阿莫林 (AEE) 2006 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Ameren first quarter 2006 earnings conference call. At this time all participants are in a listen-only mode. Following today's presentation, instructions will be given for the question-and-answer session. [OPERATOR INSTRUCTIONS]. As a reminder this conference is being recorded Thursday, May 4th, 2006. I would now like to turn the conference over to Bruce Steinke, Manager Investor Relations. Please go ahead, sir.

Thank you, Eric, and good morning, everyone.

I am Bruce Steinke, Manager of Investor Relations at Ameren Corporation. Here with me today in St. Louis is our Chairman, Chief Executive Officer and President, Gary Rainwater; our Executive Vice President and CFO, Warner Baxter; our Vice President and Treasurer, Jerre Birdsong; and other members of Ameren's senior management team. Also joining us by phone is our Vice President and Controller, Marty Lyons.

Before we begin, let me cover a few administrative details. This hour-long call is available by telephone for one week to anyone who wishes to hear it by dialing a play back 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.

We 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 statement 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 2005 to our earnings per share for the first quarter of 2006 on a comparable share basis. In addition, this presentation includes a slide that compares our 2006 earnings per share guidance to full year 2005 earnings per share. Again, on a comparable share basis. To access this presentation you may look in the investors section of our website under presentations or follow the links for the webcast.

Gary will begin this call with an overview of our first quarter 2006 results and some key operating matters. Warner will then follow with an update on regulatory matters and a more detailed review of our first quarter results. 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 first quarter 2006 earnings of $0.34 per share which compared to last year's earnings of $0.62 per share. Despite solid operations, our first quarter 2006 earnings fell short of the strong earnings we achieved last year. Several factors negatively impacted our earnings. Temperatures during 2006 winter season in our service territory were extremely mild, resulting in lower electric and gas margins. Our electric margins were also negatively impacted by higher fuel and purchased power costs due primarily to increased coal and related transportation costs. In addition, we incurred incremental costs of operating in the Midwest Independent Transmission System Operator Day Two Energy Market in the first quarter of 2006 because MISO Day Two operations didn't commence until the second quarter last year. However, the MISO costs were in line with our 2006 expectations. We've seen improvements in MISO's operations and expect these improvements to continue. These factors offset higher margins from organic growth and interchange sales compared to the first quarter of last year. Other operating expenses and taxes other than income taxes also rose, negatively affecting earnings for the quarter. These expenses rose primarily as a result of higher gross receipts taxes, the absence of a favorable property tax settlement such as the one realized during the first quarter of 2005, and higher bad debt expenses. While I recognize that we're off to a slow start in 2006, we do anticipate improvements in our operating results, especially in the second half of the year as we realize the benefits from the lack of a Callaway refueling outage, fewer outages at our other power plants, and lower MISO costs than in 2005, among other things. Consequently, we continue to expect to deliver solid earnings for the year. Warner will go through the drivers of our 2006 earnings in more detail in a few minutes, so I'll turn to a discussion of some key operating matters.

To start off, I am pleased to report that we continue to make progress in improving the operations of our power plants. Our Callaway nuclear plant was on line all quarter. In addition the availability of our coal fired fleet was 88% in the first quarter of 2006, compared to 83% in the prior year period and our capacity factor averaged 77% compared to 75% in the prior year period. These improvements were achieved despite the fact that during the month of March we lost transmission out of one of our plants for a period of time due to a tornado. While our operations performed well in the quarter, we continue to experience some delays in deliveries of coal by rail from the Powder River Basin, which provides about 90% of the coal for our plants. Deliveries were in line with expectations in January but deliveries in February through April were less than expected. However, we have been able to build coal inventory levels this year. We continue to expect that railroad maintenance in 2006 will be less disruptive to coal deliveries than it was last year. Consequently we do not intend to implement any coal conservation strategies at this time. We also continue to expect our coal and transportation costs to be up 10 to 15% this year over last year, and 15 to 20% in 2007 over 2006. Much of these increases are expected to be incurred at our regulated AmerenUE subsidiary. Warner will discuss how these costs will be addressed from a regulatory perspective in a few minutes.

I would now like to update you on the incident at our Taum Sauk pump storage hydroelectric plant. In early April, we filed a report with the Federal Energy Regulatory Commission from an independent expert the Company commissioned to examine the root cause of the December 14, 2005, breech of AmerenUE's Taum Sauk plant upper reservoir. In summary, the independent expert concluded that the root cause of theTaum Sauk incident was primarily the original design and construction of the plant back in the late 1950s and early 1960s. In addition, the independent expert determined human error contributed to the overtopping event because level protection probes were not maintained at designed heights. A FERC staff report filed this week came to similar conclusions. The independent expert also concluded that restoration of the upper reservoir to an operating condition cannot be achieved by simply repairing the breached area; and restoration, if undertaken, will require a complete rebuild of the entire dam with a completely different design concept, one that is substantially more robust. The FERC investigation as well as investigations by state agencies and authorities continue. We expect those investigations to be concluded later this year. While we want to rebuild the upper reservoir, it is too early to discuss when or if the plant will return to service. However, should the decision be made to rebuild the Taum Sauk plant, we would expect it to be out of service for most, if not all, of 2008. Any decision on the future of the plant will wait until after the investigations are concluded, further analyses are completed, and input is received from key stakeholders. We believe the liability resulting from Taum Sauk incident and repair and or replacement of the Taum Sauk facility is substantially covered by insurance.

About month ago, and unrelated to the Taum Sauk incident, we closed on the purchase of three natural gas fired combustion turbine generators with a combined capacity of nearly 1500 megawatts. These generators will serve our AmerenUE regulated business and are the lowest cost option for meeting AmerenUE's reserve margin requirements through at least 2015. These purchases also give us the option to continue studying several technologies for a future baseload plant while we monitor evolving emissions legislation.

