Welcome to the Ameren Corporation 2008 year-end earnings conference call on the 17 February, 2009. Throughout today's presentation, all participants will be in a listen-only mode. After the presentation, there will be an opportunity to ask questions. (Operator instructions) I will now hand the conference over to Mr. Doug Fischer. Please go ahead, sir.

Thank you and good morning. I'm Doug Fischer, Director of Investor Relations for Ameren Corporation. 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; our Vice President and Treasurer, Jerre Birdsong; our Vice President and Controller, Bruce Steinke, 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 hear it by dialing a callback number. The announcement you received in our news release carrying instructions on replaying the call by telephone. This call is also being broadcast live on the Internet and the web cast 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 Friday, and the forward-looking statements and risk factors sections in our periodic filings with the SEC. To assist in our call this morning, we have posted presentation slides on our website that we will refer to during this call. To access this presentation, you may look in the investors' section of our website under presentations and follow the links for the web cast. Gary will begin this call with comments on our recently announced common dividend reduction and provide an overview of 2008 earnings results and key regulatory and operating accomplishments. He will then briefly provide some perspectives on 2009. Marty will follow with more detailed comments on recent regulatory developments. Warner will then provide more detailed discussions of our 2008 results and our 2009 earnings guidance, liquidity, and financing plans and our overall earnings growth objectives. We will then open the call for questions. Here is Gary.

Thanks, Doug. Good morning and thank you for joining us. Last Friday, Ameren’s Board of Directors made the very difficult decision to reduce the quarterly common dividend to $0.385 cents per share, which is consistent with an annualized rate of $1.54 per share. We recognize the importance of our common dividend to our investors and this dividend reduction, while clearly prudent was not a decision that our board took lightly. It was made only after implementing many other less painful steps. We put in place plans to significantly reduce 2008 and projected 2009 capital and operating expenditures by approximately $800 million. We also reduced executive management salaries and incentive compensation opportunities and placed firm controls on headcount and operating expenditures. If you look at slide 3 of our presentation, as you would expect the decision to reduce the dividend was made after careful evaluation. First and foremost, the decision to reduce the dividend was based on the desire to enhance Ameren’s financial strength and flexibility as we manage our company through these unprecedented times. In addition, we recognized that Ameren’s business mix has shifted over the past several years with significant earnings and cash flow contributions coming from the non-rate-regulated generation business. The board also took into account the dramatic changes that have taken place in the economy in the capital credit and commodity markets. It is important to note that while Ameren is a financially strong company with solid current liquidity, we are not immune to the impacts of the current economic environment. Like other companies in our industry, Ameren is being impacted by a general economic downturn resulting from the global economic recession that we expect will lower customer electricity and natural gas usage in the near term and produce some uncertainty around future usage as well. The…

Thanks, Gary. As Gary mentioned we made good progress on the regulatory front in 2008 and early 2009. As we have previously discussed, in late September, the Illinois Commerce Commission or ICC authorized new electric and gas rates for our Illinois distribution utilities, AmerenCIPS, AmerenCILCO and AmerenIP effective October 1, 2008. As summarized on slide six, these new rates provide approximately $161 million in additional annual revenue, allowed returns on equity of nearly 10.7%. The ICC also approved an increase in the monthly charge for gas residential customers, such that it now recovers 80% of fixed delivery service costs versus the prior 53%. The remainder is recovered through volume-based charges. This will make our gas utility earnings less sensitive to volumetric swings. As shown on slide 7, we anticipate the redesigned gas distribution rates will result in a redistribution of margins during 2009. While the redesign is expected to have no net impact on full year 2009 results, we do anticipate margins in the first quarter will be $0.05 per share lower than in the same period in 2008, and that this decline will be offset by higher margins in the second and third quarters as shown on the slide. The increased rates are already improving the earnings and cash flows of our Ameren Illinois utilities from depressed levels. We consider the Illinois rate order a clear sign of the progress we are making towards restoring the financial health of our Ameren Illinois utilities. However, as we have previously discussed, we expect that the new Illinois rates will not fully recover the level of costs we are currently experiencing, especially financing costs. As a result, we expect our Illinois distribution utilities’ earnings to fall short of allowed rates of return. Consequently, rate case filings with the ICC are being targeted…

Thanks, Marty. Turning first to our 2008 earnings results, please turn to page 10 of our slide presentation. We announced 2008 net income in accordance with Generally Accepted Accounting Principles of $605 million or $2.88 per share compared to 2007 GAAP net income of $618 million or $2.98 per share. Excluding certain items in each year, Ameren recorded 2008 core or non-GAAP net income of $622 million or $2.95 per share compared to 2007 core net income of $685 million or $3.30 per share. We recorded several significant items in 2008 that we have excluded from our core earnings. The net costs associated with the Illinois comprehensive electric rate relief and customer assistant settlement agreement reached in 2007 reduced GAAP earnings by $0.13 per share into 2008, which was a $0.21 per share production in 2007. Net unrealized mark-to-market losses reduced 2008 GAAP earnings by $0.07 per share as compared to net unrealized mark-to-market gains of $0.04 per share in 2007. A lump-sum settlement payment in 2008, from a coal supplier for expected higher fuel costs in 2009 as a result of the premature closure of a mine and termination of a contract, benefited 2008 GAAP earnings by $0.08 per share. However, the contract termination will result in higher fuel costs for non-rate-regulated generation in 2009. Missouri accounting and electric rate orders directing our Missouri utility to record a regulatory asset for the January 2007 severe ice storm costs and authorizing amortization and recovery of these costs increased 2008 GAAP earnings by $0.07 per share. The Missouri rate order directing amortization and recovery over two years of previously incurred costs, pursuant to a 2007 Federal Energy Regulatory Commission or FERC order increased 2008 GAAP earnings by $0.04 per share. The 2007 FERC order retroactively reallocated certain MISO costs among MISO…

