Doug Fischer – Director of IR Gary Rainwater – Chairman, President and CEO Marty Lyons – SVP and Chief Accounting Officer Warner Baxter – EVP and CFO

Paul Patterson – Glenrock Associates Greg Gordon – Citigroup Yiktat Fung – Zimmer Lucas Capital David Frank – Catapult Capital Reza Hatefi – Polygon Investment Partners Michael Lapides – Goldman Sachs Steve Gambuzza – Longbow Capital Jeff Coviello – Duquesne Capital Scott Engstrom – Blenheim Capital Phyllis Gray – Dwight Asset Management

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 ongoing requirement to fund significant capital expenditures to meet customer reliability needs and environmental requirements, challenging and expensive capital and credit market conditions, volatile commodity prices, will principally impact the stability of earnings and cash flows of our non-rate-regulated generation business. The need to finance future debt maturities and credit facilities, which expire in January and July 2010, and while improved regulatory frameworks that still result in regulatory lag and inhibit us from earning our allowed return on equity in a rising cost environment. While we have challenges, we also believe that we have a long-term strategic plan that will allow us to meet them head-on. Our strategy remains one that is focused on investing in the energy infrastructure of our regulated businesses in order to deliver safe, reliable, and affordable energy to our customers in an environmentally responsible manner. This strategy will not only allow us to meet our customers’ expectations and grow our regulated businesses for the benefit of our shareholders, it will also be a critical factor in helping maintain and create jobs and provide long-term growth in Missouri and Illinois during this difficult economic period. Another key aspect of our strategy is to continue to optimize our non-rate-regulated generation assets. In that light, we are taking actions to significantly reduce spending while actively managing the existing assets in this business to execute on that strategy. The final key component of our strategy is to enhance our financial strength and flexibility for the benefit of all our stakeholders. The action that our board took in reducing our common dividend will clearly help us execute on this component. Financial strength and flexibility provide near and long-term benefits to our shareholders and customers. A lower dividend rate will allow Ameren to retain approximately $215 million of cash annually, which will help us to invest to improve reliability to meet our customers’ expectations, satisfy federal and state environmental requirements, reduce our reliance on dilutive equity and high-cost debt financings, and enhance our access to the capital and credit markets. The combination of our investment and financing strategies will drive solid long-term earnings per share growth principally from a strong regulated asset base. It is also important to note that our payout ratio has been amongst the highest of our utility peers as you can see on slide 4 of our presentation. In 2008, we paid out 88% of our GAAP earnings and dividends versus 50% to 60% for peer companies. The new dividend level better aligns our payout ratio with industry peers. Turning to slide 5, our adjusted dividend level provides Ameren with a more sustainable dividend payout ratio based upon anticipated earnings from our regulated business. This new dividend rate coupled with our targeted long-term annual earnings per share growth rate of at least 5% of the mid-point of our 2009 core earnings guidance is expected to provide competitive long-term total return potential for our shareholders. Looking ahead, our goal would be to grow the dividend level as the earnings from our rate-regulated operations increase and our overall cash flow profile improves. Of course, as they have done in the past, our board is expected to also consider several other factors including our overall payout ratio, payout ratios of our peers, potential future cash flow requirements and other key business considerations. I would now like to discuss some of our accomplishments in 2008. We reported 2008 core or non-GAAP earnings per share of $2.95, within the range of both the original guidance we issued in January of 2008 and the revised earnings guidance range we provided to the market in early November 2008. Our 2008 results were achieved despite the challenges of weakening economic conditions as well as volatile and uncertain capital, credit, and commodity markets. Importantly, in 2008 and early 2009, we were able to successfully execute on key aspects of our long-term strategic plan. Our strategic plan calls for generation excellence and improvement of customer service and satisfaction. Recall that in October 2008, our Callaway nuclear