阿莫林 (AEE) 2007 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. And welcome to the Ameren Corporation 2007 fourth quarter earnings call. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded, Thursday, February 14, 2008. I would now like to turn the call over to Bruce Steinke, Vice President and Controller. Please go ahead, sir.

Good morning everyone. I am Bruce Steinke, Vice President and Controller of Ameren Corporation and Head of Investor Relations. On the call with me today is our Chairman, President and Chief Executive Officer, Gary Rainwater; our Executive Vice President and Chief Financial Officer, Warner Baxter; our Senior Vice President and Chief Accounting Officer, Marty Lyons, and other members of the Ameren management team.

Before we begin, let me cover a few administrative details. This call will be available by telephone for one week to anyone who wishes to head us by dialing a playback number. The announcement you received and our news release carry instructions on replaying the call by telephone.

This call is also being broadcast live on the Internet, and the webcast will be available for one year on our website, www.Ameren.com. This call contains time sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited.

I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated in the forward-looking statements.

For additional information concerning these factors we ask you to read the forward-looking statement section in the news release we issued today and the forward-looking statements and risk factors section in our periodic filings with the SEC.

To assist in our call this morning we have posted a presentation on our website that includes a slide that reconciles our earnings per share for the fourth quarter and full year 2007 to our earnings per share for the fourth quarter and full year 2006 on a comparable share basis. And a slide that compares our full year 2008 earnings per share guidance to full year 2007 earnings per share guidance -- earnings per share, again on a comparable share basis.

To access this presentation you may look in the Investor section of our website under Presentations or follow links for the webcast.

Gary will begin this call with an overview of 2007 and a discussion of key operating and regulatory matters. Warner will then follow with a discussion of our 2007 results and 2008 earnings guidance. We will then open up the call for questions. Here is Gary.

Good morning and thank you for joining us. This morning we are pleased to report earnings for the fourth quarter and full year 2007 which, after adjusting for unusual items, are in line with our original and revised earnings guidance ranges for 2007. We also reaffirmed the 2008 earnings guidance that we first provided last month. Warner will discuss these items with you in more detail in a moment.

I will begin my discussion with an overview of 2007. In 2007 we accomplished some key objectives that we believe will bring significant long-term benefits to our customers and stockholders. In Illinois we reached a comprehensive settlement that will help our customers transition to new electric rates and bring stability to the power procurement process.

Rate freeze or roll back legislation in response to higher electric rates in Illinois, driven by deregulation of that market, would have had severe negative operational and financial consequences for our Company, as well as significantly impacted our ability to deliver reliable service to our customers. Major stakeholders involved with this issue agreed to the comprehensive Illinois electric settlement. Those stakeholders included the Illinois Governor's Office, the Illinois Senate and House leadership, and the Illinois Attorney General's Office. And as result, this settlement provides significantly greater levels of legislative, regulatory and legal certainty. It also enables a viable competitive power supply market to continue to develop in Illinois.

In addition, the settlement eliminates a significant distraction to our Company, and will allow us to focus on implementing our business strategies of delivering excellent service to our customers and strong returns for our shareholders.

In Missouri we were able to settle all state and federal issues associated with the 2005 Taum Sauk Plant reservoir breach. We have begun rebuilding the upper reservoir at that pumped storage hydroelectric plant. The cost of the rebuild is expected to be in the range of $450 million. And the rebuild project is expected to serve as an engine for economic growth of Southeast Missouri. Completion is scheduled for the fall of 2009. We continue to believe that substantially all damages and liabilities caused by the breach, including the cost of the rebuild, will be covered by insurance.

In both Missouri and Illinois in 2007 we significantly increased our investments in our energy infrastructure to deliver the reliable energy and cleaner air our customers and communities expect. As we discussed at our analyst day in January, these and future investments are expected to significantly contribute to long-term earnings growth in our regulated business.

However, in the near-term our returns in 2007 and expected returns in 2008 in our regulated Missouri and Illinois businesses are below levels allowed by the respective State Utility Commissions in our last rate cases. That is due to the fact that our current rates are significantly below the cost and investment levels we're facing in our businesses today. As we have discussed with you in the past, in a rising cost environment earnings will be negatively impacted due to the regulatory lag until appropriate levels of rate relief are granted.

As a result, in late 2007 we filed for an aggregate $247 million electric and gas rate increase in Illinois. We also expect to file an electric rate increase request in Missouri in the second quarter of 2008 to mitigate these higher costs and investment levels.

The request filed with the Illinois Commerce Commission were for an aggregate $180 million increase in electric and an aggregate $67 million increase in gas rates. We recognize that our Illinois electric customers have experienced sizable rate increases over the past year, primarily because of higher power supply costs on which our utilities do not make a profit. We're sensitive to this issue, and during settlement talks with stakeholders last summer we pledged to keep the overall annual residential electric bill increases in Illinois to less than 10% in the first year of for each utility's residential customers. Our Illinois electric rate filings fulfill that promise.