Thank you. (Operator instructions) Thank you. The first question is from Mr. Paul Patterson from Glenrock Associates. Please go ahead. Paul Patterson – Glenrock Associates: Good morning guys.

Good morning Paul.

Good morning. Paul Patterson – Glenrock Associates: I want to touch basically on I guess, the earnings going forward in 2010 and 2012 you guys gave us a presentation earlier in 2008, and you mentioned also prices going down. How should we think about, excuse me, how should we think about the impact of lower power prices and what your outlook is now?

Paul, this is Warner. I think as you recognized power prices have obviously fallen significantly. And so the guidance that we provided to you back in January of 2008 is no longer valid at this point in time, and what we have provided to you is our earnings per share guidance for 2009 and at this point nothing more beyond that. Paul Patterson – Glenrock Associates: Okay.

So to address your question with regard to the guidance that we provided in early 2008.

Paul, just to give you a little benchmark on that, you know, we sell a little over 30 million megawatt hours per year from that business and a $10 moment in price then means a $300 million movement in margin in that business. So, relatively small movements in price generate substantial movements in margin. And the price decline that we've seen since about last summer is on the order of $30 per megawatt hour, which is on the order of $1 billion or could be a decline of $1 billion from where we were last year; however, because of our hedging policy, prices were locked in substantially above where the market is and well we will see some decline in earnings this year and we expect to see some weakness in the market in the future years. The hedging, really, has helped sustain earnings in that business. Paul Patterson – Glenrock Associates: Okay. You mentioned $53 that is your hedge that I believe for this year, correct.

That is about right. Paul Patterson – Glenrock Associates: Okay, and then what is it in 2010 and how much lesser you hedge then? Could you just give us a little more flavor on that?

Sure. If you look at slide 13 Paul. Paul Patterson – Glenrock Associates: Right.

On our presentation, you will see that for 2009 we are hedged at 95% and that is why there is about a $52 per megawatt hour. In 2010, you know, we are not disclosing the specific hedge number that we have out there in terms of price, but you can see that we have hedged 60% of that already for 2010, and as Gary pointed out we are very proactive while those markets were more liquid especially earlier in 2008 to try and take some of that hedging of, as well as that incorporates the swap agreement that we entered into as part of the electric rate relief settlement in Illinois a couple of years ago. Paul Patterson – Glenrock Associates: Okay.

That pricing is out there and very visible. Paul Patterson – Glenrock Associates: Okay, so we will get better ideas, I guess, when you guys have your meeting in the spring about what those prices might be because just looking at the hedge number of 60%, it is really hard for us to sort of, to know what that actually translates into.

Sure. You know, in terms of that when we come back out in the spring, we will be able to provide you as we did last year some more color around not just the hedges, but also on the power side, but also gives you some more color on the fuel side as well. Paul Patterson – Glenrock Associates: Okay. Then with respect to the regulated ROE and what you guys have, you know, the challenge there in terms of earning at. When do you think you – do you think there will be an opportunity to catch up. I know you guys have lowered CapEx, etc. But I mean that might probably start up again. I mean I'm just sort of getting – trying to get an idea as to when that regulatory lag will be in a perpetual situation of serve under earning or could you elaborate a little bit on that and just with respect to the dilution of $0.23 per share, how should we think about how much equity is a component of that.

A couple of points Paul to try and address you. First, on the terms of regulatory lag, is there an opportunity for us to narrow the gap. The answer is simply, yes, and we are taking actions to narrow that gap. Number one, through the filing of more frequent rate cases, number two, looking for the ability to implement cost recovery mechanisms that give us more timely recovery. One example of that would be the environmental cost recovery mechanism rules that are currently being under study in the State of Missouri. That certainly is an opportunity as we continue to make meaningful environmental capital expenditures in that business for us to mitigate the regulatory lag that we see prospectively. And certainly, you know, we in terms of how we time the filing of our rate cases, we are going to be mindful of our ability to try and put the most current level of costs as well as update those filings in our rate cases and try and mitigate ultimately that regulatory lag.

In terms of the dilution that you asked with regard to 2009, what is reflected in there is the dilution associated with DRIP program, which is about $0.03 to $0.04 per share. Beyond that the rest of that is really related to debt financings that we reflected in there. Paul Patterson – Glenrock Associates: Thanks a lot.

Okay.

