Ladies and gentlemen thank you for standing by and welcome to the Ameren Corporation 2007 Fourth Quarter Earnings Call. During today's presentation, all parties are in a listen-only mode. And following today's presentation the conference will be open for question and answers. As a reminder, this conference is being recorded, Thursday, February 14th of 2008. I would now like to turn the call over to Bruce Steinke, Vice President and Controller. Please go ahead, sir.

Thank you, Mike and good morning everyone. I'm 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 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 hear it by dialing a playback number. The announcement you received and our news release carry instructions on replaying the call by telephone. This call is also being broadcast live on the Internet and the webcast will be available for one year on our website, www.ameren.com. This call contains time sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, and financial performance. We caution you that 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 statements 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 on 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 Investors section of our website under presentations, or follow the 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's Gary.

Thanks Bruce. 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 reaffirm that 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 customer and stockholders. In Illinois, we reached a comprehensive settlement that will help our customer's 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 is driven by deregulation of that market, but 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. The stakeholders included the Illinois Governor's office, the Illinois Senate and House leadership and the Illinois Attorney General's office. As a result, the 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 to 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 begun rebuilding the upper reservoir at…

Thanks Gary. I would now like to refer you to the slide presentation on our website, as it provides a more detailed discussion of our 2007 earnings. This presentation reconciles our earnings per share for the fourth quarter and full year 2007 for 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, the full year 2007 GAAP and non-GAAP earnings per share on a comparable share basis. Turning first to our 2007 earnings reconciliation on page three 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 recoded 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 at $0.08 per share and full year earnings per share by $0.21. 2007, a Federal Energy Regulatory Commission order, attractively 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.…

Thank you, sir. [Operator Instructions]. The first question comes from the line of Daniele Seitz with Dahlman Rose. Please go ahead.

Thank you. 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?

Sure, Daniele. This is Warner.

Thanks.

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 about 5%. Remember that our allowed ROE in Illinois is 10% of both our electric and gas operations.

Right. 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 as we have 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 I guess operations were approximately 10%.

And in terms of your coal prices, it seems that the... looking at the chart that coal prices in Missouri were particularly, well was about 28% during the quarter. What do you visualize in terms of a regulated recovery because it seems that there is a I thought you were going to be almost caught up for 2007 and seems that there is still some delay?

A couple things to keep in mind is we did point out that in 2007, we expected fuel cost to increase and frankly, we expect continued increases in our fuel cost and our Missouri regulated operations and even on our non-rate regulated operations in the future. Between 2007 and 2008, we expect fuel cost to rise approximately 10% on our regulated operations, approximately 14% in non-rate regulated. In terms of the Missouri regulated operations, as you know we filed for a fuel adjustment clause, recovery mechanism and our last rate case, that was denied but the Missouri Public Service Commission did state that we can come back and seek another fuel adjustment clause and in fact, as we filed 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 go... meaningfully increase in the future.

Thank you.

You are welcome, Daniele.

Thank you ma'am. The next question comes from the line of Ashar Khan with SAC Capital. Please go ahead sir.

Good morning.

Good morning, Ashar.

I just wanted to get your views, I guess we have had on the Illinois side, we have got a staff recommendation for ComEd and then the Integris case, I guess they denied the rider mechanism for future improvements. And so, I am just trying to based on those two data points which we didn't have when you were in New York, which have occurred, I wanted to get your thought process regarding the Illinois case.

Sure Ashar. As you know the ruling just came out on the Commonwealth Edison case the day before. But as Scott said so articulated and Gary and myself throughout the presentation at the Analyst Day is that we feel confident that we will be treated fairly in this upcoming rate case 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 describe 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 10.7% increase. But also we are aware from our perquisite [ph] is 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 about... beyond those which our in our existing test year. So as we look at sort of 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 the Illinois.

But Warren is it safe to say that the rider mechanism may not get passed, because it didn't get passed on the gas case?

It... Ashar it's 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've 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 Missouri... excuse me the Illinois Commerce Commission here in the next several months.

Thanks. And if I can just end up with one. Could you just tell us a little but if your could remind us what is the change in the auction process going to be, first with the current RFPs and then what Illinois Power Authority is going to do later on. In terms of what kind of product is going to come to the market. What are going to be the risks and to the utility or 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 it. It's a multi-phase question. In terms of the existing... for the auction process that we are going through in 2008 and one that we will utilize in 2009. One of the primary differences between those two auctions 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 the great number of megawatt hours that we still need to hedge. But nonetheless, that has been approved and we are going through the RFP process as we stand today. Once that process is completed we'll 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's for peak load as well as its for the remaining 08 load and 09 load Warner. Am I right?

