阿莫林 (AEE) 2005 Q4 法說會逐字稿

Good morning, ladies and gentlemen and welcome to the Ameren Corporation 2005 earnings conference call. [OPERATOR INSTRUCTIONS] I would now like to turn the conference over to Theresa [Needsburg] Supervisor of Investor Relations. Please go ahead.

Thank you, Eric, and good morning. I am Theresa [Needsaburg] Supervisor of Investor Relations at Ameren Corporation. Here with me today is our Chairman, Chief Executive Officer and President, Garry Rainwater, our Executive Vice President and CFO, Warner Baxter, our Vice President and our Controller, Marty Lyons, our Vice President and Treasurer, Jerre Birdsong. Our manager of Investor Relations, Bruce Spanky and other members of Ameren Senior management team. 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 playback number. The announcement you receive in our news release include instructions by receiving 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 web site at www.ameren.com.

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

For additional information concerning these factors, we ask you to read the forward-looking statement section in the news release we issued today and the forward-looking statements in Inspector 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 the fourth quarter and full year 2004 to our earnings per share for the fourth quarter and full year 2005 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. To access this presentation, you may look in the investor section of our web site under presentation, or follow the links for the webcast. Our focus this morning will be to update you on some key operating and regulatory matters since our January conference call and to discuss 2005 operating results. We do not plan on having an extensive discussion again of 2006 earnings guidance or other matters discussed during our January conference call.

Garry will begin this call with an overview of our 2005 results and some key operating and regulatory matters. Warner will then follow with a further update on regulatory matters and a more detailed review of 2005 results. We will then open it up for questions. Here's Garry

Thanks, Theresa. Good morning, and thank you for joining us.

This morning, we reported earnings of $3.02 per share for 2005, which compared to earnings of $2.84 per share last year. Excluding an $0.11 per share fourth quarter 2005 charge for the adoption of new accounting principle related to asset retirement obligations, Ameren's earnings for 2005 were $3.13 per share. Improved operating earnings in 2005, resulted from the successful integrations of Illinois Power Company and greater availability of our low cost coal-fired power plants. This availability allowed us to enhance operating margins, as we supplied increased native load demand, resulting from warmer summer weather and also took advantage of higher power prices on short-term energy sales.

In addition, our operating earnings benefited from organic growth in our service territory and from the sale of certain assets from our leveraged lease portfolio. These benefits more than offset increased fuel and purchased power expenses, including higher costs of operating in the Midwest independent transmission system operator, or MISO Day Two, energy market. Warner will go through the drivers of our 2005 earnings in more detail in a moment, so I'll turn to a discussion of some key operating matters. A highlight of 2005 was the successful completion of the refueling and maintenance outage at our Callaway nuclear plant. It was the most extensive in Callaway's history and it was also one of the most efficient and effective outages in the plant's history.

During the outage, we refuelled the plant and replaced the steam generators and turbine rotors in 63 1/2 days. The outage was originally scheduled to last 70 to 75 days. The replacement of the steam generators and turbine rotors is expected to improve reliability and has increased plant capacity by approximately 60 megawatts, positioning the plant performed very well in the future. Our coal-fired power plants also had an outstanding year. The availability of our coal-fired fleet was 87% in 2005, and our capacity factor averaged 76%, slightly higher than the record levels achieved in 2004. We believe we can achieve availability factors of about 90% and capacity factors above 80% over the next several years, and we are putting plans in place to meet that goal.

The major challenge in 2005 came from the disruptions in deliveries of coal by rail from the Powder River Basin, which provides over 85% of the coal-fired plants. The deliveries in 2005 were 5 to 10% below expected levels, due to rail maintenance, which resulted in lower than normal inventory levels. The impact of the coal delivery issues on our inventory levels was exacerbated by the warm summer weather and high power prices, which caused our plants to run more and burn more coal.

In order to maintain acceptable coal inventory levels, we purchased some higher cost Illinois coal and reduced inter-change sales, both of which had a negative impact on 2005 earnings. We expect additional rail maintenance to occur in 2006, but it's expected to have less of an impact on deliveries. As we discussed during our January conference call, there was a breach of the upper reservoir at our Taum Sauk facility in December that resulted in significant flooding in the local area, which damaged a state park and required three children to be hospitalized and later released.

We hired outside experts to review the cause of the incident and it's also being investigated by State and Federal Regulators. We expect their reports later this year. At this point, it's too early to discuss when or if the plant will return to service. Any decision on the future of the plant will wait until after these reviews are concluded. Further analyses are completed and input is received from key stake holders. The Taum Sauk incident is covered by insurance. Exactly what and how much damage and related liabilities will be covered is subject to review by our insurance carriers. On the environmental front, as we also discussed in our January 2006 call, we've been working on updating our capital expenditure estimates for compliance with SO2, NOX and Mercury Regulations.