Thank you. The next question is from Greg Gordon from Citigroup. Please go ahead with your questions. Greg Gordon – Citigroup: Good morning gentlemen.

Good morning, Greg.

Good morning, Greg. Greg Gordon – Citigroup: I know the dividend cut is a very difficult decision guys, but I think –

Greg, I'm sorry. We cannot hear very well. If you can maybe speak into the speakerphone, I apologize. Greg Gordon – Citigroup:

Yes. Hear you much better now, thank you. Greg Gordon – Citigroup: I was just going to say I know the change in dividend policy was a very difficult decision for you guys, but I know you made the right decision in the long run for your share holders.

Thank you. Greg Gordon – Citigroup: The lower – a couple of questions. What is your specific expectation for lower volumes in – what is a specific volume output expectation at the generation business for 2009? You said that you were expecting all things equal, lower volumes because of market conditions.

Yes. Greg, this is Warner. The output for our unregulated generations segment is currently expected to be 30 million megawatt hours for 2009. And as we have said, we frankly have the availability and capacity to increase that as power prices increase. We – back in November we had estimated based on market prices at that time that we would generate economic generation of approximately 32 million megawatt hours. Because of that fall in market prices, we are now down at 30 million megawatt hours. Greg Gordon – Citigroup: So, if prices were to recover, not only would you see higher margins on the 30 terawatt hours of production, but you might be able to increase volumes as well.

That is correct. Greg Gordon – Citigroup: You said $0.03 to $0.04 dilution from the DRIPS. What is that in terms of you know, hundreds of millions of dollars of issuance to the DRIP?

In terms of cash flows, the DRIP is probably going to generate about $80 million of cash under the program, assuming you are at the same level of participation. Greg Gordon – Citigroup: Thank you, and then final question. When we were – met with you in November, you indicated that you're contemplating a pretty severe cut in capital expenditures, you know, down to as low as $1 billion for 2009 from the prior budget, which looking at your March ‘08 10-K which was a $1.8 billion. It looks like you are now budgeting $1.685 billion. I'm assuming that some of that is a function of the fact that year now moderated the dividend payment. Can you talk about what is in and what is not in for 2009 guidance as it compares to what you said at EEI.

Sure. It is a bit complicating but let me try my best. We came out of the EEI, you know, we said we had a targeted meaningful reductions in both the unregulated generation business as well as our regulated business. At that time, we had actually identified specific reductions that we're going to take actions on in our unregulated generation business, and in fact those range from approximately $300 million to $400 million around 2008 levels. And in fact, when you look at both 2009, you will have to look at just 2009, but you have to also look at the reductions that we made in 2008 because we moved out very quickly to reduce our capital expenditures. And so when you look at both the reductions in 2008 versus our original plan versus where they ended up in 2009, we actually achieved approximately $400 million of both capital and O&M reductions in our unregulated generation business. On the flip side, we had said that we are going – we had identified about $400 million to $500 million of potential reductions in our regulated businesses and that we are going to continue to assess them, and in fact we did. And ultimately, when you look again between 2008 and 2009, you will see a combination of capital and O&M reductions, which approximate $300 million or so compared to our original estimates. However, we did not go all the way up and get all those reductions in our regulated businesses simply due to the fact that the Sioux scrubber project that we had identified. We thought it was more prudent to continue to move forward with that project among a few others. And so all those factors, coupled with the other things that we've done with our financial plans you described, ultimately got us to the decisions that we have made to get to our current capital expenditure and operating expenditure levels. Greg Gordon – Citigroup: Okay. I see that now, the CapEx for ‘08 actually came in almost $340 million lower than the beginning of the year budget.

Yes. Greg Gordon – Citigroup: And then you're just over $100 million later in ‘09 than the prior budget.

So it is a combination. When we were looking in November, obviously, we were not sure how quickly we can get claim on those capital expenditures out of ‘08, but we were able to make meaningful progress in ‘08 and then obviously again in ‘09. Greg Gordon – Citigroup: But the Sioux scrubber will continue as planned and the majority of the regulated capital expenditures continue to be in the budget.

Yes, by and large the Sioux scrubber was – it is a little bit delayed from what our original plans were but we are going to continue to move forward at Sioux scrubber on a more expedited basis than we had discussed in the fall. Greg Gordon – Citigroup: Okay, thank you gentlemen.

Sure.

Thank you, and the next question is from Yiktat Fung from Zimmer Lucas partners. Please go ahead with your question. Yiktat Fung – Zimmer Lucas Capital: Good morning.

Good morning. Yiktat Fung – Zimmer Lucas Capital: With regards to the CapEx cuts again, are you assuming that I think during EEI, you mentioned that you could move potentially, I think $500 million of environmental CapEx from the 2009 to 2012 timeframe back to beyond 2012. Is that move assumed in your CapEx guidance that you're currently giving out?

Yes. This is Warner. You know, as it reflected right now that you are relating that to the variance request that we made to the Illinois Pollution Control Board. At this stage, our initial variance request was initially turned down what we consider on some of the sort of the technical considerations in terms of how we made the filing, and so we are going to continue to seek that variance request with the Illinois Pollution Control Board, but our existing capital expenditure budgets include those dollars in our current plans until we get a final ruling from the Illinois Pollution Control Board. Yiktat Fung – Zimmer Lucas Capital: So, if you prevail there is an opportunity to potentially cut the CapEx even more?

