Doug Fischer – IR Tom Voss – Chairman, President and CEO Marty Lyons – SVP and CFO Warner Baxter – President and CEO, Ameren Missouri Scott Cisel – President and CEO, Ameren Illinois

Paul Ridzon – KeyBanc Reza Hatefi – Decade Capital Paul Patterson – Glenrock Associates Erica Piserchia – Wunderlich Securities Ashar Khan – Visium Julien Dumoulin-Smith – UBS Robert Howell – Prospectus Partners David Katz – Bank of America Michael Lapides – Goldman Sachs Dan Jenkins – State of Wisconsin Investment Board Charles Stunnet [ph] – Stunnet Research [ph] Sarah Eccles – Wells Fargo Advisors Steven Gambuzza – Longbow Capital Daniele Seitz – Dudack Research

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

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

Thanks, Doug. Good morning and thank you for joining us. The past year was marked by significant accomplishments at our company. I’m pleased to report that 2010 core earnings reached $2.75 per share within the upper end of our most recent earnings guidance range issued in late October and nearly equaling 2009 core earnings of $2.79 per share. Improved earnings at our regulated utilities nearly offset a decline in core results from our Merchant Generation business. Factors favorably affecting 2010 core earnings included a 9% increase in electric Kwh sales to native load customers, new electric utility rates, lower financing cost and disciplined cost management. The increase in Kwh sales was the result of favorable weather, a recovering economy, and the return to full service of the large customers’ aluminum smelter plant. Total kwh sales to industrial customers rose 16% and even after excluding sales to the aluminum smelter plant, industrial sales increased 8%. Kwh sales to residential and commercial customers rose 7%. Items offsetting these favorable factors included lower Merchant Generation margins due to lower power prices and higher fuel and related transportation cost and higher companywide depreciation and amortization expenses. Overall, our non-fuel operations and maintenance cost increased only slightly reflecting the cost of the refueling outage at our Callaway Nuclear Plant, offset by disciplined cost management across all of our business segments. You may recall that our nuclear plant did not have a refueling outage in 2009. Per share results also reflected an increased average number of common shares outstanding. Turning to page #4, you will find a list of other accomplishments in 2010. We’ve discussed many of these with you previously, so I won’t touch on each of them. However, I’d like to highlight the fact that free cash flow reached the positive $341 million in 2010. In addition, our safety and customer satisfaction showed improvement compared to 2009, as both power plant and distribution system reliability remained solid. We returned our newly rebuild Taum Sauk pumped storage hydroelectric plant to service and placed scrubbers into service at three of our power generating units. And we launched plants for growing our transmission business. All of the accomplishments listed were the result of a focused and dedicated workforce. Moving now to page #5 today, we also announced 2011 GAAP and core earnings guidance of $2.20 per share to $2.60 per share. The expected decline in 2011 core earnings per share compared to 2010 primarily reflects an assumed return to normal weather and expected lower margins at our Merchant Generation business. I’m pleased to report that we expect positive free cash flow in 2011. In fact, our Merchant Generation business expects positive free cash flow, even though 2011 capital expenditures for this segment are expected to increase, compared to prior guidance. This increase in capital expenditures reflects our plan to accelerate the installation of scrubbers at our Newton plant and the addition of an equipment upgrade at one of our large Merchant Generation plants. We’ve moved up the in-service dates of the two scrubbers at Newton by approximately one year to late 2013 and spring 2014. This decision was driven by our plants are complying with the US EPA proposed Clean Air Transport Rule. Installing scrubbers at Newton is also a key part of our plan for complying with the Illinois multi-pollutant standards. Shifting to capital spending plans in our Regulated businesses, the five-year budget that Marty will discuss in a few minutes now includes the cost of installing scrubbers at two of our Missouri coal-fired units. These scrubbers are projected to enter service by late 2015. Marty will provide further details on our 2010 earnings and cash flow and our 2011 earnings and cash flow guidance including budgeted capital expenditures. Before Marty speaks, I’d like to review recent regulatory developments at our utilities. Turning to page #6, we’ve been authorized to increase rates at both our Missouri and Illinois utilities over the past 12 months. In mid 2010, our Missouri utility obtained approval from the Missouri Public Service Commission to increase electric rates by $230 million annually and then in February