At this time, we expect our capital expenditures to comply with the Federal Clean Air Interstate Rule and clean air mercury rule to range from 2.1 billion to $2.9 billion, through 2016. Our expected environmental compliance expenditures have increased from our original estimated range of 1.4 to $1.9 billion, primarily because of the in conclusion of EEI's expenditures in our estimate, as well as revised plans for our methods of compliance and rising costs. Keep in mind that our estimated capital costs ranging from 2.1 to $2.9 billion are to comply with the Federal Clean Air rules. However, the Missouri and Illinois implementation plans, which have not been issued yet, could be more stringent. Should more stringent rules be adopted by the states, it could change our overall environmental compliance strategy, and increase related costs from our current estimate.

Of course, it's important to point out that based on the Federal Clean Air Act rules, approximately 55 to 60% of our expected capital expenditures are for our rate regulated operations. Now, moving on to regulatory matters, in January, we updated you on the key regulatory matters we have under way in Missouri and Illinois. Since then, we've received a favorable ruling from the Illinois Commerce Commission in our Illinois Power Procurement case. In the summer of 2004, we began working with stake holders in Illinois to determine the appropriate means to procure electricity for our customers, beginning in 2007, when all power supply contracts for Illinois utilities expire.

In February 2005, we proposed a power procurement auction through a filing with the Illinois Commerce Commission that we believe is a proven-- is proven and will result in the lowest possible costs to our customers. In January of this year, the Illinois Commerce Commission voted unanimously to approve our proposal. Obviously, we're very pleased by the IPC's ruling in this matter. However, we expect the Illinois attorney general and the citizens utilities board to appeal the ICC's order. While there are certain aspects of the ICC's order that we don't fully agree with, we believe the framework developed is workable and we look forward to working with all stake holders in preparing for the September 2006 auction. As we have said in the past, we do believe that our Illinois customers could experience meaningful rate increases over current bundled electric rates beginning in 2007.

As a result, we're willing to work with key stake holders to structure a rate increase phase-in plan to lessen the impact on our residential customers. Any plan must incorporate full and timely cost recovery of our costs and maintain our Illinois utilities' existing credit ratings. We are convinced that this plan will result in a constructive solution for our customers, investors, employees, and the State of Illinois, and we are actively pursuing it. With that, I'll turn this discussion over to Warner.

Thanks, Garry. Before I begin my discussion of 2005 earnings, I would like to continue the discussion of a few additional regulatory matters. In late December, we filed electric delivery services rate increase for Quest with the ICC for our Illinois distribution utilities. In our rate filings, we requested a total annual electric revenue increase of approximately $200 million. Our filings also included a two-year phase-in plan of this increase for residential customers of AmerenCILCO and AmerenIP. We expect a regulatory calendar to be set for these cases in late February and expect a decision from the Illinois Commerce Commission in November 2006.

Moving on to Missouri, there's really nothing materially new to report, since our January conference call, regarding the rule-making process by the Missouri Public Service Commission for the fuel and purchased power, and environmental cost recovery mechanisms that were signed into law last summer. We still believe the rules will be effective in the second half of this year. With regard to the expiration of the electric rate case in Missouri on June 30, 2006, the company has still not made a final determination as to when we will file for a rate case in Missouri. We did submit a confidential electric cost of service study to the Missouri Public Service Commission staff and others in late December that was required by a 2002 rate case settlement.

However, this submission was not a rate case filing. The appropriate test year, economic and energy market conditions, expected planned additions in the rule-making process surrounding fuel, purchased power and environmental cost recovery mechanisms, among other things, will drive our decision on when to file a rate case. Of course, the Missouri Public Service Commission staff and others will review the cost of service studies submitted in December.

Based upon their analysis, make may their own rate recommendations. As we discussed in our January conference call, we recently filed for approval of an amendment to the joint dispatch agreement, or JDA, among AmerenUE, AmerenCIPS and AmerenNG Generating Company of GenCo with the Federal Energy Regulatory Commission. This amendment proposes to change 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. The Office of Public Counsel, OPC, has filed a protest in the case, at FERC. In their protest, the OPC does not challenge the proposed amendment I discussed a moment ago.

However, the OPC has searched that the JDA should be further amended to value all transfers between GenCo and AmerenUE at market prices rather than incremental costs. We are still carefully reviewing the OPC's pleading, but we intend to vigorously oppose the OPC's protest, citing among other things, that their pleading are inconsistent with the Missouri Public Service Commission's order, in this case. Of course, we can't predict the outcome of this matter. Should FERC or the Missouri Commission in some future rate making proceeding require that energy transfers be priced at market it, could significantly reduce the revenue required to be collected through rates the next time electric rates are just in Missouri, as well as modify the amount of payments between AmerenUE and GenCo for the system energy transfers. Of course should this amendment be ordered, an evaluation of the continued benefits of the JDA would have to be made by the parties. GenCo, CIPS and Ameren UE have rights to terminate this agreement with one year notice, unless terminated earlier by mutual consent.