On the environmental front, as most of you well know, we've been ramping up our activities to comply with SO2, NOx, and mercury regulations. Based on the federal Clean Air Interstate Rule and Clean Air Mercury Rule, we still expect capitol costs to range from 2.1 billion to $2.9 billion through 2016. However, the Missouri and Illinois rules implementing these plans have not been issued, and could be more stringent than the federal rules. These rules could increase or accelerate costs from our current estimate. We expect activities around the adoption of state-specific rules to gain momentum over the next few months. It's important to remember that based on the current estimates, we believe approximately 55 to 60% of these costs would be recoverable through regulated rates.

Finally, with regard to post-2006 operations in Illinois, and the potential for meaningful rate increases for our customers, I want to reemphasize our commitment to work with key stakeholders to structure a rate increase phase-in plan to lessen the impact on our residential customers. As we've stated in the past, any plan must incorporate full and timely recovery of our costs and maintain our Illinois utilities’ existing credit ratings. We're convinced that this path will result in a constructive solution for our customers, investors, employees, and the state of Illinois, and we are actively pursuing it.

At this point, I will now turn the discussion over to Warner to discuss regulatory matters and our first quarter earnings in more detail.

Thanks, Gary.

As you all know, we continue to have quite a bit of activity on the regulatory front. In Illinois, appeals are still pending regarding the Illinois Commerce Commission's unanimous approval of the auction for power supply for 2007 and beyond. The auction is necessary because of the expiration of the current power supply contracts for our Illinois distribution utilities at the end of this year. As a result, despite the appeals, preparation for the September auction continues to move full speed ahead. The delivery services rate cases filed in late December for our Illinois distribution utilities also continue to progress. In our delivery services rate filings, we requested a total combined annual electric revenue increase of approximately $200 million. Our filings also included a two-year phase-in plan of this increase for residential customers for Ameren CILCO and AmerenIP with no deferral of uncollected revenues. Last week, the staff of the Illinois Commerce Commission, the Illinois Attorney General, and the Citizens Utility Board recommended combined annual electric revenue increases in the range of $70 million. The principal differences between the parties related to the recommended return on equity which ranged from 8 to 10% versus the Company's request of 11% and the disallowance of certain administrative and general expenses and rate-based items, among other things. We plan to file rebuttal testimony responding to the parties on or before May 26th and expect the ICC to issue a final decision by November of this year.

Last September, we stated we believed that our Illinois customers could experience rate increases of 20% to 35% over current bundled electric rates in 2007. Of course, that estimate was based on a host of assumptions including our Illinois utilities expected purchase power costs resulting from the auction and the final regulatory determination in our delivery services cases. As a result of the potential increases to ratepayers, we've seen two legislative proposals in Illinois. One proposal includes a potential extension of the rate freeze for 2010, which we believe is without legal merit. The extension of the rate freeze would result in severe financial consequences for our Illinois distribution utilities and would negatively impact our ability to reliably provide electric service to our customers. Following the introduction of the rate freeze proposal, a second separate piece of legislation was introduced to allow for the deferral of a portion of power procurement costs for residential customers as well as the issuance by a special purpose finance entity of securitization bonds to recover the deferred costs. From the standpoint of residential ratepayers, this proposed securitization legislation would effectively result in the recovery from ratepayers over a period of up to ten years, a portion of the power procurement cost incurred during the first two years following the January 1st, 2007, transition to competitive markets. From Ameren's standpoint, this proposed securitization legislation would result in recovery of deferred power procurement cost immediately upon the issuance of the securitization bonds. This legislation would also allow to us finance the deferrals at the lowest possible cost to our customers. The legislation does not specify the amount of power supply costs that would be deferred or the dedicated charge to be paid by residential customers in order to service interest and principal on the securitization bonds. That matter would ultimately be determined by the Illinois Commerce Commission. We view this legislative proposal as a very constructive way to mitigate the potential rate increase for residential customers. And while we believe passage of this legislative proposal may not take place in the near term, we believe it provides a meaningful platform for dialogue among key stakeholders prior to the fall veto session where we expect further discussions around this matter will take place. As Gary mentioned earlier we are willing to work with key stake holders to structure a rate increase phase-in plan to lessen the impact on our residential customers. However, any plan must incorporate full and timely recovery of our costs to maintain our Illinois utilities’ existing credit ratings.

In Missouri, the rule making process by the Missouri Public Service Commission for the fuel and purchase power and environmental cost recovery mechanisms that were signed into law last summer continues. We continue to expect rules to be effective in the second half of this year. Regarding the expiration of our electric rate freeze in Missouri on June 30, 2006, a public meeting with the Missouri Public Service Commission and key stakeholders is being conducted this afternoon to address the status of a potential rate proceeding for AmerenUE. At this meeting, we expect to inform the Commission that we intend to file for a rate increase later this year. Of course, the Missouri Public Service Commission's staff and others will review any filing, and based upon their analyses, will make their own rate recommendations. The exact timing of our filing and amount of the requested increase is still to be determined.