We have also requested rate adjustment mechanisms for bad debt expenses and certain electric infrastructure investments. In addition, we have requested the decoupling of the collection of revenues for fixed natural gas delivery costs from sales volumes to assure we do not over or under collect delivery service revenues. The staff and intervener testimony is due in this case in mid-March, and a decision is expected from the Illinois Commerce Commission in September.

Constructive outcomes for the rate cases in Illinois and Missouri are very important to our regulated utility businesses. We need to recover our costs to continue investing in energy infrastructure on a timely basis and provide our customers with safe and reliable service.

On the Missouri side, last week AmerenUE filed an integrated resource plan with the Missouri Public Service Commission. This plan was put together with significant stakeholder input from representatives of organizations that include consumer advocates, those who represent low income customers, advocates for large business interests, environmental groups and officials from the Missouri Department of Natural Resources, the Office of Public Counsel, and the Missouri Public Service Commission staff. The integrated resource plan outlines support for energy efficiency measures to reduce demand growth, expand renewable generation, and increase existing power plant efficiency. Some of UE's coal fired power plants are also aging, and an analysis will be completed in 2009 to determine which units are likely candidates for retirement.

The integrated resource plan concludes that a new baseload plant is expected to be required in our regulated Missouri operations in 2018 to 2020 timeframe. For that reason we're preserving the option to develop additional nuclear generation, while researching clean coal and carbon sequestration technologies. This year we expect to file a construction and operating license application with the Nuclear Regulatory Commission for a new unit at AmerenUE's Callaway Nuclear Plant site. While this filing does not represent a final decision, it preserves the option to build a nuclear unit.

As we have stated in the past, we will not proceed with any new baseload power plant without construction cost being allowed in the rate base in Missouri. In addition to considering a new unit at Callaway, we also began the process this year to extend through 2044 the existing unit license at Callaway, which currently expires in 2024. The Missouri Public Service Commission has scheduled a prehearing conference on the IRP to set a procedural schedule.

In our nonrate regulated generation operations we continued in 2007 to execute our plan for investing in our power plants to improve their future productivity, as well as to effectively market our generation, consistent with our risk management framework. We have also begun major work on some of our coal fired plants to begin installing additional environmental controls.

I believe our accomplishments in 2007 position us well to execute on the business strategies we outlined for you in January at our analyst day. We firmly believe the execution of these strategies will deliver strong earnings growth and solid risk-adjusted returns in the future. That growth will come primarily from our regulated businesses. Growth in our regulated businesses will be driven by significantly higher investment levels to improve the reliability of our distribution systems and to comply with environmental regulations to produce cleaner air. These investments by consistent with our customers' and regulators' expectations.

In addition, growth in our regulated businesses will come from updating our current rates to better reflect the current levels of cost and investments we're experiencing in these businesses. Today we are earning substandard returns on our regulated businesses due to the regulatory lag. Our plan to address this shortfall and to achieve growth is very straightforward. We will file more frequent rate cases, requesting moderate rate increases, as well as seek appropriate cost recovery mechanisms to mitigate regulatory lag.

In addition, we will continue to optimize our nonrate regulated generation assets, focusing on improving our plants' output and related energy marketing. By 2010 we expect our nonrate regulated baseload plant output to increase approximately 10% over 2007 levels to nearly 33 million megawatt hours.

While we currently believe that rising costs, including fuel, depreciation and financing costs, will largely offset these productivity gains, we believe our plants will be well-positioned for earnings growth in the future should energy and capacity prices improve, consistent with the market fundamentals we discussed with you in January.

The bottom line is that we anticipate average earnings per share growth on the order of 4% to 6% per year through 2010 from a normalized 2007 base, with earnings of approximately $3.70 per share by 2010. By 2011 we expect to be able to achieve earnings of about $4 per share and higher in 2012. While our earnings per share growth will not be linear from our normalized 2007 base, that is due to the impact of regulatory lag and making upgrades at our nonrate regulated power plants, we are confident we can deliver these results by the end of 2010. In addition, we're still dedicated to providing a strong, sustainable dividend and are focused on setting a foundation for future dividend growth. We believe the business strategy to achieve these goals is proven and lower risk and that we will be successful.

I will now turn it over to Warner to walk you through our 2007 earnings and 2008 earnings guidance.

I would now like to refer you to the slide presentation on our website as I provide a more detailed discussion of our 2007 earnings. This presentation reconciles our earnings per share for the fourth quarter and full year 2007 to our earnings per share for the fourth quarter and full year 2006, on a comparable share basis. In addition, this presentation includes a slide that compares our 2008 GAAP and non-GAAP earnings per share guidance to full year 2007 GAAP and non-GAAP earnings per share on a comparable share basis.

