that?

There is some discussion about it still. Our view is that legislation is not required, but I suspect the Commerce Commission would take comfort if they had some legislation that authorized them to implement the auction process. And there could be something like that.

Daniele Seitz, Maxcor Financial.

Two things. One, could you give me the CapEx for '06 as well as '07, and how much of your environmental expenditures are going to be into those CapEx?

Let me see if we can't (multiple speakers). This is Warner. With regard to overall CapEx, I think as you can see from the guidance, we are at 880 million for 2005. For 2006 to 2009, we expect that CapEx to range anywhere from 4.2 to $5.3 billion over those ensuing years. I don't have the specific number for 2006 in front of me here.

I mean, obviously, rising. And did environmental costs peak sometime at the end of that period?

You know, the environmental capital expenditures that we expect to expend over the next five years in many respects will be contingent upon what our environmental compliance strategy will be -- how we plan to utilize various technologies, how we may plan to utilize our emission allowances and the like. If you look just over the next five years, that range could be anywhere as low as 500 million up to maybe 1.5 billion in terms of CapEx related to environmental expenditures, depending upon the various types of strategies that we can employ. As Gary mentioned in the conference call a little bit earlier, that strategy is something that we are still -- we're further in advance in our planning stage, but we haven't finally concluded as to what we'll end up doing in terms of environmental.

I guess also because you have -- Missouri is obviously regulated, you may ask for some sort of a long-term phasing of those expenditures in your rate base?

Yes. As we mentioned before, approximately 2/3 of our environmental CapEx are in the regulated businesses, and primarily that is Missouri. So again, that would be reflected in rate base. We don't see any particular issues. When we have those environmental capital expenditures, they'll reflect that in the regulatory process.

Thank you. The other question I had was about the MISO. How much do you think are those going to be -- those expenditures are going to look like? And net net, do you feel that this is going to be a plus in terms of, as you said, expending your (technical difficulty)

Daniele, I think from a financial standpoint what we've said before is that when we went into MISO -- now, this is including Illinois Power -- that the transmission costs could increase from 10 to $25 million annually. IP was about $5 million of that number. And similarly, all things being equal, we would expect revenues could go down, say, 5 to 15 million with IP. So I will tell you that the revenue number is a conservative one. Because we do expect once the MISO Day 2 markets are fully functioning, as Gary said, that the MISO Day 2 markets will begin in April, we will have a greater ability to sink our excess low-cost generation in the MISO marketplace. So we have not, I would suggest, factored those potential opportunities, in terms of incremental revenues and margins, in the future. So we do think that there will be meaningful benefits in time with the MISO Day 2 markets.

You also mentioned (indiscernible). Can you just elaborate somewhat in MISO Day 2?

I think we didn't mean to be overly alarming.

No, no. I just -- please educate me. That's all.

I think generally speaking whenever you go into the new marketplace -- and if I recall, when PJM actually moved into their marketplace, there was a great deal of price volatility -- number one. Two, you have to make sure that you do the appropriate things from a system standpoint. There are quite a bit more settlements that we have to make under this new MISO Day 2 versus before. So you have a little bit of those "operating risks" to make sure that you have got all the i's dotted and the t's crossed. We have a team of several individuals, as well as outside people, helping us with that to make sure that we have a smooth transition here at Ameren.

(indiscernible), Luminous (ph) Management.

A question on the Illinois Power sort of estimate on ROE that you gave. What would be the impact sort of going forward of the refinancing of the high-cost debt there. And then also, I guess the reduction in power purchase costs at Illinois Power -- does that have a significant impact on the return at IP?

I think a couple of things with regard to -- let me talk about your cap structure. One thing, clearly, is IP's historical capital structure was somewhere in the mid-40s. As a result of our recapitalization, their capital structure now is somewhere between 50 and 55 percent. And so, we believe we will have a good opportunity to earn on that increased capital structure equity constant in that capital structure prospectively.

