阿莫林 (AEE) 2006 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Ameren Corporation 2006 earnings and 2007 earnings guidance conference call. During today's presentation all parties will be in a listen-only mode. Follow the presentation, the conference will be open for questions. [OPERATOR INSTRUCTIONS] As a reminder, this conference is being recorded today, Thursday, the 15th of February, 2007. I would now like to turn the conference over to Mr. Bruce Steinke, Manager of Investor Relations. Please go ahead, sir.

Thank you, Michael. And good morning, everyone. I am Bruce Steinke, Manager of Investor Relations at Ameren Corporation. On the call with me today is our Chairman, President, and Chief Executive Officer, Gary Rainwater; our Chief Financial Officer, Warner Baxter; our Vice President and Controller, Marty Lyons; and other members of the Ameren 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 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.

I also need to let you know that comments made on this conference call may be 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 factor sections in our periodic 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 fourth quarter and full-year 2006 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 full-year 2007 non-GAAP earnings per share guidance to full-year 2006 earnings per share, again, on a comparable share basis. This presentation also includes other slides which reflect some key considerations for 2007 by reporting segment, and updates on regulatory matters. To access this presentation, you may look in the investors section of our website under "presentations" or follow the link for the Webcast. Gary will begin this call with an overview of 2006, as well as discuss some of our key focus areas in 2007. Warner will then follow with a discussion of our 2006 results, and present our 2007 earnings guidance. We will then open it up for questions. Here's Gary.

Thanks, Bruce. Good morning, and thank you for joining us. As Bruce said, this morning I want to start with a brief overview of 2006. Clearly, 2006 will be remembered as an incredibly challenging year for Ameren, as well as for the communities we serve. For the better part of the second half of 2006, our management team was focused on addressing the consequences resulting from unprecedented summer and winter storms. Those storms resulted in outages to more than 1.5 million of our electric customers over the course of these events, and our utilities spent approximately $210 million to restore their power. My thanks go out to our customers for their patience, to our employees, local contractors, and crews from across the nation, who tirelessly worked to restore power, as well as to community service organizations, local leaders, security personnel, and many others who helped our communities during those trying times.

In 2006, we also continued our extensive restoration efforts associated with the December 2005 breech of the upper reservoir at our Taum Sauk pump storage hydroelectric facility, and settled related liability matters with federal authorities. Throughout the year, we also actively worked with state authorities on liability matters related to the Taum Sauk incident. Unfortunately, we did not receive a unified offer from all relevant state authorities, and in December, the Missouri Attorney General filed a lawsuit against AmerenUE related to the Taum Sauk matter. We remain committed to working with Missouri authorities involved in this incident to resolve all associated liabilities as soon as possible. On February 2nd, we submitted plans and an environmental report to the Federal Energy Regulatory Commission to rebuild the upper reservoir of the Taum Sauk plant, assuming successful resolution of outstanding issues with agencies of the State of Missouri. We would not be seeking to return this plant to service if we were not absolutely certain that our design met or exceeded all modern safety criteria. If we proceed with rebuilding the Taum Sauk facility, we expect the plant will remain out of service through at least 2009, if not longer.

And finally, we were very busy addressing a host of regulatory and legislative matters in Illinois and Missouri throughout 2006. As most of you know, things have been quite active in Illinois. Despite a great deal of debate and a host of legal challenges, the ICC approved auction for the procurement of Illinois utilities power supply was successfully completed. In November, we received an ICC order increasing our Illinois Utilities electric delivery service rates by an aggregate of $97 million. This order authorized a 10% return on equity, but was significantly less than our request for an approximate $200 million increase, primarily because of the disallowance of significant levels of expenses, which we believe were prudently incurred. The costs included in our rate increase requests were primarily based on 2004 historical costs. Unfortunately, costs since then have increased even further, and consequently our new electric rates fall well short of covering the expenses we are incurring today. These factors will result in a return on equity in 2007 for our Illinois regulated operations that will be meaningfully below our allowed 10% return.

The good news is that a rehearing was granted by the ICC on $50 million of the disallowance. The ICC is expected to issue an order related to this rehearing by May of 2007. Certainly, the necessity and timing of additional electric delivery services rate increase requests in Illinois will be influenced by the result of this rehearing. In addition, our Customer-Elect electric rate increase phase-in plan was approved by the ICC in December 2006. The Customer-Elect plan provides residential customers, eligible schools, local governments, and small commercial customers the option of either paying the full amount of higher electric costs in 2007, or phasing in an annual maximum increase of approximately 14% for each of the three years. Deferred amounts will be recovered ratably from 2010 to 2012. Amounts deferred are charged a below market interest rate of 3.25%. As part of the Customer-Elect plan, the Ameren Illinois Utilities also agreed to donate $15 million to bill paying assistance for those in need and for energy efficiency programs. I'm very pleased that we were able to develop a constructive rate solution that was approved by the ICC that gives the vast majority of our customers the choice to adjust to higher electric rates over a period of time, while allowing our Illinois utilities to recover their costs in a timely fashion and remain financially viable.

Moving on to Missouri regulatory matters, as most of you know this past July, AmerenUE filed for its first electric rate increase in almost 20 years. AmerenUE's electric filing included a proposed annual increase in electric rates of $361 million, and also included a request for a fuel and purchase power cost recovery mechanism, and a return on equity of 12%. AmerenUE also filed last July for an increase in natural gas delivery rates of $11 million annually. In December 2006, the Missouri Public Service Commission Staff recommended an electric rate decrease of $136 million to $168 million, based on returns on equity of 9% to 9.75%. The staff also recommended that AmerenUE not be granted the right to use a fuel and purchase power cost recovery mechanism, despite enabling legislation granting us the right to employ the clause. Other interveners also made recommendations in the cases.

As shown on Slide 14 of our presentation, the primary areas of disagreement, besides return on equity in the fuel adjustment clause, are depreciation levels, the treatment of a cost-based contract from Ameren's 80% owned Electric Energy Inc. which expired in December of 2006, margins for off-system sales, and the treatment of emissions allowance sales. Interestingly, about 70% of the difference between the staff's position in the case and our position are driven by these issues. These areas of disagreement were expected, as well as the aggressive positions taken by the parties on these issues. However, I am still discouraged by the recommended rate decreases and efforts to block use of a fuel adjustment clause.

AmerenUE's costs of providing service are rising rapidly, including fuel costs, and this will only be exacerbated by rising service expectations across the state. The bottom line is that at the end of 2006, our electric rates in Missouri were 37% below the average retail rates nationally, 24% below those in states which like Missouri, have not restructured their electric utilities, and 16% below those already approved by the Missouri Public Service Commission for the other Missouri investor-owned utilities. Simply put, our current electric rate levels are inconsistent with our costs and industry-wide rate trends, and in our view, sound regulatory policy. Consequently, we will continue to vigorously defend our positions in these cases. Hearings are scheduled for March, and decisions are expected by the Missouri Public Service Commission by early June.

