Douglas Fischer – Director, IR Tom Voss – President and CEO Martin Lyons – SVP and CFO Charles Naslund – Chairman, President and CEO, Ameren Energy Resources; Chairman and President, AmerenEnergy Generating Company Warner Baxter – President and CEO, AmerenUE

Paul Patterson – Glenrock Associates Reza Hatefi – Decade Capital Management Carl Seligson – Utility Financial Experts Yiktat Fung – Zimmer Lucas Dan Jenkins – State of Wisconsin Investment Board Billy Hagstrom – Catapult Capital Michael Lapides – Goldman Sachs Steve Gambuzza – Longbow Capital

Greetings and welcome to the Ameren Corporation’s fourth quarter and year-end call. At this time all participants are in a listen-only mode. A 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 Mr. Douglas Fischer, Director of Investor Relations for Ameren Corporation. Thank you Mr. Fischer, you may begin.

Thank you, and good morning. I'm Doug Fischer, Director of Investor Relations for Ameren Corporation. On the call with me today are our President and Chief Executive Officer, Tom Voss; and our Senior Vice President and Chief Financial Officer, Marty Lyons, as well as 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 contain 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. 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, please look in the investors' section of our website under webcast and presentations and follow the appropriate link. Turning to slide two of our presentation, I need to let you know that comments made in 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 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 sections in our periodic filings with the SEC. Tom will begin this call with an overview of 2009 earnings and 2010 earnings guidance followed by a business and regulatory update. Marty will follow with a more detailed discussion of our 2009 financial results, our 2010 earnings guidance and a financial update. We will then open the call up for questions. Here is Tom.