Turning first to our 2007 earnings reconciliation on page 3 of our presentation. Today we announced 2007 GAAP net income of $618 million or $2.98 per share, compared to 2006 GAAP net income of $547 million or $2.66 per share. Excluding unusual items in each year, Ameren recorded 2007 non-GAAP net income of $690 million, or $3.34 per share, compared to 2006 non-GAAP net income of $599 million or $2.92 per share. Ameren recorded GAAP net income of $108 million or $0.52 per share for the fourth quarter of 2007, compared to $61 million or $0.30 per share for the fourth quarter of 2006.

Excluding unusual items in the fourth quarter of each year, Ameren recorded 2007 non-GAAP net income of $123 million or $0.61 per share, compared to 2006 non-GAAP net income of $89 million or $0.43 per share. Both 2006 and 2007 included several unusual items. The net cost of the 2007 Illinois comprehensive electric settlement reduced fourth quarter 2007 earnings by $0.08 per share and full year earnings per share by $0.21.

In 2007 a Federal Energy Regulatory Commission order retroactively adjusting prior year's regional transmission organization costs reduced fourth quarter earnings by $0.01 per share and full year 2007 earnings by $0.06 per share.

In 2006 restoration efforts associated with severe storms reduced net income by $0.13 per share in the fourth quarter and $0.26 per share for the year. The impact of storm restoration efforts was less in 2007, but still significant. Costs associated with severe storms in 2007 reduced full year earnings per share by $0.09 per share. I will note that we are seeking deferral and recovery of the 2007 storm costs from the Missouri Public Service Commission. We expect a decision from the Commission later this year.

Non-GAAP earnings in 2007 principally benefited from higher priced power sales contracts in our nonrate regulated generation business segments, the June 2007 implementation of the Missouri electric rate order, and greater demand for electricity and natural gas caused by warmer summer and cooler winter weather than in 2006. Reducing the benefit of these positive items were, among other things, higher operating expenses including fuel costs, lower emission allowance sales, increased expenditures to improve reliability in our regulated business segments, and higher depreciation and financing costs due to greater energy infrastructure investments.

More specifically, in 2007 Illinois regulated business segment margins were $0.07 per share lower than 2006. This was due primarily to the move from a bundled to an unbundled electric delivery service rate structure.

Another change in our electric rate structure in Illinois had a more significant impact on the fourth quarter of 2007. Prior to 2007 our Illinois residential electric rates were designed to be lower during the winter heating periods and higher during the summer cooling periods. Throughout 2007 we have been billing electric sales based on rates designed to be the same throughout the year. As a result, fourth quarter 2007 earnings were $0.14 per share higher than the prior year period. As we provided for you at our analyst day, this allocation of revenues among quarters will change again in 2008 due to an Illinois Commerce Commission order.

The results of the Missouri electric and gas rate case added $0.08 per share to earnings in the fourth quarter and $0.21 per share for the full year 2007 compared to the year ago period. This includes the benefit of higher electric and gas rates, lower depreciation and decreased taxes pursuant to the Missouri Public Service Commission electric and gas rate orders effective in June and April 2007, respectively.

Other electric margins increased $0.48 per share in the fourth quarter and $1.46 per share for the full year 2007, primarily as result of the higher sales prices for the output of our nonrate regulated generation fleet.

Higher costs for fuel and related transportation, primarily in our Missouri regulated operations, reduced electric margins by approximately $0.08 per share in the fourth quarter and $0.31 per share for all of 2007 compared to the year ago period.

Favorable weather, primarily in the summer, drove full year 2007 margins higher by $0.14 per share versus the prior year, and $0.10 per share versus normal weather conditions. Cooling degree days increased 19% in 2007 compared to 2006, and were 37% above normal. Heating degree days were 8% above 2006, but 10% below normal.

The scheduled Callaway Nuclear Plant refueling and maintenance outage reduced full year 2007 earnings by $0.09 per share compared to 2006 when there was no scheduled outage.

Labor and benefit costs increased $0.06 per share in the fourth quarter of 2007 and $0.18 per share for the full year 2007 versus 2006. Increased expenditures for distribution system reliability and maintenance reduced earnings by $0.09 per share in the fourth quarter and $0.15 per share for all of 2007 compared to the year ago periods, as we began to make significant incremental investments to improve reliability and customer satisfaction.

Depreciation and amortization expenses were $0.13 per share higher in 2007 than in 2006, primarily because of increased capital additions and amortization of a regulatory asset associated with the recovery of Ameren IP acquisition integration costs, which began in January of 2007.

Dilution and financing costs reduced fourth quarter 2007 earnings by $0.04 and full year 2007 earnings by $0.17 versus 2006. Dilution and financing costs in 2007 were higher than the year ago period as a result of continued funding of energy infrastructure and power generation investments, whilst higher borrowing costs resulting from credit rating downgrades. These downgrades were largely associated with the legislative uncertainties in Illinois.

Reduced costs associated with the 2005 Taum Sauk Plant upper reservoir breach improved 2007 earnings by $0.15 per share relative to last year, and $0.04 in the fourth quarter. Increased emission allowance sales also reduced earnings by $0.09 per share in the fourth quarter and $0.16 per share for all of 2007 compared to the prior year periods. We also did not benefit in the fourth quarter of 2007 from a $0.15 per share gain on the sale of noncore properties, principally leveraged leases, as we did in the 2006 period.