In our calls with you earlier this year, we discussed a request we filed with the Federal Energy Regulatory Commission for approval of an amendment to the joint dispatch agreement, or JDA, among AmerenUE, AmerenCIPS, and Ameren Energy Generating Company, or GenCo. This amendment was approved in March, with retroactive application to January 10th, 2006, and changed the allocation of margins on short-term energy sales in accordance with the Missouri Public Service Commission order issued in 2005, approving the Illinois service territory transfer from AmerenUE to AmerenCIPS. Based on operating performance for 2005, the amendment would likely have resulted in a transfer of electric margins from GenCo to AmerenUE of approximately 35 to $45 million. In the first quarter of 2006, it resulted in the transfer of approximately $9 million of electric margins from GenCo to AmerenUE. As we discussed in our last call, during the filing process at the FERC, the Missouri Office of Public Counsel asserted that the JDA should be further amended to value all transfers between GenCo and AmerenUE at market prices rather than incremental costs. The protest was denied by the FERC, but we expect the JDA to continue to be an issue during the next rate proceeding in Missouri. Both GenCo and AmerenUE have rights to terminate this agreement with one year's notice unless terminated earlier by mutual consent. Should the JDA be modified to price energy transfers at market or otherwise be terminated, it could significantly reduce the revenue required to be collected through rates the next time electric rates are adjusted in Missouri, as well as modify or eliminate the amount of cost-based energy transfers between AmerenUE and GenCo.

I would now like to refer you to our website as I provide a more detailed discussion of 2006 earnings. As Bruce mentioned earlier, 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 2005 to our earnings per share for the first quarter of 2006 on a comparable share basis. In addition, this presentation includes a slide that compares our 2006 earnings per share guidance to full year 2005 earnings per share on a comparable share basis.

For the first quarter of 2006, we reported net income of $70 million, or $0.34 per share compared to net income for first quarter 2005 of $121 million, or $0.62 per share. As Gary mentioned earlier, electric and gas margins were lower during the quarter due to the extremely mild weather we experienced in January and February. Heating degree days in the first quarter of 2006 were approximately 11% below a mild 2005 first quarter and 18% below normal, according to the National Weather Service. As a result, weather-sensitive natural gas sales decreased 8% and residential megawatt hour sales in the 2006 first quarter decreased 2% from the mild 2005 first quarter. Weather is estimated to have reduced first quarter 2006 earnings by $0.04 per share versus 2005 and $0.07 per share versus normal weather conditions.

During the first quarter of 2006, we incurred higher incremental costs of operating in the Day Two Energy Market of MISO due to the fact that MISO Day Two operations didn't commence until the second quarter 2005. While MISO Day Two costs reduced our first quarter 2006 earnings by $0.06 per share compared to last year, they were in line with our expectations. Electric margins were also negatively impacted by $0.02 per share during the quarter due to the Taum Sauk plant being out of service. Other electric margins including interchange sales were generally flat during the quarter. Benefits from the additions of Noranda Aluminum in June 2005, organic growth, and higher interchange margins were offset by higher fuel and purchased power expenses during the quarter.

Interchange margins rose due primarily to increased sales by the Company's 80% owned unregulated electric generation subsidiary Electric Energy, Inc., or EEI. EEI's interchange sales rose as a result of the December 31st, 2005, expiration of cost-based long-term sales contracts with our regulated affiliates for power that is now available for sale in the interchange markets. However, our fuel and purchased power expenses also rose during the quarter for these regulated entities as they replaced the power previously supplied by EEI. Since our rates are current frozen, these increased costs are not currently recoverable from our customers. Of course, the other major driver for our increase in fuel and purchased power expenses was the increase in coal and related transportation costs. For the quarter, our fuel costs rose 12% consistent with our expectations. Fuel and purchased power expenses also increased during the quarter due to incremental water usage fees incurred at AmerenUE's Osage hydroelectric plant which reduced earnings by $0.02 per share.

Emission credit sales generated a $0.01 per share gain in first quarter of 2006 versus none in the first quarter of 2005. With higher natural gas prices and a restriction on disconnections, we are expecting higher bad debt expenses in 2006. Our provisions for higher bad debt expenses reduced earnings by $0.02 per share in the first quarter of 2006 over the year-ago period. Net dilution and financing costs reduced earnings by $0.03 per share in the first quarter 2006 over the same period a year ago. Dilution resulting from the conversion into common shares of 7.4 million of our adjustable conversion equity security units in May 2005 primarily drove the variance. Higher depreciation and amortization expenses reduced earnings by $0.02 per share in the first quarter of 2006 compared to the year-ago period, primarily because of capital additions. Taxes other than income taxes were a negative variance in the first quarter of 2006 compared to the first quarter of 2005 as a result of increased gross receipts and payroll taxes and the absence in 2006 of the $0.03 per share benefit of a tax settlement that was received in the first quarter of 2005. Other items netted a negative $0.02 per share.

This morning we also announced that we have narrowed our expectations for 2006 earnings to $2.95 and $3.15 per share from our previous guidance of $2.95 to $3.25 per share. This narrowing of earnings per share guidance was due primarily to warmer than normal weather in the first quarter of 2006, which, as I stated before, reduced earnings by an estimated $0.07, and power prices for interchange sales for the remainder of 2006 which we anticipate to be lower than originally expected. While our first quarter earnings were below our strong 2005 first quarter earnings, we anticipate improved operating results, especially in our earnings in the second half of 2006. It is important to note that our Callaway nuclear plant had an extended scheduled refueling outage last year in the third and fourth quarters that will not take place this year. The lack of a refueling outage is expected to benefit 2006 earnings by $0.17 per share compared to 2005. In addition, we have fewer scheduled maintenance outages at our other power plants in the second half of this year, and we expect improved operating performance from all our plants. These factors should improve electric margins and lower expenses on a comparative basis. In addition, we expect to see lower MISO Day Two costs in the second half of this year compared to 2005. You may recall that the MISO Day Two Markets began in earnest around June 1st last year, and we experienced higher than expected costs due to the infancy of that marketplace and significant volatility in summer weather patterns. So while we have gotten off to a slow start in 2006, we have a game plan to deliver solid earnings performance for 2006.

Ameren's guidance assumes normal weather for the rest of 2006 and is 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 Ameren's forward-looking statements.

