Welcome to the Ameren Corporation’s Year-End and Fourth-Quarter Earnings Call. At this time, all participants’ are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Douglas Fischer, Director of Investor Relations for Ameren Corporation. Thank you, Mr. Fischer. You may begin.

Thank you, and good morning. I am Doug Fischer, Director of Investor Relations for Ameren Corporation. On the call with me today are our Chairman, President, and Chief Executive Officer; Tom Voss; our Senior Vice President and Chief Financial Officer, Marty Lyons; and other members of the Ameren management team. Before we begin, let me cover a few administrative details. The 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 in our news release include instructions for replaying the call by telephone. This call will also be broadcast live on the Internet and the webcast will be available for one year on our Web site at www.ameren.com. This call contains time sensitive data that is accurate only as of the date of today’s live broadcast. Redistribution of this broadcast is prohibited. To assist with our call this morning, we’ve posted a presentation on our Web site to which we’ll refer during this call. To access this presentation, please look in the Investors section of our Web site under ‘Webcasts and Presentations’ and follow the appropriate link. Turning to page #2 of the presentation, I need to inform you that comments made during 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, events, conditions and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated and described in the forward-looking statements. For additional information concerning these factors, please read the forward-looking statement section in the news release we issued today and the forward-looking statements and risk factors sections in our filings with the SEC. Tom will begin this call with an overview of 2010 earnings and 2011 guidance, followed by a discussion of recent business developments. Marty will follow with more detailed discussions of 2010 financial results, our 2011 guidance and regulatory and financial matters. We’ll then open the call for questions. Here’s Tom who will start on page #3 of the presentation.

Thanks, Doug. Good morning and thank you for joining us. The past year was marked by significant accomplishments at our company. I’m pleased to report that 2010 core earnings reached $2.75 per share within the upper end of our most recent earnings guidance range issued in late October and nearly equaling 2009 core earnings of $2.79 per share. Improved earnings at our regulated utilities nearly offset a decline in core results from our Merchant Generation business. Factors favorably affecting 2010 core earnings included a 9% increase in electric Kwh sales to native load customers, new electric utility rates, lower financing cost and disciplined cost management. The increase in Kwh sales was the result of favorable weather, a recovering economy, and the return to full service of the large customers’ aluminum smelter plant. Total kwh sales to industrial customers rose 16% and even after excluding sales to the aluminum smelter plant, industrial sales increased 8%. Kwh sales to residential and commercial customers rose 7%. Items offsetting these favorable factors included lower Merchant Generation margins due to lower power prices and higher fuel and related transportation cost and higher companywide depreciation and amortization expenses. Overall, our non-fuel operations and maintenance cost increased only slightly reflecting the cost of the refueling outage at our Callaway Nuclear Plant, offset by disciplined cost management across all of our business segments. You may recall that our nuclear plant did not have a refueling outage in 2009. Per share results also reflected an increased average number of common shares outstanding. Turning to page #4, you will find a list of other accomplishments in 2010. We’ve discussed many of these with you previously, so I won’t touch on each of them. However, I’d like to highlight the fact that free cash flow reached the positive $341 million in…

Thanks, Tom. Turning to page #7 of the presentation and the year 2010 column, today, we reported 2010 earnings in accordance with Generally Accepted Accounting Principles or GAAP of $0.58 per share compared to 2009 GAAP earnings of $2.78 per share. Excluding certain items in each year, Ameren reported 2010 core earnings of $2.75 per share, compared with 2009 core earnings of $2.79 per share. 2010 core earnings exclude three items that are included in GAAP earnings. The first of these is goodwill and other asset impairment charges associated with our Merchant Generation business. We recorded these charges in the third quarter. These non-cash charges reduced 2010 GAAP results by $522 million or $2.19 per share. The second item excluded is a $0.08 per share gain from the net effect of an unrealized mark-to-market activity. The third item excluded in arriving at 2010 core earnings is a charge for the deferred tax impact of new Federal Healthcare loss which decreased earnings by $0.06 per share. On page #8, we highlight key factors driving the variance between core earnings per share for 2010 and 2009. Factors favorably impacting this comparison included increased regulated electric and natural gas margins, excluding the impact of rate changes. These margins lifted earnings by $0.71 per share driven by the previously discussed increase in electricity sales. Warmer summer and to a lesser extent colder winter weather increased 2010 earnings by an estimated $0.40 per share compared to 2009 and by an estimated $0.24 per share compared to normal weather. New utility rates increased 2010 earnings by $0.36 per share net of certain related expenses compared to 2009 results. Reduced financing expenses, primarily reflecting increased capitalization of construction financing costs or AFEDC, improved 2010 earnings by $0.10 per share. Factors adversely impacting the comparison between 2010 and…

(Operator instructions) Our first question comes from Paul Ridzon with KeyBanc. Please proceed with your question.