Moving on to 2008 and slide 4, as Gary noted earlier, and as we stated in our news release this morning, we reaffirmed that we expect 2008 GAAP earnings to be in the range of $2.68 to $3.08 per share and non-GAAP earnings to be in the range of $2.80 to $3.20 per share. The $0.12 per share differences between GAAP and non-GAAP guidance is because of the estimated negative impact in 2008 on GAAP earnings for the 2007 comprehensive electric settlement agreement among parties in Illinois. We also reaffirmed this morning the expected contributions from our three business segments as shown on slide 5.

The 2008 earnings guidance range and expected segment contribution ranges are consistent with those that we provided to you at our analyst day in January. Similarly, the reconciliation of 2008 earnings guidance to 2007 actual earnings is largely consistent with the reconciliation we provided at the analyst day. As a result, I do not plan on going through our 2008 earnings guidance reconciliation again in detail.

Ameren's guidance for 2008 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 or referred to in the forward-looking statements section of our press release.

To close, as we look beyond 2008, not only do we believe that there is strong, underlying value of our enterprise, but as Gary noted earlier, and as we discussed at our analyst day, we're convinced we have a very straightforward and executable strategy to deliver strong earnings for 2010 and beyond.

That strategy consists of updating our rates to reflect more current cost levels and earning fair returns on incremental investments desired by our customers and regulators in our regulated businesses. It also requires optimizing our existing nonrate regulated generation assets and positioning them for potential energy market improvements. While we know execution of this strategy will not be a simple lay up, we strongly believe it is a strategy consistent with our business strengths and one that will bring superior long-term value to you, our shareholders.

This completes my prepared remarks. We will now be happy to take your questions.

(OPERATOR INSTRUCTIONS). Daniele Seitz, Dahlman Rose.

You mentioned that your ROE was way below where it should be. Could you give us some details on the different sections of the operations and what type of ROE are you experiencing?

This is Warner. With regard to our Illinois regulated segments, we are earning in 2007 an ROE of approximately 5%, and expect that ROE to be consistent in 2008. That is around 5%. Remember that our allowed ROE in Illinois is 10% for both our electric and gas operations.

And you are expecting a rate increase in September?

We are expecting to hear from the Illinois Commerce Commission in September, with any rate increase effective in the fourth quarter of this year. In Missouri we earned approximately 9% ROE in 2007, and our expected ROE in 2008, we discussed at analyst day, is expected to approximate a 7% ROE. In our electric operations in Missouri our allowed ROE was 10.2% in our last rate case, and our gas operations were approximately 10%.

In terms of your coal prices it seems that looking at the charts that coal prices in Missouri were particularly -- rose about 28% during the quarter. What do you visualize in terms of regulated recovery? Because it seems that there is a -- I thought you are going to be almost caught up for 2007 and it seems that there is still some delay.

A couple of things to keep in mind is we did point out that in 2007 we expect fuel costs to increase, and frankly we expect continued increases in our fuel costs in our Missouri regulated operations and even in our nonrate regulated operations in the future. Between 2007 and 2008 we expect the fuel costs to rise approximately 10% in our regulated operations and approximately 14% in nonrate regulated.

In terms of the Missouri regulated operations, as you know, we filed for a fuel adjustment clause recovery mechanism in our last rate case. That was denied. But the Missouri Public Service Commission did state that we could come back in and seek another fuel adjustment clause. And in fact, as we file this next rate case here in the second quarter of this year, we expect to file for a fuel cost recovery mechanism in that case with the objective to mitigate these cost increases, which will continue to meaningfully increase in the future.

Ashar Khan, S.A.C. Capital Management.

I just wanted to get your views -- I guess we have had on the Illinois side, we have got a staff recommendation for ConEd. And then the Integrys case, I guess they denied the rider mechanism for future improvements. I'm just trying to base on those two data points, which we didn't have when you are in New York, which have occurred, I wanted to get your thought process regarding the Illinois case.

As you know, the ruling just came out on the Commonwealth Edison case the day before. But as Scott Cisel articulated and Gary and myself throughout the presentation at the analyst days, that we feel confident that we will be treated fairly in this upcoming rate case in Illinois because we are simply looking to update our rates to reflect the more current cost levels that we are experiencing in our business, coupled with seeking recovery of the investments that we are making for reliability in our business, which are consistent with both customers' and regulators' expectations.

When you look at the data points that you described, from our quick read of the Commonwealth Edison case, the staff has recommended a return on equity of approximately -- I believe 10.3%. I believe as part of their case they requested a 10.75% increase.

But also we are aware from our quick read of it that the staff, in terms of what their recommendation was for a rate increase versus what Commonwealth Edison was seeking, one of the major areas of disputes appear to be associated with incremental rate base additions that were taking place outside of the test year in their particular case.