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

[OPERATOR INSTRUCTIONS]. Greg Gordon, Citigroup.

Thanks. Good morning, gentlemen.

Good morning.

Two questions. When we look at the first quarter obviously it was -- the number you printed was significantly below consensus, but when I look at where you were -- where you were lower, it looks like the only structural issue in terms of your ability to meet your full-year guidance is weather, and that a lot of this was expense timing in the quarter. Is that a fair interpretation?

Well, certainly weather. It was certainly a structural issue, and as you see that we lowered the upper end of our guidance $0.10 per share of which compared to normal weather was down $0.07 per share. As we also pointed out, power prices in the markets were a little bit lower than our expectations going into the year, and so that -- that also has some factor as we approach the rest of the year, which we discussed.

Right. But there's $0.06 of MISO Day Two in the quarter, $0.02 of bad debt, and $0.07 of taxes versus the first quarter last year, and it just seems to me that a lot of that stuff was maybe stuff we thought would be booked more sort of ratably across the year?

I tink that's a fair statement. Certainly, I think when you think about the MISO Day Two costs, as you look at our guidance, we actually expect MISO Day Two costs to be maybe negative $0.01 up to positive $0.08. So clearly that negative $0.06 we see turning around be booked more ratably, and then we'll see some of those benefits in the second half. Certainly we had a favorable property tax settlement of $0.03 per share last year which is in taxes rather than income, and so that too is timing. And so basically, when you say that statement, there are some timing issues that I think clearly are going to be reflected more in the second half of this year so your statement I would generally support is right, certainly couple that with weather, but we point out a little bit about the power prices. But as we said, we still feel very confident to hit our earnings targets under our original guidance.

Great. And then my second question, the -- this JDA issue, if you're a really -- real hard-core utility geek, I think you understand it, but maybe a good way to explain it to us would be if we looked at the last fiscal year, what would have happened if we went back to the last fiscal year and looked at the JDA, and if you had not been transferring it at transfer prices but at market prices what would the financial impact have been?

Greg, that's really a tough question to answer because really if you look back at the last fiscal year, there are several things to think about in terms of the JDA. The first thing you have to think about is the level of transfers that took place last year, which was right about 9 million megawatt hours. And that transfer took place from UE to GenCo, and those were priced at cost. When you look at that transfer -- those levels of transfers, we expect those to be significantly lower going forward. That would be due to the fact, number one, remember, Noranda Aluminum, which is the largest energy user in Missouri, they really didn't come online until June of 2005, and so basically, you have to -- you'd factor their level of sales for an entire year. That will take away some of the excess power that UE would to have transfer to GenCo in the future. Couple that with the fact that the EE, Inc. power supply contract that we talked about, that was a 400 megawatt contract between UE and EE, Inc., that, too, is going away, or did go away at the end of 2005. And so when we look at 2006, that is indeed some incremental excess generation that UE will not have going forward. So those are just two factors as well as organic growth that need to be looked into. So it -- I don't think it's appropriate just to look at that -- the transfer levels of transfers last year.

Okay. So the transfer -- the amount that gets transferred drops dramatically, but when we think about what the impact might be it would be to increase the -- let's say it dropped to 3 or 4 million megawatt hours. And I'm just pulling that number out of the air. The way to think about the financial impact would be if we increased the revenue booked at UE from a transfer price to a market price, that would serve as a jurisdictional offset to retail rates? Is that fair -- it that the right way to think about?

I think in terms of that, at the end of the day, to the extent that whatever transfers had historically taken, when you normalize it for all these other conditions, that would have an impact, assuming that market is greater than cost, which it is, of reducing the overall revenue requirement for UE. I think the other thing which is complicated in terms of the joint dispatch agreement is trying to figure out just exactly what the appropriate market price to utilize. When you look, certainly, at last year's market prices -- now, number one, they were not only volatile but they were significantly higher because a lot of the hurricane effects that took place. So while you may look at a normal test year type of deal for UE or when you look back at 2005, the other challenge associated with the joint dispatch agreement isn't just the level of transfers but it's determining what that appropriate market price should be for setting future rates should that change be made.

Thank you, gentlemen.

You're welcome.

Paul Ridzon, KeyBanc.

Good morning. How are you?

Well. How are you doing?

Okay. Just a follow-up on Greg's question. Just want to make sure I understand the mechanism. Would this transfer flow through fuel clause or would it actually be a base rate issue?

With regard to that, that's still not determined, because the final rules associated with the fuel clause have not been -- have not been established. In fact, there have been draft rules that are being circulated that are going to be commented on by the end of this week, and so it would be premature for me speculate whether the changes to the joint dispatch agreement -- any changes to the joint dispatch agreement would flow through the fuel clause or be part of base rates. Frankly, in the future, even if there is a fuel clause it could be part of both. It could go either way. So -- but number one, with regard to the JDA, we do believe, as we said before, that this will be an that issue will be addressed in an upcoming rate case and the JDA could be addressed in either form, whether it be in the fuel adjustment clause or in base rates.

And then secondly, unrelated, what was the strategy in the first quarter with regards to trying to conserve coal and where are coal piles and could maybe some of the weakness we saw in the first quarter be offset by having stronger coal piles that might be of great value in the summer?

Paul, this is Gary Rainwater. We really did not try to conserve coal in the first quarter. We have been able to improve our inventories somewhat. I would say we're still not back to the levels that we would like to be. One of the things that we did late last year is purchase additional rail cars, so we've been able to increase our schedules even though we're not getting full delivery under those schedules. We are -- inventories are improving. We don't expect to need to conserve coal this year.

Okay. Thank you.

Paul Patterson, Glenrock Associates.