plant completed its first-ever breaker-to-breaker run and completed a plant record 28 day refueling and maintenance outage this past fall. At AmerenUE, equivalent availability of our coal-fired generating units was a solid 88% as compared to 89% in 2007. At our non-rate-regulated generation operations, we set new generation records producing approximately 31 million total megawatt hours as equivalent availability for our coal-fired units was 85% compared to 81% in 2007. Amidst the economic challenges facing us and our nation, we have remained focused on our customers and have made significant investments in our energy infrastructure to improve overall reliability and customer satisfaction. In Missouri, through the year-old Power On’ Reliability program, we buried more than 100 miles of electric line, trimmed tress along more than 6500 miles of line, tested nearly 100,000 wood utility poles, and inspected over 8000 miles of line. In Illinois, we targeted the worst performing circuits and aggressively trimmed trees in our 44,000 square mile territory, and continued to automate our transmission system to elevate our reliability. We believe that high-quality customer service is essential to earning solid returns in our regulated businesses. On that note, I'm pleased to say that we made meaningful progress on the regulatory front in 2008 and early 2009. On our third-quarter 2008 call, we discussed with you the details of the much-needed increases of approximately $161 million in electric and natural gas rates authorized for our Illinois regulated operations, which became effective October 1, 2008. In Missouri, AmerenUE received approval of an electric rate increase on January 27 of this year with new rates expected to be effective March 1. The authorized increase in annual electric revenues is approximately $162 million. We are also pleased to report that the Missouri rate order authorized a fuel adjustment clause, as well as reliability cost tracker mechanism. Fuel adjustment clause and other tracker mechanisms improve our ability to continue to invest in infrastructure, so that we will be able to meet our customers’ expectations for safe and reliable service. We do consider the Illinois and Missouri rate orders to be clear signs of the progress we are making on the regulatory front in a strong foundation for future growth in our regulated businesses. And while rising operating and financing costs are still resulting in regulatory lag in both Missouri and Illinois, we will be filing rate cases more frequently in the future to minimize regulatory lag as well as to make any bill increases more manageable for our customers. Marty will cover the details of recent rate orders in Missouri and Illinois in a moment. Despite our recently granted rate increases in Missouri and Illinois and our proactive sales of 2009 non-rate-regulated generation in early 2008, we believe our 2009 core earnings will be relatively flat compared with 2008 core earnings. As I mentioned earlier, we are navigating our company through a global recession, volatile commodity markets, and unprecedented strains in the capital and credit markets. We believe these factors will result in lower customer usage versus 2008, lower power prices for unsold non-rate-regulated generation, and higher financing cost throughout 2009 and longer. Warner will walk you through some of our key drivers for 2009 a bit later. In closing, we have taken timely, prudent actions over the past few months to build on our financial strength and enhance our financial flexibility in light of the difficult economic, capital, and credit market conditions. These actions included reducing our common dividend, accessing the capital markets to increase our available liquidity, as well as making significant reductions in our 2008 and projected 2009 spending plans while still meeting our reliability, environmental, and safety objectives. As a result, our current available liquidity, which represents our cash on hand and amounts available under our credit facilities stands at a solid $1.3 billion. The need for utilities to have strong cash flows and good credit ratings, solid overall returns on their investments, and the ability to access the credit and capital markets on a timely basis has never been more apparent. The bottom line is that our management team remains keenly focused on prudently managing our business during this difficult economic period to ensure that we are able to execute on our long-term strategic plan of maintaining solid available liquidity and financial flexibility, so that we are able to invest in our energy infrastructure for the benefit of our customers and to deliver solid long-term returns to our shareholders. I will now turn the call over to Marty to discuss recent revelatory developments.