In our case, as filed, we have not sought any incremental rate base additions beyond those which are in our existing test year. So as we look at -- so the staff's recommendation there are some differences between obviously the two cases in terms of how they were originally filed, but the bottom line is we still feel strongly in terms of our fair treatment prospectively in the state of Illinois.

Warner is it safe to say that a rider mechanism may not get past because it didn't past in the gas case?

It is impossible to speculate. I won't try to speculate in terms of what their specific provisions were versus what ours are. But we feel that we have put together a very strong case to support all the rider mechanisms that we are seeking. And so we look forward to presenting our case to the Illinois Commerce Commission here in the next several months.

If I can just end up with, Warner, could you just tell us a little bit, if you can remind us, what is the change in the auction process going to be, first with the current RFPs and what the Illinois Power Authority is going to do later on, in terms of what kind of product is going to come to market, what are going to be the risks to the utility and not to the utility? Could you just take us a little bit through into the difference in the auction processes from the last one to the current one and to the one contemplated with the Illinois Power Authority, please?

Let me try -- and that is a multiphase question. In terms of the existing -- for the auction process that we're going through in 2008 and one that we will utilize in 2009, one of the primary differences between those two options is that in 2008 this is one basically where the utilities are going to basically run that existing auction process.

As you know, the Illinois Power Agency is going to come into place in 2009. So we have submitted an RFP plan to the Illinois Commerce Commission that has been approved by the Illinois Commerce Commission for 2008, which we obviously do not have a great number of megawatt hours that we still need to hedge. But nonetheless, that has been approved and we're going through the RFP process as we stand today. Once that process is completed, we will present our results to the Illinois Commerce Commission. And upon their approval we will simply execute those contracts and pass those costs through to our customers because we have a mechanism to do so.

And that is for peak load as well as it is for the remaining '08 load and '09 load, Warner? Am I right?

I'm sorry. Say that began.

That is for peak load as well -- that is for the whole full requirements load, and it goes for '08 and '09? Is that right?

The period that they are looking forward to fill in is for some '08 and '09. It does -- it is from June through July of the following period. Excuse me, June through May. Then in 2009, keep in mind that is the Illinois Power Agency will play more integral role in that process. And frankly it is premature to say just exactly how that will play out, but certainly part of that process is that we will submit data to the Illinois Power Agency, including our low profiles, and as well as work with them in terms of setting up a procurement process with not just the agency, but also a third-party administrator that they will utilize as part of that process.

But our view it then once we go through that process and once an RFP type of process is settled upon, that too the Illinois Commerce Commission will continue to play an integral role. We will present the process to them, as well as the results of the procurement process. And then upon their approval then those purchases are deemed prudent by the Illinois Commerce Commission. So therefore the risk for our Illinois regulated entity in terms of the procurement, or not being able to recover those incremental procurement dollars, is frankly the same as that we have had in the past, in that there were past through mechanisms to our customers.

Warner, so we, sitting from here should not expect that though the auction process is changing in terms of whose implementing it and how it is being implemented, that the pricing should follow the same pattern that it followed in the previous auction. That there will be a base price and the full requirement price will be a premium to that price. And those premiums should be somewhat similar to what was in the last auction. I'm trying to understand. There is nothing fundamentally changing in terms of which will play a role in changing the way the different components are valued in the market?

This is Gary. There is one thing that is a fundamental change in that with the auction -- and you keep referring to the auction, the auction is no longer there. We don't even use the term auction anymore. But in the auction utilities -- or the power companies bid on a load following product, which means that the power companies took the risks of weather variation and load and any other kind of variation in load, and assumed the cost of following the load.

The difference in the RFP process, which we're adopting now, is that the utility company will not buy load following products, it will buy blocks of power and build up those blocks of power to essentially provide the load following on its own.

There is a shift in risk, and because of a shift in risk you would expect somewhat of a shift in price as well. Pricing blocks of known amounts of power, those will be priced differently than the unknown load fluctuations that the power companies had to account for before.

But the point Warner made is that when you get down to utility level, the basic concept is that utility customers pay for whatever the price of power is. The utility stockholders do not make any profit on power, and therefore do not take on any of the risk of the power supply.

Paul Ridzon, KeyBanc.

It was my understanding that you had Missouri legislation that allowed a fuel clause. Could the Commission deny it again?

With regard to your question, it is SB 179. That is legislation, which does give the Commission the option to implement a fuel adjustment mechanism. We have to do that in connection with the rate case. So, yes, the Commission has the ability to review the facts or circumstances of our case and decide whether we qualify, or they believe it is appropriate for us to have a fuel adjustment clause. The long-winded answer is, yes, they could look at the fact and circumstances and deny our fuel adjustment clause again. Although we feel, again as we said in January at our analyst day and Tom Voss spoke directly to this particular issue, we feel confident that because of the nature of our costs, as well as the importance to the enterprise that we will get a fuel adjustment clause in this next rate case.

What was weather year-over-year and then year versus normal?