I am sorry Ashar, say that again.

That is for peak load as well... that's for the whole full requirements load. And it goes for 08 and '09. Am I right?

It's the period that they are looking for to fill in is for some 08 and '09. It does gives from June through the July following period.

Okay.

And then... excuse me June to May. Now then in 2009 keep in mind that that is the... the Illinois Power Agency will play a more integral role in that process. And it's... frankly its premature to say just exactly how that will play out. But certainly prior to 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 this part of that process. But our view is that once we go to 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'll 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 procumbent or if not been able to recover those incremental procurement dollars is frankly the same as that we've had in the past. And that they were to pass through mechanisms to our customers.

Okay. And Warren so we from... sitting from here should not expect that though the auction process is changing in terms of who is implementing and then how it's been 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 it 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?

Ashar, 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. So, 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 in load and any other kind of variation in load and assume 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 falling products, it will buy blocks of power and build up those blocks of power essentially provide the load following on its own. So, there is a shift in risk and because of a shift in risk you would expect a somewhat of a shift in price as well. Pricing blocks of known amounts of power, those will be priced differently than the unknown load fluctuation that the power companies had to account for before. But the point Warner made is that when you get down to the 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 other risk of the power supply.

Okay, I appreciate.

Thank you, sir. The next question comes from the line of Paul Ridzon with Keybanc. Please go ahead.

Good morning, Warner. How are you?

Greetings. How are you today?

Okay. It was my understanding that you had Missouri legislation that allowed a fuel clause; could the commission deny it again?

With regard to... Paul with regard to your question, it has to be 179, that is legislation which does give the commission the option to implement a fuel adjustment mechanism and we have to do that in connection with the rate case. So, yes the commission has the ability to review the facts of circumstance of our case and decide whether we qualify or they believe its appropriate for us to have a fuel adjustment clause. So, the long winning answer is yes, take a look at the facts of 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 cost as well as the importance to the enterprise that will get a fuel adjustment clause next rate case.

And what was weather year-over-year and then year versus normal?

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

Both positive?

Excuse me?

Both positive?

Yes.

And when you gave your ROEs at the utilities, did you weather norm those or is that applicable?

No, the ROEs that I have provided to you were exclusive sort of the unusual items there, 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 the Illinois regulated business, the electric piece of weather was not a significant variable, they are obviously driven little more by the gas business in terms of the variations.

And you kind of 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?

Well, I think when you look at... we updated our guidance, in January from a non-GAAP basis to be $3 in the quarter to $3.35 per share. It's in the range, sometimes its a time in certain expenditures coming in the play and then of course, as you looked at some of the sales that we're able to make towards the end of the year, they are a little bit better, perhaps than we thought but nothing major Paul, I would say it's sort of joke but that $0.03 or $0.04 per share difference, frankly.

And what were the... did you have EA sales in the year and what were those?

I am sorry, say it again.

Emission allowances.

Do we have emission allowance sales...

In the fourth quarter and the year?

Yes, we did have some emission allowance sales throughout the year and if you're 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. And obviously we had significantly great allowance levels of emission allowance sales in both the regulated and unregulated side of 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 am sorry?

Did you have any in 4Q?

We had less than $1 million.

Was that after-tax?

No, pre-tax.

Okay, thank you very much.

You are welcome.

Thank you. The next question comes from the line of Michael Lapides with Goldman Sachs. Please go ahead

Hey guys two questions, little bit unrelated. 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's a huge increase from the year ago period as well. Can you talk about plans for dealing with the short term debt? That's the first question. And the second question is, can you talk about on the non-regulated side, which plants are having scrubber installations over the next few years? And if there is any information regarding timing?

Sure. I'll handle the short term debt and then Gary can comment a little bit on the environmental fees. But on the short term debt they did increase from Q3 to Q4. But I think you have to look at our net cash position too. We are sitting on about $300 million or so of cash at the end of the year. And I think when you look from Q3 to Q4 on that short term debt net of cash is perhaps may be about $100 million. The bottom line allowed that's 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. And so, we plan on executing this strategy throughout 2008 whereby we'll 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. Now I'll let Gary comment on the environmental fee

Yes 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 then our Coffeen plant that's 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 Jasper power plant and that... those will be installed... Edwards as well. One or two units at Edwards and those are installed over about a four or five-year period.