$522 million write-down at Merchant, but depreciation is flat, what’s driving that? Is it really just all goodwill?

Yes, Paul. If you recall, there was goodwill, there was also some plant impairment, but largest part was goodwill, which, of course, for accounting purpose isn’t amortized or depreciated. The power plant write-off piece was much smaller, but what we also did is took a look at the lives of the power plants within the fleet. So while our write-off of some power plant expense we typically decreased depreciation, we’ve also taken a look at the lives of our other units and net, it came out to no net positive or negative impact from depreciation expenses.

What drove the acceleration of Merchant CapEx? Is there something fundamental in the market, or are you trying to take advantage of bonus depreciation?

Well, bonus depreciation is part of it. I mean that certainly helps in terms of the returns on those projects. But, as we mentioned in the call, when you look at the CapEx for Merchant, the biggest driver you see there is moving out the in-service date of the Newton scrubbers. Previously, we had forecast that at 2014 and 2015, we’ve moved that up to late 2013, early 2014. And as we said on the call, primarily because of the expected impact that the Clean Air Transport Rules will have on our fleet, so we believe it’s prudent to move that investment up and that’s the big driver of the cash flows. But you’re right; there is also then the benefit that we’ll get from bonus depreciation.

How much is bonus depreciation and how much is regulated?

The bonus depreciation for 2010 that came out in that law companywide expected to help cash in 2011 by about $100 million to $150 million.

How much for ‘12?

Yes. I don’t have the ‘12 numbers at this point.

The breakdown between Merchant and Regulated?

The $100 million and $150 million, I don’t have the breakdown overall on the $100 million, $150 million between the segments.

Okay, thank you very much.

Our next question comes from Reza Hatefi from Decade Capital. Please proceed with your question.

Thank you. Just wanted a couple of clarifications on your hedging, fuel per MWh in 2011 and ‘12 went down versus your third-quarter slide by about $1 to $1.50 per MWh, what drove that?

Yes, it’s a good point. In both cases, we pointed out for some time that the hedges we’ve in place for coal were at prices that we believe were above current market prices for coal. So as we’ve layered in additional hedges for both 2011 and 2012, we’ve brought down the average cost per MWh of the blended generation. In ‘11, however, in addition to the benefit of those lower cost hedges we put in place, we’re also benefiting as we look to these numbers and refine them, lower emission allowance cost as well as lower expected taxes that we pay on our delivered fuel cost. So in 2011, we’re getting the benefit of, I’d say all three of those factors. In 2012, it was largely driven by the lower cost coal we put in place.

And then your 2013 hedges, $42, are they around the clock, or are they weighted more towards peak as of now? How should we think about that?

I think as you look at those hedges, the 2012 hedges look very much like an around the clock kind of product, the ATC typically about 47% to 48% on peak. The 2013 hedge profile is a little more weighted to our base load generation mix, which tends to be about 52% on peak.

And just finally, could you comment on, I guess, strategically your thoughts on the Merchant segment and with the forward curve being as weak as it is any thoughts there in terms of this segment continuing to be part of Ameren?

This is Tom Voss. We think that it’s one of our core businesses that what we know how to do, we know how to generate electricity at the power plants. We think we do it very well. We think those merchant plants are well-positioned. They’ve got recent environmental upgrades; they’ve very good heat rates. They dispatch well on the MISO stack. So we think generally they are positioned well for a recovery of power prices in the future.

Thank you very much.

Our next question comes from Paul Patterson with Glenrock Associates. Please proceed with your question.

Good morning, guys.

Good morning.

Good morning.