There will be an opportunity for us to defer some of that CapEx out from the ‘09 to ‘11 time period out beyond ‘12 through ‘13 and beyond. Yiktat Fung – Zimmer Lucas Capital: And when would you expect a final decision in that issue?

No it is uncertain. The Pollution Control Board has not said a specific date, but we would expect that to be sometime in the second and third quarter, before we get a final determination on that at least at this time. Yiktat Fung – Zimmer Lucas Capital: Okay. With regards to your second guidance, I was wondering if you could allocate some of those items that you listed on slide 14 that gives 2009 earnings guidance to each segment, was that both the depreciation and the pension and benefit cost. Those items that are not exactly clear where they reside in the three segments.

Sure. I guess some of those I think, we've identified as part of the conversation. For instance, the dilution and financing we had identified in our call $0.13 of the $0.23 related to the regulated operations where the rest really related to the unregulated generation. The pension and OPEB costs, Marty do you have more of a breakdown on that one?

Yes. I have more of a breakdown in terms of components being you know, active medical and pension, but not so clear of a breakdown frankly on the segment guidance.

You know, what we can do to break that down a little bit for you. We can probably give you little bit more of that information by segment. But certainly when you look at the pension and OPEB cost primarily that in large part will be driven by the unrelated generation segment. Remember, we have this pension and OPEB cost tracker in Missouri. So that is helpful there in part as well as in the distribution system reliability, a good chunk of that still relates to the Missouri operations in Illinois, probably a little bit more in Missouri versus the Illinois at this point in time. We can come back to you with a little bit more detail and we can provide some of that certainly at Analyst Day to kind of help you through some of those specific line items if you would like us to. Yiktat Fung – Zimmer Lucas Capital: Okay. That will be great. Just a couple of more questions. Can you kind of explain the out performance at the non-rate-regulated segment in 2008? I think that segment beat your – the top end of your guidance by about $0.09 and also the slight underperformance at Union Electric.

Yes, you know, I think there are a couple of things to think about there. With regard to the unregulated generation segment that was principally driven by solid operating performance by our generating units. They delivered record generation levels, and so we are pleased to see not just the record generation levels but the improvement in overall the plan operations. So that was certainly one of the key drivers there. Yiktat Fung – Zimmer Lucas Capital: Those being the higher output?

Yes.

And I think the other thing too that power prices were a little bit better in terms of what we done, and then also we are active at the beginning of ‘08 to really hedge before prices fell later or open generation position. So it is a combination of all those things really drove the performance there. In terms of UE being slightly down, certainly we had some incremental financing cost, we had replaced our auction rate debt earlier in the year at costs, which were certainly higher; and then beyond that, I think they had a few related Callaway outages. So they had a Callaway outage later in December which you know, affected a little bit their operations, and then really it is just a bunch of cats and dogs, including some tax related items that drove it down, but nothing significant. Yiktat Fung – Zimmer Lucas Capital: And just one final question, with regards to the hedging disclosure that you gave. Is that $53 that you mentioned during EEI for 2009 still valid?

Well, what we have said, I just spoke I believe is to Paul a little bit earlier, that number for 2009 that you see on slide 13 that 95% hedge. That is at $52 per megawatt hour. That number is good. Yiktat Fung – Zimmer Lucas Capital: Okay, and does that $52, is that just the around-the-clock price or it does also include the margins from capacity payments and ancillary services.

I'm sorry, I didn't hear the question. Yiktat Fung – Zimmer Lucas Capital: Is the $52 just the around-the-clock component or does that also include capacity prices? Do you also mix in the capacity revenues and the ancillary service revenues?

Yes. Some sort of that. That is all in price. Yiktat Fung – Zimmer Lucas Capital: All in price, okay. Thank you.

Thank you. The next question is from David Frank from Catapult Capital. Please go ahead with your questions. David Frank – Catapult Capital: Yes. Hi good morning Warner.

Good morning David. David Frank – Catapult Capital: I guess given all the talk of uncertainties like future carbon regulation, commodity price volatility, has any of this caused the management consider divesting the coal plans, the merchant coal plans, are you married to those plans for now?

Yes, David this is Gary. Actually, we have considered divesting in some of the units and that work hasn’t gone public yet, but we are putting in place a plan to potentially sell some of the smaller units. David Frank – Catapult Capital: Like the small coal units in Illinois.

The smaller coal units like Meredosia. David Frank – Catapult Capital: Is there a market out there now for those plants do you think?

There is potentially some market for them and we don't know the full answer to that question, but there is potentially a market. It depends on the buyer and what the buyer like co-ops and munis may be interested in those kinds of units. David Frank – Catapult Capital: Okay. And just on that note, have you actually refiled yet with the State of Illinois on the delay of the pollution spending or can we expect you to make that filing soon?