While 2006 was full of challenges, we did remain focused on our core operations and were able to achieve several notable accomplishments. From an operational standpoint, our power plants performed very well in 2006, setting records for generation output. Availability and capacity factors of our Missouri regulated coal-fired power plants were comparable with solid 2005 results, averaging 90% and 82% respectively. In 2006, our non-rate-regulated coal-fired plants improved their availability from 82% to 85% year-over-year, and capacity factors from 68% to 73%. We believe there is further opportunity to improve the performance of these plants, and are making investments this year to lay the foundation for this improvement.

We also successfully executed our plan to hedge our available non-rate-regulated generation due to the expiration of our below market affiliate contracts at the end of 2006. Through a mix of physical and financial sales contracts, the Illinois auction, we have hedged approximately 90% of our non-rate-regulated generation position for 2007, as well as approximately 55% for 2008. Finally, in December 2006, we announced a new organizational structure to align our Company's management structure and financial reporting more closely with our three distinct areas of business; Missouri regulated operations, Illinois regulated operations, and non-rate-regulated generation operations. We expect this new structure will improve our focus on providing top tier service for our customers and bottom line results for you, our shareholders.

Looking ahead to 2007, there are several areas that we will be focusing on. From an operational perspective, we'll continue to focus on improving the performance of our generating plants. In 2007, we expect to see improvement in the output of our plants, especially our non-rate-regulated generating plants, as we seek to increase generation output by 5% and raise those plants' capacity factors to approximately 78%. With increased output from our non-rate-regulating generating plants and the expiration of 1 million megawatt hours of below market power supply contracts by the end of 2007, we will continue to employ our strategy of meaningfully selling this output for 2008 and beyond, through forward sales in 2007, and through the January 2008 auction. Our marketing strategy is to sell our generation output in a low risk manner to minimize earnings and cash flow volatility, while capitalizing on our low-cost generation fleet to provide for solid sustainable returns.

We'll also continue to make significant investments in our energy infrastructure to improve overall system reliability in order to meet rising customer expectations for the 21st Century and address environmental compliance requirements. Effectively managing these projects will be a very important objective for us in 2007. On the environmental front, we'll continue to be actively engaged in the debate over future legislation addressing greenhouse gas emissions. As always, we'll also be very active in the regulatory and legislative arenas in Illinois and Missouri. In Illinois, despite the fact that the ICC approved our Customer-Elect rate increase phase-in plan in December, we expect that the Illinois General Assembly will continue to consider legislation to address the recent January 2nd rate increases, including the roll back of rates to 2006 levels. The last session ended in a stalemate between the House and Senate on this matter. Of course, we believe we already have in place a constructive solution to this issue with our Customer-Elect rate increase phase-in plan. As we did throughout all of 2006, we'll be actively engaged in the legislative process to protect the interests of our Company.

On the regulatory front, we'll be working very hard to achieve constructive outcomes in our pending electric and gas cases in Missouri, and the rehearing of certain issues in our Illinois electric delivery service cases. In 2007, our regulated utilities will experience significant increases in the costs of serving our customers. Fuel and transportation, labor and material costs continue to rise, and energy infrastructure investments continue to increase. Many of these costs are well in excess of those reflected in our recent and ongoing rate cases because rates are largely based on historical costs. Needless to say, we'll be working very hard to not only recover our historical costs in rates, but continue to explore constructive regulatory solutions to minimize regulatory lag in the future, so that our regulated utilities are able to make timely investments in our energy infrastructure in a cost effective manner in order to meet our customers' needs.

As you can see, 2007 will be a very busy and important year for our Company. We'll work tirelessly on these key initiatives so that we may continue to deliver solid returns in 2007, and in the future. With that, I'll now turn the discussion over to Warner.

Thanks, Gary. I would now like to refer you to our website as I provide a more detailed discussion of our earnings for 2006 and earnings guidance for 2007. As Bruce mentioned earlier, to assist in our call this morning, we've made a slide presentation available on our website. This presentation reconciles our earnings per share for 2006 to our earnings per share for 2005 on a comparable share basis. In addition, this presentation includes a slide that compares our 2007 non-GAAP earnings per share guidance to full-year 2006 earnings per share on a comparable share basis.

Now, beginning on slide 3, for the full year of 2006, we reported net income of $547 million or $2.66 per share, compared to net income for 2005 of $606 million or $3.02 per share. Ameren recorded net income of $61 million or $0.30 per share for the fourth quarter of 2006, compared to $20 million or $0.10 per share for the fourth quarter of 2005. Fourth quarter 2006 results included $28 million or $0.13 per share of storm-related costs, and fourth quarter 2005 results included a $22 million for $0.11 per share charge for the cumulative effect of a change in accounting principle related to accounting for asset retirement obligations. For the full-year of 2006, restoration efforts associated with the severe summer and winter storms reduced net income by $0.26 per share. Excluding the earnings impact of severe storms of $0.26 per share, non-GAAP earnings in 2006 were $2.92 per share. These results were within Ameren's previously announced earnings per share guidance range of $2.75 to $3 per share, which also excluded the estimated earnings impact of severe storms.

Electric margins improved $0.13 per share in the fourth quarter and $0.20 per share for the full year in 2006 as compared to 2005. For the year, native load growth, including industrial customers switching back to the Illinois utilities, improved plant operations, the lack of coal conservation measures, and higher interchange margins, more than offset higher coal and related transportation costs and purchase power expenses. Native load margins improved due to solid growth in our service territory, as well as because several commercial and industrial customers in Illinois switched back to Illinois tariff rates as a result of the expiration of power contracts with suppliers. We estimate our Illinois regulated operations electric margins benefited by approximately $0.08 per share due to customer switching. These and other factors contributed $0.32 per share to earnings in 2006 compared to 2005. In addition, interchange margins rose $0.33 per share during 2006, due largely to the expiration of a cost-based power supply contract from 80% owned Electric Energy Inc. at the end of 2005, the expiration of low margin wholesale contracts, improved plant operations, and milder weather.

Lower energy prices during 2006 offset in part these positive factors. Energy prices were higher in 2005 as a result of the significant impact of hurricanes and rail disruptions. Higher fuel and purchased power costs decreased electric margins by $0.45 per share in 2006 compared to 2005, due to higher coal and related transportation costs and due to the expiration of Electric Energy Inc.'s cost-based power supply contracts with our regulated utilities. Heating degree days in 2006 were 17% below normal and 9% below the prior year period, according to the National Weather Service. Cooling degree days in 2006 were 16% above normal, but 9% below the prior year period. The lower electric and gas sales resulting from the milder weather are estimated to have reduced 2006 earnings by $0.17 per share compared to the prior year, and $0.04 per share compared to normal. Mild weather reduced fourth quarter 2006 earnings by $0.06 per share compared to the fourth quarter of 2005.