this year to increase gas rates by $9 million annually. These rate increases have been necessary to recover the costs of infrastructure investments, higher fuel costs and other operating expenses. While on the topic of prior rate orders, I’d like to comment on ongoing litigation surrounding appeals of certain aspects of the two most recent Missouri Electric orders. As disclosed in an 8-K filed on Wednesday of last week the Missouri Office of Public Counsel made a filing with the Missouri Public Service Commission arguing that a late December Missouri Circuit Court stay of our 2010 electric rate increase as it applies to four industrial customers should now be effective for all customers. Needless to say, this would be unprecedented and we adamantly disagree with the OPC’s argument. In late December, the Missouri Circuit Court found that four industrial customers appealing the 2010 electric rate increase could pay the portions of their bills representing increases from previously approved levels into the court’s registry pending resolution of these appeals. This effectively stayed the rate increase for those parties. We disagree with the court’s ruling granting these industrial customers a stay and we do not believe any of the issues being appealed by the parties are probable of loss based on the merits. Given that this is an act of legal matter, we won’t be able to comment further on this call, but we’ll be responding to the arguments of the Office of Public Counsel in supporting arguments made by certain industrial customers and filings with the Missouri Public Service Commission this week. Turning now to Illinois. In November 2010, our Illinois delivery utility received an order on rehearing from the Illinois Commerce Commission on issues arising from the Commission’s amended order of May 2010. This rehearing order brought the total annual revenue increase in this case to $53 million. Moving to pending rate cases in September 2010, our Missouri Utility filed for a $263 million annual electric revenue increase. On February 8, other parties filed their initial testimony. While we strongly disagree with elements of the staffs and other parties initial recommendation this case is still in its early stages. We look forward to presenting our case to the Missouri Public Service Commission beginning in April. A Public Service Commission order is expected in July. A few days ago, our Illinois electric and gas delivery utility filed with the Illinois Commerce Commission for a $111 million increase in annual revenues. This request is based on a test year ending December 31st 2012 with an ICC decision expected in January of 2012. The use of a future test year is designed to better match our 2012 rate levels to our expected 2012 cost, reducing regulatory lag and providing an improved opportunity to earn a fair return on investment. Marty will provide further details on the interveners initial recommendations in the Missouri electric case and the Illinois delivery rate filing. In addition to these developments in our state jurisdictions, we’re awaiting action from the Federal Energy Regulatory Commission on our filing for pre-approval of supportive rate treatment for Phase I of our proposed Grand Rivers regional electric transmission projects. We continue to position our company for long-term success. On February, the 9th we announced changes in assignments for several members of our executive management. Chuck Naslund, who did a tremendous job of better positioning our Merchant Generation business to weather this period of low power prices, will assume the role of Senior Vice President, Generation and Environmental Projects at Ameren Missouri. Chuck will also lead our Ameren wide generation initiative, which includes evaluation and optimization of environmental compliant strategies. In Chuck’s career at Ameren, he has a one time or another overseen the operation of all our power plants and has been instrumental at optimizing the performance of our Merchant Sioux existing scrubbers and re-evaluating and lowering projected cost of compliance with the Illinois Multi-Pollutant Standard. Over the coming months we expect to see a host of proposals and rules from the US EPA and I believe that having Chuck’s focused time and attention on Ameren wide compliance planning efforts will ensure that we make the best decisions for our future. Steve Sullivan, our Corporate Secretary and General Counsel succeeds Chuck as President and CEO of Ameren Energy Resources. In addition to his many years of legal, regulatory and financial experience, Steve has also been responsible for overseeing government and regulatory relations at both the state and federal levels, fuel purchasing and our electric transmission organization. We’re making these changes and others within our organization to take full advantage of our leadership expertise and bring new ideas to the evolving business conditions we face. As I mentioned, this could be a pivotal year in the area of environmental regulation. The EPA is scheduled to finalize its proposed