Got it. And is there a timing known for new networks in Jasper.

I don't have the schedule in front of me. But not in the next two years. But I would say 2 to5 years.

We can get that information to you Mike. We'll get that back to you.

That would be great. And just one question. How, when you think about what it does in the year of installation to the capacity factor of the plant. I mean is it done during a normal maintenance outage? Does it extend the maintenance outage, kind of just try get our arms around that?

Well 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 is 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 base load generation from these plants by about 10% and from roughly 30 million megawatt hours to 33 million megawatt hours. In '08 and 09 it will have a negative impact.

So. I want to make sure I understand. In 08 and 09 it has a negative impact because of Duck Creek and Coffeen. Then some time after 09 Newton, Edwards and Jasper have the same thing happen. How do you get to the 33 million before you are done with all five plants?

It's 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 non-rate regulated generation versus about 89% for the regulated generation, which isn't going through these kinds of outages. And we are 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 Jasper installations we would expect the performance of those units to be more like 90% availability and the capacity factor to be even higher.

Got it. Okay, thank you guys. Much appreciate it.

You're welcome, Michael.

Thank you. The next question comes from line of Raza Hatefi [ph] with Polygon Investments. Please go ahead.

Thank you very much. Could you discuss little bit about the coal markets. I guess going back to your January slide 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 etcetera?

Sure. And... this is Warner. In terms of the coal prices certainly we have seen here and recently some pressure on coal prices. Spot market rate is risen a $1 or $2 here over the last month or two as a result of many of the things that you read in terms of the overall demand for coal. But keep in mind we saw a similar types of increases two or three years ago where the coal prices went through the roof because of particular demands. 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 in to for a long term contract. So, the bottom line is we are seeing some of those increase in prices, obviously we continue to go through our hedging strategy whereby generally around 20% per year of our coal contracts typically roll losses or typically anywhere from 4 to 5-year types of contracts. And so when you look out there in 2010, obviously we are not hedged as much, but of course we factored in some of our thinking, what marketplace observations that we had at the time and we expected them to take place prospectively. So, I wouldn't suggest that just sort of a spot market rate that we took in to consideration when we put together our guidance. Of course the other piece that drives that isn't just coal prices but also transportation fees and that too is in fact is major drivers other than there is anything in terms of the increases in our coal cost prospectively.

And could you remind us after the '09 scrubbers come on and then going forward when the Newton, Edwards and the other scrubbers also come on or is there going to be a shift from PRB to some other kind of call or because I guess right now your 90% PRB if I am not mistaken?

There won't necessarily be a shift from PRB to Illinois coal. Though it depend on the economics but we are planning to create some flexibility, we are installing mostly wet scrubbers. In scrubber technology, you have got two choices dry scrubbers which are 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. So, we will be sure that we provide that flexibility given how the markets change and we might switch back to Illinois coals in the future.

And your 2011 guidance of $4 or round about, are you assuming that your trending or you add somewhat of a... you are earning basically around your allowed ROE or fair ROE, or is there a still under earnings going on even with that nice guidance?

Sure, with regard to 2000, and of course 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 seek coupled with the cost recovery mechanisms that we are 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 on our actual returns on equities are. So, we expect those to certainly be meaningfully declined in terms of specifics, in terms of what we are expecting out in the future years, we haven't provide that level of detail out there in 2001.

Thank you very much.

You are welcome.

Thank you, sir. The next question comes from the line of Steven Gambuzza with Longbow Capital. Please go ahead.

Good morning.

Good morning, Steve.

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

Steve, the only numbers that I can recall and give you a short answer to your question first, I don't have a good number to give you. But as far as capital cost in the past, we've worked with numbers around $300 per kilowatt. And I know those numbers are under pressure just because of shortage of construction forces out there, they are rising but I don't know exactly what the new number is. And 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.

Okay. And then you talked about your scrubber plans, I was wondering if you have, if you would give us a run down also in terms of SCRs, have you planning installing any SCRs that you are regulating?

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

And Steve, did you ask about the regulated units?

No, just the unregulated units.

Okay that's what I thought, that's why there was this clarification. So, Gary was addressing that.

Bruce is trying to find some information there.