Costs related to the December 2005 breach of the upper reservoir at AmerenUE's Taum Sauk pump storage hydroelectric facility decreased 2006 earnings by $0.05 per share in the fourth quarter and $0.20 per share for the full year. Costs associated with the Midwest Independent Transmission System Operator, Day Two energy markets were lower in the fourth quarter of 2006, improving earnings by $0.05 per share from the same period in 2005. Notably, these costs were flat for the full year 2006, despite only a partial year of MISO Day Two operations in 2005. Sales of excess emission allowances benefited earnings in the fourth quarter of 2006 by $0.06 per share, and benefited full year 2006 earnings by $0.05 per share. Emission allowance sales in 2006 contributed $0.17 per share, and as I will discuss in the 2007 guidance portion of our presentation, we do not expect this level of sales to continue in 2007. During the fourth quarter of 2005, we performed a refueling and maintenance outage at our Callaway nuclear plant, which reduced 2005 earnings by $0.15 per share. Since there was no outage this year, earnings benefited. The full gainfrom the lack of a planned refueling and maintenance outage from full year 2006 was $0.18 per share over 2005. However, a second quarter 2006 unscheduled outage at the Callaway plant cost $0.07 per share.

Bad debt expense was lower than expected in 2006 as a result of mild weather and lower natural gas prices, benefiting earnings by $0.02 per share during the fourth quarter and $0.05 for the year. Higher depreciation and amortization expenses reduced earnings by $0.05 per share in the fourth quarter of 2006, and $0.11 per share for all of 2006 compared to the year ago period, primarily because of capital additions. Increased taxes, other than income taxes, reduced fourth quarter and full-year 2006 earnings by $0.02 and $0.08 per share respectively. These increases were due in part to favorable tax settlements in 2005 that were not repeated in 2006. Net dilution and financing costs reduced earnings by $0.03 per share in the fourth quarter of 2006, and $0.14 for the full year of 2006 over the same periods a year ago, due to increased borrowings, as well as our ACES share conversion in the second quarter of 2005.

In the fourth quarter, we also sold certain non-core properties, which included leveraged leases. The net benefit of these sales in 2006 was $0.16 per share, or $0.09 per share over the prior year period. We have now sold nearly all of our leveraged leases. Finally, as Gary mentioned, in the fourth quarter, the ICC approved our Illinois electric rate increase phase-in plan, which included a requirement to fund $15 million in energy efficiency and assistance programs. The approval of this program resulted in a $0.05 per share charge in the fourth quarter of 2006.

I would now like to turn to our 2007 earnings guidance. This morning, we announced that we expect 2007 non-GAAP earnings for Ameren to range between $3.15 and $3.60 per share. While we recognize that our earnings guidance range is relatively wide, it is important to keep in mind that we have major rate cases pending in both Missouri and Illinois. The outcome of these cases could differ significantly from the assumptions we have reflected in our earnings guidance, which I will discuss in a moment. Our Missouri regulated segment, Illinois regulated segment, and non-rate-regulated generation segment are expected to contribute approximately $305 million, $115 million and $285 million to earnings in 2007 respectively. Costs related to the January 2007 ice storms, as well as accounting charges expected in 2007 related to offering below market financing associated with the Illinois utilities Customer-Elect phase-in plan, are excluded from the non-GAAP earnings guidance because they are unusual and the associated costs cannot be fully determined at this time.

Ameren's consolidated and segment guidance for 2007 assumes normal weather and is subject to, among other things, regulatory and legislative decisions, plant operations, energy market and economic conditions, severe storms, unusual or otherwise unexpected gains or losses, and other risks and uncertainties outlined in Ameren's forward-looking statements and risk factor sections in our releases or periodic filings with the SEC. You will see in the 2007 guidance slides posted on our website that we have used single number estimates for the key variables we expect to impact 2007 earnings as compared to 2006, as well as expected segment net income. There is, of course, a range of outcomes that could occur around each of these variables in our segment results, but for the sake of simplicity, we have provided a range only for total earnings per share and total net income. As I go through the key items that are expected to impact 2007 earnings, I will attempt to highlight those items that could have the greatest range of outcomes.

Starting at the top of slide 4, we have added back the impact of the severe storms that we incurred in 2006 to arrive at our 2006 non-GAAP earnings per share starting point. As I said previously, our 2007 guidance does not reflect the impact of our January 2007 ice storm. We will discuss the impact of those storms during our first quarter conference call in April. As Gary noted in his comments, we received an order from the ICC in November 2006, effective January 2nd, 2007, increasing our electric delivery service rates by an aggregate of $97 million. While electric margins for our Illinois regulated segment will be $0.30 per share greater than they otherwise would have been due to this order, several other factors will impact electric margins in 2007 when compared to 2006. As a result of these factors, we expect the change in Illinois regulated margins to have only a modest $0.04 per share benefit on 2007 earnings as compared to 2006. To facilitate your understanding, we have listed the major factors impacting this comparison on slide 7 of our presentation.

In early 2006, based largely on a 2004 historical test year, we requested an aggregate $200 million electric delivery service rate increase, and as I stated, in November 2006, we were only granted a $97 million increase. Rates incorporating the $97 million increase are now in effect. However, we sought rehearing of certain disallowances in that case. For our 2007 guidance, we have arbitrarily assumed we will be granted, effective June 1st, 2007, an additional $25 million increase in rates, representing approximately half of the administrative and general expense disallowance at a subject rehearing. Obviously, the outcome of this rehearing could vary significantly from our assumption. The effect of the January 2nd, Illinois electric rate increase, coupled with the assumed rehearing-related June 1st rate increase, totals about $0.35 per share. Remember, however, that very few customers were actually on electric delivery service rates in Illinois in 2006. Rather, they were on bundled rates.

Due to the change in rate structure, and despite the delivery service rate increases, electric margins in our Illinois regulated segment are only expected to increase by $0.04 per share compared to 2006. This is in part due to the growth in electric margins of about $0.18 per share experienced in 2006 under the old bundled rate structure. Electric margins increased in 2006 due to customer switching. That is, several of our Illinois electric commercial and industrial customers returned to the below-market bundled tariff rates as their higher cost power supply contracts expired in 2006. Electric margins in 2006 also benefited from lower purchased power costs to cover our Illinois customer needs, as power prices fell from 2005 levels, as I described earlier.

Another factor offsetting the positive impact of the delivery service rate increase is the effect of the completion of the amortization of an AmerenIP purchase accounting adjustment, which positively impacted earnings by $0.13 per share in 2006. These factors help explain how our earnings changed from 2006 to 2007. However, the bottom line is that the current rate levels approved by the ICC for our Illinois distribution businesses are not sufficient to recover our cost of operations and earn our allowed return on equity of 10% due to the cost disallowances and regulatory lag Gary described earlier. The necessity and timing of new Illinois delivery rate cases will be driven by several factors, including the results of the rehearing.