Good morning, guys.

Good morning, Paul. How are you?

All right. I just want to sort of maybe have you guys elaborate a little bit more on what you see in Illinois. You guys mentioned that some of the legislative proposals that are there. You also said that you didn't think anything was going to necessarily happen soon. And I was wondering, do you still believe legislation's necessary for the deferral? And if so, when do you think it might happen? Do you think it might happen in the veto session, or what should we look out for?

I think, Paul, with regard to sort of the events in Illinois, we -- as we said, the Illinois legislative session is likely to wrap up perhaps sometime here in May, and we don't believe the legislative proposals, whether the rate freeze or the securitization legislation, will be addressed in this legislative session, but do believe that both over the summer as well as we approach the fall veto session that more discussions around this issue will take place. Certainly with regard to securitization, to embrace securitization as a form of rate mitigation, we would definitely need to have legislation. There's no question. And so we obviously are supportive. We think that is a constructive way to address the issues for our residential customers, and so indeed, that would require legislation. All things being equal in terms of a rate increase phase-in plan, we still think it is necessary to have a legislation to address potential issues associated with the rate deferrals that would be granted from the ICC. Absent that, and tell me if I didn't address the rest of your questions, but that's generally the color that we expect to see. And we do expect this to be addressed in the fall veto session in some form or fashion.

Okay. So you guys -- okay. So the fall veto session's the time to look out for it, I guess.

That's fair.

Okay. And then -- and then in terms of Taum Sauk, you say insurance covers it. And I'm just wondering does that cover everything that you expect, including property damage, law suits, and stuff like that, or is it just -- what does the insurance, in your opinion, cover exactly?

Well, we have two different forms of coverage. We have one that deals with sort of the property damage. As you know, we damaged a state park, and among other things, and that's under sort of one policy. And then we have a -- sort of a separate policy that addresses the potential rebuilding of the plant. And based upon our analysis, the liability that we've incurred in terms of the property damage is substantially covered by insurance, and similarly, we believe that the ultimate rebuild of the plant, should that ultimately be granted after our -- after all the analyses are completed and we've talked to stakeholders, we think that would be substantially covered by insurance. Of course, as you might expect, we have deductibles. With the property damage itself, we had a $1 million deductible, and with the rebuild of the plant there's a $15 million deductible. So those are not covered, obviously, but they're consistent with the existing insurance policies that we have.

Okay. Great. Thanks a lot.

You're welcome.

Doug Fischer, A.G. Edwards.

Thank you, and good morning.

Good morning, Doug.

Good morning, Warner. Do you think that your decision that you're going to actually file a case in Missouri means that the staff is not going to consider any kind of show cause filing at this time, and they would wait for evaluation of your full rate case?

Doug, I think that's certainly a possibility, that the staff would wait and have the rate case go and move forward, although I think they're certainly not precluded from continuing to do analysis, as well as other stakeholders to do an analysis and potentially file a complaint case.

If there were to be such a complaint case filing from the staff or other parties, what's the approximate normal timing given that they've been looking at your, I guess, year-end '05 or maybe September 30, '05, numbers here for awhile?

Well, I think, Doug, with regard to that, I mean -- this is, in fact, one of the issues that's going to be discussed in this agenda session this afternoon in Jefferson City. But I think, in general, what would generally happen, if a complaint case was filed by the staff or other party, no matter what would happen, there would be a discussion in terms of what the appropriate test year should be utilized. And we are firmly convinced that it's appropriate to try and match the most recent costs to establish future rates, because obviously rates, even if a case was established today, or filed today, either by Ameren or by someone else, the likelihood of that case being adjudicated until sometime early in 2007 is the normal course, usually 11 months. So I think that that's the first thing that would happen. And even if the staff or another intervener would file a complaint case, we still have the right to file our own rate case on top of that, and often what ends up happening is that those causes are usually consolidated, as opposed to two separate cases, because you're really addressing the same issues. So it -- whether a complaint case or a rate case is ultimately filed, I think it's likely that a review of AmerenUE's rates will take place in some form or fashion this year.

Now, in your filing, I assume you will make a decision as to whether to proceed with the joint dispatch agreement or whether to propose in this case its elimination. Would that be the forum?

Yes. I think in terms of the rate case, I mean, certainly there are a host of issues in terms of putting that together that you need to make decisions on, and how we would address the JDA is certainly one of those decisions.

And if I understood correctly, while there's -- would be some revenue shift away from the unregulated generating company with the elimination of the JDA, that's partially offset by the Joplin EEEE -- EEI plant going to market. Is that the right way to think about it?

Well, I think the right way to think about it, from -- I guess there are a couple ways to think about that. I guess, number one, the level of transfers from AmerenUE to GenCo would decrease as a result of the expiration of that EEI contract, which, as you may know, that contract has been disputed by interveners in FERC proceedings in the past, and we would expect that to be an issue even in this current case, so that would change the level of transfers and therefore the level of revenues that UE may receive under the JDA at market base rates. And, of course, the EE, Inc. incremental generation that is now unregulated, you're right, that would be an opportunity to sell that into the marketplace at market prices versus what has historically been at cost-base prices, and so that would be a mitigating effect, you're right.

What's the volume that is now at market from EE, Inc. that used to be under contract and is the contract -- the contracted price is a public number, maybe you can tell us what that is.

Off the top, it was -- generally it was 800 megawatts. And, Bruce, do you know the exact number of megawatt hours?

Well, EEI owns -- or EU owns 40% of EEI, and EEI sells about 8 million megawatt hours a year. And the cost -- it was a cost-based contract which I think is sub $20.

That's about right, Doug, and then there's another 400 megawatts that's owned by GenCo.