Thanks, Doug. Good morning and thank you for joining us. Moving to slide three of the presentation posted on our website, I'm pleased to report that 2009 non-GAAP or core earnings were $2.79 per share in line with our expectation. Key drivers favorably affecting 2009 core earnings per share compared to 2008 results included new utility service rates in Illinois and Missouri, and lower operations and maintenance expenses. These lower expenses were due in part to the absence in 2009 of the refueling outage at the Callaway nuclear plant, and proactive cost-cutting efforts across all of our businesses. These positive factors were more than offset by lower electricity and natural gas sales in our regulated utility businesses as a result of weak economic conditions in the Noranda outage and milder 2009 weather. Merchant Generation margins were also hurt by higher fuel costs and less generation being in the money. Higher depreciation and interest expense and an increased average number of common shares outstanding further affected comparative results. Turning to slide four today, we also announced 2010 GAAP and core earnings guidance of $2.20 to $2.60 per share. The expected decline in 2010 earnings from 2009 primarily reflects the lower projected Merchant Generation segment margins and earnings. While earnings of our regulated utilities are expected to improve, regulatory ladies and gentlemen is anticipated to result in earnings lower than those authorized by state commissions. Marty will provide further details on our 2009 earnings and 2010 guidance in his remarks. But before I turn the call over to him, I would like to provide a business and regulatory update. Looking now at slide five, electricity sale at our regulated utilities it is clear that the economy drove our sales down in 2009. While 2009 was indeed a difficult year, there are signs that the weak economy has hit bottom in our regions. In a positive sales development, the Noranda Aluminum smelter plant has continued to add to its load as the plant now starts returning to full capacity. You may recall that Noranda’s New Madrid, Missouri, smelter plant, AmerenUE’s largest customer sustained damage because of a power interruption on non-Ameren owned power lines during a severe ice storm in January 2009. As a result, the smelter’s load was sharply reduced, but has been rising steadily as repairs have been made to their production lines with full production expected to be reached early in the second quarter of this year. In Illinois, our industrial sales are expected to benefit significantly from the expansion of an oil refinery and the resumption of higher levels of operations at several other facilities. While increased industrial sales in Illinois will not significantly contribute to margins, the health of local businesses is certainly a key to the prosperity of all of our customers. Moving on to the regulatory front, we have rate cases pending in both our Illinois and Missouri jurisdictions. We are seeking revenue levels that reflect the significant investments we have made electric and gas utility infrastructure to improve reliability. We are also seeking recovery of higher financing costs, and in Missouri rising net fuel costs. As detailed on slide six, our Ameren Illinois utilities are currently requesting $130 million annual increase in base electric and natural gas delivery rates. This amount is less than our original request of $226 million due in part to the removal of revenues related to reliability audit expenditures. We are now seeking recovery of these costs in a separate rider. The lower rate request also reflects updates to our requested rates of return on equity and other items. The staff of the Illinois Commerce Commission or ICC is currently supporting a $46 million annual revenue increase. The staff’s lower revenue amount reflects their lower recommended return on equity of approximately 10.1% compared to our request of approximately 11.5%, and use of a lower pension and benefits expense level among other things. ICC Administrative Law Judges are scheduled to issue their proposed rate order in this case by February 25 with the ICC expected to issue an order in late April. New rates should be effective by early May 2010. Turning to slide seven, at AmerenUE we filed a request with the Missouri Public Service Commission in July of 2009 for an annual electric service rate increase of $402 million. More than half of the request was for anticipated higher net fuel costs. These increased net fuel costs would have been eligible for recovery through the fuel adjustment cost absence this filing. On December 18, the staff of the Missouri Public Service Commission filed its direct testimony in the rate case recommending an annual electric service rate increase of $218 million to $251 million with approximately $214 million of this related to higher net fuel costs. The staff's lower revenue amount reflects their recommended return on equity range of 9% to 9.7%, which was lower than our initial request of 11.5%. Staff’s revenue amount also incorporated lower depreciation, lower plant maintenance and financing costs levels as well as other adjustments. The staff testimony reflects continuation of the current fuel adjustment clause and the pension and OPEB trackers, and a modified environmental cost recovery mechanism. Other parties filed testimony in December including a group of large industrial customers and the Office of Public Counsel. The Office of Public Counsel recommended a return on equity of 10.2%. The large industrial customers recommended a rate increase of $139 million, which included $181 million increase related to net fuel costs. Their lower revenue requirement reflects their lower recommended return on equity of 10%, the use of significantly lower depreciation rates and plant maintenance expenses, as well as lowered financing costs and consumption levels among other things. It should be noted that the large industrial customers’ testimony reflects continuation of the current fuel adjustment clause, as well as the modified approach for the accounting and recovery of the environmental cost. Last Thursday, AmerenUE filed its rebuttal testimony in this case, which included among other things a modification of its originally requested ROE down to 10.8%. We anticipate that certain major changes to revenues, expenses, rate case and capital structure will be trued up through January 31, 2010 in an early March update. A PSC order is expected by late May with new rates effective in late June 2010. We are very aware that the prospect of higher utility rates is difficult for our customers in Illinois and Missouri, especially in this economic environment. We have taken many proactive steps across our company to control our cost in order to moderate the need for higher rates. These steps include reductions in planned operating and capital expenditures, headcount reductions, and the freezing of management salaries. As always, there are several issues which need to be carefully considered in these rate cases, some of which are rather complicated. We believe we have filed well supported rate cases in both Illinois and Missouri, and expect to be treated fairly by the respective commissions. Parties in both states have filed very aggressive positions in a number of areas, including return on equity, depreciation and certain operating expenses. These aggressive recommendations are not consistent with sound long-term energy policy, and would result in our need to reduce our level of investment in energy infrastructure and operations. For several years, our regulated utility businesses have been earning returns on investments that are well below our authorized levels, in part due to regulatory lag. We are committed to improving earnings to levels that represent fair returns on our regulated investments. We strongly believe that consistent, constructive regulatory outcomes will allow us to achieve this objective, as well as to continue to invest in our energy infrastructure on a timely basis in order to maintain reliability consistent with our customers’ expectations. I would like to shift from a discussion of our regulated utilities to an update on our Merchant Generation business. Currently power prices are lower, a condition very much linked to weak economic conditions. Weak economic conditions have reduced the demand for power and other energy commodities. We believe that when the economy recovers and we expect it to recover these prices will rise. In the meantime, we continue to look for every opportunity to prudently reduce our operating and capital spending in this business, as well as protect and enhance margins. We’ve a consistent practice of hedging both our power sales and our fuel costs. As a result, our margins were well protected in 2009, and we have a solid base of sales hedges for 2010 and out through 2012 at prices that are above current market prices. Such hedging protects credit quality and reduces earnings and cash flow volatility. In addition, we continue to focus on providing value-added electricity products to the market. Leveraging our competitive merchant generation asserts, our experienced power marketing group has a track record of enhancing margins through sale to wholesale and retail customers. Strength in our ability to successfully weather the current price environment, we have reduced planned operating and capital spending, substantially improving the cash flow outlook for our Merchant Generation business. Turning to slide eight, those actions have included updating and refining our strategy for compliance with current environmental standards. Most of you will recall that our Merchant Generation business reached an agreement with the Illinois Environmental Protection Agency in 2006. This agreement was ultimately adopted by the Illinois Pollution Control Board as a compliance alternative to the Illinois mercury regulations. These regulations, which are modified in 2009, require our Merchant Generation plants to reduce emissions for sulphur dioxide or SO2, nitrous oxide or Nox, and mercury over a number of years. The nitric oxide emissions standards phase in through January 1, 2012 and the sulphur dioxide emissions standards phase in through January 1, 2017. The mercury removal efficiency requirements are deferred to January 1, 2015. Nox and Sox compliance is determined on a system-wide basis. As you know, during 2009 we reduced over anticipated non-environmental capital spending in the Merchant segment by approximately $1 billion over the period of 2009 to 2013. Because of the excellent performance of recently installed scrubbers at our Duck Creek and Coffeen plants, which are achieving removal rights beyond those contemplated in our initial plans, we have been able to re-evaluate and improve our environmental compliance strategy. As a result of this performance and updated cost experience, our estimate of capital expenditures required for compliance with existing air emission standards for our Merchant Generation fleet has been reduced. We now expect these expenditures will cumulatively be between 1.2 billion and 1.5 billion over the period of 2010 through 2017. Our previously disclosed range of comparable capital expenditures was 1.5 billion to 2 billion. These estimates are for capital spending required to comply with regulation as of December 31, 2009, and would allow for each of our merchant coal-fired power plants to remain in service beyond January 1, 2017. As you would expect, we have teams in place that continue to evaluate our plans in light of changing technologies, power prices and delivered fuel costs in order to ensure that we identify the lowest cost options in terms of both capital and ongoing operating costs. Over the next two years our environmental capital expenditure plans are moderate. We will use this time to continue to evaluate our plans looking for any opportunities to reduce compliance cost. Over the past 18 months, we have reduced planned spending, headcount and investment across the company to mitigate the negative impact on sales of a weak economy and related lower power prices. We have also enhanced our financial strength and liquidity position. Our regulated utilities are controlling spending and seeking updated rates to recover our cost and earn fair returns on investment. I believe that our actions have established a solid foundation for executing on future strategies and creating long-term shareholder value. While we expect earnings per share to decline in 2010, we expect earnings from our regulated businesses to improve over time as a result of narrowing the gap between our earned and authorized returns, and investing in improving reliability and promoting a cleaner environment. Our Merchant Generation business is poised to benefit from an expected eventual recovery in power prices. Further, I believe the Ameren common shares provide investors with an attractive and sustainable dividend supported by our rate regulated utility earnings. I will now turn the call over to Marty to walk you through the details of our 2009 earnings and our 2010 earnings guidance.