With regard to the purchased power costs -- again, here through the end of '06, we have purchased power agreements that we signed up for Illinois Power. But post '06, those purchased power agreements are over. And then we move into this new marketplace that Gary described a little bit earlier. And our proposal -- this is the auction process. So our proposal is that whatever the results of that auction process is, then we will then reflect those currently in rates under a pass-through mechanism. So there really is no margin to be earned by that; we will simply pass through the cost to rate payers that will result in that auction.

Right. But in 2004, was a part of that year under the old Dynegy structure at the higher power purchased cost, or had it been -- was most of 2004 under the revised contract for power purchased?

The 2004 would have been under the old Dynegy power supply agreement. That expired at the end of 2004. And then we entered into a new power supply agreement with Dynegy for about 70 percent of those requirements that will expire at the end of 2006, and have entered into other agreements to take care of the other 30 percent.

Ted Heim, Smith Barney.

I was wondering if you guys could give me the contribution to EPS from interchanges sales and emission credits for '04?

The contribution to earnings per share from interchanges sales was, on a comparable share basis, 71 cents per share in 2004.

And you guys are seeing that you could -- saying that could go down by 10 to 20 cents next year?

That's right. Now, one thing you have to keep in mind -- that is true. You have got to kind of, because of the dilution and how we show the slides in there, you've got to make sure that -- we put all the dilution on sort of one slide, one line item. So you have to do it on a comparable share basis.

Understood.

But, yes. As you look on our guidance slide, we do expect interchanges sales to go down by 10 to 20 cents per share, largely due to the volume issues that we discussed a little bit earlier with Doug Fischer.

Also, you guys mentioned the MISO Day 2 a little bit. Can you talk about -- it's my understanding there's a 60 day trial period where sales into the marketplace need to be on some sort of cost index basis as opposed to a market price basis. Do you guys have an estimate of how that is going to affect you, and is that included in the 10 to 20 cents?

That's kind of interesting. You're exactly right, and let me clarify what that is. Basically, when MISO proposed to implement the Day 2 markets, they had suggested to FERC, and FERC ultimately then ordered that -- and for the first two months of MISO DAY 2 operations -- that prices will be cleared at the fully loaded cost of the highest cost plants that, I guess, clears the market on any given day. And so that is the way it is expected to operate.

Now, how much that really ultimately will affect the marketplace, it's hard to say, and how much volatility. Obviously, the reason they did that, I believe, was to reduce some of the volatility and some of the issues that they had (technical difficulty) MISO, but what others have experienced in the past.

In terms of what we have reflected, certainly we have reflected, I would say, an estimate of what the MISO Day 2 markets may be, including those two months. Our sense is that, just as you pointed out, the markets are fully aware of this pricing, and frankly, reflected that already into their forward curves. So it remains to be seen. We put that out as a cautionary because we can't ultimately predict because of that two month time period. But we don't -- we hopefully don't expect to see that be a significant effect one way or the other.

So it's really -- the big driver is the Callaway outage and more volume sold to the retail business, as opposed to probably the MISO -- the effect of MISO (multiple speakers) that two months.

That is a fair statement.

Then, just the emission credits for '04?

What were the emission credit sales?

What did you guys recognize on an EPS basis?

On an EPS basis for emission credits we recognized 9 cents per share.

David Grumhaus, Copia Capital.

A couple of questions for you. The Noranda opportunity kind of pulled us into your service territory. Can you talk about that, what that would mean? Would that go under -- be just a customer and rate base, or would that be -- would you bid that as a wholesale customer?

Our proposal for the Noranda Aluminum, as I said before, is a 470 MW customer. They would essentially become a regulated customer. We would essentially extend our service territory to their plant in Southern Missouri and they would become a regulated customer. Of course, as you know, rates are frozen through June 30, 2006. So we have sort of this interim rate that we'll charge Noranda Aluminum, and then once we have our next rate case in Missouri, they will be treated like any other industrial customer.

And are they working with you on this?

Yes. Noranda is working with us. This is our case that we filed, but they have filed supporting testimony in that case.