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 for late in the second quarter or early in the third quarter of 2009. Turning now to slide 8 and Missouri, in April 2008 AmerenUE requested an electric revenue increase due to higher costs across its business, including fuel and reliability costs as well as higher infrastructure investments. A critical aspect of this case was AmerenUE’s request for implementation of a fuel adjustment clause. As Gary mentioned, on January 27, 2009, the Missouri Public Service Commission authorized AmerenUE to increase annual electric revenues by approximately $162 million. The new rates reflect an allowed return on equity of 10.76% on 52% common equity ratio and a rate base of 5.8 billion. Importantly, the Missouri rate order authorized AmerenUE to implement a fuel adjustment clause. The fuel adjustment clause applies to net fuel costs, which include delivered fuel and purchased power costs net of off system sales revenues, including Midwest Independent Transmission System Operator or MISO cost and revenues. The fuel adjustment clause passes through to customers 95% of deviations between actual net fuel costs and net fuel costs of approximately $328 million included in base rates, subject to prudency review as shown on slide 9. In addition to the fuel adjustment clause, the Missouri Commission also approved vegetation management and infrastructure inspection cost tracker. The Missouri Commission also authorized continued use of the pension and other post-retirement employee benefits cost tracker first approved in the May 2007 electric rate order. The Missouri Commission also approved amortization and recovery over five years of $25 million of previously expensed O&M related to the January 2007 severe ice storm. In addition, previously expensed MISO Day 2 expenses of $12 million were authorized for amortization and recovery over two years. In total, the portion of the full rate increase granted by the Missouri Commission, which provides a recovery of net additional prior period cost will result in approximately $12 million of additional annual amortization expenses. Overall, we believe this order by the Missouri Commission is constructive, however, because of continuing investments in our utility infrastructure, rising operating costs, and cost of capital we do not expect to earn the return on equity allowed in this proceeding during 2009. As a result, we expect to file another electric rate case in Missouri later this year. At that time, it will depend on the timing and magnitude of cost increases and rate base additions among other things. On January 29, 2009, just one day after the Missouri Commission delivered its order in this case, a severe ice storm hit Southeast Missouri. This severe winter ice storm caused a power outage and AmerenUE’s largest retail customer, Noranda Aluminum. According to Noranda’s January's 29th 8-K filing with the Securities and Exchange Commission, the outage affected approximately 75% of the smelter plant’s capacity. Further, Noranda stated that preliminary information and management's initial assessment indicated restoring full capacity may take up to 12 months with partial capacity phased in during the 12-month period. AmerenUE supplies electricity to this facility with the transmission and distribution lines that feed the Noranda facility and that failed are owned by others. This is too early to assess the exact impact of the outage on AmerenUE’s business. While AmerenUE expects it will be able to sell the power that would have gone to Noranda into the off-system wholesale power market at prices that are currently about Noranda’s tariff rate, the newly approved Missouri fuel adjustment clause requires that 95% of the incremental off-system sales margins to be flowed through to electric customers. In response to this unanticipated event, AmerenUE filed a request with the Missouri Commission for a rehearing of the January 2009 electric rate order in consideration of revisions to the fuel adjustment clause tariff to mitigate the Noranda issue. Unfortunately, the Missouri Commission expressed its intent to deny the hearing request at a public agenda session last week, and an official vote to that effect is expected later this week. If 75% of Noranda's capacity were down for 12 months, the reduction in AmerenUE’s pre-tax annual earnings could be as much as $73 million due to the loss of up to approximately 3.2 million megawatt hours of retail sale. At this time, we are unable to reasonably estimate that impact of the Noranda outage as well as the impact of other storm related costs on our earnings. UE is currently considering other possible steps it might take to mitigate the loss of revenues from Noranda, including filing for an Accounting Authority Order. Consistent with our past practice, we will exclude the earnings impact of this severe ice storm from core earnings. I will now turn the call over to Warner.