In total, EE, Inc., is a 1,000-megawatt plant. And so -- we owned 80% of it. The other 20% is owned by LG&E. And so, in total, the -- all of that 1,000 megawatts are going to market from EE, Inc., of which Ameren receives 80% of the benefits of that.

And 40% of that is UE-owned, or was contracted to UE?

Well, it was contracted to UE, 400 megawatts, that's right.

But UE does not own the asset. It's a subsidiary --

So that contract has gone to market now.

That is correct, yes. And that contract is not in the regulated rate base of Union Electric.

Okay.

Or that --

And that would be captured in a new base rate case, the increased costs.

That's exactly right.

Or through the fuel clause. Okay.

That's right, Doug.

And you can't give us any -- and this is my last -- you can't give us any color on the draft rules for the fuel or emissions or environmental issues at this point?

Well, I think in terms of the color I can give you, there have been draft rules that have been circulated, and the Missouri Public Service Commission staff has sent a notice around to all interested parties to comment on those rules. The utility group expects -- and those comments are due by the end of the day tomorrow, so the utility groups will be commenting, and I'm sure all the other stakeholders will be doing the same. So it'd probably a little premature in terms of saying just exactly where those rules are headed, but I think there are a host of issues that people are trying to deal with, and a lot of it has to do with just the level of detail that has to be provided in those rules as well as issues in terms of just how those rules ultimately will be implemented in particular rate cases, transition issues. And so those are things that are likely going to be addressed by the Missouri Public Service Commission in the form of hearings at some point in time, but nonetheless, it is our understanding that the staff and Missouri Public Service Commission would like to get rules established, especially for the fuel adjustment clause here by the end of the year. That's where the rules are being circulated. Right now the rules have not been circulated for the environmental cost recovery mechanism, but we would expect that to take place soon there after.

Thank you.

You're welcome, Doug.

Ashar Kahn, SAC Capital.

Good morning.

Good morning, Ashar.

Just going back to -- I just want to go over the drivers for 2007. Warren, if you can just -- one is, I guess, if the auction goes through, right? What prices -- how are you doing hedging for 2007? Could you just address that, to your power plants -- are you just going to wait for the auctions, and then set the price? Or how are you setting up your load for 2007? Could you elaborate on that?

With regard to 2007, and let me talk just briefly about drivers, and then I'll circle back to then in terms of sort of our hedging strategy for that. With regard to 2007, certainly we -- with regard to the Illinois auction, we have today prices with affiliates that are at about $37 per megawatt hour, and today you can utilize whatever curve you want to use for 2007. Prices are in excess of that at this stage. So that obviously has potential opportunity. But then secondly, other things which will be taking place in 2007 will be the consummation of our Illinois delivery services rate cases which we expect to be consummated by the end of this year. Obviously we're looking for $200 million increase. The interveners have put $70 million, so at some point that'll be adjudicated, but will likely be an increase in overall revenues for our Illinois delivery services companies. Also issues that we'll be addressing or we expect to continue to have is increased plant improvements. As Gary noted a little bit earlier, we've been successful in improving the overall operations of our plant, and we would hope to continue to do that next year as well. Other factors that you have to think about sort of on the other side in terms of the expense side we will have a Callaway refueling outage next year, whereas this year we do not have one. So that will be an incremental expense. We do expect coal and related transportation costs to continue to rise 15 to 20% next year. Of course, some of those issues we hope to be addressed in resetting rates in Missouri, and so some of that potentially may be mitigated in some form or fashion. Of course, we do expect the Taum Sauk plant to continue to be out next year. That's -- that is going to be consistent in terms of what you see this year in our 2006 results.

Stepping back, then, and talking about 2007 and hedging, we are actively looking to hedge our open positions in 2007, and it isn't just the open positions that we have in Illinois just simply aren't what we have tied up with affiliate contracts. We also have some retail contracts and wholesale contracts which typically are 3- to 5-year contracts, which are rolling off systematically over the next several years. So we are actively looking to potentially hedge those various positions in a lot of different forms, and part of that would be included in the auction. And so we look to try and enter into a host of different arrangements with either retail customers, wholesale customers, financial intermediaries, as well as potentially doing it in the auction. So that's what we plan on doing.

Warren, can you share how much you're hedged in 2007?

No, I think, Ashar, at this point in time that would be premature to give away some of that information. It certainly is competitive information that we don't want to give away our overall position. And so -- but we are certainly actively looking to make sure that we hedge our financial position throughout this year for 2007. And we'll continue to give you updates as appropriate.

And then can I just go to Missouri? If you get a fuel adjustment clause decision in the next few weeks, I guess, if I understand it, it will become implemented at the time of a rate case decision, which won't happen I guess if you file later in the year, probably until the middle of next year, correct? So what happens? Does the rate increases that you get become effective from that day so you are like in a catch-up mode, you get a new updated fuel factor from the day that the decision happens? Could you just elaborate how that would work?

Well, again, Ashar, it's a bit premature for me to elaborate how it would definitely work because the rules aren't ultimately implemented, but just to clarify one thing, the rules may be submitted -- what has to happen with the rules is that they have to be submitted to the secretary of state, and then there will be public hearings. And so while there may be rules submitted to the secretary of state, there is a -- basically a five-month process that has to take place before those rules are, quote, unquote, effective and can be utilized by utilities. You're right. The legislation does require that utilities must file a rate case to try and adopt either the fuel adjustment mechanism or the environmental cost recovery mechanism. And what we are hopeful to have implemented in the rules is a transition. And what that transition -- what I mean by that is there may be utilities, and there are existing utilities out there today who have rate cases pending before the Missouri Public Service Commission. We may also be one of those utilities that would, even though the rate case would start, that they could potentially utilize the rules coming out of SB 179, even though they may not become effective until after a rate case is filed. That's always a possibility. And, of course, in the context of a rate case, you can always have a settlement with the various parties that would address a fuel adjustment clause. So there are a lot of ways to potentially address the questions that you have. And in terms of the specifics, as to whether it would be retroactive or prospective, it's just -- it's impossible for me to say at this point.