Thanks Tom. Turning to slide nine, I would like to direct you to the year column, which reconciles 2008 earnings to 2009 earnings. 2009 net income in accordance with Generally Accepted Accounting Principles was $612 million or $2.78 per share compared to 2008 GAAP net income of $605 million or $2.88 per share. Excluding certain items in each year, Ameren recorded 2009 core net income of $615 million or $2.79 per share compared with 2008 core net income of $622 million or $2.95 per share. There are three items in 2009 that we have excluded from our core earnings. These are the net costs associated with the Illinois comprehensive electric rate relief and customer assistance settlement agreement reached in 2007, which reduced 2009 GAAP earnings by $0.08 per share. The net effects of unrealized mark-to-market activities, which increased 2009 GAAP earnings by $0.14 per share and employee separation and impairment charges related to our headcount reduction and facilities closures, which reduced 2009 GAAP earnings by $0.07 per share. Continuing with the 2008 to 2009 earnings reconciliation on slide nine, the Missouri electric rate increase, which took effect March 1, 2009 raised 2009 earnings by $0.40 per share, net of amortizations compared to 2008. The net increase in Illinois electric and natural gas delivery service rates effective October 1, 2008, lifted 2009 earnings by $0.40 per share compared to the prior year. We estimate milder weather reduced 2009 earnings by $0.15 per share compared to 2008, and by $0.13 per share compared to normal. Moving to the next slide in our year-to-year reconciliation, reduced sales to Noranda Aluminum lowered 2009 earnings by $0.11 per share. Other electric and gas margins for our regulated utility operations, excluding the impact of rate adjustments, weather and the lost Noranda sales, decreased earnings by $0.30 per share. As Tom discussed earlier, this decline in margin was largely due to lower electric and natural gas sales volumes as a result of the weak economy. The next line on the reconciliation is a $0.10 per share decline in our Merchant Generation segment’s earnings, reflecting the absence in 2009 of the gain recorded in 2008 for a lump sum settlement payment received from a coal supplier related to a contract termination. Other electric margins for the Merchant Generation business, decreased by $0.05 per share in 2009 compared to 2008. This Merchant Generation margin decline was largely due to having less in the money generation and higher fuel and related transportation costs, offset in part by improved realized revenue per megawatt hour. Proactive forward sales and hedges of 2009 generation, executed in prior years at higher than 2009 market prices, largely shielded Merchant Generation segment earnings from the impact of falling market prices for power. The absence of a refueling and maintenance outage at the Callaway nuclear plant boosted 2009 earnings by $0.09 per share versus the prior year. You will recall that Callaway is typically refueled every 18 months. So there is no refueling outage every third year. The next three lines on our reconciliation combined to reduce 2009 earnings by $0.02 per share compared to 2008. This reflected higher distribution system reliability spending and higher depreciation and amortization expense, offset by lower plant operations and maintenance expense. Higher financing costs and share dilution reduced 2009 earnings by a combined $0.31 per share versus 2008. Moving now to the other taxes line on the reconciliation, where higher property taxes contributed to a $0.06 per share increase in cost versus the year ago period. Finally, the net impact of other items including lower bad debt and non-plant operations and maintenance expenses, increased 2009 earnings per share by $0.05 per share compared to 2008. Turning to slide 10, I would like to discuss the key assumptions and drivers behind our 2010 core earnings guidance of $1.90 per share to $2.15 per share for our Missouri and Illinois regulated utilities businesses. In 2010, we expect to achieve returns on equity of approximately 7.5% to 8.5% on average expected 2010 utility common equity of about $6 billion. These returns are anticipated to be up from our average 2009 returns on utility common equity of approximately 6.5% to 6.8%. The guidance for our regulated utilities reflects expected new Illinois electric and gas delivery rates effective in late April or early May, and expected new Missouri electric rates effective in late June. Further, our guidance assumes some moderate electric sales growth. The sales outlook incorporates our expectations that the Noranda smelter plant will return to full operation early in the second quarter of 2010, adding an estimated $0.10 per share to earnings compared to 2009. Note that 2010 earnings per share guidance variances versus 2009 are calculated using 2009 average common shares outstanding. As usual, guidance is based on normal weather, which would add an estimated $0.13 to earnings per share versus the milder than normal 2009. In addition, the Taum Sauk pumped-storage hydroelectric facility is expected to return to service in the second quarter of 2010, improving margins by approximately $1.8 million per month. The scheduled spring refueling and maintenance outage at the Callaway nuclear plant is expected to reduce 2010 earnings by $0.09 per share compared to 2009. 2010 earnings guidance incorporates higher expected plant operations and maintenance expenses, primarily for scheduled work at AmerenUE’s coal-fired plant. Pension and benefit, depreciation and other tax expenses are also expected to increase in 2010 versus 2009. As I wrap up my discussion of 2010 guidance for our regulated utilities, let me be clear that the return on equity of 7.5% to 8.5% assumed in our guidance is well below the level we consider to be reasonable. As Tom stated earlier, our management is committed to lifting the return on investment at our regulated utilities to levels that are fair. For every 100 basis points by which our unregulated utilities under earn their allowed returns on equity, our shareholders are deprived of earnings of approximately $0.25 per share. We believe that given the current regulatory frameworks in place in Missouri and Illinois, achieving these higher returns will not be accomplished in one rate case proceeding. We are focused on achieving fair returns by pursuing consistent, constructive regulatory outcomes including mechanisms that reduce regulatory lag as well as synchronizing our spending consistent with the level of rates authorized by the