Okay, that's helpful. Next question. Coal and transportation costs -- I know when you had bought CILCORP, you had thought you would see some step-ups as some contracts rolled off, positive accretion. Are you seeing those? Have those been overcome a little bit by the higher coal and transportation costs? What is your outlook as you look at '05 and '06?

I think in general, let me talk about -- broadly about Ameren, and then I'll get focused a little bit more on your CILCORP question. In general, as we have said before, we do expect to see rising all-in coal and transportation costs by about 3 to 4 percent per year over the next couple of years for the Ameren system as a whole. Obviously, with regard to CILCORP, they were obviously a big user of Illinois coal. And we still have, in our plans to convert, some of their plants to BRB. So frankly, the expectations that we had before, even though the cost may be rising a tad, are still positive in terms of the savings that we expect to realize from that.

That's helpful. The last question for you, and I think Daniele touched on this a little bit -- recovery of emissions cost in Missouri as you go to make these expenditures will -- I think typically in Missouri you just have to file rate cases to get those recovered. And, obviously, Great Plains has been trying to, or KCP&L has been trying to change things a little bit on that front. Do you think there will be opportunities for you to be able to recover these costs before you make the expenditures? Is that still in the planning stage? How are you looking at all of that?

I guess there are a couple of things. One, obviously, as I said before, we believe we have the opportunity, and we'll clearly have the opportunity as it's part of the regulatory process to recover those. One thing which is actually going through the Legislature (indiscernible) this morning (technical difficulty) hearings on this thing, is a bill that will enable the Missouri Public Service Commission to regulate or to provide for a number of different things in terms of their regulatory framework -- including, potentially, a fuel adjustment clause; including, potentially, an environmental cost rider; including, potentially, incentive regulation. This is at the very early stages of the legislative process in the state of Missouri, and all this simply does is enables the Commission to potentially do this in the future, whereas today they really by law do not have that opportunity to do that by themselves absent the stipulation. So, I guess the long-winded answer to your question is that should that law pass, and should we be able to then structure a framework that we could present to the Commission that they would accept, we may indeed have the opportunity to recover some of those environmental costs on a more timely basis in the future.

Ashar Khan, SAC Capital.

Warner, going to the emission credits, is the lower credit earnings in '05 that you are projecting -- should we assume the similar level going forward, or there will be further lesser use of emission credit sales going forward after 2005?

I think at this time, as I said before, we are still in the process of fine-tuning our environmental compliance strategy. So, in terms of a run rate in terms of emission allowances sales, we expect this year, 2005, to be somewhere in that $10 million range, roughly, in terms of total dollars. Beyond that, when we come out with our final environmental compliance strategy, I will be able to give you better guidance in terms of what '06 and beyond may look like.

I don't know, I might have missed this in the details. What is the average share count on which the 2005 guidance has been based on?

Ashar, we'll go back and take a quick look. My guess is it is somewhere between 190 and 200 million --

195 and 200 -- somewhere in that range.

That was Bruce. I think it's close to 200 million, roughly. It may be a little -- a tad shy of that.

I was just going back to some of the things on this slide for '05 guidance. Some of the ranges on, like, employee benefits -- you have a -1 to a -5. I'm just trying to understand why such a range? Haven't you set in your benefit costs and everything for the year? I'm just trying to see how it could vary.

Sure. I think with regard to pensions and OPEBs, those types of things generally get to be locked down. But, of course, we have medical claims that employees use as part of their employee benefit plan. So, some of that is for all practical purposes self-insured. So, that being the case, how their claims are filed -- that could move that number. And we are actively working on sort of plans to, frankly, have employees to -- I guess, plans to maybe minimize what medical claims -- sort of a wellness type of plan for employees prospectively; in fact, we have seen some meaningful benefits already from that this year. So there's a bit of that range around that. That's why you see that.

And if I can just end up with -- can you just remind us what is the approximate timing of the Callaway outage? When did it start?

It's in the fall. Gary, do you remember?

It is roughly mid-September. And I don't recall the exact date, but it is projected to be a 70 to 75 day outage in order to replace steam generators.

Philson Yim, Morgan Stanley.