David, this is Warner. We have refiled that. A few weeks ago, we did make that filing and so, you know, we – the process started and so we anxiously await the Illinois Pollution Control Board’s decision here later this year. David Frank – Catapult Capital: Do we ever find out why it took them so long just to come back and say you didn't file it appropriately or you made some technical, there were some technical problems, I mean.

You know, David, I think the Illinois Pollution Control Board addressed that in the normal course of their procedures, and so I wouldn't suggest that it was sort of a delay, you know they considered it, they made a decision. And so, we've been working with the Illinois EPA to in terms of making our amended filing, and so I wouldn't suggest that they sat on their hands in any way. I think they just went through the normal course of business. David Frank – Catapult Capital: Okay, all right. Thanks guys.

Thank you. The next question is from Jeff Coviello, Duquesne Capital. Please go ahead. Jeff Coviello – Duquesne Capital: Hello.

. : Reza Hatefi – Polygon Investment Partners: Thank you. Would you also happen to have a forecasted unregulated generation number for 2010, I think 2009 you said 30 terawatt hours.

Yes. At this time we are not providing any guidance beyond 2009 in terms of generation levels. We will be able to give some more color, when we come back to you in the spring in Analyst Day, but at this point we are sticking with just 2009. Reza Hatefi – Polygon Investment Partners: Okay, and how about percentage hedged for 2011 for power. Is that available now or –

No at this point we, you know, we are not providing the specifics but certainly when you look at it, you know, we already had the swap out there, which we entered into some time ago and that was probably approximately 25% of the overall generation under historical generation levels. But beyond that, no we are not providing any other guidance for 2011 at this point in time. Reza Hatefi – Polygon Investment Partners: Okay, and back at EEI you had – I think you also spoke about this today a little bit. You had forecasted $50 million to $100 million of operating expense reductions I think at the unregulated operations for 2009. Is that still the range? Is that still good for O&M cut $50 million to $100 million and is that, is that – is it better to – is that a cut versus 2008 levels or is that an elimination of expected higher O&M that is no longer there in ’09?

Sure. With regard to the guidance we gave you, we bet those reductions were achieved in the unrelated generation business. In terms of, you know, eliminated versus deferred, I think frankly it is a combination of some of those depending upon certain of the capital expenditures, which obviously drive some of the O&M as well, but I don't have a specific breakdown as to which of that would be entirely eliminated prospectively versus what may show up in the later years. Reza Hatefi – Polygon Investment Partners: Okay, and do you happen to have a – formulated a new estimate of sorts regarding environmental CapEx going forward. I guess some of that is still up in the air with the Illinois issues, but is there any update on that at all.

You know, in terms of the overall environmental, you know, what we will do certainly at the end of this month, we will provide the information in our 10-K that will outline our five-year capital expenditure plan, and we will have some insight in there in terms of environmental, and reflected in there will be some color around the various issues that we’ve talked about including not just the Illinois Pollution Control Board, but obviously care [ph] has been reinstated. So we will have to reflect those provisions in our guidance as well as, you know, other rules associated with the Illinois EPAs rules and regulations. (inaudible) give you some more color here very soon on that and certainly when we come back to you at our Analyst meeting, we will be able to give you even more in-depth discussion around that. Reza Hatefi – Polygon Investment Partners: Thank you very much.

You're welcome.

Thank you. The next question is from Mr. Jeff Coviello. Please go ahead with your questions.

Jeff, are you there? We obviously are having phone connection problems with you because if you speaking, we obviously can't hear you. So operator if you can go to the next question please.

Thank you. Mr. Coviello's line has now disconnected. I do apologize. Again the next question is from Michael Lapides from Goldman Sachs. Please go ahead sir. Michael Lapides – Goldman Sachs: Guys, a couple of just CapEx related questions. Can you just refresh our memories which coal plants on the non-reg side you're scrubbing in 2009 and adding SCRs to?

In 2009, we are scrubbing Coffeen plant and Duck Creek plant. And SCRs, we've already added at Coffeen and any others.

I don’t recall any other SCRs. I think that is it. Michael Lapides – Goldman Sachs: And how long are the outages at each plant as you are finishing up installing the scrubbers, I mean just on average?

I can’t give you a precise number, but it is in the range of 12 weeks to tie in the scrubber for the final operation. Michael Lapides – Goldman Sachs: Got it, and when we think about the Illinois requirements that exist today regardless of, you know, assuming current rules no variance, which are the plants that have to be scrubbed or have SCRs on them by 2013 or 2014?

The Newton plant and Edwards plant and those are the two that we asked for variance from the Illinois Pollution Control Board in order to move those out into the later years. I still am fairly confident that we will get that, but in the meantime we have moved that capital requirement back into the earlier years, and so it is reflected in our current capital estimates for ’09, beginning in ‘09. Michael Lapides – Goldman Sachs: Meaning that you’ve got in your ‘09 CapEx guidance some CapEx related to putting scrubbers on either or both Newton and Edwards that may actually get pushed out if you get the variance?

That is correct. It is in ‘09, ‘10 and ‘11 currently and would get pushed on beyond that time period if we get the variance. Michael Lapides – Goldman Sachs: Got it. Okay, thank you guys.

Thank you Mike.