Year-over-year on a net basis weather had a $0.10 cent per share impact. And then that is compared -- excuse me, that is compared to normal. Year-over-year there is about a $0.14 per share impact.

Both positive?

Excuse me?

Both positive?

Yes.

When you gave your ROEs at the utilities did you whether norm those, or is that absolute?

No, the ROEs that I provided to you excluded the unusual items. They were sort of the non-GAAP, but they did not affect -- they were not adjusted for weather.

So they are even worse then?

If you take out the impacts of weather, then certainly on the Missouri side they benefited more from weather. I would say in the Illinois regulated business, the electric piece of weather was not a significant variable. They are obviously driven a little more by the gas business in terms of the variations.

You kind of -- you hit the top end of your guidance. What were the big drivers of getting there versus, I guess, we would assume that you were thinking midpoint?

I think when you look at -- we updated our guidance in January from a non-GAAP basis to be $3.25 to $3.35 per share. Now we are within the range. Sometimes it is a timing of certain expenditures coming into play. Then of course, as you looked at some of the sales that we were able to make towards the end of the year they were a little bit better perhaps than we had thought. But nothing major I would say that sort of drove that $0.03 or $0.04 per share difference, frankly.

Did you have EA sales in the year, and what were those?

I'm sorry, say it again?

Emission allowances.

Did we have emission allowances sales?

In the fourth quarter and the year.

Yes, we did have some emission allowance sales throughout the year. If you looking at the fourth quarter in particular?

Both.

For the year we had emission allowance sales of about $7.5 million to $8 million for the year for 2007. Obviously we had significantly greater levels of emission allowance sales in both the regulated and unregulated side in 2006. And when you look at our reconciliation, you see that as one of the significant differences between the two years.

Did you have any in 4Q?

I'm sorry?

Did you have any in 4Q?

We had less than $1 million.

Was it after-tax?

No, pretax.

Michael Lapides, Goldman Sachs.

Two questions, a little bit and related. First question, short-term debt at the end of fourth quarter '06, and just short-term, not even the currently maturing long-term, is up about $300 million from third quarter -- I mean, third quarter '07 to fourth quarter '07 is up about $300 million and the total is about $1.5 billion. That is a huge increase from the year ago period as well. Can you talk about plans for dealing with the short-term debt? That is first question.

The second question is, can you talk about on the non-regulated side which plants are having scrubber insulations over the next few years, and if there's any information regarding timing?

I will handle the short-term debt, and then Gary can comment a little bit on the environmental piece. But on the short-term debt, it did increase I guess from Q3 to Q4, but I think you have to look at our net cash position too. We were sitting on about $300 million or so of cash at the end of year. I think when you look from Q3 to Q4, our net short-term debt, net of cash, was perhaps maybe about $100 million.

So bottom line a lot of that is a little bit choppy. In terms of what we typically do is we build up our short-term debt, and then we go out into the marketplace and term that out with the issuance of long-term debt. We plan on executing this strategy throughout 2008 whereby we will be very active in the capital markets terming out that short-term debt with long-term debt instruments for both our regulated and unregulated operations. I will Gary comment on the environmental piece.

On the scrubbers on the non-reg business, we have construction going on now for two plants. At our Duck Creek Plant we are installing a single scrubber, which should be online by the end of this year. And at our Coffeen Plant -- that is a two unit plant -- we are building two scrubbers that will be online by the end of '09.

And for the longer-term, and I don't recall which units specifically are getting scrubbers, but basically all of our large units, which would include two units at Newton. It includes about four units of the six units at our Joppa Power Plant and those will be installed. Edwards as well, one or two units at Edwards. And those are installed over about a four or a five year period.

Got it. Is there a timing known for Newton, Edwards and Joppa?

I don't have the schedule in front of me, but not in the next two years, but I would say to two to five years.

We can get that information to you, Mike. We will get that back to you.

That would be great. Just one question, how when you think about what it does in the year of installation to the capacity factor of the plant, is it done during a normal maintenance outage? Does it extend the maintenance outage? Just trying to get our arms around that.

It will reduce the capacity factor and reduce the availability. And I can't give you an exact number, but it extends the outage. And then there's always the possibility that on startup there could be startup delays. So we have factored that into our expectations though, and we still predict over the next couple of years increasing baseload generation from these plants by about 10%, from roughly 30 million megawatt hours to 33 million megawatt hours. In '08 and '09 it will have a negative impact.

I want to make sure I understand. In '08 and '09 it has a negative impact because Duck Creek and Coffeen. Then sometime after '09, Newton, Edwards and Joppa have the same thing happen. How do you get to the $33 million before you're done with all five plants?

It is partly due to the fact that the historical performance hasn't been that good. If you look at the availability of those plants just in the last year it was at 81% for our non-regulated generation versus about 89% for the regulated generation, which isn't going through these kinds of outages. We aren't predicting to get it up to 90% by 2010, but we should improve it to something on the order of 85% by then. If we look a little longer by the time that we get through the Newton, Edwards and Joppa installations we would expect the performance of those units to be more like 90% availability and the capacity factor to be even higher.