clean air transport rule which is aimed at reducing emissions of sulfur-dioxide and nitrogen oxide. Further the agency has scheduled proposed requirements for retrofitting power plants with maximum, achievable, control technologies to reduce hazardous air pollutants such as mercury and acid gases. The EPA is also expected to issue cooling water standards and rules for reducing green house gas emissions. These rules are expected to impose additional cost that could be substantial for the company and therefore our customers. I want to assure you that we’ve a team of experts in place who are continually anticipating and evaluating changing environmental standards for our power plants and are focused on meeting these requirements in a most cost-effective manner possible. In addition, we’re actively working to shape new environmental rules for the benefit of our customers and shareholders. Our strategy for financial success is unchanged. Our regulated utilities remain focused on earning fair returns on investment by seeking consistent constructive regulatory outcomes including mechanisms that reduce regulatory lag like the use of the future test year in our Illinois rate filing. Further, we continue to focus on disciplined cost management, including aligning our spending with the levels of rates authorized by our regulators. In 2010, our regulated utilities narrowed the gap between their core earnings and they are allowed returns on equity by almost 300 basis points and by more than 100 basis points on a weather-normalized basis. Our 2011 regulated utility earnings guidance equates to a return on equity of 8% to 9% in line with the improved level we achieved in 2010 on a weather-normalized basis. Let me be clear that this return continues to be below our authorized level and what we consider to be appropriate. We believe our pending rate cases, our cost control efforts and ongoing work to improve our regulatory frameworks will allow us to further narrow the gap between our earned and allowed returns. Our Merchant Generation business continues to aggressively manage operating and capital costs so that this business remains well-positioned to weather current low power prices and benefit from an expected power price recovery. In 2010, our Merchant Generation business further lowered its cost structure to enhance its long-term competitiveness. At the same time, we’ve increased the resources we’re dedicating to marketing and delivering higher value energy projects to large retail customers in the Midwest region, where we compete. And at both our regulated and Merchant businesses we remain committed to operating in a safe, reliable and environmentally responsible manner. Now, I’ll turn the call over to Marty.

Thanks, Tom. Turning to page #7 of the presentation and the year 2010 column, today, we reported 2010 earnings in accordance with Generally Accepted Accounting Principles or GAAP of $0.58 per share compared to 2009 GAAP earnings of $2.78 per share. Excluding certain items in each year, Ameren reported 2010 core earnings of $2.75 per share, compared with 2009 core earnings of $2.79 per share. 2010 core earnings exclude three items that are included in GAAP earnings. The first of these is goodwill and other asset impairment charges associated with our Merchant Generation business. We recorded these charges in the third quarter. These non-cash charges reduced 2010 GAAP results by $522 million or $2.19 per share. The second item excluded is a $0.08 per share gain from the net effect of an unrealized mark-to-market activity. The third item excluded in arriving at 2010 core earnings is a charge for the deferred tax impact of new Federal Healthcare loss which decreased earnings by $0.06 per share. On page #8, we highlight key factors driving the variance between core earnings per share for 2010 and 2009. Factors favorably impacting this comparison included increased regulated electric and natural gas margins, excluding the impact of rate changes. These margins lifted earnings by $0.71 per share driven by the previously discussed increase in electricity sales. Warmer summer and to a lesser extent colder winter weather increased 2010 earnings by an estimated $0.40 per share compared to 2009 and by an estimated $0.24 per share compared to normal weather. New utility rates increased 2010 earnings by $0.36 per share net of certain related expenses compared to 2009 results. Reduced financing expenses, primarily reflecting increased capitalization of construction financing costs or AFEDC, improved 2010 earnings by $0.10 per share. Factors adversely impacting the comparison between 2010 and 2009 core earnings included a decline in 2010 margins at the Merchant Generation business of $0.79 per share compared to 2009. This reflected lower realized power prices and higher fuel and related transportation costs. Higher depreciation and amortization expenses reduced 2010 earnings by $0.09 per share, reflecting increased investment in our businesses. These investments included scrubbers placed in service in late 2009 and early 