respective commissions. Turning to slide 11, let us now move to a discussion of the key drivers and assumptions behind our 2010 Merchant Generation business earnings guidance. We expect this business segment to post core earnings of $0.30 to $0.45 per share in 2010. The largest driver of the decline in Merchant Generation business earnings from 2009 to 2010 is a decrease in expected margins of $0.70 to $0.80 per share. We expect our base load merchant plans to generate approximately 30.5 million MWh in 2010. Approximately 26 million MWh of this is hedged at an average price of $47 per megawatt hour. Our expected margins assume that all non-hedged expected generation is sold at current market prices. In 2010, we anticipate having base load capacity available to generate 35 million MWh in the event power prices rise, and support higher generation levels. A $5 per megawatt hour improvement in 2010 market power prices as compared to current prices would increase our expected 2010 generation output by approximately 1.5 million MWh, and our expected 2010 Merchant Generation margins by approximately $30 million. Our all in base load fuel cost are 100% hedged at approximately $23.25 per megawatt hour. Lastly, the Merchant Generation business is expected to post higher depreciation and interest expense in 2010 compared to 2009. Moving now to key companywide assumptions, our earnings guidance reflects an expected effective consolidated income tax rate of approximately 34%, and average number of common shares outstanding of approximately 239 million for 2010. As I close our discussion of 2010 earnings guidance, I will remind you that any net unrealized mark-to-market gains or losses will affect our GAAP earnings, but are excluded from our GAAP and core earnings guidance because the company is unable to reasonably estimate the impact of any such gains or losses. Further, our earnings guidance for 2010 assumes normal weather for the year, and is subject to among other things regulatory decisions and legislative action, plant operations, energy and capital and credit market conditions, economic conditions, severe storms, and usual or otherwise unexpected gains or losses and other risks and uncertainties outlined or referred to in the forward-looking statements section of today's press release. Turning now to slide 12, I would like to report on our 2009 and projected 2010 cash flow. A year ago we shared with you that we expected 2009 negative free cash flow, defined as cash flows from operations less capital expenditures and common dividend, of approximately $450 million. I'm pleased to report that we were able to achieve markedly better results. This significant improvement was the result of curtailed spending and cash tax saving, including deferral of tax payments as a result of bonus depreciation. As we look to 2010, despite expected reduced earnings, we anticipate that free cash flow from our Merchant Generation segment will be positive allowing us to reduce outstanding borrowings. We anticipate that our regulated utilities will continue to generate negative free cash flow although at reduced levels, while providing funding for our current dividend. In summary, we anticipate that Ameren on a consolidated basis will require minimal net additional capital from external sources during 2010. We ended 2009 with approximately 1.9 billion of total available liquidity. That was comprised of cash on hand, as well as available borrowing capacity under our revolving credit facility. Our debt maturities in 2010 are a very manageable $220 million. Before we conclude our formal remarks, I would like to share with you some additional numbers to assist you in assessing Ameren’s longer-term outlook. On slide 13, we detail Ameren’s updated five-year capital expenditure outlook. Over the 2010 through 2014 period, cumulative capital spending is projected to range between 6.3 billion and 8.1 billion and between 1.1 billion and 1.7 billion per year. These spending levels reflect reductions made to planned spending in both the regulated utility and merchant generation segments of our business. On slide 14, we present our expected capital expenditures for our Merchant Generation business segment for each of the next five years. The amounts shown reflect lower than planned actual expenditures in 2009, and a reduction of $45 million in the years 2010 through 2013 versus estimates we shared with you at the Edison Electric Institute financial conference last November. These numbers are included in the total Ameren wide capital expenditures I just mentioned. Our Merchant Generation business spending plans are particularly moderate this year and next year. Of course, we will continue to review and adjust as needed our Merchant Generation business spending plans in light of evolving outlooks for power prices, delivered fuel cost, environmental standards and compliance technologies among other things. Moving now to slide 15, we provide an update on our 2010 through 2012 forward power sales and hedges. As you can see, we have significant hedges in place for 2010 through 2012 at power prices above the current market. We already discussed our 2010 hedges. For 2011 we have hedged approximately 18 million MWh at an average price of $49 per megawatt hour. Further for 2012, we have hedged approximately 12 million MWh at an average price of $53 per megawatt hour. Our capacity sales are approximately 75% hedged in 2010, approximately 40% hedged in 2011, and approximately 20% hedged in 2012. To assist you in understanding our Merchant Generation business segment’s margin drivers, we have provided a pie chart that breaks down our 2010 expected revenue by type. Now turning to slide 16, we update our Merchant Generation segment’s fuel and related transportation hedges. We previously discussed our 2010 hedging. For 2011, we have hedged approximately 20 million MWh at about $25.50 per megawatt hour. For 2012, we have hedged approximately 11 million MWh at about $26.50 per megawatt hour. Similar to our previous slide dealing with Merchant Generation revenues, we have included a pie chart that breaks down forecasted 2010 all in fuel cost to provide a perspective on how each component contributes to our overall cost. As Tom stated, our management team is extremely focused on meaningfully improving the returns at our regulated utilities, and continuing to position our Merchant Generation business to whether current power market conditions, and benefit from an expected eventual recovery in power prices. This completes our prepared remarks. We will now be happy to take your questions.