Reza Hatefi, Polygon Investments.

Could you discuss a little bit about coal markets? I guess going back to your January slides you guys showed your hedges through 2010, and specifically the non-regulated $23 per megawatt hour for 2010, only 16% hedged. How does that relate to how the coal markets have moved in recent weeks? And what do you think about the future of coal prices, etc.?

This is Warner. In terms of coal prices certainly we have seen here in recent weeks some pressure on coal prices. The spot market rate has probably risen a $1 or $2 here over the last month or two as a result of many things that you read in terms of the overall demand for coal. But keep in mind, we saw similar types of increases two or three years ago where the coal prices went through the roof because of particular demand. The other thing to keep in mind is you can't just look at the spot market rates and suggest that they too will be what you enter into for long-term contracts.

The bottom line is we are seeing some of those increases in prices. Obviously, we continue to go through our hedging strategy, whereby generally around 20% per year of our coal contracts typically roll off since they are typically anywhere from four to five year types contracts.

So when you look out there in 2010, obviously we're not hedged as much. But of course we factored in some of our thinking what marketplace observations that we had at the time and what we expected then to take place prospectively. I wouldn't suggest that it was sort of a spot market rate that we took into consideration when we put together our guidance. Of course the other piece that drives that isn't just the coal prices, but also the transportation piece, and that too is in fact is a major driver as other -- as anything in terms of the increases in our coal costs prospectively.

Could remind us after the '09 scrubbers come on, and then going forward when the Newton, Edwards and the other scrubbers also come on, is there going to be a shift from PRB to some other kind of coal? Because I guess right now you're 90% PRB, if I'm not mistaken?

There won't necessarily be a shift from PRB to Illinois coal, it will depend on the economics, but we are planning to create some flexibility. We're installing mostly wet scrubbers. In scrubber technology you've got two choices, dry scrubbers, which are a little less capital investment. Wet scrubbers are little more capital investment. Dry scrubbers really don't have the flexibility to scrub either Powder River or Illinois coal, but the wet scrubbers do. We will be sure that we provide that flexibility, given how the market has changed, and we might switch back to Illinois coals in the future.

Your 2011 guidance of $4 or roundabouts, are you assuming that you're trending or you're at somewhat of a -- you're earning basically around your allowed ROE or a fair ROE, or is there still an under-earnings going on even with that nice guidance?

With regard to 2011, of course you know we didn't give that level of detail in terms of what our expectations were prospectively. But what we did say in January is that we did expect regulatory lag to persist as long as there is this rising cost environment.

But having said that, we do expect to meaningfully decrease the level of regulatory lag that we are experiencing today through the frequent levels of rate cases that we will continue to see, coupled with the cost recovery mechanisms that we're going to be seeking in both Missouri and Illinois, whether it be fuel, environmental or infrastructure investment. All those items will meaningfully impact the difference between our allowed return on equity and what our actual returns on equities are.

So we expect those to certainly be meaningfully declined. In terms of specifics, in terms of what we're expecting out in the future years, we haven't provided that level of detail out there in 2011.

[Steven Gambuzza], Longbow Capital.

I was wondering if you could let us know if you have any expectations for what the increased operation and maintenance expense is associated with operating a scrubber in terms of the rule of thumb for dollar per megawatt hour variable, or the fixed cost per KW. Is there any kind of rule of thumb or expectation you have in terms of the operating cost of these equipment?

The only numbers that I can recall, and I will give you the sort short answer to your question first, because I don't have a good number to give you. But as far as capital cost in the past we have worked with numbers around $300 per kilowatt. And I know those numbers are under pressure just because of the shortage of construction forces out there. They rising, but I don't know exactly what the new number is. As far as cost per megawatt hour, why don't we try to get you a number, because I don't have one off the top of my head.

You talked about your scrubber plans. I was wondering if you have -- if you could give us a rundown also in terms of SCRs, if you plan on installing any SCRs at your unregulated units?

I don't recall which units are getting SCRs. I know that we already -- we've installed SCRs already on our Coffeen units. And I think that those are the only ones that we've installed.

You asked -- did you ask about the regulated units?

No, just the unregulated units.

That's what I thought. That is what I -- that was just clarification. So Gary was addressing that.

Bruce is trying to find some information there.

In terms of in the analyst book you had disclosed your contracted position for the unregulated coal requirements. I was just wondering how aggressively you are seeking to close that uncontracted position, which you identified in the 2011 timeframe. Do you have an objective as to how hedged for 2011 you would like to be by the end of 2008 per se?

Typically -- this is Warner. In terms of the -- again, there are two pieces to it. There is coal and transportation. And typically what we have historically seen for the coal contracts are anywhere from four to five year types of contracts. Transportation, we try to link them up as closely as we can to the coal contracts in terms of tenure, but they're more plant specific and oftentimes do not have the same exact duration.