On the 8-K that you guys filed late Friday, it wasn’t clear to me what the actual case is about with those four customers. If you look at the 10-Q or at least when I looked at it, it just says that they are appealing certain aspects of it. I guess what I’m trying to get a sense of here is what is that the merits of the case I guess OPC apparently feels as well, got some issue there. Can we get any sense as to what the impact of that would be versus just the stay which seems to be sort of a more generalized or perhaps a bigger impact? Do you follow me?

Hi, Paul, this is Warner Baxter. Let me try and address your questions, because I think they’re probably two of them in there. Number one, as you saw in the 8-K filing, basically, the Office of Public Counsel and some of our industrial customers are arguing that a stay of our rate increase which was granted to four of our industrial customers in the December 2010 Circuit Court order should essentially be applied to all customers, and that is essentially what they have asked the Commission to address. They have not addressed the commission to address the essential merits of those two rate orders, which are on appeal before the various courts. Those orders probably had anywhere from 8 to 10 issues which are still pending. And so in the bigger picture of things when you look at those issues which are being appealed, they are obviously at much smaller subset, compared to the overall rate increase, and as I have stated on the call, we do not believe that any of those issues on the merits are a probable loss at this time, and we’ll continue to address those appropriately in the courts. And, of course, as Tom said in the call, we strongly disagree with the positions taken by both the Office of Public Counsel and the industrial customers in their interpretation of that circuit order, as well as the overall stay order that was issued in December of 2010 and you can plan on us to vigorously defend our position before the Public Service Commission and the courts as appropriate and you can expect our complete response to those matters, no later than February 25.

Okay. And then just we’ve seen some companies move from MISO to PJM partly I think because of capacity pricing differential. I was wondering if you guys were thinking about anything like that or how you are looking at the capacity markets going forward in your area versus what you might be seeing otherwise if you were in PJM.

This is Tom Voss. We’ve been working with MISO to develop a better capacity market, so it’s looks more like PJM’s market, capacity market and we expect MISO to file sometime later this year a plan to the FERC that would show a better capacity market than what currently exist. So our plans right now are to work with MISO on improving it.

How soon should we think about the changes that MISO might propose actually flowing through to the bottom-line of generators in MISO?

We think right now that if everything goes right and everything keeps moving it should be in the 2012 year.

Okay. Thanks a lot.

Our next question comes from Erica Piserchia with Wunderlich Securities. Please proceed with your question.

Hi, how are you? Just have a couple of questions. I am wondering first if on the Merchant, if you can talk a little bit shaping, I know historically you’ve gotten shape on I think anywhere from 20% to 40% of your MWh sales product and it looks like you locked in some shape on 2012, 2013, relative to what the ATC prices in that market. I am just wondering if you can talk about what percentage of your sales are currently getting shape and how we should think about that kind of going forward?

Well, I think, Erica, as we look out over time, we frankly try to sell as much as we can with the shaped product and we haven’t really given a break-down for year, which you are right, I mean our sales strategy is to go after the higher margin customer segments in the areas, where we’ve generation, as those opportunities present themselves (inaudible) to lock in the higher margins that you can see in those list of power prices.

Okay. And then I guess just you talked about potentially being able to ramp-up your Generation output. I believe you mentioned you could potentially ramp-up to as high as 34 million MWh. Just looking back over the last couple years, you kept the output obviously flat. When you talk about potential market recovery, what levels would you need to see in the market to get you more incentive towards doing that, we’re talking about going back to pricing that was in existence a couple of years ago, or clearly probably a little bit longer term, what are your thoughts on that?

Well, what we tried to provide in the script was a little bit of a metric in terms of, if we saw a $5 (inaudible) in power prices based on our open and available Generation for 2011 that that could produce up to $30 million of additional margins. We provide that metric to give you a sense of, given the available capacity that we’ve, if power prices were to move what kind of incremental generation we would have and what those margins are. Any given year the amount of generation that we’ve got available obviously is dictated by the outage schedule we’ve for that year, but we think that metric maybe helpful to you as you look at, where our incremental generation is in terms of cost, and if they were to be dispatched at those higher prices, what kind of margins we could get.

Sure. So like a sensitivity. Last question just on your 2011 guidance for the Regulated end of the business. Does the low-end of the range encompass sort of on the Missouri side of the staff’s recommendation and on the Illinois side, sort the existing state of, well, I guess it would because your new rates there wouldn’t take effect till 2012, but on the Missouri side is the staff end of the recommendation included in that low end or how do we think about that?