: Paul Patterson - Glenrock Associates: Good morning guys.

Good morning Paul. Paul Patterson - Glenrock Associates: Just to get a sense for what we are looking at in terms of power prices in your region for 2011, and beyond when you look at the forward curve, what kind of neighborhood are we in with respect to that. Could you give us a flavor for that?

Sure Paul. You know, when they look at the power market ordinarily or typically, as you probably know we look at some of the, you know, thin hub [ph] prices, and you know, right now thin hub around-the-clock prices are -- for 2011 in neighborhood of around $35 per megawatt hour. Paul Patterson - Glenrock Associates: Okay -- and you guys would be on a basis differential with that, how much should we think about that or is it pretty close to that number?

Well, I think there is a couple of things that you want to remember about it is you know, first of all that sort of just the thin hub prices. We talked about on the call and they typically as we are out in the market, we're looking for opportunities to enhance margins beyond you know, the prices you see just at thin hub you know, through sales to retail customers around the states that we operate it. But in terms of basis differentials, you know, some of the things that we've seen recently this past year, we certainly saw basis differentials widen out versus what we've seen in other periods when loads were higher you know, essentially as the economy slipped and we saw a demand drop off, we saw you know, some of the basis differential increase, and it was on peak around our service territory in Illinois around 7% decrement on peak to synergy, and about 14% off peak this past calendar year. Now it varies from region to region if you go down to, you know, for example where our EEI Joppa facility is. It is actually better the basis differential there is positive on peak, and a little bit negative off peak about 6%. So, you know, as we've gone into 2010 planning, you know, we've assumed similar kinds of basis differentials to 2009 as we look out to 2010, but we'd expect you should look beyond into ‘11 and ‘12, we would actually expect to see those basis differentials tighten up as the economy recovers. Paul Patterson - Glenrock Associates: Okay, and then just finally on the discussion of getting to a better ROE, you mentioned that you don't see this as a one-time sort of rate case catch-up situation, and you mentioned some sort of efforts. Obviously, you guys are lowering Capex there, and I guess maybe getting some sort of more timely recovery. If you could just elaborate a little bit on that and just, also if you could just tell us what it is in the non-regulated compliance generation Capex reduction, what you guys did there, and why you guys are coming in with a lower number now?

Sure, maybe we'll take those out of order. Well, first we will talk about you know, what we did in terms of capital expenditures on the merchant side of our business, and I will let Charles Naslund, the president of that segment discuss that a little bit.

You know, on the Capex for our merchant business, again if you kind of look at slide 8 that we covered, outlines basically in the state of Illinois what plans have to be scrubbed, which ones are complete, and which ones are yet to go, and basically what you'll see there as we have remaining in order to meet all the compliance requirements in Illinois to scrub the two Newton units, and then to scrub three out of six of the Joppa units, and what the change was because of the -- as Marty mentioned earlier, the great performance of the first phase of scrubbers and removal rates, it has actually allowed us to remove scrubbers on Edwards unit II and III, which effectively removed 400 million to 500 million out the 2010 through 2017 budget. Paul Patterson - Glenrock Associates: Okay, so Mississippi [ph] basically the same achievement with less Capex, right?

That's correct. The other thing I would add as Marty mentioned, we're continuing to look at other technologies and looking at once perhaps or maybe higher O&M and much lower Capex. And so we do have a breathing period here. 2010 and 2011, we finished our phase I scrubbers. We have a couple of years before heavy investment needs to start on our phase 2, and it gives us plenty of time as the technologies evolve here to come up with alternate solutions. I'm very optimistic that for some of our smaller units like our Joppa units that we're going to be able to come up with technologies, and actually continue to work on reducing those Capex expenditures.

Great. Thanks Chuck. I appreciate that. You know, Paul, on your other question in terms of you know, reducing the amount of under earning that we are seeing in our regulated businesses, obviously some of things we’ve talked about over time is you know, filing the rate cases on a regular basis to make sure that we are recovering our cost on a timely basis and earning fair returns, certainly seeking cost recovery mechanisms in the cases that we have pending. You know, those cost recovery mechanisms would allow us to recover our costs on a more timely basis reducing the amount of lag that we have. Those kinds of recovery mechanisms such as trackers or riders are certainly helpful in terms of being given an opportunity to earn you know, your allowed return in your jurisdiction. And then I think too, we'll also be looking and making sure that we manage our spend appropriately, and try to manage our spending to help close those gaps over time. Before I leave the whole Q&A with you Paul, I appreciate the questions. You know, as it relates to basis differential, one thing I did want to mention is that when you look at some of those basis differentials, it is really only a percentage of our volumes that are exposed, when you look at something like 2010. Some of our hedges really do protect us from some of that basis differential of our total megawatt hours that we have expected to generate next year of about 30.5, only about 35% of those are actually exposed to some of those basis differentials I discussed before. So, you know, that also helps to sort of mitigate the impact of those basis differentials. Paul Patterson - Glenrock Associates: Thanks.

Good questions.

Our next question is coming from Reza Hatefi with Decade Capital Management. Please state your question. Reza Hatefi - Decade Capital Management: Thank you. I guess one of the drivers on slide 10 is an earned ROE of 7.5% to 8.5%, is it kind of fair to say that because of the timing of the rate cases, and when they go effective that may be in the first half of 2010, you will earn close to ROE, I guess you earned in ’09, which was like 6.7% or something, and then in the back half of 2010, you are expecting to earn roughly 9%, which kind of averages to about 8% for the year? Is that the best way to think about it?