In Missouri, our 2007 guidance arbitrarily assumes a $103 million rate increase, which is the midpoint of the original Missouri staff position and our position on the rate case filings that Gary described earlier. We assume the increases will be effective June 1st. For simplicity, no other regulatory conditions or assumptions are being made. These increases are expected to result in a $0.19 per share increase in earnings in 2007 from 2006. Clearly, since there is over a $500 million range between our rate case positions and those of the staff, the final Missouri commission order could vary significantly from our assumptions, and our 2007 earnings guidance range does not fully account for the entire range of possible outcomes.

Other electric margins are expected to improve by $1.34 per share. The increase in electric margins is being driven primarily by the replacement of below market power sales contracts, which expired in 2006, with higher price contracts in 2007 in our non-rate-regulated generation segment. In addition, electric margins are increasing due to improved plant operations, especially in our non-rate-regulated segment, and organic growth. Of course, this is another item that could have significant variability around the midpoint provided in our guidance, due to the volatility of power prices, planned availability, and the final Missouri commission order. However, as Gary discussed earlier, we have significantly mitigated the potential impacts of energy price volatility by hedging approximately 90% of our expected generation output for our non-rate-regulated operations. We have also hedged approximately 85% of our Missouri regulated generation output. On slide 8 of our presentation, we have provided some key metrics related to sales and pricing for our non-rate-regulated segment portfolio.

As we have been indicating for some period of time, we expect coal and related transportation costs in 2007 to increase by approximately 20% and offset some of the benefit in increased electric margins. Approximately 70% of this increase is being driven by increases in fuel costs in our Missouri regulated business due to significant increases in coal and related transportation contracts. Our current Missouri electric rate case is seeking recovery of these fuel cost increases, and as Gary discussed earlier, we are also requesting that the commission approve a fuel and purchase power cost recovery mechanism to address future changes in fuel costs. The weather impact of $0.04 per share is simply adjusting 2006 actual results to our assumption of normal weather for 2007. Weather is certainly a variable that we cannot control, and could have a significant impact on our 2007 earnings.

There will be a 30 to 35 day Callaway nuclear plant refueling and maintenance outage in our Missouri regulated segment in the spring of 2007. This outage is expected to reduce 2007 earnings by $0.07 per share as compared to 2006. Of course, should this outage differ from our plans, that too will impact our 2007 earnings. In addition to maintenance at the Callaway plant, we expect to perform meaningful maintenance work at our coal fire power plants in 2007 in order to continue to improve their operating performance. These expenditures are projected to reduce 2007 earnings by $0.11 per share. We also expect to meaningfully increase spending on reliability-related projects in our electric and gas distribution businesses, reducing earnings by $0.05 per share in 2007 from 2006.

Labor and benefit costs are also expected to increase in 2007, reducing earnings by $0.17 per share compared to 2006. Approximately $0.05 of this increase is due to increased amortization, pension, and post-retirement, medical-related regulatory assets in our Illinois regulated operations. These costs are being recovered in current rates. With higher electric rates in 2007, bad debt expense is projected to rise by $0.08 per share. We also expect to incur higher depreciation and amortization, and related financing costs of $0.08 per share. About $0.05 per share of this change is due to amortization related to the Illinois power integration costs, which were deferred as a regulatory asset, and are now being amortized and recovered in rates. The balance of the increase is due largely to capital additions.

This year, we plan to invest $1.3 billion across the system, which is comparable to the amount that was spent in 2006. However, 2006 included $292 million related to the acquisition of combustion turbine peaking units for AmerenUE and $140 million related to storm restoration. In 2007, environmental-related expenditures at our generating plants are expected to increase. In particular, the non-rate-regulated generation expenditures are expected to increase from $162 million to $400 million in 2007, primarily to meet new Illinois environmental standards. We, like others in the industry, are projecting higher labor and material costs for capital projects. As a result, we have increased our environmental capital expenditure estimates to $3.5 billion to $4.5 billion through 2016. Approximately 50% of these expenditures should be recoverable in rates through the regulatory framework in Missouri. Our capital expenditure program is laid out on slides 9 and 11. Dilution and financing costs will also rise due to our capital expenditure program and related regulatory lag.

We do still expect to incur costs in 2007 related to the Taum Sauk plant incident. This cost is projected to be about $0.05 per share versus $0.20 per share last year, and relates primarily to replacement power costs. In 2006, we incurred Taum Sauk-related costs for fines, as well as costs for meeting our insurance deductible for replacement power. In 2006, we realized gains on the sale of emission allowances and sales of non-core properties. We do not expect to achieve similar sales levels of these items in 2007. Finally, as I mentioned earlier, in 2006 we recorded a charge of $15 million or $0.05 per share related to contributions to energy assistance and efficiency programs ordered by the ICC as part of the electric rate increase phase-in plan approval. This charge will not recur in 2007. This completes our prepared comments. We will now be happy to take your questions.

[OPERATOR INSTRUCTIONS] Ashar Khan. SAC Capital.

Warner, I guess this is a little bit -- I'm a little bit frustrated. So take this remark, then you guys weren't in charge. But I just want to make kind of a strategic remark, that this Company, which was Union Electric, earned around $3 in earnings in 1994. And if you just increase those earnings and the allowed book ROE was 11.4. And we come back to 2007, and if you just increased earnings by 2%, we could have been like at $3.88 in 2007. And we went through all of these mergers and we still are a little bit shy of that mark. And so I just want to -- and you guys weren't in charge, so it's not your fault or anything. But I just want to say sometimes these mergers and all that, I don't know, they get lost in terms of not creating value, especially in your case. Unless we are going to produce much higher earnings by the time these rate cases are done, and the whole thing is done. Because if you had remained as Union Electric, would have remained a regulated Company with a much higher multiple and things going on. So, I don't know, it's a little bit of frustrating remark, but I just want to mention to you that unless I'm missing something, these mergers haven't helped Union Electric through present Ameren as things stand today.

Well, Ashar, this is Warner. I guess a couple comments. Look, we understand your frustration and certainly we're going the best we can to continue to provide shareholder value. I think as you look back and you look over the years, there have been a lot of changes in our industry which have taken place, including the significant rise in related costs of operating our business. And we've cited in our guidance today, and in our, the issues associated with regulatory lag. And certainly the biggest increase in our business in terms of costs have been coal and related transportation costs. And they have skyrocketed since that time.