Thank you. The next question is from Steve Gambuzza from Longbow Capital. Please go ahead. Steve Gambuzza – Longbow Capital: Good morning. Following up on Michael’s question, what exactly is the non-regulated CapEx guidance for 2009?

Sure. Why don’t I try and actually just give the specifics for all the segments, because my guess is that that is of interest to the entire group. I mean in general, the Missouri regulated segments will have capital expenditures of about $835 million. The Illinois regulated segment is right around $440 million. The unregulated or non-rate-regulated generation segment is around $400 million, and then we have other capital expenditures of approximately $10 million, which should bring you very close to the numbers that we have identified for our capital expenditures of approximately $1.7 billion. Steve Gambuzza – Longbow Capital: Okay, and Coffeen and Duck Creek will those scrubber installations be completed in 2009?

Duck Creek is being completed now and Coffeen is in early 2010. Steve Gambuzza – Longbow Capital: Okay, will – what percentage of Coffeen’s capital cost will be completed by the end of 2009? Will it be substantially complete in terms of the capital spending?

Say, most of it will be done by then. Steve Gambuzza – Longbow Capital:

I think with regard to – is your question, I mean the Coffeen and Duck Creek are moving forward? Steve Gambuzza – Longbow Capital: Yes.

So your question relates to Newton and Edwards. Yes, I think with regard to 2009 that number probably ranges between $30 million to $50 million that can be moved out as a result of that. The bigger impact for those frankly are in the ‘10 and ‘11 time period. Steve Gambuzza – Longbow Capital: Okay.

Okay. Steve Gambuzza – Longbow Capital: And is the non-environmental kind of maintenance related CapEx at the non-reg is that in the kind of $50 million to $100 million range?

I would say in terms of when you look at the unregulated generation, you look at the discretionary CapEx or the nonenvironmental CapEx that has been taken down very meaningfully in terms of where they are at. So, I'm not sure, it is something less than $100 million in terms of –

$100 million would be a more normal number, I think it is in the 20 to 40 range. Steve Gambuzza – Longbow Capital: Okay. So it looks like there is roughly $300 million in 2009 for finishing Coffeen and Duck Creek.

You know, I think in terms of the specifics, you know, I think we can come back to you in terms of what those specific projects are in terms of ’09. I think that to say that that is exactly that number. I think I'd like to hold off on that and then we can provide some more guidance to you on that specifically later. Steve Gambuzza – Longbow Capital: Okay, and you pointed about the non-regulated O&M expense reductions of $50 million to $100 million that is embedded in your 2009 outlook, and I guess that is not necessarily $50 million to $100 million sequential decline or it is versus what your old plan was. Is that the way to think about it?

Well, you know, I think when we look at the $50 million to $100 million, yes. And indeed that is in our plan, number one, and then two when we talked about that before when you look at overall O&M expenditures compared to ‘08 levels those are the kind of numbers that we are trying to achieve and we did. Steve Gambuzza – Longbow Capital: Can you give a sense for sequentially what that means of what ‘09 non-reg O&M would be sequentially versus where ‘08 came out?

In terms of the top, I do not have that on top of my head in terms of what that would be. I'm sorry. Steve Gambuzza – Longbow Capital: Okay, and then finally at your 2008 Analyst Day you provided an outlook on estimated fuel costs for the non-reg business as well as your hedge position, which has been substantially filled out, particularly – essentially all in 2009 and that 2010 piece with the signing of the transport contracts has been substantially filled out, and at that time you forecasted non-regulated fuel costs to rise by $2 a megawatt hour in ‘09 versus ‘08 and then a further $2 a megawatt hour in 2010. This seems – this is obviously very important information. I was wondering if you could provide any additional color on that now or if not should we do know, at least think of those – those increases are still being in the ballpark of what you have locked in.

Sure. I think what we can provide you is ‘09 versus anything beyond that because consistent with what we said, we are going to stick to our ‘09 numbers and then provide the other information in an appropriate fashion either at Analyst Day or even and later, but when you look at ‘09 for the unregulated generation, we expect those fuel costs to come in around $23 per megawatt hour roughly for 2009, which is up a little bit from what I think will were in Analyst Day. Steve Gambuzza – Longbow Capital: And what was the driver that was just the potential, was it on – can you comment on what diverged in terms of you know, driving those costs higher.

I think, number one, we had some more environmental requirements in terms of what we had to do to increase those costs so that was part of that increase I think in terms of where we ultimately landed. Remember, we still had some of the transportation costs. But then the other piece, remember we had, and we talked about this during the year, was the Exxon contract termination. Remember, we said that we picked up the entire gain. Steve Gambuzza – Longbow Capital: Okay.

Steve Gambuzza – Longbow Capital:

That is right. Steve Gambuzza – Longbow Capital: Okay.

It is an apples-to-apples comparison. So that is one of the biggest drivers and that is probably $25 million to $30 million. Steve Gambuzza – Longbow Capital: Pre-tax.

Yes. Steve Gambuzza – Longbow Capital: Okay. That's very helpful and then your –

Steve, we do remember we did get paid for that. Steve Gambuzza – Longbow Capital: Yes, understood.

We get paid for that. Steve Gambuzza – Longbow Capital: So that you received the cash in ’08.