Well, I won't comment on the specific earned ROE percentages in the first half and the second half. But your overall thought process, I think is good, meaning that until those rate cases come to a conclusion, and we have rate adjustments. We would expect in the first-half of the year to continue to experience some of the regulatory lag that we did see last year. So, and again I wouldn't comment on the percentages. There is certainly seasonal volatility, and depending upon power planned outages, things like that, it could certainly swing those earned ROE percentages. But overall, your thoughts are generally correct. Reza Hatefi - Decade Capital Management: And then looking at slide 15, a follow up on the hedge question from earlier, if I look at 2012 hedges, 12 terawatt hours at $53. If I remember it correctly, about 8.7 terawatt hours of that is from the Illinois swap contract, I think was at $53, and then 1 terawatt hour is the legacy hedges like $33 is that right?

Yes. This sounds about right. Certainly the contracts that we have in place in the swaps provide the base, and I think you are right there about 8.8 million megawatt hours, and then some of the legacy contracts do provide the reminder, which typically those contracts are with wholesale concerns or large industrial concerns around the state of Illinois. I guess, I had also mentioned when you look out to 2011 and 2012 and when you look at those hedges, the shaping of the hedges approximate the kind of profile you would see in a round-the-clock kind of product. However, given the shape of the generation that we actually have available, the unhedged megawatt hours are a little more to on-peak than off, probably 55 on-peak, 45 off-peak, which is also true for the unhedged megawatt hours for 2010. Reza Hatefi - Decade Capital Management: And I guess just on that hedged numbers, 8.8 terawatt hours is $53 hours, and 1 terawatt hour is $33, sort of implies that the other 2.3 or so terawatt hour about $61 or $62 is packing into it. Is that -- are those just hedges that were layered on back in 2007 or 2008 or I guess what -- seems like a really nice price. I guess when where those hedges put on?

Yes, sure. Those contracts were put in place in prior years, and I can't speak to the exact pricing on all those legacy contracts, but your assumption is correct. They were put in place a couple of years ago. Reza Hatefi - Decade Capital Management: Have you started hedging 2013 yet?

I wouldn't comment on 2013 at this point. Reza Hatefi - Decade Capital Management: Thank you very much.

Thank you.

Our next question is coming from Carl Seligson with Utility Financial Experts. Please state your question. Carl Seligson - Utility Financial Experts: Good morning gentlemen. I am as usual, and unfortunate it has been going on for several years, terribly disappointed at the actions of the Missouri Commission in particular, and your assumptions that you will be earning 2 or 3 percentage points on equity, less than what you have before. I noticed that last week the commission granted an increase to Michigan Gas and Missouri Gas Energy, which of course they were a small company, but nonetheless it was down at 10% ROE down from 10.5%, and the chairman made a statement about the unanimity of the decision. I don't think in talking to individual commissioners necessarily your unanimity would in the bargaining seems to go towards the low end rather than the high end. But I wonder what steps you might take, either be they with the legislature or in specific filings, and things that you ask for, trackers et cetera to try to cut the spread between earned returns and allowed returns. You don't have a forward year, although they try to supposedly update your year during the course of the proceeding, but what else besides the forward year can you look to put in, and to get the legislature say that this makes sense because otherwise, you are going to have to continue to cut Capex, and continue to try to avoid the financial markets?

Carl this is Marty. You know, I think -- yes, and thanks for dialing in. you know, as we look to this ongoing rate case, we remain optimistic that we will get a fair outcome in this case. And I think Carl with respect to the things that will help close the ROE gap over time, something that as we mentioned in our talking points, you know, we are very focused on and we are very cognizant that we need to achieve for our investor base. You know, as part of this case we are looking for continuation of some of the constructive riders that we’ve received in the past trackers such as the fuel adjustment clause, and the pension and OPEB kinds of trackers that we have. We are also looking for other things that will help us in making sure that we can earn something closer to our allowed ROEs. You know something like the environmental cost recovery mechanism that we are seeking in our current case in Missouri, as well as some of the other adjustments that we laid out on slide 7 of our presentation. So you know, we are looking to work over time to improve our ability to earn fair rates of return in our jurisdiction. Carl Seligson - Utility Financial Experts: Yeah, I know you are looking for it. You have been looking for it for several years, but it doesn't seem to do you much good, and I wondered if there wasn't anything more specific, more action that you can take. The current case is a pretty good example as far as most of the recommended increase by staff has to do with fuel clause which you would gotten through -- fuel costs which you would have gotten through the operation of the fuel clause in any case. So, they have not given you any breaks as far as…

Carl, this is Warner Baxter. How are you doing? Carl Seligson - Utility Financial Experts: Hi, Warner. Good.

You know, I think at the end of the day you know, we have as Tom said earlier, we put together a well supported case, and we feel confident in our ability to have a fair hearing of this case in front of the commission, and a fair outcome ultimate from that commission. Marty outlined the various riders and tracking mechanisms that will seek in this case, as well as potentially in future cases we can seek potentially other mechanisms to continue to mitigate that lag. And lastly, you know, there are other alternatives even outside of the regulatory mechanisms as you know that we could consider from a legislative perspective that mitigate that, but that's not in the short term. That would be something down the road. So we're mindful of it, and we are going to continue to do the best we can to narrow that gap as Marty said. Carl Seligson - Utility Financial Experts: Good luck.

Thank you.

Our next question is coming from Yiktat Fung with Zimmer Lucas. Please state your question. Yiktat Fung - Zimmer Lucas: Good morning. First of all, congratulations on the solid numbers, and especially on the improvement on the environmental and Capex outlook. My first question pertains to the revenue break down on slide 15. In terms of the 79% portion that is energy and capacity for the full requirements [ph] contracts. Are those contracts exposed to customer switching?