When we go back and we look at the acquisitions that have taken place, we believe those acquisitions have been very solid acquisitions, they've been strategic, and they have been accretive to earnings. Recognizing that we still have pending rate cases out there in our Illinois operations and obviously, we'll continue to try and address some of the low ROEs that we're achieving in our Illinois operations. And like we said, we did achieve, with regard to the merger with CIPS, was the acquisition of very low cost base load generation, which we are now able to capitalize on some of those, with the repricing of some of these contracts, which you see some of the earnings movement. But having said all those things, we're going to continue to stay focussed on our overall strategic game plan, and the focus on our core operations and to continue to deliver solid returns.

And if I can just go to the slides. Warner, the way I'm looking -- what is the $1 million -- is it at 37, which comes off? And what can you well in the market for the 2008?

Ashar, I think you may be referring to the million megawatt hours of wholesale contracts, which are rolling off -- .

That's correct.

-- by the end of 2007. Those are at about $37 and $38 today. And of course, if you look at a [shaped] product, those costs are certainly north of that today. If you just look on average in terms of our portfolio that we cite in the slides there, our portfolio is right around $51 per megawatt hour. So that also includes some very low cost wholesale contracts, which are still embedded in our overall portfolio. So we'll let you make your own observations in terms of what the potential market upside could be. But we certainly believe there be, could be given current market conditions.

But Warner, could you please explain how you come to that $51? What are the significant things that we look at? What is under water? And how does this average move up or stay flat over the next few years?

Well, I think when you look at the $51, the $51 consists of a multitude of things. It includes the megawatt hours that we sold during the auction at 65. And that was about 7 million megawatt hours. That also includes some of the existing wholesale transactions, which we just talked about before, which are priced at again, in that $35 to $40 range, and that's about 5 million megawatt hours. And then you have other transactions that we entered into throughout the year, including some block types of transactions with financial players, as well as some contracts that we entered into with some of our larger commercial and industrial customers. And again, those were -- none of those contracts are under water. In fact, when you look at those block transactions in those C&I customer contracts that we entered into, they were entered into, in many respects, earlier in the year. And since then -- earlier in the year in 2006. And since the, market prices have fallen off. So I think if you look at our book of business, it is well in the money.

Greg Gordon, Citigroup.

When we look at the midpoint of the guidance, the $115 million of net income you're assuming in Illinois, what type of return on equity and rate base does that infer? Because I'm coming up with a number of like 3%. And I just want to make sure I'm in the right ballpark.

When you look at the entire Illinois regulated segment, and basically the net income is fairly comparable year-over-year, it's probably around that 5% metric.

5% ROE?

Yes, 5% ROE. That's correct. 5% to 6%, somewhere in there.

Okay. And in Missouri, the 305 number -- and I understand your point, that you could drive not just a truck, but probably a dozen trucks through the [ask] spread in the case, but if we just look at that 305 number you're using as a place holder for guidance today, what type of an ROE does that infer?

Greg, we'll have to take a look at that in terms of the ROE. I can tell you that at the earnings level for the UE regulated segment at the end of 2006, that number was right around 9%, roughly. And so for every $50 million, it's about 100 basis points is every $50 million. So basically, you're looking at -- .

Of bottom line net income?

No, that's pretax, excuse me.

Okay. Sorry. Okay, $50 million pretax. Got it.

So, at those levels, you're probably looking at something maybe around 10ish, a hair shy, give or take either way.

Okay. And you said in your build up from '06 to '07 that fuel costs are a $0.34 drag, 70% of that's Missouri, as we're presuming you don't get a fuel clause. So that would be around $0.23 impact in Missouri. So if, in fact, you wind up coming away with a fuel clause mid year, roughly half of that $0.23 or -- would be recovered in rates. And then on a prospective basis, you'd be made whole for fuel if the commission actually abides by the law and doesn't abide by staff's position. Is that a fair way to look at it?

I think, Greg, the way to look at it simply, is that, of course, in our rate request of the 360 some odd million in the Missouri electric rate case, we've reflected the increase in fuel costs effective 1/1/07. That's embedded in that number. And so, again, all we've simply done from a guidance standpoint, as we said, arbitrarily take the midpoint between the staff's position and ours. It depends on how the commission ultimately would think about those fuel costs. But I wouldn't necessarily say that they'd give us a fuel adjustment clause that you would be able to take that $0.23, half of that $0.23, and think that that would be recovered. It's hard for me to just sit there and speculate exactly, but it is not necessarily going to be the case.

Okay. But if you got some sort of fuel recovery mechanism, there'd be a methodology for assessing the prudence of those costs and allowing for their recovery?

Yes, there absolutely would be.

Okay. And then final question, because I know there's probably a queue. When we look at the -- you said you had 5 million megawatt hours under contract at $35 to $40. You say in your '08 guidance that only about 1 million of that rolls off?

That's right. And -- .

When's the rest -- what's the half-life of the remaining contract?

Yes, another 2 million megawatt hours will roll off by the end of '08, and then basically for the next couple of years it stays pretty steady after that, Greg.

Okay.

So basically between now and 2009, you have 3 million megawatt hours, which are certainly below current market prices, will be rolling off on unregulated business.

And you indicate that you're going to be only -- that you want to be pretty much fully hedged by the time you get to the next auction. So should it be our assumption that you're only going to be a modest participant in the auctions? And you'd rather -- ?

Let me clarify that. What we said is that if you assume the auction's going to take place in January, we said that by the end of January, we would be 85% to 90% hedged. So -- .

By the end of January, okay.

So you shouldn't assume that we wouldn't be an active participant in the auction. Again, we'll assess our strategy throughout this year in terms of how much we want to play in that. And as we've said, we're already 55% hedged for our '08 economic generation. So we've already made significant strides, as well as significant strides for 2009 already, as well. We're probably close to 30% or so hedged of our generation at this point in time.

Do you have an average price at which you're hedged on those percentages that you're willing to disclose?

With regard to the other ones -- .

To '08 and '09.

Excuse me? '08 and '09? I think you would expect to look at those. Most of this stuff's been hedged with the auction already. So those are visible prices. And then some of those others are obviously those lower cost wholesale contracts. So you would probably find a blended price that'll be somewhat close to what we're showing for -- .

I got it. So if I take 6.8 in '08 and add the 4 million -- 6.8 in '08 hedged at 65, and 4 million hedged at between 35 and 40, whatever the delta is, just assume some sort of -- .

That'll get you to a blended rate somewhere between those two numbers. That's a fair way to think about it.

Thank you, Warner.

Dan Jenkins, Bank of Wisconsin Investment.

Just a few questions on your guidance here. First, I think you mentioned your assumption for the Missouri rate case, you said 103 million. Is that just the fact that the increase goes in 6/1. So if you annualize that to annualize your increase, you'd have to multiply that by essentially [twelve-sevenths]?