Well, I wouldn’t really tie it to that necessarily as much as just to say that we think it’s a reasonable range given a variety of things, estimates and expectations that we make and it’s certainly regulatory outcomes is one of those, but sales growth, operating spending levels, storms and plant outages and the like. Certainly, our goal remains to improve our earned returns over time. We made good progress in 2010. We plan to make incremental progress in 2011 and continue to align spending with regulatory outcomes that we receive. So we wouldn’t tie the ranges to anybody’s recommendations in our case particular, but again a range that incorporates those elements of our estimates that I laid out.

Okay, thank you.

(Operator instructions) Our next question will come from Ashar Khan with Visium. Please proceed with your question.

Good morning. Marty, can I just ask you, when were the 2013 hedges put in place? Because that was a new data. Were they put in place during the last three months or six months? Could you give us some timing of those hedges?

Ashar, we’ve been working on hedges for some time. So some of those were put on in 2010 timeframe, others were put on some periods prior, but we’ve been working at those over time. We’re never kind of sitting on our hands. We’re always looking at sales opportunities as they present themselves. We’ve talked about our strategy of going after retail customers and you have to act on those when they are available in the market and they arise from time-to-time, and we execute on those.

If I can remember the contract with the Illinois rate that ends in 2012, am I right?

Yes, that’s right.

Okay, thank you very much.

Welcome.

Our next question comes from Julien Dumoulin-Smith with UBS. Please proceed with your question.

Good morning. Thank you. So just wanted to first touch on the Illinois side of the house and ask about the ComEd legislative proposal. Just on your side, are you guys supportive of it and any kind of expectations out of the process this year, more confidence in certain aspects relative to others?

This is Scott Cisel. I’ll respond to your question. Concerning the rate formula bill, we certainly are very supportive of the bill as it’s been presented. As you know, it would enable utilities to continue to make prudent and reasonable investments into the system and then be allowed to realize a reasonable return on the investment. The amendment is the rate formula bill will be introduced this afternoon in a committee hearing and then from that point on, it will begin the process of discussions and eventually consideration. It’s very early in the session to give any sort of prediction but we and other will participate and we’ll strive to see if we can end up with a workable compromise and do so yet this spring legislative session.

Then secondly on the Regulated side of the house with regards to the stay order, perhaps could you discuss some of the levers that you might be able to pull to resolve the pending litigation, be it at an Appeals Court, at the Commission, I mean perhaps just walk through some of the way to from here if you will?

This is Warner Baxter. I’ll respond. I think as we’ve stated we’re going to be filing our position by the end of this week with the Missouri Public Service Commission on the Office of Public Counsel on the industrial consumers’ pleadings. Really beyond that I’m really not in a position to address really any other specific questions or positions or strategies, we’re going to take for this pending litigation matter.

Then finally, just quick last question, more detail-oriented. On the O&M side from Merchant Gen I know that’s a little bit of rise year-on-year. Could you walk through that very quickly if you don’t mind?

I think that as you look at the Merchant Generation business at 03/10 slightly up from where we’re at last year and some of the things in there are nuts and bolts items like increases and benefits expenses year-over-year, increases in wages for employees. I think there is just some of those nuts and bolts items in there. We also do have, however, an outage at one of our power plants and plan for this year where we’re looking to do both the maintenance and capital work and that too is impacting the figures.

Thanks, again.

Our next question comes from Robert Howell with Prospectus Partners. Please proceed with your question.

Good morning. Wanted to just ask about the Merchant Generation CapEx outlook slide, 2015 is really a pretty dramatic drop. I guess the figures, at least the environmental part would be that those projects get done, but also the maintenance CapEx seems to be going down dramatically as well, and just sort of wondering what was happening there with maybe some maintenance CapEx getting pushed into some forward years or what’s happening?