During 2005, GenCo received 9 million-megawatt areas of net- energy transfer from AmerenUE in incremental costs, which were a historical high. While we can't predict what level of energy transfers will occur between the two companies in the future, we do believe that under normal operating conditions, the level of energy transfers from AmerenUE to GenCo will decline from 2005 levels to less access generation being available at UE. This is expected to result from greater native load demand at AmerenUE due to the addition of [Neranda] aluminum in June of 2005 and continued organic growth, as well as the expiration of a low cost electric energy, Inc., purchased power contract at AmerenUE, among other things.

As a result, the ultimate impact of OPC's proposed amendment, or the amendment proposed by the company in the existing FERC proceeding will be determined by whether the JD A continues to exist, future native load demand, the availability of electric generation at AmerenUE and GenCo and market prices, among other things. Ameren's earnings will be unaffected by these proposed amendments until electric rates for AmerenUE are adjusted by Missouri Public Service Commission, reflecting the impact of these or other changes to the JDA in the future. I would like to now refer to you our web site as I provide a more detailed discussion of 2005 earnings. As Theresa mentioned earlier we have posted a slide presentation on our website that reconciles our earnings per share for the fourth quarter and full year 2004, to our earnings per share for the fourth quarter and full year 2005 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. In this presentation, and in our comments this morning, we have isolated the impact of the Illinois Power Company acquisition in order to allow for an easier year-over-year analysis of our preacquisition operations. For the full year 2005, we reported net income before the cumulative effect of a change in accounting principle of $628 million, or $ 3.13 per share compared to net income for 2004 of $530 million, or $2.84 per share. In the fourth quarter of 2005, we reported net income before the cumulative effect of a change in accounting principle of $42 million, or $ 0.21 per share, compared to net income in the fourth quarter of 2004 of $83 million, or $0.42 per share. These fourth quarter and full year 2005 numbers exclude a $22 million or $0.11 per share after-tax charge for the adoption of FIN 47, accounting for additional asset retirement obligations.

The adoption of FIN 47 required liabilities to be recorded for retirement costs associated with asbestos removal, ash pond closures and the removal of various river structures, among other things. In our nonrate-regulated operations this, resulted in a charge to income. Native load margins increased $0.05 per share in 2005 as compared to 2006. Benefits from the addition of [Neranda] aluminum in June 2005 and organic growth were partially offset by higher fuel and purchased power expenses.

Fuel purchased power expenses rose in 2005, due primarily to higher coal and related transportation costs, coal conservation, unscheduled outages at some of our coal-fired power plants this past summer and greater utilization of some of our gas-fired peaking plants. Native load margins decreased in the fourth quarter of 2005 compared to the prior year, due largely to higher fuel costs resulting from coal conservation measures. Cooling degree days in 2005 were approximately 37%, above a mild 2004 according to the National Weather Service.

Excluding the effect of the Illinois Power Company acquisition, weather sensitive residential megawatt hour electric sales increased 10%, and commercial megawatt hour electric sales increased 3% in 2005, compared to 2004. It is estimated that weather benefited 2005 earnings by $0.26 per share as compared to 2004 and about $0.06 to $0.09 per share versus normal. Contribution from interchange power sales margins increased $0.11 per share in 2005, as compared to the prior year, largely due to higher power prices and access to the MISO Day Two energy market. In 2005, interchange revenues averaged $44.00 per megawatt hour versus $30.00 per megawatt hour, in 2004. These factors more than offset the 19% decrease in year-over-year interchange sales in 2005.

Interchange sales were reduced in 2005 to primarily less excess power being available for sale, as a result of the addition of [Neranda] aluminum as a customer, increased residential and native load demand due to warmer weather in organic growth and coal conservation efforts required as a result of disruptions in coal deliveries. Interchange sales in the fourth quarter were additionally impacted by our Callaway Nuclear Plant outage.

During 2005, we incurred higher incremental costs of operating in the Day Two energy market of MISO, which started on April 1. We estimated that MISO Day Two two reduced our 2005 earnings by $0.29 per share and $0.12 per share in the fourth quarter. We believe it is significant charges incurred in 2005 were largely due to volatile summer weather patterns and related loads and the relative infancy for the MISO Day Two energy market. We're fine tuning our operations and working closely with MISO to ensure that the MISO Day Two energy market operates more efficiently and effectively in the future. Gains from emission credit transactions added $0.02 per share to 2005 earnings over 2004, including $0.05 per share in the fourth quarter.

As Gary mentioned earlier, we had a highly successful refueling and maintenance outage at our Callaway nuclear plant in the fourth quarter of 2005. In to 2004, the Callaway outage was conducted in the second quarter. As a result, fourth quarter 2005 earnings were negatively impacted when compared to last year. While both outages lasted about the same amount of time, 2005 was a more capital intensive outage and therefore benefited 2005 earnings by $0.03 per share when compared to 2004. AmerenIP contributed incremental net income of $68 million to Ameren's earnings in 2005. The recovery of the dilution from common shares issued by Ameren in advance of the September 2004 completion of the Illinois Power acquisition added $0.18 per share.