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 market participants. This resulted in a 2007 charge to GAAP earnings of $0.06 per share. Finishing up the non-core items, asset impairment charges related primarily to the Indian Trails Cogeneration Plant resulting from the suspension of operations of the plant's only customer reduced 2008 GAAP earnings per share by $0.06. Then on slide 10 on the presentation, and focusing only on some of the most significant items, the full-year impact of the 2007 Missouri electric and natural gas rate increases raised earnings by $0.08 per share. The net increase in Illinois electric and natural gas delivery rates effective October 1, 2008, boosted earnings by $0.09 per share. Other electric and gas margins increased $0.64 per share in 2008 compared to the prior period, primarily as a result of improved generating plant output and higher realized electric margins at our non-rate-regulated generation operations. More normal summer weather in 2008 compared to the extremely hot summer weather in 2007 was the primary reason that weather reduced 2008 earnings by an estimated $0.16 per share compared to the prior year. For 2008, a weather sensitive residential and commercial electric sales were down approximately 2% and 1% respectively compared to 2007. After adjusting for weather, we estimate our combined residential and commercial electric sales increased approximately 2% in 2008 versus 2007. However, our industrial sales showed the impact of the weakening economy declining approximately 3% in 2008 compared to 2007. Higher costs for fuel and related transportation reduced 2008 earnings by $0.37 per share compared to 2007. In addition, higher plant operations and maintenance expenses reduced 2008 earnings by $0.16 per share versus 2007. Distribution system reliability expenditures reduced earnings by $0.16 per share in 2008 compared to the year ago period as we continued to make significant incremental investments to improve reliability and customer satisfaction. Financing costs also rose in 2008 as we refinanced auction rate debt earlier in the year due to the volatility in the capital markets, as well as higher cost debt later in 2008 under significantly strained capital market conditions. Bad debts, labor, depreciation and amortization, and other expenses also increased year-over-year. Moving onto our 2009 guidance on slide 11, as we stated in our news release from Friday afternoon, we expect our core earnings to be in the range of $2.75 to $3.15 per share. Before I discuss a detailed reconciliation between our 2008 earnings results and our 2009 guidance, I believe it is important to look at 2008 core results and 2009 core guidance by segments. In total, our two regulated segments posted core earnings of $1.36 per share in 2008. We expect results from these regulated units to improve in 2009 to a range of $1.65 to $1.85 per share on a core basis, up approximately 25% to 35% over 2008 results reflecting the benefits of the net rate increases in Illinois and the recently granted Missouri electric rate increase. However, the expected 2009 regulated results, while higher will still fall below the allowed returns on equity authorized by our regulators. The new rates are based on historical test year data, and 2009 costs are expected to be higher than the levels we covered in rates. This is especially true of financing costs in Illinois with sharply higher debt financing costs, which were incurred after our rate cases were filed are not being recovered in rates. Turning now to slide 12, the midpoint of our core guidance range for Missouri regulated operations translates into an estimated return on equity of approximately 8% in the midpoint of our core guidance range for our Illinois regulated operations, translates into an estimated return on equity of approximately 6%. As Marty mentioned earlier, our allowed returns on equity are approximately 10.7% in both jurisdictions. So in summary, we expect earnings from our Missouri and Illinois regulated operations to show marked improvements but still fall short of our allowed return levels. While discouraging, the primary factors resulting in regulatory lag can be addressed in very straightforward manner by freshening up our rates in Illinois and Missouri to reflect our energy infrastructure investments and higher financing costs as well as other higher operating costs. As Marty discussed earlier, this is exactly what we intend to do. It is this straightforward strategy that uses confidence in our ability to grow our regulated earnings from their current levels. Note for every 1% that we narrow the gap between our allowed return on equity and our earned return on equity in our regulated operations, we generate an incremental $50 million and $25 million in pre-tax revenues in Missouri and Illinois respectively. It should be emphasized that the 2009 Missouri regulated operations core segment guidance and the related return on equity estimate exclude the impact of the Noranda outage and the January 2009 ice storm. For the Illinois regulated operations segment, the 2009 core segment guidance and related return on equity estimate exclude an estimated $0.03 per share negative impact on the 2008 settlement agreement among parties in Illinois to provide comprehensive electric rate relief. While core earnings from our regulated segments are expected to grow materially, 2008 core earnings in our non-rate regulated generation segments are expected to