I wonder if you could talk about IP. Last quarter you had mentioned that locking up the incremental 30 percent of power for IP was going to squeeze margins a little bit. Was that what happened?

In terms of the additional 30 percent of our load, yes, we anticipated those prices to squeeze margins a little bit. And they have been reflected in our guidance.

So the increased accretion guidance is from just additional synergies that are to be realized?

Principally, Philson, that is exactly right -- incremental synergies. And in particular, we were very successful, as we said before, at getting that very high-cost debt of Illinois Power out. In fact, we got more of it out more rapidly than we had expected. So that -- in terms of where we were before, say, in October, November -- that is probably one of the major drivers that moved the number up from 5 to 10 up to 9 to 13.

How do we think about maybe kind of the generation rate at IP? Is that over-earning on those purchased power costs? I mean, is there going to be an incremental benefit from those contracts being passed through in '07 at IP?

I'm trying to make sure I understand the question and make sure I answer it properly. I don't suggest that -- I guess the way I look at IP, especially from generation, is that you have '05 to '06, and that sort of structure kind of goes away. And then post-'06, Illinois Power, obviously, is short generation; it does not have generation. It's just going to go out into the competitive markets. And you will pass whatever costs come -- at least we hope -- whatever costs come from the auction process, you'll just pass those through to customers. And basically we won't earn any margin on that.

Right. But right now, because you're under a rate freeze, your purchased power has -- have increased when you locked up the incremental 30 percent. What I'm trying to get a sense is kind of like is that -- would there be upside from not having to get squeezed on that purchased power (multiple speakers) in '07?

I don't believe so. I wouldn't certainly factor in much upside there as a result of the purchased power costs and getting squeezed. I don't think so.

Dan Jenkins (ph), State of Wisconsin Investment Board.

I was wondering -- you talked about one of the benefits was strong performance at your coal plants. It sounds like you had record performance at the coal plants. Is that right?

Dan, we generated about 75 million MWH last year and saw roughly a 2 percent increase in capacity factor. And we are projecting that continued increase in capacity factor to reach about 80 percent on our system over the next couple of years.

Okay. So that's sustainable and you see further improvement then in that?

Sustainable at least in the short-term. Eventually you'll reach a theoretical limit when the availability of your plants gets into the low 90s, but we're not quite to that 90 percent level right now, so we can go higher. 80 percent within the next couple of years, I think, is realistic. And then after that, it really depends on how the markets continue to develop. Potentially it could go to 85 or 90 percent if we maintain the kind of market that we have now long-term, and some of the transmission constraints that we have at times go away after we get into the MISO Day 2 market.

Daniele Seitz, Maxcor Financial.

Just to, if you could, give us a sketch on your next rate filings. There are several of them that are going to be on the TND area in Illinois. And also, are all of those rate filings going to happen this year, or is it more likely to be in '06?

Daniele, this is Warner again. With regard to Illinois, we plan to make a rate filing for -- well, let me step back. Number one, you're going to see a filing that is going to be made by the end of this month that will be essentially a tariff filing. And that tariff filing basically is going to outline how we believe the overall generation procurement process and auction process should go forward, as well as reflect a change in the tariff to give us the ability to -- the pass-through mechanism to pass through the generation cost. So that's sort of an immediate type of filing.

Then, either later this year or as late as early next year, we would expect to file in Illinois Cost of Service studies and what I would consider more the traditional rate case for the energy delivery portion of our businesses. We have not decided at this point in time whether we would do that either later this year or early next; that's still -- we're still under consideration.

In Missouri, what has to happen is that by January 1, 2006 we have to file a Cost of Service study with the Missouri Public Service Commission. Whether a full-blown rate case will be filed at that time or not will be dependent upon really the results of that study. So, that would be, clearly, later in '05 and more likely the first part of '06, should that occur.

Gentlemen, at this time there are no further questions. I'll turn things back over to you for any additional or closing remarks you may have.

Thank you, everyone, for participating in this call. Let me remind you again that this call is available through February 15 on playback and for one 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.

Thank you. This does conclude today's conference call.