In addition, accretion from this acquisition added $0.05 per share to earnings in 2005. Combined with the accretion of $0.07 per share from this acquisition in 2004, the IP acquisition has added $0.12 per share to earnings through 2005. Net dilution and financing costs excluding Illinois power-related financing reduced earnings by $0.07 per share in 2005 over 2004. Dilution resulting from the conversion of 7.4 million shares of our adjustable conversion equity security units in May, coupled with the issuance of shares under our dividend reinvestment and employee benefit plans was offset by lower financing costs.

Depreciation and amortization expenses were higher due to capital additions and reduced earnings by $0.06 per share in 2005, as compared to the year-ago period. As we have noted in our third quarter conference call, we have been evaluating the potential divestiture of some or all of our legacy leveraged lease investments. In the fourth quarter of 2005, we sold some of these leveraged leases, which generate a gain of $0.11 per share. This gain offset a third quarter 2005 charge of $0.04 per share related to the write-off of a leverage lease investment associated with Delta Airlines.

In 2004, upon reentering MISO, Ameren received a refund of fees paid when we originally exited MISO, that benefited second quarter 2004 earnings by $0.06 per share. This benefit did not repeat in 2005, causing a negative year-over-year variance of $0.06 per share. This morning, we also reaffirmed that we expect our 2006 earnings to range between $2.95 and $3.25 per share, consistent with the guidance we gave in January. Our guidance assumes normal weather for all of 2006 and is subject to, among other things, power 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. We have modified certain line items on our 2006 earnings guidance reconciliation slide to reflect actual results for 2005, but the changes are not that significant when compared to our original guidance.

Consequently, I do not plan on going through our guidance again in detail. The webcast of our January guidance presentation is still accessible on our web site. I'm sure that most of you also have access to transcript services. This completes our prepared comments. We will now be happy to take your questions.

Thank you, sir. [OPERATOR INSTRUCTIONS] Sharge with SAC Capital. Please go a head with your question.

Good morning.

Good morning.

Warner, could you just go to these, if I could just go-- trying to compare the guidance as to what was provided a year ago, there were a couple of things. One was that you were expecting much higher margin from sales growth, or I guess it's being translated as native load margin and it came up a little bit shy from those numbers, and then I guess the MISO Day Two costs, had you not envisioned a year ago and they came up to be a negative. I guess they reversed themselves in '06. But could you just generally talk about why the, why the native load margin didn't grow too much in 05 versus what was projected, and also on the MISO Day Two costs, why they came out to be such a big negative factor for the year.

Sure. Two things, really, Shra. With regard to the native load margins, I think one of the biggest drivers there relates to some of our coal conservation efforts that we had to employ throughout the year. As a result of those coal conservation efforts, they drove our fuel and purchased power costs up higher than levels than we would have originally expected. So that's probably one of the biggest drivers there, as well as just generally a bit higher coal-related transportation costs than what we had expected going into the year. Otherwise, our organic growth, and certainly the sales associated with-- were consistent with our expectations going in.

Okay.

When you look at the Miso Day Two Day Two, as we've said throughout the year, we did experience higher than expected costs to the MISO Day Two as a result of MISO Day Two energy market. And those costs, we believe, are higher than expected due, frankly, to the relative emphasis of the MISO Day Two energy market, as well as some of the volatile weather patterns that we saw in the summer. Those things, coupled with, frankly just the market participants, still giving use to the overall energy market resulted in the higher than expected costs. As we pointed out in our conference call in January, we do expect meaningful progress in terms of reducing those costs in 2006 compared to 2005.

But, Warner, the negative is nearly $0.29, right, from the presentation year-to-date, right?

That is correct.

So your reverse $0.08, if I'm right, the high end for '06, if I'm right.

That's correct.

Could we expect the remaining $0.21 to get reversed in years after 2006, or are those just costs which are permanent into the system, which have to be absorbed as part of this process?

Sure. Certainly from our perspective certainly in working closely with MISO, we have the hope and the desire to continue to reduce those costs prospectively. The costs that you're talking about basically, that you look into the ongoing costs relates to congestion, relates to revenue sufficiency guarantees, as well as some administration costs. And we have teams in place working with MISO to try to continue to reduce those costs, not just to 2006 levels, but beyond those. Of course when you look at the MISO Day Two costs, as you know, we are currently in a rate freeze in our, both Missouri and Illinois jurisdictions. We would hope prospectively to recover these costs in the regulatory framework, but of course we can't predict what level of costs we will recover sometime in the future, should future rate proceedings address these matters.

Okay, and then, if I can just go to the Illinois situation currently, if I'm right, isn't like the 16th or the 17th the last date when any kind of bills can be introduced in committees, or things like that as the schedule, or can you just tell us, I guess the session goes on till April 7th. If-- what is happening in any of the subcommittees regarding any more hearings or anything like that and when is the last date that, if anybody decides to propose any bill that, it can be entertained in any subcommittee in the house?