decline. We project this segment core earnings will be $1.10 to $1.30 per share this year, down from the $1.59 of earnings per share posted in 2008. In 2009, non-rate-regulated generation segment core earnings guidance excludes an estimated $0.04 per share negative impact in the 2007 Illinois settlement agreement. The decline is expected despite our proactive sales of 2009 non-rate-regulated generation in early 2008 at power prices well above current market prices. However, the combination of lower power prices for our unsold generation, higher fuel costs, and decline in our estimated generation level to approximately 30 million megawatt and higher environmental related costs are the reasons we expect lower core earnings in this segment in 2009 versus 2008. It is important to note, excuse me, it is important to point out that the lower estimated generation level is largely a function of the decline in power prices. We told you in early November 2008 that for 2009 we have hedged approximately 85% of our estimated non-rate regulated generation of 32 million megawatt hours at approximately $53 per megawatt hour. Approximately 2 million megawatt hours of generation output that we had expected as of our November forecast is no longer economic due to the significant decline in power prices since that time. Consequently, should power prices rebound during 2009, we clearly have the capacity and availability to sell more generation, which could result in higher than currently expected margins. Finishing up my discussion of our non-rate-regulated generation business on slide 13, will continue to believe there is meaningful value associated with having iron in the ground at a time when generation capacity expansion is limited due to the state of the capital markets. You can also see that we have been actively hedging our open generation and fuel positions. Through 2010, we have significantly hedged our fuel requirements. In addition, in terms of power, we have significantly hedged our current economic generation as well as have a meaningful portion of our 2010 economic generation hedged. Moving on from the segment perspective to an overall Ameren perspective, we have on slide 14 our earnings per share guidance reconciled between 2008 and 2009. Beginning our discussion with 2008 core earnings per share number of $2.95, which we discussed earlier, I will comment on some of the more meaningful items. First, you see the impact of the recent Missouri electric rate order, which increases retail rates by approximately $162 million annually. We expect the new rates, net of increased amortization expenses to benefit our earnings per share by approximately $0.39 in 2009. The Illinois net rate increases are expected to boost earnings per share by approximately $0.38 per share. For non-rate-regulated generation operations, other electric margins are expected to be lower and reduce earnings by $0.05 per share, reflecting lower expected generation levels and a significant decline in power prices that I just discussed. Regarding our Callaway nuclear plant, we do expect a $0.09 per share earnings pick up because of lower operations and maintenance expenses resulting from no refueling outage being scheduled for this year, something that occurs every third year. We also continued substantial spending on distribution system reliability in our regulated businesses. Increased depreciation and amortization expenses primarily reflect rate-based growth and are expected to reduce 2009 core earnings by $0.15 per share. Net dilution in financing costs are expected to reduce year-over-year earnings by $00.23 per share. In addition to the higher cost of financings recently completed, we expect meaningfully higher interest rates from prospective debt refinancings due to the disruption in capital markets. Further, we plan to issue additional debt to fund a portion of our capital expenditures. It is important to note that approximately $0.12 for the $0.23 projected increase in financing costs is being driven by our regulated operations. Other taxes are expected to reduce earnings by $0.10 per share principally due to higher ad valorem taxes. In addition, other expenses are expected to rise year-over-year. An estimated $0.07 per share negative impact in 2009 due to 2007 settlement agreement among parties in Illinois to provide comprehensive electric rate relief and customer assistance is excluded from core earnings guidance. Any net unrealized mark-to-market gains or losses will impact GAAP earnings are excluded from GAAP and core earnings guidance as the company is unable to reasonably estimate the impact of any such gains or losses at this time. In addition, the effects of a severe winter ice storm, including the impact of the related outage at the Noranda plant, also excluded from GAAP and core earnings guidance. The company is unable to reasonably estimate at this time the impact of the storm and outage on earnings. Bottom line is our core earnings per share guidance for 2009 ranges from $2.75 to $3.15 per share. We expect our 2009 GAAP earnings to be in the range of $2.68 to $3.08 per share. Ameren’s earnings guidance for 2009 assumes normal weather and is subject to, among other things, regulatory decisions and legislative actions, plant operations, energy and capital and credit market conditions, economic conditions, severe storms, unusual or otherwise unexpected gains or losses, and other risks and uncertainties outlined, or referred to, in the