I think -- I apologize. You broke up at least as far as I could hear a little bit. I think you're asking about the capacity hedges on slide 15. Yiktat Fung - Zimmer Lucas: I'm actually asking about the full requirements contracts that make up 79% of your revenue.

Oh, so you're talking about the power hedge sales themselves, and whether there is some exposure to customer switching. Yiktat Fung - Zimmer Lucas: Correct.

You know, it's really diminished because you know, as we -- previously some of these contracts were for auction related sales, but those auction related sales have been dropping off over the past couple of years, and you know, the swap contracts come into place, and so as the auction contracts roll off, which actually roll off middle of this year, you know, we're really less exposed to that kind of customer switching. Yiktat Fung - Zimmer Lucas: I see. And going back to your earnings drivers for the Merchant segment, one of the drivers that seems to be missing or doesn’t seem to be mentioned on slide 11 is basically O&M cost. Does that mean that O&M is flat year-on-year at this segment?

Yeah, I think if you actually if you go back and look at some of the guidance we provided in previous quarters, we've really been working to reduce the O&M, and I believe it's actually down a little bit in 2010 versus 2009 levels. Yiktat Fung - Zimmer Lucas: So that previous guidance, bringing it back down to around 2008 levels still holds?

Yes, we had provided some guidance back at the end of the year. I think it was the third quarter relative to 2008, 2008 levels, and that guidance was about right. Yiktat Fung - Zimmer Lucas: Okay, and then going on to the regulated segment, can you just give a bit more color as to what you assume for your load for low growth in 2010 versus 2009. I think you mentioned that you expect, obviously, the Noranda plant to come back and that industrial sales in Illinois would have a little up-tick. Can you comment a bit on what you assume for residential and commercial?

Yes, we're -- I'd say fairly bearish on -- in terms of residential and in industrial and commercial sales, and in industrial where we talked about, we are expecting some growth as Tom mentioned in our sales to Noranda, which is -- they seem to be coming back strong which is terrific news. In Illinois, we do see some industrial growth in particular that we expect to take place and again while we have certain low margins in that business, we do believe that's good for the economy in general for our customers, as well as for certainly for power prices as well. So those are all good, but in terms of the residential and commercial sales more modest expectations there. And you know, really we think that we won't see real strong improvement in those areas until you know, you look out into the future and you see some stronger economic recovery that would support some job growth. Yiktat Fung - Zimmer Lucas: Actually, so basically the assumption is somewhere around flat year-on-year for residential and commercial?

Yes, I think you know close to that of sort of the low 2009 level that we saw. Yiktat Fung - Zimmer Lucas: Okay. Thank you very much.

Our next question is coming from Dan Jenkins with State of Wisconsin Investment Board. Please state your question. Dan Jenkins - State of Wisconsin Investment Board: Hi, good morning. Had a couple of questions on the Missouri case in this slide 7, I guess, there is -- when you mentioned the $402 million annual request, does that reflect the 11.5 ROE that you initially requested or the 10.8 that you are asking for now, and if it is the 11.5 then what is the difference in that. And then I was also curious, you mentioned that you are going to true-up through January 31, and you obviously already have results through December 31, and you probably got an idea on January. How's that going to impact the request?

Right, the $402 -- if I understood your questions, the $402 million request was based on and is based on the initial ROE that was filed. We did, as you mentioned, drop the ROE request there, and I guess it is a frame of reference. I think it is about every 100 basis points, it is about you know, $45 million or so. So you kind of do the math to figure out the impact there in terms of the ROE drop. However, as you mentioned there are and we mentioned that there are going to be updates through the end of January and we don't have all of those numbers today. We will be making a filing in March, but the parties will be in the case anyway in the March timeframe that would provide sort of the overall pluses and minuses, you know, of course one of the things that you see in that list that will go the other way in terms of moving the you know, the ROE going down would move the overall request down, but you know, certainly pushing the other way would be our anticipation that we would be able to update the capital structure to reflect the equity that we did put into Union Electric when we issued equity in the fall. Dan Jenkins - State of Wisconsin Investment Board: Okay. And then I just want to make sure I have this cleared. So as the staff not contesting the fuel clause or the pension OPEB trackers that in this case is that…

That is right. I mean basically what we are saying is that you know, the staffs’ testimony didn't object to continuation of those, the FAC and those trackers for pension and OPEB. Dan Jenkins - State of Wisconsin Investment Board: Okay. So, the only one -- this is the only tracker they are really contesting in vegetation [ph] and infrastructure inspection costs or is there other things that are being contested?

Dan, this is Warner Baxter. That is correct. The other thing they are contesting, we asked for a storm tracking mechanism in our rate case. It gets a little bit to an earlier question about the things that we are seeking to try and mitigate regulatory lag. One of the new things we did ask for in this case was a strong tracking mechanism and the staff is opposing this -- that recommendation at least to date in their filing. Dan Jenkins - State of Wisconsin Investment Board: Okay, thank you. That's all I have.

Our next question is coming from Billy Hagstrom with Catapult Capital. Please state your question. Billy Hagstrom - Catapult Capital: Hi guys. Thanks. You talk about an improved regulated earnings outlook as you narrow the gap. If I look at slide 10, your 2010 regulated guidance of 205 mid point roughly is an 8% ROE. If I think about the bullet at the bottom of the page that highlights $0.25 of earnings for every 100 basis points of ROE, and these pending rate cases allow you to earn closer to your currently allowed ROEs, are you expecting to get roughly 250 of earnings just for the regulated business by next year?