With regard to your question as to the last date someone can introduce a bill to the house, I do not have that information in front of me, so I won't be able to respond to that. So, Shra, we'll try to get that answered and get that to you off line. In terms of what's going on on in the legislature, I do understand that there is another house energy committee meeting this Wednesday. To the extent that weather it is not clear to me whether there's anything substantive with regard to legislation that well be proposed at that time, but of course when subcommittees meet, there's always that possibility. Beyond that, at least as of this morning, there have not been any other specific bills proposed in the legislature addressing what I presume you are asking about is the post 2006 auction process or things similar to that.

Okay. I appreciate it. Thank you very much.

You're welcome.

Our next question comes from Danielle [inaudible] [rose. ] Please go ahead.

Thank you. Actually I was wondering, in Missouri, is there any approximate timing when we will know what the commission would like to do? Is there anything you can help us with the schedule?

Danielle, are you referring-- this is Warner. Are you referring to the SB 179 rule making proceedings?

Yes.

Okay. With regard to the SB 179 rule making proceedings, the commission has basically three types of rules they are considering. One relates to gas conservation and weather usage. One relates to fuel and purchase power and one relates to environmental cost recovery mechanisms. The gas conservation and weather utilization rule is moving forward now with the commission, and the other two, fuel and environmental, are lagging behind that. There is no set timetable that is out there. This is not like a typical Missouri Public Service Commission hearing or rate case type of process. They basically have no particular timetable they have to abide by, but we do believe that based upon our discussions with staff and others, that it is the commission's intent to try and have the rule-making process completed and the rules effective sometime in the second half of this year. And that's about the best we can provide you at this point.

Okay, great. And as far as the environmental costs, you announce your total budget. Is there any-- I mean is it skewed toward majority of those expenditures being done before 2010, or they are really spread out evenly?

Yes, I believe we, we do have some of those-- expenditures are certainly spread out.

Okay.

To give you a kind of some insight, basically of that 2.1 to $2.9 billion expenditures through 2016, we expect that between 2007 and 2010, that approximately 1 billion to $1.4 billion of those expenditures will be incurred. Then the remainder being incurred between 2011 and 2016. And of course that's split between the regulated and unregulated businesses as well.

Right. Thank you very much.

You're welcome.

Our next question comes from Terran Miller with UBs. Please go ahead.

Good morning. I was just looking at the last page of your presentation with reference to the gas flow guidance from 2006 and trying to get a sense at which operating subs do you expect to have financing requirements?

Okay. I'll-- Jerre Birdsong our treasurer is here. I'll let him address those.

Yes. We expect to have financing requirements at all of the subsidiaries that are operating electric C&D utilities. That would include the three Illinois utilities and the union electric.

And do you have approximate sizes of those requirements?

It would be geared more towards the union electric side as it has been in the past.

In terms of the size, it would be premature to state that at this point in time, but-- because we're still evaluating that, but we will be active in the marketplace for typical capital expenditure requirements for normal capital additions in our regulated business.

Okay, thank you.

You're welcome.

Our next question comes from Greg Gordon with Citigroup.

Hi. Thank you. My questions have been asked and answered. Thank you.

Great.

Paul Ridzon with KeyBanc, please go ahead.

You indicated you had insurance Taum Sauk is there any business interruption insurance there?

In terms of-- Paul, this is Warner. In terms of business interruption, are you talking about replacement power costs, those types of things?

Exactly.

Yes, we do have some coverage for replacement power costs included in the coverage. Of course we have some deductibles that we have to meet associated with that. It's approximately $15 million deductibles on the plant side. And then there are certain caps that we have with regard to replacement power as well. But we do have some coverage for replacement power costs.

And your January guidance on the impact of Taum Sauk contemplated that coverage?

It certainly did.

And then I'm sorry, I actually got displaced out of my office for IT work. I don't have everything in front of me.

That's okay.

Were we previously working for Callaway to be an incremental negative in '05?

You know, going into the year, for '05, we plan to put a fairly broad range around that. I believe we had about a nickel positive, as well as negative. It really depended upon how well the outage ultimately went. So all things being equal, we expected the Callaway outage to approximate 70 to 75 days, whereas I believe last year, it was around a 64-day outage. So generally speaking, you would have thought maybe a slight negative variance with regard to Callaway, but because of the outage doing certainly better than we had expected, as Garry pointed out, it was one of the most efficient and effective outages that we've had, coupled with the capital intensive nature of the outage, because of the replacement steam generators and the like, it had a favorable year-over-year variance of about $0.03 per share.

Did the ultimate cost in allocation of Capital and O&M, what drove moving to the positive side, just the lower overall cost or allocation of costs?