That is correct. Steve Gambuzza – Longbow Capital: Okay, and then your financing plans $500 dollars at the Genco, you know, clearly credit markets have improved and there is kind of a window now that exists. You know, are you – but it seems like this, who knows how long this window will last. Could you comment on what part of the year you might consider doing that that Genco financing?

Do you know, as I said in my talking points, in terms of our overall financing plan, whether it be debt, equity or linked directly, we are going to be opportunistic and proactive and access through the markets to finance our plans including looking at this unregulated generation financings. Certainly, we strongly believe that the actions that we have taken in terms of not just capital expenditure reductions but also the action that we took with regard to the dividend, obviously is credit enhancing and will give us greater ability to execute all of those financings not just in 2009 and beyond. So, in terms of timing, you know, I think that as you point out, we will watch carefully the markets. We will access it when we believe it is appropriate to get reasonable terms to get that across the finish line. Steve Gambuzza – Longbow Capital: Is it fair to say you like to get the Illinois Pollution Control Board situation resolved before proceeding with that financing?

You know that is a factor. Certainly it is a factor to say that is the factor and the only factor that would not be appropriate to say that. Steve Gambuzza – Longbow Capital: Okay. Thank you for your time.

Sure.

Thank you. The next question is from Zach Schreiber from Duquesne Capital. Please go ahead with your questions. Jeff Coviello – Duquesne Capital: I think let us try this again. Can you guys hear me?

Yes Jeff. Jeff Coviello – Duquesne Capital: It is actually Jeff.

Hi, Jeff. I am sorry. Jeff Coviello – Duquesne Capital: Sorry about that. I don’t know what happened.

You beat me here. Jeff Coviello – Duquesne Capital: I wanted to ask two questions. The first is on the strategic review of the coal plants you mentioned earlier in the call. I'm just wondering if that encompassed all the units or you’re only really looking at the small ones. Or if it could, in fact, give the whole segment and then the second question just has to do with 2010 hedging and I realize you're not going to give out an exact number, but is it – do you think if it being above the 2009 number as far as the price you hedged at or below it.

I will address the second question and let Gary, you know, tackle the strategy one here in a moment. In terms of the other, I really don't want to give sort of you know, leaning one way or the other. It is just – it wouldn’t be appropriate at this point in time. I will say as we said in the past that we were aggressively trying to hedge out some of those positions in those outer years. Obviously, as you know, the liquidity in those markets began to dry up more so as the year went on in 2008, but we have put some of those positions on earlier as you even saw some of our earlier presentations in terms of hedge percentages were. So, we will be able to give you some more of that insight, as well as to think that would be helpful when we talk more. We will be, obviously, we are a peak [ph] process, which is going to be taking place in Illinois (inaudible) sometime in the second or third quarter. And so that will be instructed to in terms of not just ‘10 but also some of the years beyond ’09. We will be able to give you some of that. Now, let Gary comment a little bit more on the final strategies and thinking around the unregulated generation plans.

Yes, Jeff as far as the strategic review, we still believe that our merchant generation business is a good complement to the regulated business. It is just as not a business so that we can count on to pay the dividend year-after-year because of the volatility of the commodity cycle. But a good point to note though is that even with this downside market that we are seeing now which is probably the worst recession that the US has experienced in 40 or 50 years and severe down commodity market. You know, we are weathering this reasonably well. We do expect to see an earnings decline this year and soft earnings for a couple of years, but we expect this business to remain positive and be a good earnings contributor to our company long-term. The strategy though that we are kind of moving to with the reduced dividend is the ability to pay the dividend from the regulated businesses. And as the earnings in the regulated businesses grow, we would hope to grow the dividend in the future, and we have materials in fact included in our material. As you can see that with the increase in earnings this year of $1.75, we are able to fully cover the dividend from our regulated businesses. Jeff Coviello – Duquesne Capital: And so I guess so, on the non-reg strategic review then is just looking at individual assets, I think some smaller assets.

Jeff Coviello – Duquesne Capital: Okay, thank you very much.

Thank you. The next question is from Mr. Scott Engstrom from Blenheim Capital. Please go ahead. Scott Engstrom – Blenheim Capital: Thank you. Good morning.

Good morning Scott. Scott Engstrom – Blenheim Capital: Question on slide 11 and 14. On 11, you have the segment guidance and on the non-regulated ‘08 was $1.59 and the midpoint of ‘09 would be $1.20. So call that a round number is $0.40 delta year-over-year? And then on slide and I guess these questions have kind of been asked in different ways but maybe I will be more direct. Slide 14, you show, specifically your $0.5 from margin. I'm just trying to pick up the other $0.35. I think what you said is – the dilution is of that dilution $0.23 of $0.11 is at regulated or $0.12 is at regulated. So, I still assume $0.11 is non-regulated. Is that right?

Yes. I think the answer $0.23 was the dilution of which – yes, I mean, I think you've got that accurate. Scott Engstrom – Blenheim Capital: And you said substantially a large portion of the pension would be non-reg. So, if I said that was $0.06 and that gets me – those three items would get me to $0.22. Can you help fill the gap on where the other $0.18 is?