Yes, Dan, that's right. You only get a partial year of that because it goes in June 1st. And of course, if it goes in June 1st, it gets summer rate impact. So it's a little bit of variability around that. But if you would assume you would get that $100 million rate increase effective June 1st, then you would get a full year of that increase in 2008. And that's reflected on page 10 of our slides, where we talk a little bit about the 2008 outlook.

I haven't had a chance to -- .

That's fine. I just wanted -- .

-- comb through all of these slides yet. On the number you have there for Illinois regulated, you mentioned an $0.08 decline related to the customer switching. Have you assumed basically that -- I guess you're not -- you'll only get distribution rates from all of those customers? I guess what's the assumption behind that? And are any of those then reflected in your sale -- your non-reg sales? I guess I'm trying to get a feel for -- ?

Sure. What that relates to, is sort of the transition from '06 to '07. And basically what we're seeing is that when you compare '06 to'07, our Illinois regulated margins were enhanced by this customer switching. Now as you look forward, the only thing that our Illinois regulated operations will experience will be the distribution rates. And that's the $97 million, plus whatever we get out of the rehearing. That's what they will experience. And the C&I customers are being picked up in the margins that we're achieving in our non-rate-regulated segment from our marketing perspective. So that $1.34 per share that we show there, reflects improved margins by entering into new contracts with some of those large commercial and industrial customers.

Okay. That's kind of what I thought. So some of the -- some of the recent Illinois number is not higher than -- is not as high because some that money is shifted down into the third line, the other electric margins.

Yes, and again, that is exactly -- when you're looking '06 to '07, you get that comparison. But really the bottom line, is if you're looking at the Illinois regulated operations, is that when you step back and you -- the existing rates that we have for our Illinois regulated business, as I said, are not sufficient to cover our existing costs or earn an appropriate return on investment to earn our allowed ROE of 10%. And that's due to the fact that we sought a $200 million rate increase for our Illinois regulated operations, and basically, at least to this point, we only achieved half of that. Hopeful to get more out of the rehearing, because we think that's absolutely critical for our business. But that's the simple facts of it. And that's the simple math.

Right. Then on the fuel costs, that negative $0.34, is that just up until the rate case goes into effect, since you -- or is that -- there more to that than that, since you've assumed -- ?

Sure, Dan. That is just simply isolating the fuel cost increases. If you looked at our fuel costs and didn't really reflect any regulatory frame work there, that's what isolating the price increases and fuel and related transportation, that's what that would be.

Okay. So -- .

The rate case is being reflected, and that's for a full-year, of course.

Right.

The rate case, obviously for Missouri, that doesn't go into effect until June 1st. So at a minimum in 2007, we are experiencing regulatory lag, even if we got 100% of those cost increases in Missouri, we're experiencing regulatory lag for those fuel costs increases between now and June 1st.

Paul Patterson, Glenrock Associates.

Just to clarify something here. You guys earned $0.17 in emission allowances for 2006 and that won't be in 2007? Is that the number?

That is correct. Our expectation is that we will not have the same sales levels of emission allowances in 2007 versus 2006.

Right. And then you said in 2008 on slide 10, that you expect higher environmental compliance expenditures. Is that O&M? I mean, is that like emission allowance expenditures? Or is that just CapEx, or both? How do we see that trending, I guess, in 2008 and beyond? You've got some CapEx going -- ?

I'm sorry, I didn't mean to interrupt you. The increase -- what we're really identifying with regard to 2008 is principally capital expenditures at that point in time, and of course, there are related financing costs associated with that. But as you put -- as you make these environmental expenditures and you start making changes to your plans, down the road, we do expect to then incur higher levels of O&M in our business, as well, as a result of those. So therefore, again, in '08, you would see mostly the CapEx, But beginning in '09 and beyond, we will start seeing some creep in O&M.

Michael Lapides, Goldman Sachs.

Guys, I'm looking at the environmental CapEx page in the presentation, page 11, versus the one you put out at EEI just three month ago. Wanted to double check two things. I'm looking mostly at AmerenUE, but also at the non-reg side, as well. Can you talk a little bit about what has changed in the three months? That's kind of topic 1. And topic 2, can you you talk a little bit about what you can do to lock in costs? About whether you can limit the risk to both yourselves and shareholders, obviously, of continued cost creep here?

Sure. Well, basically at EEI, we were still in the process of assessing our environmental -- not just our compliance program, but our environmental capital spend. And typically at the end of the year, we try and pull all those things together and we make some decisions in terms of where we think things will be going forward. So what you basically are seeing in our most recent update, is what we believe to be meaningful increases with regard to labor and material costs to really perform the projects that we have had in place and had in mind through most of 2006. So that's number one.

The second thing you related to the Missouri business, as we point out on that slide, we do believe that under the -- that the regulatory framework in Missouri, even just standard rate making, that much of the environmental costs, capital costs, as well as O&M, would be recoverable in the regulatory framework. And we're hoping to mitigate the regulatory lag associated with those environmental CapEx through the environmental cost recovery mechanism, where enabling legislation has been passed, and rules will be considered by the commission sometime, we believe, in 2007, at least the rule making process will start. And finally, with regard to how you're locking some of those things in, Gary, you can probably comment a little bit more about the association that we have with Hitachi to perform some of this work here over the next several years, that will give us the necessary labor, as well as some of the materials associated with those.

Well, what Warner is referring to is an alliance with Hitachi. Hitachi is doing most of the scrubber work. The scrubbers that we have under construction right now, I believe are at Coffeen Plant, Sioux Plant, Duck Creek Plant. And the costs for those are locked in. Beyond that, we have not locked in the environmental costs. But as Warner said, it's primarily labor and materials. They're increasing not just for us, but for everyone in the industry.

Erica Piserchia, Merrill Lynch.

First question, so when would you be looking to file your next full blown electric rate cases in Illinois to kind of get more accurate historical costs reflected in here? Do you have to get out past the, I assume past the rehearing decision. But then how soon after that would be filing, and when would you be looking for new rates there?

Sure. Erica, you're exactly right. We have to wait for the rehearing to be completed before we would file another rate case, even if we were going to do that right on the heels of that, that would probably be mid year at the earliest. But as we said in our call, and in our statements a little bit earlier, several factors will determine when exactly we will file for a rate case in Illinois. Those factors obviously include the results of the hearing in part. But also, we'll take a look at when our expenses -- how our costs are going to be looking at in Illinois, as well as when we may be making some meaningful rate base additions, so we can try and time the filing of that rate case as best we can to minimize regulatory lag to the greatest extent possible. But it is possible that we will be looking -- we could file a rate case as early as this year in our Illinois delivery services business. But that has not been determined at this point.

Scott Engstrom, Satellite Asset Management.

I appreciate your segment breakdown that you guys shared last time. But are you still willing to give an SEC breakdown for me?

You bet. You bet we're still willing to do that.

Great.