I think it's probably a little bit of both. It was probably the allocation in some respects, because as capital, more capital than O&M in the prior year and certainly when you look at the original estimate that we had, we had estimated a 70 to 75-day outage and it turned in to be closer to 63 to 64 days. So those two factors together. Probably really more so on the less days in terms of, in terms of the original guidance, is the fact that it was six or seven days, if not longer compared to our original estimates.

And that's all O&M, I imagine?

Principally, principally, although some of it's capital. Principally that would have been O&M and replacement power.

And then what were the EA's in the first quarter and versus last year?

I'm sorry, Paul, what was that question? What were the emission credit sales, what was the impact in the fourth quarter and how did that compare to last year? Sure. In the fourth quarter of this year, we had emission sales of approximately $19 million, principally from our non-regulated operations, and then compared to last year, we had approximately $5 million of sales.

So that's the $0.05 you talked about, is the year-over-year?

Yes.

Thank you very much.

You're welcome.

Our next question comes from David Grumhaus with Copia Capital. Please go ahead.

Good morning.

Good morning, David. How are you?

Good.

Good.

Warner, on the MISO cost, how much of those are recoverable through rate cases once you eventually, assuming you eventually go into Missouri?

Well, in theory, David, as you know, we should be able to recover all costs incurred for our regulated businesses, but I can't predict in the context of a rate case whether all those costs would be recoverable. Of course, that's something because of MISO Day Two costs being new to the Missouri and Illinois jurisdictions, that obviously raises some level of uncertainty, but clearly we believe it's appropriate to recover all of our costs incurred for the MISO Day Two energy markets.

And those are all regulated costs as opposed to some of the, being a part of unregulated [inaudible]

I think it's fair to say that there could be some that would go to the unregulated Gen, but the vast majority would still be in the unregulated operations.

Okay. That's helpful. Second question, in terms of Illinois, obviously there's a lot of speculation about whether Mattagan's going to introduce something in the house. Is your all's strategy right now just to sort of wait and see if the other shoe drops, or are you more trying to go in there and craft some sort of settlement to get everyone on board and put everything behind you so you can just move forward with the auction?

Well, David, as we've said in the past, and as Garry pointed out a little bit earlier, we are actively working to try and develop a constructive rate increase phase-in plan, because we think that's the most constructive solution for all stake holders. And so we're not sitting on our hands and hoping everything just sort of comes out okay. We're actively trying to construct something that makes sense for all stake holders, and from our perspective, as we said in the past, that includes full and timely recovery of all of our costs, plus a plan that maintains our existing credit rating. So again, also as we said in the past, we have not gone into details in terms of the specifics of a plan, nor how we are going about trying to get some plan developed across the Finish Line because we don't think that's particularly constructive at this point. And so but rest assured we continue to actively pursue a constructive plan.

And that constructive plan, is it with legislators? Is it with Mattagan? Is it with the governor's office? Is it with all parties involved? How do you sort of focus that?

Let me just say this. Again, as we've done in the past, we're not going by and saying, look, this is who we talked to and this is when we talked. Again, we don't think that's constructive. But we do believe, ultimately should a phase-in plan be adopted that, there would have to be legislation. That's consistent with what we said in the past, that legislation would have to be required for a phase-in plan.

Okay, great. Thanks for the time.

Sure.

Our next question comes from Scott [Agstrom] with Fine line Asset management. Please go ahead.

Good morning, Scott. I wonder if you had at your fingertips there-- for the quarter or the year.

I do have that, if you can be patient, I will find it for you. For the-- I do not have it by quarter, but I do have it by year.

That's fine.

Let me give that to you. Our net income over the year for union electric is $346 million. For CIPS, $41 million. For GenCo, $97 million. For CILCO, $3 million, for IP, $95 million, and then for other unregulated operations, $24 million to come to a total net income of $606 million.

Great. Thanks very much.

You're welcome.

Our next question comes from Michael [Apates] with Goldman Sachs. Please go ahead.

Hey, guys, quick question, can you walk me through what a possible time line for a potential-- I know it's not formally been filed, but what a potential Missouri rate case would be like, and whether you think you've got any earnings at risk in Missouri.

Well, with regard to the Missouri rate case, as we've said, there are a host of factors that we're carefully considering. In terms of when we would file, say if it is in sort of totally our control to file a rate case, things that we are considering are the appropriate cost of service, study to file, meaning the appropriate costs to include in rates in our original filing. We also have to look at how things continue to proceed with regard to the SP 179 proceedings, among other things, including issues surrounding the JDA and others. And I think we also laid out during our January conference call, a host of considerations that we would have to factor in as part of a Missouri rate case. Generally speaking should we file a rate case, it would take normally 11 months to adjudicate that. And so if a rate case would be filed sometime here, there's an example in June or July or sometime this year, you just add 11 months and that's when the typical hearing process would take place. As we pointed out, we've submitted our cost of service study to the staff and others. They will look at that study and they may decide to take rate actions on their own and potentially file a complaint case. Should that be the case, there is no specific time line set as to when a complaint case would have to be adjudicate, but typically those have historically been done generally in about that same period of time, if not maybe a little bit longer. So that gives you sort of a time line.