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

Well typically... Steve, 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 anywhere from 4 to 5 year types of contracts. Transportation we try to link them up as closer as we can to the coal contract in terms of tenure but they are more plant specific and often times do not have the sane, exact duration. So as we look out, most... especially in the 9-10 timeframe... obviously coal is better hedged than some of our transportation contracts. So as I said at the Analyst Day we are actively seeking to show up especially the transportation contracts of those. Open power plants especially on our unregulated generation business. And with the coal contracts we systematically go through a period where we will hedge some of those open positions. I would call sort of a dollar cost averaging. We don't try and to be market timeframe frankly. We get out there. We are in constant contact with our suppliers. Both on the rail side as well as the commodity side. And so it's almost an ongoing process throughout the year that we are engaging in discussions with these folks. And so there is... we are not putting the peddle to metal today anymore differently than we would in January probably March of any other year. We would just take that type of approach to our hedging position.

Okay. And 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 at least for the Illinois regulated and unregulated segments.

Sure we'll... I'll give those to you for the 2007 for the reporting entities?

Yes.

The Union Electric, that is $336 million; our 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 reported entities.

And EEI?

EEI is a component of UE.

Okay, great. Thank you very much.

You're welcome.

Thank you. The next question comes from the line of Epuch Fung with Zimmer's and Lucas Partners [ph]. Please go ahead.

Good morning.

Good morning.

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

Sure. As we have discussed at the Analyst Day, we expect the rules that... more clarity around the rules sometime we think by the end of the first quarter of this year with we will be able to see the rules. The final set of those rules sometime early in the second. And so as we approach our rate case in Missouri we'll have visibility to those rules where we expect to file that here in the second quarter. And we would expect to seek an environmental cost recovery mechanism in our next rate case.

Okay, thank you very much.

Welcome.

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 that for the other plants we are reducing NOx primarily with low NOx burners and with fine tuning technology than tunes the plants for NOx emissions.

Thank you. The next question comes from the line of Gregg Orrill with Lehman Brothers. Please go ahead.

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

Sure. You know Greg obviously the commission spoke in their order and addressed the rationale but behind that and some of the rationale included what they deemed to be the volatility of our fuel costs. But I think the other think that you need to look at when we approached our last rate case in terms of the fuel cost recovery mechanism that case was very complicated; 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 EEN [ph] contract which was at disputed time. It related to setting the appropriate market prices for our system sales. And coupled with that we were the first utility at that point in time to seek a fuel adjustment mechanism. So, I won't speak for the commission but certainly as we look at it those were all issues and factors in the last rate case that had be determined by the Missouri Public Service Commission. As we look now going forward to this rate case, the join dispatch agreement is now been in place and we'll have history that we will be on the show in terms of the impacts of that. The EEN contract will settled in the last rate case in our favor. So, we think that the issue surrounding the fuel adjustment cost mechanism for Ameren and this UE in this next case will be a simpler exercise. For the commission to review in the case that we'll file here in the second quarter.

Okay, thanks.

You're welcome.

Thank you, sir. The last question is a follow-up question from Daniele Seitz with Dahlman Rose. Please go ahead.

Hi. I was wondering you are presenting a lot of distribution system reliability additions or expenses basically in that area. Have all of these programs been already previously also rise [ph] by the Commission? Or actually these are just your own planning?

Well Daniele its regarded to the incremental expenditures that we're doing in 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 are doing. If you recall the Analyst Day, Tom Voss even 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 overall reliability but they say that they have authorized that and accrued and raised [ph] that would be premature for us to say that. However, we will see to recover these incremental costs in these upcoming rate cases and we believe it's consistent with both the commission's expectations as well as our customer's expectations in this area.

And then the efficiency and conservation programs that you are proposing do they come with also some sort of compensation for the company as well?

Our cost for our energy efficiency programs in both Missouri and Illinois are recoverable on rates.

Okay, so that is already understood. Great, thank you.

Thank you ma'am. This time there are no further questions. I would like to turn it back over to management.

Great. We want to thank you all for participating in this call this morning. Let me remind you again that this call is available through February 21st on playback and for one year on our website. The announcement carries instructions on listening to the playback. You can also call the context listed on our news release. Those on the call, who are financial analysts, please call Bruce Steinke or Terese [ph]. Media should call Tim Fox. Contact Numbers are on the news release. Again, thank you for dialing in.

Thank you, ladies and gentlemen. This does conclude the Ameren Corporation 2007 fourth quarter earnings call. If you would like to listen to a replay of today's call, please dial 800-405-2236 or 303-590-3000. Once again, our toll free 1800-405-2236 or 303-590-3000. The passcode for the conference call will be 11108033, followed by the pound sign. Once again that's 11108033, followed by the pound sign. You may now disconnect and thank you for using AT&T Teleconferencing.