Let me try and go down the list for you. This is just for 2006 full-year net income. For UE, that would be $343 million, for CIPS $35 million, for GenCo $49 million, for CILCORP $19 million, for IP it is $55 million, and then we had the sort of the parent company stuff of $46 million, to get to a total net Ameren net income of $547 million.

That includes the storm costs that you guys scrubbed out of the adjusted number, right?

I'm sorry, Scott, what did you say?

It includes storm costs, yes.

Yes, it does, thank you.

Do you have the storm costs by reporting entity?

Yes, we do. If you'll give me a moment, we'll be able to come up with those for you. By entity -- we have it by really regulated segment. I'll tell you what, Scott can we get back with you on that?

Sure.

We have it by sort of the segment and -- .

No problem. I'll follow-up. Could I ask a question -- ?

Yes, if you could follow-up. We do have that information, though.

Can I ask a question on cash flows then? Just thinking of kind of sources and uses. Last couple of years operating cash has been running at $1.25 billion. Assuming some step up in that this year. But CapEx estimated at $1.3 billion and dividends of $525 million, call it. Looks like somewhere in the $500 million to $600 million shortfall there of sources and uses, assuming you match debt with retained earnings on a -- for a 50/50 basis, that's $175 million of that $500 million to $600 million. Looks to me like about a $300 million, $400 million financing gap. How should we think about that? And is that with the environmental expenditures, is that kind of a run rate we're going to see going forward? Or will CapEx fall off or OCF pick up? How should we kind of think about that?

Well, certainly, your observation with regard to free cash flow with regard to 2007 is generally in that ballpark. I would say a shortfall of $500 million to $700 million, give or take, because of the -- largely due to the large capital expenditure program. But also keep in mind that part of the other -- our Customer-Elect phase-in plan includes the possibility for customers to defer some of their -- some of the -- we would defer some of the collections from our customers for our billings. So that number in our cash flows could be affected by ultimately the number of customers who choose to sign up for the Customer-Elect phase-in plan. And that's what we alluded to a little bit earlier. But we do expect to continue to have meaningful infrastructure investments in our regulated businesses. We do expect to continue to have sizable capital expenditures, especially from environmental programs. And so we could see over the next few years still some negative cash flows. And until we see really how the customer participation rate will be in the Customer-Elect plan, we'll just have to see how that really plays out.

Leon Dubov, Zimmer Lucas Partners.

I just wanted to check, which segment do you guys put the Joppa generating plant into? Is that part of the Missouri operations? Or is that part of the nonregulated generation?

It's part of the nonregulated generation.

So that's included in the guidance for the nonregulated gen, and that's part of the $51 average price that you guys quoted?

It is indeed.

Thank you very much.

Paul Ridzon, KeyBanc.

Warner, you had the $0.19 impact from the Missouri rate case, that's assuming the midpoint. But in assuming that midpoint, you've got to be -- some piece of that's probably fuel recovery. I'm just trying to figure out how you arrived at that $0.19 and the $0.34 drag? Tell us flat out what your guidance assumes for under recovery in Missouri for the back half of '07.

Well, I think there's nothing particularly magical about it. What we did was take the midpoint of our filing -- our original filing with the -- with our position and the staff's, a position at a 9% ROE, and you get to that $100 million, and you assume that effective June 1st, and you get $0.19. As I said before, we reflected in our $360 million-plus filing, the reflection of fuel costs, effective January 1st, 2007. So those numbers are reflected, at least in our request. We have not assumed any other regulatory conditions. And as I said, that doesn't assume any fuel clause or anything like that. It's not to say that we don't think that there's a chance that we would get one. It's just that we kept the assumption fairly simple.

With regard to the $0.34, that's just simply taking business as usual. If our fuel costs are going up, and as a result of that are going to have a drag of $0.34 per share. Some piece of that $0.19 that we're talking about is potentially recovering some of those fuel costs. It just remains to be seen on how the commission rules on that. But one thing which is happening, which I can say very clearly, is that no matter what happens, that the fuel cost increases that we have between January 1st and say May 31st before rates go into effect, and to the extent those fuel costs are impacting our Missouri operations, we are being negatively impacted one per one for those due to regulatory lag. That is reflective in our guidance. To the extent, then, that we have a fuel adjustment clause or a constructive regulatory outcome, those costs going forward would be mitigated in the Missouri regulatory framework.

Doug Fischer, A.G. Edwards.

Just to hit on those fuel costs again. Would they be back-end loaded given the importance of sales in the third quarter?

Oh, I think in terms of volumes, certainly. I think that's probably a fair statement, that you would see the summer impacts. And so they would be more back-end loaded than they would be front-end loaded. That's fair.

And then any update on the Missouri commission setting rules for the environmental rider?

With regard, Doug, to that,there has been no recent discussions that I'm aware of by the Missouri commission. I think the Missouri commission has been very, very busy dealing with multiple rate cases, as well as a host of other issues in front of them. And so they have not put any time line in terms of when they'll address those particular rules. We're certainly hopeful that they'll take some of that rule making process up here in 2007. But to the best of my knowledge, they have not put any deadline -- excuse me time line around that at this point.

And finally, what's your strategy with regard to addressing the concerns in Missouri and Illinois with regard to the storms and reliability, especially in Missouri with the legislature -- some bills circulating?

Well, I think Doug, our strategy is just simply to do the best we can, and to educate the key stake holders in the process. We have had people meeting with these key legislators, with the commissioners, as you know, as well as with the staff to talk about the storms, to talk about reliability. We have provided a letter to the Missouri commission with some ideas in terms of how we can make some steps in terms of that. And there'll be a lot of dialogue between now and certainly the rest of this year and going forward, in terms of what we can do as a Company to meet customers' expectations for the 21st Century. Gary, anything beyond that?

Well, Doug, we do plan to spent more money in some programs. And to some extent, that is partly built into our current rate case. But just to put it in perspective for you, the storms that we had last year were really extraordinary. We had the most severe weather in the United States in the St. Louis region last year and the most severe weather ever experienced. So it raises questions about how do you plan for that kind of weather? There really is not a lot that we can do that will reduce customer outages in storms like that, short of cutting down all the trees or putting all the lines underground. Hopefully people have seen that wherever there are those kind of storms, there are outages in other parts of the country, not just in St. Louis. But we will be spending more money to improve reliability. We're going to be very focussed on that. The storms have highlighted the reliability issue, and we're going to do better in terms of improving reliability of the system and meeting expectations.

Gregg Orrill, Lehman Brothers.

Two quick questions. One on the labor and employee benefits, what areas of the Company that related to? And then also on the other electric margins, again, on the '07 guidance, if you could break out numerically the pieces of that?