Whether earnings are at risk, another host of factors that you have to look at and we're not really predisposed to give you any more than that, other than you have to look at rate-base additions, as we discussed in the past. You have to look at trends of costs, including rising coal and related transportation costs, which we talked about during our last conference call. You have to look at other issues surrounding interchange margins and how they may be reflected in future rates, the joint dispatch agreement, and a host of other things, including how you think about weather and the Callaway refueling outages. Again, these are all items that we put on our last-- or we discussed during our January conference call. So as we put all those things together and we make some decisions, at that point in time we'll be able to give you some more information as to what a Missouri rate case may look like.

Are you-- I mean the last public data I saw on a rate base amount for Missouri, for Union electric, was right around 5.1, $5.2 billion. I think that was done prior to the acquisitions of the various gas plants that were announced in the fourth quarter and early '06. What's kind of an updated rate base estimate for union electric?

Sure. On the electric side of AmerenUE, that number is just a hair shy at 12-31-05, a hair shy of $5.5 billion and that does not include the $290 million of additional peaker purchases, which are subject to regulatory approval.

Okay.

Okay.

I appreciate it. Thank you.

You're welcome. Sure.

Our next question comes from David Frank wit Sidoti capital management. Please go ahead.

Yes, hi, good morning.

Good morning, David.

Wonder, could you just talk a little bit about your capacity requirements and reserve margins for '06, given all this new generation you've moved into Union electric, for Union electric?

Well, with regard to our capacity requirements going into 2006, David, we were short capacity, which is why we actually had to go out and purchase additional peaking units. When we were short principle because of the addition of aluminum. Typically, we operate our reserve margin right around 15% and so that, that would-- that's generally a benchmark we look at, but then that's-- those are sort of the some of the minimum requirements. Maybe a normal reserve margin may be closer to around 17% or so, and so if we procure these additional units, we would have reserve margins in excess of that for a short period of time and then we would continue to grow into that. Of course factoring into our reserve margins in 2006 also would be the fact that we do not have Taum Sauk available to us throughout 2006, which we discussed earlier today as well as during our January call. So that, that-- depending upon whether Taum Sauk comes back into operation in the future, of course remains to be seen, as Gary discussed a little bit earlier, after several-- after further analysis and the reports are done, we will make that determination later. So that, too, will also factor into what our reserve margin requirements are at UE in the future.

I guess assuming Taum Sauk is out for 2006 and you officially transfer all of these peakers and other assets into UE that you have planned, do you have an estimate of what the reserve margin would be for 2006 approximately?

Just to be clear, David, number one, we're not transferring any more units in to UE. We've already completed that 550-megawatt transfer, if that's what you may have been referring to. The only other addition would be the additional peakers that we would hopefully complete the purchase of, subject to regulatory approval sometime later this year. Absent that, I think that I don't have in front of me what those reserve margin requirements would be after you put all those things together, so I'm sorry. I just don't know that at this point in time when you factor in Taum Sauk and some of those other things. My sense is that it would be somewhere in the, 20% range-ish, but, again, I don't have that specific number in front of me.

Okay. The other question, just on Illinois, I know a couple people have talked about, or asked you about legislative intent and potentially timing. How important do you think the look back prudencey review clause that the commission put in is, how important is that to the legislature? Illinois?

David, it's impossible to say just exactly how important it is to the legislature. We do know that the attorney general and the citizens utility board felt it was important to have some level of prudence review. They raised that in the case in the Illinois Commerce Commission reviewed that and deemed it appropriate. Whether the legislature would deem that adequate enough, it's really impossible to say.

Well, given-- if it was-- if it is very important to the HE and potentially important to the legislature, is that an area where you think you would be willing to compromise?

Well, I think with regard to-- look, the bottom line, is David, we an order from the Illinois Commerce Commission and so if that order ultimately is sustainable, there's no debate. It's just that's what will be the law of the land and we will certainly follow it. We have appealed that aspect of the order because we think it may have the ability of raising prices ultimately to customers because of prudencey risk for suppliers, but at the end of the day, we don't see this prudence determination by the ICC to be all that difficult to work with. We think it's a workable solution, and so by and large, if that be the case, then, we will abide by that order and work within that framework going forward, should that ultimately not be resolved after the appeals process is completed.

Okay, great. Thanks a lot. Warner.

You're welcome.

Our next question comes from Paul Patterson with Glenrock Associates. Please go ahead.

Good morning, guys.

Good morning.

Just I guess a follow-up sort of the legislative question. Is there any idea about what-- any-- maybe there isn't any sense as to the timing as to when any rate phase-in legislation could-- would be more or less likely to show up? I mean could this happen in the veto session-- is there any rough idea you have in terms of when we might see something come together with respect to this?