Okay. And then, Warren, if I can just -- I guess you said today that you'll be filing a rate increase in Missouri at the end of the year. So what's the prospect -- I guess you didn't mention in your '07 driver as any increase in Missouri jurisdiction from this rate hike.

I didn't mean to overlook that. I guess, number one, what we said is that we expect to file for a rate increase in Missouri later this year, with no specificity in terms of amount or timing, but secondly, we would expect, should we file for a Missouri rate increase this year, that then depending upon the timing of that filing, and assuming, say, an 11-month process, that, too, would have an impact on 2007 and could potentially be a driver. Absolutely.

Okay. Thank you.

You're welcome.

Dan Jenkins, State of Wisconsin Investments.

Good morning.

Good morning, Dan.

I have a couple things. First, I'm curious on your '06 guidance, you have quite a negative amount for weather. Is that where you have above normal weather for the last three-quarters of the year last year? Is that what's driving that? And then in excess of what you had in the first quarter?

Sure. If you look back at our guidance that we provided back in January when we first initiated guidance for 2006, we said that weather, on a year-over-year basis, would have a negative impact of $0.06 to $0.09. And basically what that -- what that represented at that time was the favorable impact that weather had on our earnings compared to normalized weather in 2005. And so we always assume normal weather when we do our guidance or certainly our projections, and so that was a $0.06 to $0.09 unfavorable variance year-over-year. Now, as a result of this first quarter being more mild than normal, by $0.07 per share, what we simply did was add $0.07 to that $0.06 to $0.09 that we had last year. So on a comparative basis, that's what the impact would be, because we always assume normalized weather.

Okay. Then similarly, on your taxes other than income, it was negative 7 in the first quarter, but then you've got 0 to negative 6 for the whole year, but it sounds like of the fact that you got a refund, that should persist, right? So what's driving that to be -- was it like a timing issue on those -- what were those taxes -- the --

Well, it was gross receipts in part, and then the other piece is payroll taxes, which is timing. We had an increase in payroll taxes in the first quarter, and that -- those payroll taxes will be less on a year-over-year basis and for the remainder of the year. So we expect, again, to fall within that 0 to negative 6 range. So part of the 7 -- the negative 7 that you see in the first quarter will reverse later in the year because of timing.

Okay.

At least that's what we expect to have happen.

And then on the -- for the full year, your amount for dilution and financing of negative 12 to negative 16. How much of that is dilution, and how much of that is financing? Do you know that?

Sure, I can give you sort of the breakdown generally of that. In general, we have incremental financing as a result of -- for instance, the peaker purchases that we just completed that Gary mentioned a little bit earlier, that's $290 million. That's about $0.03 per share in terms of incremental interest cost. We also had the conversion of the ACES that we talked a little bit about here in the first quarter. We expect for the full year that will have a dilutive effect of about $0.04 per share. And then we have an ongoing dividend -- a DRIP program. That didn't have really much of an impact in the first quarter, but we expect that to be around $0.03 per share for the whole year. So when you pick up those numbers, you kind of get closer to the 12 to 16. We do expect incremental financing costs year-over-year besides the peakers, that's probably negative, oh, say, $0.04 per share. So if you really look at the true financing costs, if you're talking about just interest cost, you're probably looking somewhere closer to $0.07 per share in terms of the incremental interest expense. And that's mostly due simply to capital additions and financing construction expenditures.

So do you anticipate -- will you still need to come to market to finance those peakers, or have you already done that?

I'll turn it over to Jerre Birdsong, and he can comment a little bit about our financing plans this year.

We have not done that yet, and we'll have to obtain permission from the Missouri Public Service Commission in order to complete that financing, and so we'll get that done after we've received that authorization.

But that -- the numbers that I gave you is reflected -- those are reflected in our guidance that we did anticipate doing that.

Okay. And then you said -- I think I heard you say that the staff is targeting for these new -- this rule making for the old clause and environmental rider by year end? Is that what you said?

Yes -- well, I think the staff is target getting the rules out and submitted to the secretary of state and the State of Missouri sometime soon, so that can go through that process. And that's about a five-month process. And so when you do the math, then, hopefully within the next month or two those rules will be submitted to the secretary of state, and then will then be effective by the end of the year after that rule making process goes through its normal course.

Okay. And then on your Noranda and EEI, it was -- it looks like a 15% increase in industrial for Noranda, so that should recur in the second quarter, it sounds like, and then the 35% of higher interchange sales would that persist in each quarter then going forward, or when did they --

Sure, sure. Let me address at Noranda. Remember, Noranda was effective on June 1st, so obviously we will have favorable comparisons year-over-year for May -- or excuse me. April and May, and then Noranda then will be more levelized for the rest of the year. With regard to interchange margins, we do expect interchange sales and margins to be up because of the expiration that EEI contract. And then -- but also, as we've said, we also do expect that fuel and purchased power costs will also be increasing on a year-over-year basis because the deregulated entities had to replace that power with some generation of their own system or going out into the marketplace to replace that power for their generation needs.

So is 100% of EEI now market-based -- there's -- it has no contracts right now?

That is correct. 100% of the 1,000 megawatts of EEI is being sold at market prices.

Is part of your decline of the wholesale then that those -- that's generation going from wholesale to interchange at EEI, or is there something else going on with the drop in the wholesale?