As we look out, and especially in the '09, '10 timeframes, obviously we have -- coal is better hedged in some of our transportation contracts. So as I said at the analyst day, we were actively seeking to shore up especially the transportation contracts of those open power plants, especially on our unregulated generation business.

With the coal contracts we systematically go through a period where we will hedge some of those open positions. I would call it sort of a dollar cost averaging. We don't try and be market timers, frankly. We get out there. We're in constant contact with our suppliers, both on the rail side as well as the commodity side. And so it is almost an ongoing process throughout the year that we're engaging in discussions with these folks.

And so there are -- we're not putting the petal to the metal today anymore differently than we would in January, February, March of any other year. We just take that type of approach to our hedging position.

Then finally, as you have done on prior calls, I was wondering if you might be able to provide the 2007 net income by reporting entity for the Illinois regulated and unregulated segments?

I will give those to you for the 2007 on the reporting entities?

Yes.

For Union Electric that is $336 million, for CIPS was $14 million, for Genco it was $128 million, for CILCORP it was $46 million, our IP was at $24 million. Those are the reporting entities.

And EI?

EEI is a component of UE.

Yiktat Fung, Zimmer Lucas Partners.

Can you please just give us an update on getting the environmental recovery rider in Missouri? For example, has the rules with that been set, and will you be applying for that this in this upcoming rate case?

Sure. As we discussed at the analyst day, we expect the rules, a lot more clarity around the rules. Sometime we think by the end of the first quarter of this year we will be able to see that the rules -- the final set of those rules sometime early in the second. So as we approach our rate case in Missouri, we will have visibility to those rules when we expect to file that here in the second quarter. We would expect to seek an environmental cost recovery mechanism in our next rate case.

Thank you very much.

To come back quickly to the question on the SCRs, here is the data for you. We have already installed one SCR unit at our Edwards plant, one at our Duck Creek Plant, two at our Coffeen plant. And there are no current plans to do more than that in the unregulated generation business. I think for the other plants we are reducing NOx primarily with low NOx burners and with tuning technology that tunes the plants for NOx emissions.

Gregg Orrill, Lehman Brothers.

I was wondering if you could remind me of the context around Missouri declining the fuel recovery clause previously?

Obviously, the Commission spoke in their order and addressed the rationale behind that. Some of the rationale included what they deemed to be the volatility of our fuel costs. But I think the other thing that you need to look at when me approached our last rate case in terms of the fuel cost recovery mechanism, that case was very complicated. It had several complicated issues in terms of trying to determine what an appropriate level of not just fuel cost would be, but also off system sales. Those issues, if you recall, related to the joint dispatch agreement going away. It related to the EE Inc. contract which was at dispute at the time. It related to setting the appropriate market prices for off system sales. And coupled with the fact we were the first utility at that point in time to seek a fuel adjustment mechanism.

So I will won't for the Commission, but certainly as we look at it, those were all issues and factors in the last rate case that had to be determined by the Missouri Public Service Commission.

As we look now going forward to this rate case, the joint dispatch agreement has now been in place and we will have history that we will be able to show in terms of with the impacts of that. The EE Inc. contract was settled in the last rate case in our favor. So we think that the issues surrounding the fuel adjustment clause mechanism for Ameren and UE in this next case will be a simpler exercise for the Commission to review in the case that we will file here in the second quarter.

Daniele Seitz, Dahlman Rose.

I was wondering, you are presenting a lot of distribution system reliability, additional expenses basically in that area. Have all of these programs been already previously authorized by the Commissions, or actually these are just your own planning?

With regard to the incremental expenditures that we're doing on both the capital and O&M side of our business for reliability, certainly both Tom Voss and Scott Cisel and their teams have been in communication with the Commissions and the Commission staff people in terms of what we're doing.

If you recall at the analyst day, Tom Voss went through the Power On program, which has been very visible, not just to the regulators, but also to the community. So we have spoken to them about it. They are supportive of the certainly improving our overall reliability. But to say that they have authorized that and approved (inaudible) of that, that would be premature for us to say that. However, we will seek to recover these incremental costs from these upcoming rate cases. And we do believe it is consistent with both the Commission's expectations, as well as our customers' expectations in this area.

The efficiency and conservation programs that you are proposing, do they come with also some sort of compensation for the Company as well?

Our costs for -- our energy efficiency programs of both Missouri and Illinois are recoverable in rates.

That is already understood. Great. Thank you.

At this time there are no further questions. I would like to turn it back over to management.

We want to thank you all for participating in this call this morning. Let me remind 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 listed on our news release.

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, thank you for dialing in.

Thank you, ladies and gentlemen. That does conclude the Ameren Corporation 2007 fourth quarter earnings call. If you'd like to listen to a replay of today's call, please dial 800-405-2236 or toll 303-590-3000. (OPERATOR INSTRUCTIONS). The pass code for the conference call will be 11108033 followed by the pound sign. (OPERATOR INSTRUCTIONS). You may now disconnect. And thank you for using AT&T Teleconferencing.