A good question. I think that’s right. I mean I’d note that this in 2010 the point of reference, we actually were able to limit the capital expenditures for that segment to $89 million, so certainly being able to keep maintenance in other as well pretty low is something that we think is doable. So when you look at 2015 levels, not too in line with what we’re seeing in 2010, but our thought is actually given some of the maintenance that’s already been done in the years leading up to the present as well as the maintenance in other items that we got planned for ‘11 through ‘14 that we’ll have done requisite maintenance on our big base-load facilities. We feel like when we get out to 2015 the necessary efforts and expenditures will be behind us. So as we said on the call, certainly as we move through time we’ll look at the power price environment, we’ll pay close attention to our cash flows, some of the expenditures in ‘13 and ‘14 could conceivably move out to ‘15, but right now I think this is a good snapshot of where we stand today.

And so are those low levels for ‘15 something that could kind of continue out for the next couple years, it sounds like the ‘15 number from a maintenance CapEx perspective is may be a tiny, but lower than the long on average because you pushed it forward, but will you be able to kind of keep it low like that for a couple years before it gradually ramps up or?

I can’t comment on ‘16 to ‘17, I think you’re right over a long-term you’re going to need to do perform certain maintenance CapEx on your plants. Again as far as looking out to ‘15, this is what we see.

Okay, thank you.

Our next question comes from David Katz with Bank of America. Please proceed with your question.

Good morning. Thank you. I just had a question on your average utility book equity in 2010. You guys were saying last year it would be about $6 billion. Where did it end up at?

I don’t know, I’d think it probably ended up somewhere close to that, David, I don’t have the exact number.

Okay. So then as we look at the $6.2 billion for 2011 average equity, how much of that or what percentage of that is Missouri and what percentage of that is Illinois?

I don’t have that break down either. I mean it’s obviously roll-forward of increased earnings and months to regulated businesses less the dividends it’s pretty simple math. I know you know but I don’t have the breakdown between the regulatory jurisdiction.

Just quickly on the O&M growth. I know you say there’s a Callaway refueling outage later this year and that expected impact should be slightly less than what it was last year. You have to increase nonfuel O&M as one of the drivers. What kind of growth in nonfuel O&M should we be looking at?

Well, I think as we look into 2011, we already talked about Merchant, the O&M going up a little bit there. Then we commented on regulated overall. Certainly as you think about that, we said last year if we’re successful in re-hearing under the Illinois rates that we would restore some of the spending in Illinois that had been reduced and we’re following through on that, so we’ve got some incremental O&M spending in Illinois. Then we do have some incremental spending in Missouri as well scheduled for our Energy Delivery business to continue to improve reliability there, as well as in our power plants. But I don’t have the exact percentage in front of me, but we’ll continue to look for opportunities to synchronize the spending with the regulatory outcomes that we get.

Okay, thank you.

Our next question comes from Michael Lapides with Goldman Sachs. Please proceed with your question.

Hey, guys. Question for you just on the coal hedging at the Merchant Generation, I’m not positive I understood some of the comments about Illinois basin in PRB. Does this imply you’re starting to, in the forward market, to buy a bit more Illinois basin so you benefit from better heat content? Or are you keeping the split similar between PRB and IB?

I wouldn’t say the comment was about our strategy going forward in terms of fuel burn. We’ll certainly buy what we believe the most economical to burn. But what we’re really trying to point out there is that the embedded cost of our coal hedges for 2013 are well above current PRB broker quotes. So what I was really trying to convey there is similar to what we’ve seen in ‘11 and ‘12. As we bought additional fuel, the average hedge price has come down. What I was trying to convey there is we’ve the same expectation with respect to 2013. When we lay in additional hedges, if we’re to lay today we would bring down that average price per MWh.

Are you still expecting you’ve talked in the past that the rail transportation piece, or however you use transportation, will be roughly two-thirds of the total all-in cost of fuel?

We break that out. If you see on that slide 18, you actually see that for 2011 the transportation about 52% with fuel surcharges, it gets you to about 58%, so that’s our expectation for ‘11. We’ve also commented over time that we do believe that while you look out you see some of the rail contracts or rail hedges rolling off. We do believe that the contracts we’ve in place today are at about market rates, so we’re not really expecting any major deviation as we lock in new rail contracts.

Got it, okay, thank you guys. Much appreciate it. I’ll follow up with Doug offline.

Our next question comes from Dan Jenkins with State of Wisconsin Investment Board. Please proceed with your question.

Hi, good morning.

Good morning.