Forward-looking Statements section of the press release we issued last Friday in the Forward-Looking Statements and Risk Factors sections in our periodic filings with the SEC. Next, turning to slide 15 of our presentation, I would like to discuss our current available liquidity position. As Gary noted, we currently have a solid $1.3 billion of available liquidity. That is comprised of cash on hand as well as available borrowing capacity under our $2.15 billion of revolving credit facilities. As you know, we have taken aggressive and prudent actions to manage our available liquidity position since late last year, including making plans to significantly reduce our capital and operating expenditures in 2008 and 2009 as well as reducing our dividend. These actions are designed to reduce our need to access costly and uncertain capital markets. During our third-quarter 2008 call, we stated that we plan to significantly reduce our originally estimated negative free cash flow for 2008 of approximately $1.5 billion. We delivered on that commitment. Our negative free cash flow at December 31, 2008, approximated $1.1 billion as shown on slide 16. In 2009, we expect that our operating and capital expenditure reductions and coupled with our dividend reduction will drive our negative free cash flow down to approximately $500 million. Moving on to slide 17, you'll note that we have modest debt maturities over the next three years. As we look ahead in 2009, we will focus on $250 million of long-term debt to be refinanced with our regulated utilities as well as $124 million at our non-rate-regulated generation segments, and $300 million for Ameren Corporation. We will also take steps to replace our $2.15 billion of credit facilities that expire in 2010. We recognize that the credit markets are very challenging these days. While we will be seeking a full renewal of our bank facilities on reasonable terms, we anticipate the possibility that the capacity under our revolvers could be reduced and be more costly. Given this uncertainty, we plan to more aggressively term out our short-term borrowings under such facilities, which will provide further financial flexibility. In all, we currently expect to issue approximately $650 million of debt in our regulated utilities, $250 million in Ameren Corporation, and approximately $500 million at the non-rate-regulated generation subsidiaries in 2009. Of course, we expect these debt issuances as well as our borrowings under our credit facilities will be more costly compared to what we have experienced in the past. In terms of equity financings, as a result of the dividend reduction, other than equity proceeds received under our dividend reinvestment and employee benefit plans, we do not currently anticipate the need for additional equity issuances during 2009. Having said that, our actions today clearly point to the value we place on having financial strength and flexibility. As we continue to make meaningful investments in our businesses, most notably our regulated businesses, we intend to finance those investments with a blend of equity and debt in the future that we maintain a solid capital structure in our regulated businesses, which would approximate 50% to 55% equity. Having such a capital structure not only strengthens the financial position of those capital intensive businesses, it also gives us the ability to earn solid returns on those equity investments. Consequently, we do expect to make appropriate equity issuances in the future consistent with this framework as well as to address any unanticipated events should the need arise. The bottom line is that we plan to be proactive and opportunistic as we implement our long-term financing plans for debt, equity, or equity linked securities in order to appropriately finance our operations, reach scheduled maturities, and maintain financial strength and flexibility for the long-term benefit of all of our stakeholders. To wrap up, we remain very committed to our straightforward long-term business strategy of investing in our Missouri and Illinois regulated businesses in order to deliver safe, reliable, and affordable energy to our customers. As you can see on slide 18, we plan to continue to make significant investments in our regulated businesses to improve reliability to meet our customer's expectations as well as satisfy environmental requirements. From 2009 through 2011, we expect our regulated rate base to grow approximately 9% per year, and we will seek to recover those investments and earn solid returns through frequent rate case filings and potential future cost recovery mechanisms. These increased investments and coupled with the fact that our current rates are not reflective of higher operating and the significant financing costs that we are experiencing as shown on slide 12 earlier, gives us the confidence in our ability to achieve our long-term annual earnings per share growth target of at least 5% of the midpoint of our 2009 core earnings guidance. This targeted earnings growth rate when combined with our new dividend rate will provide competitive long-term total return potential for shareholders. Before we open the line-up for questions, I want to let you know that we do plan to hold an Analyst Day in New York City in spring. We will inform you of the details when they are finalized. We will now be happy to take your questions.

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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