Sure, I'd be happy to do that. With regard to labor and employee benefits, I think what you -- we made in our statement about a third of that relates to the amortization of that regulatory asset in our Illinois jurisdiction, [inaudible] pensions and OPEBs. The other piece just relates simply to the rising benefit and medical costs, and I would say those are being seen throughout our entire system, that's not particularly to one particular segment or not. And I think you're just seeing sort of your normal wage increase in there, which is factored in. And then, we are increasing our head count a little bit. And I would say those head count increases are coming primarily in our regulated operations. So it's a combination of all of those factors, none of which, other than the $0.05, really sort of stands out significantly.

When you look at that $1.34, I would characterize it as sort of four major areas that are really driving that. One, the vast majority of that increase relates simply to the repricing of those contracts in our non-rate-regulated businesses. As you know, many of those contracts rolled off at the end of 2006. We repriced those. And I would say about $1.30 of that increase relates to the repricing of those contracts, it's nearly 21 million megawatt hours that were repriced. Secondly, we continue to expect to see solid organic growth in our service territory. Of course, that would be in our regulated businesses. That's somewhere, I would say between $0.15 and $0.20 in terms of what the -- that growth would be.

As Gary mentioned, we expect to improve our overall generation plant output, especially in our non-rate-regulated businesses. In total, that's probably between $0.05 and $0.10, roughly. We do expect, all other things being equal, that exclusive of the impact of the JDA, that interchange margins may be down a little bit. Those will probably be in that $0.15 to $0.20 category in terms of how they may be down. When you sum all those plus and minuses up, you come somewhere around that $1.34, $1.35. But that's the high level color around the pieces to that. And as we said, I think especially when you look at some of these other things, we have, because of our hedge percentage at both the unregulated segment as well as the regulated piece, at 85% and 90%, we have taken quite a bit of the market volatility and risk out of that portfolio, at least from a market standpoint.

Tom O'Neill, Highbridge Capital.

Just had a quick question on the coal transportation costs. That's mainly reflecting the movement of PRB Coal into the Midwest, is that correct?

That's correct. That's correct. And principally the increase is due to the transportation costs.

Right. And just kind of curious on what sort of market rates you're resetting at, and the term of those contracts is at the $18 to $19 a ton, kind of what you're seeing in terms of market rates these days?

I think we don't disclose the specific rates associated with any of our contracts. Typically our contracts have been 3 to 5 years. More towards the 5 years. And so basically, we see about 20% of our coal and related transportation needs roll off every year. This year, we're 100% hedged. Next year, we're -- I think we're close to the 90%, roughly, in terms of being hedged. But what we have seen recently, in terms of overall market prices for coal and even some related transportation, that compared to where they were say a year ago, those prices have fallen off in terms of the coal commodity, fairly significantly.

Steve Gambuzza, Longbow Capital.

My questions have been asked and answered. Thank you.

Vic Khaitan, Deutsche Bank.

I am sorry if this question was answered already, but what's your view about the Illinois legislation, they don't seem to go away? How do you see this thing will eventually sort out?

Go ahead, Gary.

I would say that there is still a lot of concern about the impact of the rate increases on customers. And we do expect a bill to be introduced in the house to roll back rates to 2006 levels. But in the call a while ago, we talked about the stalemate situation that we had between the house and the senate. We expect it to continue like that. And we do believe that our rate phase-in plan will pretty effectively address the need to mitigate the cost increases for the low income customers. So I think in time, that issue will subside. There will be, though, continuing interest in Illinois to do something different in regard to the way the business is structured. Whether it should be reregulated, or whether the auction process should be changed in some way, there will be discussion about that. So we would expect the discussion to move from the rate freeze issue to restructuring issues.

[Danielle Sites, Delman Rose].

If you were to receive a -- the environmental rider, and when -- how soon would you file for that, given the acceleration of your environmental cost?

Danielle, I think what you're pointing out is that with regard to the legislation -- .

Right.

In [any legislation], you have to file a rate case. And so depending upon when those rules will be done, depending upon the results of this pending rate case in Missouri, it's impossible to say just exactly how -- how quickly we would file for a rate case, and then employ that mechanism. Of course, a lot of that would also be contingent upon our level of capital expenditures and O&M costs that we're incurring in our regulated operations too. We'll take it a step at a time. We'll see what the rules look like when they're ultimately addressed and passed. And we'll factor in the existing rate case, as well as what our future expenditures will be. That'll dictate when we want to file the next case.

Dan Jenkins, State of Wisconsin Investment Board.

I had a question on your charge there, or lower earnings from the Callaway refueling outage. In '06, you also had an unplanned outage at Callaway. So, does that amount kind of net those two effects? Or is that -- the '06 unplanned outage not reflected in the guidance?

I think you're asking about the -- are you referring to on page 4 the $0.07 charge -- or the negative impact there? Is that what you're referring to? In general, that is a net number, by the way. Just to kind of cut to the chase. That is a net number, reflecting the benefit that we picked up of no scheduled refueling outage in 2006, offset in part by the unscheduled outage earlier in the year.

Paul Ridzon, KeyBanc

I'll try asking it another way. Got the $0.34 incremental fuel drag. That's -- that's incremental. Can you kind of outline what you think the absolute under-recovery in Missouri is for the back half of '07?

Well, for the back half of '07, it's impossible to say whether there would be any under-recovery in Missouri, depending upon the outcome of the rate case. Again, we simply -- there's some component of that $100 million -- $103 million rate case, which is effective June 1st, which will, I'm sure, reflect some level, if not all of those fuel costs. Again, it's just an arbitrary midpoint. And it could be -- may not be any lag at all in the second half of the year. And if there's a fuel adjustment clause, there should be no lag at all related to the second half of the year.

Paul Patterson, Glenrock Associates.

Yes, the plant maintenance -- can you hear me?

Yes.

The plant maintenance in 2007 of $0.11, is that showing up again in 2008? Or should we expect that to sort of go away?

I think it'd be premature to speculate just exactly what our level of plant maintenance would be in 2008. Certainly, we're making extensive -- or having extensive outages and maintenance this year, and much of it is in our non-rate-regulated operations to improve the overall plant operations. We, as Gary mentioned, we have a plan to continue to improve those operations. And to do so, you have to invest in those plants. And that's what we're doing this year to continue to drive those capacity factors and equivalent availability factors up in the future.

Management, there are no further questions at this time. Please continue with any closing comments.

Great. We certainly thank you all for participating in this call. Let me remind you again that this call is available through February 22nd on play back, and for one year on our website. The announcement carries instructions on listening to the play back. You can also call the contacts listed on our news release. For those on the call who are financial analysts, please call Bruce Steinke or Theresa Nistendirk. Media should call Tim Fox. Contact numbers are on the news release. Again, thanks for dialing in.

Thank you. Ladies and gentlemen, this does conclude the Ameren Corporation 2006 earnings and 2007 earnings guidance conference call. You may now disconnect. Thank you for using ACT Conferencing. Have a very pleasant day.