I just wanted to clarify. I think you said when you were talking about cash flows; did you say you’re planning to pay off that Ameren Illinois maturity of $150 million in June that you’re going to refinance?

You’re correct, our plan is to pay that off, redeem that.

Then while you continue to issue new shares like the DRIP program and those programs and they’re still how much would you expect that to be?

We do expect to do that, to continue that through this year that’s embedded in our guidance and I guess that’s in the range of $90 million or so.

Will there be any other financing then given that you expect a positive free cash flow?

At this time, we don’t have any other plans.

Okay, thank you.

Our next question comes from Charles Stunnet [ph] with Stunnet Research [ph]. Please proceed with your question.

Good morning. I’m disturbed by the trend in CapEx. You spent $1.031 billion in 2010, you show here $1.250 billion for 2011 and the midpoint of your range from 2012 to 2015 is $1.5 billion. Why are you increasing your CapEx while the price to book is below one? And how do you expect to get favorable rate decisions if you continue to invest shareholder capital when markets tell you not to do so?

Good morning. I’m disturbed by the trend in CapEx. You spent $1.031 billion in 2010, you show here $1.250 billion for 2011 and the midpoint of your range from 2012 to 2015 is $1.5 billion. Why are you increasing your CapEx while the price to book is below one? And how do you expect to get favorable rate decisions if you continue to invest shareholder capital when markets tell you not to do so?

I think Charles, as we look out; certainly, we’ve been cognizant about managing our capital expenditures. If you look back, we brought those down considerably over the past couple of years. As you look out at our capital expenditures say for the Regulated businesses, and if you were listening when we talked about, we talked about having two additional scrubbers in place in the Missouri Regulated business over that five-year period. And if you look at our capital expenditures out over that five-year period versus prior disclosures we’ve given, they are about flat to down a little bit versus what we’ve previously shown. So we’re certainly managing our capital and we’ll continue to manage our capital investments in light of the regulatory outcomes that we received. So that said, what we’re looking to do is improve the regulatory returns in both our primary Illinois and Missouri Regulated businesses as well as deploy capital into transmission which is something you see as well in our five-year forecast. Our strategy for doing that as we talked about in Illinois using the forecast in forward test year in the current case to improve the returns and improve our ability to earn fair returns on the capital that we’re deploying and we certainly got an active rate case in Missouri right now where we’re working to achieve a constructive outcome and a constructive framework that will provide for going forward good returns on the investments we make in Missouri.

Okay, thank you.

Okay, thank you.

Our next question comes from Sarah Eccles with Wells Fargo Advisors. Please proceed with your question.

Hey, good morning.

Good morning.

I’m curious as to whether you’re having conversations with the MISO about the potential for reliability must run contracts and whether that’s something you expect to be addressed in a capacity filing with the FERC and also just any comments or insights you could provide on your expectation as to what the MISO capacity proposal might look like?

We’ve talked with MISO actually fairly recently and they are in the process of studying as far what’s going to be required. Right now, the MISO footprint to say in an evolution of fluxes and understatement with FirstEnergy and part of Duke system leaving MISO, but I know they’re looking at that, but that’s all I can say on topic specifically. Just to add, they are working on the themes issue between MISO and PJM and the portability, if you will, to transfer energy across that theme for all market participants.

Great, thank you.

Our next question comes from Steven Gambuzza with Longbow Capital. Please proceed with your question.

Good morning.

Good morning.

The CapEx guidance that you provided is very specific for Genco, is it rather wide range for the rest of the company between 2015? I guess I was surprised to see point estimates for Genco but then there is wide range and I was wondering if you could comment on the potential for the scope of the program either at Genco or Union Electric to be changed to include additional controls and whether pending EPA rules on hazardous gases and mercury might significantly impact either the regulated or the unregulated forecast?

Sure, I think that’s as Tom mentioned in his prepared remarks, we as well as everybody else in the industry I think is anticipating to see some proposed rules coming out of EPA middle March. And we’ll see what those require. And as Tom mentioned we put together a team of people that have been working diligently over the past year and well into the coming year to take a look at what comes out of the EPA and make the best decisions about what kinds of additional investments will or won’t be made in the plants we’ve and try to make the most efficient economical investment decisions that we can for the best interest of the shareholders and the customers. So could that require additional CapEx? Certainly so. But we’re really going to make those decisions on the plant by plant basis across our fleet.