If I can try and answer your question, I think that on the pension and OPEB that I would say substantially, obviously a piece of that is part of the Illinois regulated operations as well, and then in trying to fill the rest of the gap, you know, I think you've got the depreciation and amortization is a meaningful number in there too, and a piece of that is not just the regulated operations, but a part of that will also be the unregulated. Scott Engstrom – Blenheim Capital: Okay. That is $0.15 in total. I assume maybe a third of that is unregulated. Is that going to be ballparkish?

I think that, you know, we can – Marty do you have any more specifics on that breakdown?

I don't have the specifics but I actually think the depreciation and amortization may be closer to half non-rate-regulated. Some of the projects we discussed earlier like the scrubber project at Duck Creek when those types of assets going to serve us will be using sort of a higher depreciation rate, I would say on those than some of our historical plants. So – okay.

And I think Scott you look at, for instance, the other taxes. I mean, you start picking up cats and dogs. And you probably have $0.03 to $0.04 of those other taxes related to some incremental property taxes we expect to incur at the unregulated generation segment. So, you know, I think that you started picking up those pieces here and there, you just started getting close to that reconciliation. We can, again in terms of the Analyst Day, we can provide some more substantive reconciliation if that would be helpful for you to identify or try to reconcile the numbers on a segment by segment basis. Scott Engstrom – Blenheim Capital: Okay, and then that will be – I will look forward to that, and if I focus just on the dilution line, say $0.11 just back on the envelope that is about $30 million pre-tax. Does that come from essentially financing negative free cash flows or is that related to higher financing costs. I mean how do you break that down between new financing and higher rates?

You know, I think it is really a combination of both of those. I mean, we're going to refinance some existing debt which is out there, as we laid out in the slide coupled with the fact that yes, we are experiencing negative free cash flow. We talked about the negative $500 million cash flow on an Ameren basis, and so as we said we are going to be out there issuing approximately $500 million of unregulated debt financings, and our plan is for 2009 and that is the combination to replace lower-cost, which is existing – which is outstanding already but also to access the markets to finance our existing operation. Scott Engstrom – Blenheim Capital: Last question, just trying to think about the impact of implementing the fuel cost at Missouri. If I look at on slide 14, the $0.39 impact of the rate case. Does that fix up I assume the uplift from getting the fuel cost and is the $0.06 of other electric and gas margin negative – the $0.06 negative. Does that capture losing some of the off-system sales? Is that how I should think about?

Yes. This is Marty. Let me try to help you with that. I think in terms of, you know, the Missouri rate case that what that $0.39 is, it is really the rate increase that we get, which is about $162 million less the amortizations we talked about on the call of about $12 million. And then it is about 10 months of that. That gives you the $0.39. So it doesn't incorporate the switch over to the FAC. That amount is buried down there, if you will, in the $0.06 of negative regulated electric and gas margins, and what you see down there is both the change in, you know, the January and February margins your year-over-year from ’08 to ‘09 prior to the rate increase going into effect and the FAC going into effect. It also incorporates the impact of moving from no FAC to an FAC, and as we provided you, I believe it was on slide 15, where we gave you the break down of the – what was in our 2008 actual income statement in terms of fuel costs in off-system sales, which was $277 million versus what was included in the rates that the commission grant, which was $328 million. That is the delta of about $51 million and that is actually on slide 9, I apologize. I think I directed you to the wrong slide, but that $51 million increase is included in that the rate increase granted by the commission. So, you would actually to figure out the impact again take ten-twelfths of that for the 2009 impact, which is about a $42 million 2009 increase in fuel expense that is embedded in the $162 million increase that the commission granted. So what you're seeing down there is those two items, the 2009 fuel cost increases, the change in January and February margins, and then that has been partially offset by load mix changes, and you know, other elements of margin that are not included in the FAC.

Vivian [ph], we have time for one more question.

Okay. Thank you very much. The next question is from Phyllis Gray from Dwight Asset Management. Please go ahead. Phyllis Gray – Dwight Asset Management: Good morning.

Good morning, Phyllis. Phyllis Gray – Dwight Asset Management: Could you tell me if the cash flow forecast on slide 16 reflects the Noranda outage impact?

I'm sorry Phyllis. Could you – we didn't hear that. Could you say again please? Phyllis Gray – Dwight Asset Management: Can you hear me better?

Yes. That is much better. Thank you. Phyllis Gray – Dwight Asset Management: Does the cash flow forecast on slide 16 reflects of the outage at the Noranda plant?

The cash flow forecast. No it does not, it does not reflect that. Phyllis Gray – Dwight Asset Management: Okay, thank you. And I'm sorry if I missed it, did you talk about any need for a cash contribution to your pension plan this year?

No, we haven't addressed that but our practice is to make a cash contribution equal to the expense. So, even though we would not have a required contribution this year, we would plan to make a contribution equal to the expense for the pension plans. Phyllis Gray – Dwight Asset Management: Okay, and is that included in your cash flow forecast on slide 16?

Yes it is. Phyllis Gray – Dwight Asset Management: Very good. Thanks very much.

You're welcome.

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