Well, with regard to the legislation, I mean basically there are generally two opportunities for them to take care of it. That would be during the spring session, which we're in the middle of now, as well as then the fall veto session. It is currently scheduled for this current legislative session to be completed in April. In the past, we have seen those sessions go into May, but at this point in time, it's my understanding that they are going try and complete that session in April. If something's going to happen this legislative session, it's going have to happen here in the next few months. It is certainly possible that legislation could carry over into the fall veto session and that veto session would take place sometime after the November elections and generally that session is a two-week session. And so that, too, has been raised as a possibility, should legislation be adopted as a time period as to when that could happen. So how, how you weigh, whether it happens this session or the next session, that, too, is just impossible to say at this point in time.

Okay. And then there's been this bill introduced called HB 4977, which sort of creates a director of retail market development, and I don't know. I mean to promote sort of retail competition, it seems to be-- I don't know. That's at least what I seem to read into it. Is there anything more, do you see anything significant about this, or do you have any comments on it, or--

Well, you know, in terms of whether there's anything significant to it, in terms of the bill, that bill itself, we're generally neutral. I think the ICC has said that they want to find a way to continue to promote retail competition and so I'm thinking it may be-- and certainly the legislature has stated that and so it's not inconsistent with past statements, whether this bill is expanded into something beyond what is originally stated, that certainly is a possibility, but it's impossible for me to predict at this point whether that would be the case.

Okay. Thanks a lot, guys.

You're welcome.

[OPERATOR INSTRUCTIONS] The next question is a follow-up from Danielle [Sipes]

Just one more. Have you heard anything about an improvement in the coal transportation from the western coal area? Has there been any comments made as to when they will go, come back to normal?

Danielle, the railroads have told us that they expect deliveries to be essentially normal this year and what we've seen so far in January is that deliveries are normal. So we expect to receive the amount of coal that we scheduled.

Oh, so you do not anticipate any more disturbances for transportation?

There is additional maintenance planned, but we think deliveries should still be close to normal.

Oh, okay. Okay. Because other companies are mentioning that depending on which area the coal was being delivered, I guess in your case, you are in the clear.

Well, yes, I think that, you know, again, we-- as Gary stated, we do believe that there will be some additional maintenance. Based upon our discussions with the coal companies, we do expect to see improvement from last year, where we see 90 to 95% of our deliveries and we expect to see all of them this year. Of course that could change. How we compare to other companies, frankly I'm not sure just exactly--

No, that is the reason for my question. I'm sorry. The other question I had is did you have any-- maybe you already said that, the-- recommendation on the distribution case, do you have any feel for the timing of that?

Yes, at this point, Danielle, a calendar for our distribution case is supposed to be set at the end of February. So you should see something hopefully within the next couple weeks that will lay all of that out.

Okay.

We're expecting an ICC decision in November. So it will still be several months down the road, I would think, before we would see the recommendations from the staff in our particular case.

Great. Thanks a lot.

You're welcome.

Our next question is a follow-up from Scott [Agstrom] Please go ahead.

Just a question on the FAS 47 charge. Was that all at GenCo, or is that right around?

Yes, all of the charge related to the non-regulated operation, that would include not only GenCo, but also EEI, our 80%-owned subsidiary. The liabilities recorded were actually greater than that, but to the extent that they were in the rate regulated operations, they were offset by regulatory asset.

Okay. So it's not correct to say that all of it was at GenCo, is that correct?

That is correct.

Okay. All right. I'll just wait for the "K" then, thanks.

Okay.

[inaudible] Deutsche asset management, please go ahead with your question.

Thank you. Just to clarify this look back prudencey clause-- who is at risk? Is it the supplier of power, or is it the Ameren utilities for the prudence test?

Ultimately the Ameren utilities are the ones that are at risk on the prudencey test.

But the under the rules have been set out, as well as the auction will be done through the premise of ICC. So are they also at risk?

Well, you know, I think-- I don't know if the ICC is quote, unquote at risk. The bottom line is the ICC is going to be actively participating in that. We will have an independent auction monitor and our belief, then, is if we followed the rules of the auction process as they have been laid out, then we believe that the results of that auction process will give us a great deal of factual evidence in terms of the prudencey of our actions, and so and I think that's not terribly inconsistent with what the prudent standard that we would have to meet going forward, but it would ultimately be the prudence that look over the shoulder would be of the Ameren Illinois utilities and they would quote, unquote, be at risk should the ICC disallow certain of those costs resulting from the auction process.

Okay. Thanks for the clarification.

Sure.

Gentlemen, at this time, I'm showing no further questions. Please continue with your presentation.

Great. Thank you, everybody, for participating in this call. Let me remind you, again that, this call is available through February 21 on playback and for one year on our website. The announcement carries instructions on listening to the playback. You can also call the contacts list order our news release. For those on the call who are financial analysts, please call Bryce Steinke. Media should call Tim Fox. Members for both are on the news release. Again, thanks for dialing in.

Ladies and gentlemen, this does conclude the Ameren Corporation 2005 earnings conference call. You may now disconnect, and thank you for using AT&T teleconferencing.