In your prepared remarks, I heard you mentioned the coal combustion byproduct rule and the Clean Air Transport Rule as the two, I guess regulatory issues that your CapEx forecast was taking into account. I didn’t hear you mention the mercury or the hazardous gas rules, but we should assume that your expectation regarding those regulations are embedded in your forecast?

Just to be clear, I mean, historically, when we’ve provided our CapEx, we talked about it being consistent with current laws and regulations and so what we’ve done here is, we’ve seen proposed rules that have been out for the Clean Air Transport Rule, as well as the coal combustion byproducts and so based on our assessment of the likely outcome on those rules, we’ve updated our CapEx for both Missouri as well as for the Merchant business to reflect our expected outcome under those rules and then we’ll see what comes of the Federal EPA. I’d remind you, Steve, that in our Merchant part of our business we’re complying with also Illinois Multi-Pollutant Standard which already had requirements for certain of those elements that the Federal EPA looks to regulate, so we’ll see how those compare those proposed rules come out and evolve.

Okay. And then finally, can you comment on which two units in Missouri you do intend to scrub?

That’s something that is going to be assessed. We’re certainly beginning some additional design work, but that would be applicable to whatever units we decided to go forward.

Okay, thank you.

This is Doug Fischer. We have time for just one or two more questions here.

Our next question comes from Daniele Seitz with Dudack Research. Please proceed with your question.

Thank you. I was going to ask exactly the same questions and so at this point your CapEx really built on your estimates of what the EPA rules are going to come out whether it’s not just on the Illinois Multi-Pollutant Standard, is that correct?

Yes and no, Daniele. I think, again what we’re saying was that it does incorporate an assessment of requirements that the Clean Air Transport Rule will impose, as well as rule for coal combustion byproducts, but nothing further than that from a Federal EPA standpoint.

Okay. On your side, are you trying to convince your regulators that actually in order not to file so many rate cases. It would be easier if you were operating under riders at this time, or are they reluctant to allow this kind of rules?

I think Daniele; certainly we’ve been successful at getting some riders over the past few years. Those can have the added benefit of being able to go for a more extended time periods between rate cases and be able to recover your cost on a timely basis, so that is something that we’ve pursued and will continue to pursue in the future.

Obviously, the comment legislative proposal would put the step forward toward a more timely type of regulatory environment. Will that replace whatever ambitions you have regarding riders?

I think as it relates to Illinois, the rate case that we filed on Friday incorporated a forward-looking test year. It also incorporated a request for a rider for pension expenses going forward, so we’ve made those filings. I think that the legislative proposal that has been discussed, that Scott earlier said, we’re supportive of, if that was put in place, I think likely would supersede those other kinds of efforts.

And on the side of the Missouri, do you see any new effort or progress in that area?

Could you repeat that? I know it was Missouri, but I couldn’t tell what the –

Do you see any in-roads that you may make regarding additional riders?

Daniele, This is Warner Baxter. I’d comment on that in a couple of ways. Number one, we certainly made good progress in our last rate case in maintaining some of the rider mechanisms, as well as getting the construction accounting that we got for the Sioux scrubber project. And even in this case, this current rate case, we’re seeking to enhance some of the recovery mechanisms that we’ve for some of our construction projects, as well as for energy efficiency. Beyond that we continue to look at some of the regulatory rule makings, we continue to look at potential legislative efforts, aligning our spend, we’re looking at a host of things to continue to mitigate the regulatory lag and improve our returns, so that is an effort that is ongoing, and we recognize the importance of that, not just to our shareholders, but also to our customers, because they gave us the necessary cash flows to invest in our infrastructure to deliver good reliability and Clean Air Energy Reform.

I think at that point we’re going to have to end here. We’ve gone a little bit longer than normal, but we thank you for your participation in this call. Let me remind you again that this call is available through March 1st on playback, and for one year on our Web site. Today’s press release contains instructions for listening to that playback. You may also call the contacts listed on the release. Financial analyst inquiries should be directed to me, Doug Fischer. Media should call Susan Gallagher. Our contact numbers are on the news release. Again, thank you for your interest in Ameren.

This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.