Well, I think what you're seeing in the wholesale marketplace there in terms of some of the drops in sales, we've had contracts that have rolled off. As we've said before, some of those contracts are going to roll off over the next three to five years. And so we are either replacing those contracts and taking that excess energy into the interchange market, which is affecting some of our interchange margins, or it's -- could just be simply timing in terms of when we can sign those new contracts back up. So it could be simply a timing difference or the excess generation would likely then be going into interchange markets.

And then the last thing, on those EEI interchange, is the current -- given the current market prices, is the margin on those higher than what they were when they were under contract?

Well, if you think about when they were under contracts before they were simply cost-based contracts, and EEI is probably one of the lowest cost generators in the country, so certainly market prices are higher than the cost-based contracts that they had last year.

Okay. Thank you.

You're welcome.

Michael Lapides, Goldman Sachs.

Hi. Real easy one here. What's your estimated -- after adding the new megawatt generation, what's your estimated rate base at Union Electric?

If you give us a second, we will -- we will be able to get that for you here in a moment.

Our estimated rate base at 3/31 is right about $5.5 billion, a little north of that for electric --

And that includes all of the new assets?

Yes.

Okay.

Because we completed the purchase on March 31st, so that includes those assets, and, yes, so that's for our electric. Assuming you're just asking for electric.

And actually just total rate base at UE as well.

Okay. Well, then we have about 200 million in terms of Missouri gas -- AmerenUE gas rate base.

Okay. I appreciate it, guys. Thank you.

You're right, that was an easy one. We can handle those.

Daniele Seitz, Dahlman Rose.

Hi. Thank you. I gather that this rate base will not include any of the environmental expenditures. In your planning or -- how do you visualize this pass-through of environmental expenditures, and by the time you file, how much will you have piled up in that area?

Yes, Daniele, I think you're right, in terms of the $5.5 billion -- in terms of the environmental CapEx that we disclosed in our 10-K, none of those are really reflected in our rate base at AmerenUE. In terms of the -- how those environmental expenditures will be reflected prospectively under the environmental rider, that obviously remains to be seen, but Missouri has had a policy of not reflecting construction work in progress in rate base in the past, and so how that environmental rider will have to handle that, we'll have to obviously take that into consideration as well.

Do you anticipate that securitization will be one of the solutions, or do you -- because obviously if it is a rider, will that be rate based? I was wondering if those were the alternatives?

Yes, well, I think, certainly -- I mean, stepping back for one moment, in terms of environmental capital expenditures, of the amounts I think it's -- that basically it's 2 to $3 billion in terms of environmental CapEx over the next 10 years, 55 to 60% of those are expected to be in our UE regulated operations. All things being equal, while we can't say definitively that they would be reflected in rates in the future, we would expect if we would manage those project prudently and they're in accordance with law, they would be reflected. How the environmental rider would -- is -- whether that would be an alternative, whether we could reflect those on a more timely basis in rate base, again, those rules have to be still determined how that would work. But I think if we don't get those reflected in rate base more timely as opposed to when it's completed, we would be able to reflect at least the return on some of those assets on an interim basis and get some interim cash flows as well as cash flows for the O&M expenditures that we would incur for environmental CapEx. But again, the environmental rules have -- in terms of timing and the level of review on those, I would say they are still several weeks behind where the fuel adjustment clause mechanism is.

Great. And if you get to -- let's assume you are filing sometimes -- [inaudible] or something like that, would you -- how much would you have spent in Missouri, roughly, at that point?

In terms of environmental capital expenditures?

Right.

I think this year that, in terms of the estimates, I would think they would be generally pretty modest. I think they would be somewhere around $60 million this year that we expect to spend by the end of the year.

Okay. So it won't be -- it will be more of a -- on a forward basis that those will apply, I guess.

Yes. I mean, and if you look -- I believe it's in our -- it will be in our Q, and certainly our 10-K, we kind of lay it out for what we expect '06 to be, and then we lay it out what we expect it to be through 2010, then what we expect it to be through 2016. And you can see that they are -- they're kind of back-end loaded versus 2006.

Thank you.

You're welcome.

[OPERATOR INSTRUCTIONS]. Ashar Kahn.

Warren, I was just trying to predict, if I'm right, the fuel costs, a majority of them in the regulated arena, right? So I guess they're going to start hurting it -- lowering the UE's operating income as the year goes by this year, next year. First, is that a fair statement?

Ashar, that is a fair statement we do expect the increased coal and related transportation costs -- they are when you look at both '06, and certainly as we look forward to '07, they will be weighed a little bit more towards the deregulated Missouri side of the business, and will start impacting those returns, absolutely.

And similarly, Taum Sauk is also UE Missouri rate case issue, right? So if it's no longer, I guess, rate based because it no longer exists, earnings are not going to be at the rate base, so that needs to be updated, either at the fuel clause or in the rate base number, correct?

Well, certainly. I mean, we -- as we see some of these increases in coal and related transportation costs, certainly our position is that it's important to match current costs with -- to address future rates. And so that -- clearly from our perspective, we want to look not only at the increase in '06 costs but also the increase that we're going to see in '07.

And could you just tell us, as of March 31 what is the equity ratio at UE?

I certainly can if you give me one moment. I believe it is right around 55% -- at least 55% or north of that.

Okay. Thank you very much.

You're welcome.

Gentlemen, at this time there are no further questions. Please continue with your presentation.

Great. Thank you all for participating in this call. Let me remind you again that this call is available through May 11th on playback and for one year on our website. The announcements carries instructions on listening to the playback. You can also call the contacts listed on our news release. 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.

Ladies and gentlemen, this does conclude the Ameren Corporation 2006 first quarter earnings conference call. You may now disconnect, and thank you for using AT&T Teleconferencing.