That was not the comment. I think the comment here overall was that you know, we do plan to reduce the regulatory lag in the businesses that we have through the pending rate cases, where we expect to improve the returns that last year we're in the 6.5ish percent range. We'd expect to improve those up to the 7.5% to 8.5% range, you know, in the current year and then you know, as we look out over time, we see the opportunity as we close the gap between say that mid-point, let us say, 8% and our allowed returns which in our last series of rate cases in Missouri and Illinois, the ROEs that were allowed were around 10.7%. So you know, what we're seeing there is for every 1% we can close from say that 8% mid-point up through 10% or 10.7% is going to provide us the opportunity to get $0.50 or more of earnings. So it is kind of -- it is just illustrating some of the earnings power of the businesses that we have. Billy Hagstrom - Catapult Capital: Okay, that's helpful. Good luck guys.

Thank you.

Our next question is coming from Michael Lapides with Goldman Sachs. Please state your question. Michael Lapides - Goldman Sachs: Hi guys. On the environmental slide in terms of meeting the NPS [ph] requirements, you talk a good bit about scrubbers, can you talk about SCRs at all? Do you no longer, do you not need SCRs at these facilities because you are meeting your Nox requirements through the scrubber. Talk -- if you mind giving an update on that. And also can you talk about alternative technologies to have looked at, meaning things like turn [ph] injections as a substitute for scrubbing?

Yes, Michael. It is Chuck Naslund again. As far as your question on SCRs, we currently have adequate SCRs and Nox burners on all of our units to be able to meet all the Nox requirements in Illinois NPS out through 2017. So we have no additional Capex expenditures in that particular area. As far as alternate technologies, you're right on. We are looking very hard at turn injection or some kind of sodium bicarbonate type of injection where you know, very low Capex expenditure, but more of an O&M component, and we believe some of our older smaller units that may be the best economical approach. And we have plenty of time as that technology shakes out to adjust Capex for those Joppa units out in the future. Michael Lapides - Goldman Sachs: Okay. Can you talk about the returns on capital you expect to make on the -- if you have to -- meaning if you can’t use (inaudible) and you have to do the scrubbers, what kind of returns on capital you expect to make on that investment?

Yes, Michael. Could you repeat that question? I apologize. Michael Lapides - Goldman Sachs: Sure. I mean, and this is -- lots of companies in the industry face this in terms of whether to scrub plants or shut plants down. Can you talk about the returns on capital you expect to make on the scrubbing on some of your larger units on the non-regulated side?

Yes, I guess, I don't have the returns off the top of my head in the non-regulated unit side of the business, and I think what we're going to be doing over the next couple of years as we reevaluate and evaluate these plans is certainly look, as I said before, at the power price conditions, fuel cost, look at you know, developments in the regulated areas, and you know, look at whether these incremental investments that we have that you know, today we plan to make, you know, will provide us returns in excess of our cost of capital, and that's what we'll be taking a look at if we you know, make the final decisions as to how to proceed with the capital expenditures that we have planned. Michael Lapides - Goldman Sachs: Got it, and last question, this is just a balance sheet one. I was looking at the earnings release and noticed that long-term debt had come down about $800 million, but that the -- I think it is the draw on the credit facility or the borrowing on the credit facility is now about $830 million. Can you just talk about plans for that, meaning are you going to just leave that outstanding or you going to return that out at one of the utility subs?

Yes, we expect as we said before that overall as we look at you know, this year that we expect to be around cash flow neutral at the overall, at the Ameren Corp. level, and as you look at some of those borrowings that you see there, some of those borrowings are for the Merchant business, support the Merchant business, some of the cash that we have on hand is that the regulated businesses. The regulated businesses, we are expecting as I said before, for them to be cash flow negative, and eat into some of those cash balances this year, whereas on the merchant side of our business, where we expect to be cash flow positive to have the ability to pay down some of those borrowings this year. So you should see the borrowings and the cash balances coming down over the course of the year, and then you know, while we don't have to access the capital markets this year, we just don't have the possibility, especially late in the year of doing some additional debt at the Merchant Generation segment, say a couple of hundred million dollars which that long-term debt might also be utilized to keep the borrowings under the credit facility level. Michael Lapides - Goldman Sachs: Got it. Okay, thank you guys. Much appreciated.

Okay. Thank you Michael.

:

Okay. Our last question is coming from Steve Gambuzza from Longbow Capital. Please state your question. Steve Gambuzza - Longbow Capital: Good morning. Just on the non-reg O&M, I just want to make sure I understood that the answer, that was the prior guidance that 2010 non-reg or Merchant Generation O&M would be roughly flat with 2008 level. Is that correct?

That is correct. Steve Gambuzza - Longbow Capital: Okay. Can you just tell me what the number was in 2009?

Oh boy. I apologize. I don't have that handy. We can try to… Steve Gambuzza - Longbow Capital: I'll follow-up off-line.

Maybe so. We could try to look it up real quick, but may be following up off-line would be best. Steve Gambuzza - Longbow Capital: Thanks very much.

Thank you.

Yes, Steve. This is Doug Fisher. If you'll just give me a call about that, we'll catch up on that. Unfortunately our hour has expired. Thank you for all your interest in participating in this call. Let me remind you again that this call is available through February 24th on playback, and for one year on our website. Today's press release includes instructions. On listening to the playback, you may also call the contacts listed on the release. Financial analyst inquiries should be directed to me, Doug Fisher, media should call Susan Gallagher. Susan’s and my contact numbers are on the news release. Again, thanks for your interest in Ameren and have a good day.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time, and we thank you for your participation.