2010 at the Coffeen Merchant Generation plant. Higher non-fuel operations and maintenance expenses decreased 2010 earnings by $0.02 per share compared to 2009. Expenditures in 2010 reflected the cost of the Callaway refueling outage. There was no refueling outage in 2009. As Tom mentioned, these costs were mitigated by disciplined cost management across all our business segments. This included reduced non-fuel O&M spending at our Merchant Generation business. Last, an increased average number of common shares outstanding reduced 2010 earnings as compared to 2009 on a per share basis. This increase in shares primarily reflected our September 2009 stock offering. Turning to page #9, I’d now like to discuss the key drivers and assumptions behind our 2011 earnings guidance for our Missouri and Illinois regulated utility businesses of $2.05 to $2.30 per share. In 2011, we expect to achieve an earned return on equity of approximately 8% to 9% on regulated average utility common equity of about $6.2 billion. This guidance for our regulated utilities assumes a return to normal weather reducing EPS by an estimated $0.24, compared to 2010 results. Weather-normalized margins are expected to increase as a result of moderate growth in weather-normalized electricity sales volumes, new Missouri natural gas delivery rates effective in February and Missouri electric rates expected to be effective in early August. Regulated utility earnings guidance for 2011 incorporates increased non-fuel operations and maintenance costs as well as increased depreciation and amortization expenses. From a timing perspective, this year’s Callaway Nuclear Plant refueling and maintenance outage is scheduled for the fall compared to the spring refueling in 2010 and the 2011 cost is expected to be slightly less than the 2010 level. In 2011, financing costs are expected to increase because of lower equity related capitalized financing costs or AFUDC. This lower equity related AFUDC is expected to reduce earnings by $0.11 per share compared to 2010. Amongst other things, the post-construction accounting treatment authorized for the Sioux scrubbers in the 2010 Missouri electric rate order provides for Ameren Missouri to continue to capitalize for regulatory purposes, its full financing cost including equity related cost through the date when the new electric rates go into effect. However, accounting rules do not permit the recognition of current income for the equity portion of carrying costs being capitalized. That income will be recognized over the regulatory recovery period. Moving to page #10, let’s now shift to a discussion of the key drivers and assumptions behind our 2011 Merchant Generation business earnings guidance. We expect this business segment to post earnings of $0.15 to $0.30 per share this year. The largest driver of the expected earnings decline in 2011 compared to 2010 is a decrease in margins of $0.10 to $0.20 per share due to lower realized power prices and higher oil and fuel costs. We expect our merchant plants to generate approximately 29.5 million MWh in 2011 with approximately 26 million MWh of this sold or hedged at an average price of $46 per MWh. Our guidance assumes that all non-hedged expected generation is sold at current market prices. In 2011, we anticipate having base-load capacity available to generate up to 34 million MWh in the event power prices rise and support higher generation levels. Further we estimate that a $5 per MWh improvement in 2011 market power prices as compared to current prices would increase our 2011 generation output by approximately 2 million MWh and our 2011 Merchant Generation margin by approximately $30 million. Our all-in base-load fuel costs are about 90% hedged and we expect the all-in cost of such volume to be approximately $23.50 per megawatt hour. We project non-fuel operations and maintenance expenses will approximate $310 million in 2011. Depreciation expense at the Merchant Generation business is expected to be essentially flat while interest expense is expected to decline increasing earnings by approximately $0.06 per share. This lower projected interest expense primarily reflects the benefit of redeeming $200 million of Genco debt in late 2010. Regarding key Ameren wide assumptions our earnings guidance reflects an effective consolidated income tax rate of approximately 36.5% to 37% which incorporates the expected impact of higher Illinois state income taxes. The average number of common share outstanding in 2011 is expected to approximate $242 million up from approximately $239 million in 2010. Reflecting the use of new issue shares for our dividend reinvestment and 401(k) plans. As I close our discussion of 2011 earnings guidance. I’ll 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 2011 is subject to the risks and uncertainties outlined or referred to in the forward-looking statement section of today’s press release. Turning then to page #11 we provide both our actual 2010 and projected 2011 cash flow information. As Tom mentioned, we’re able to achieve free cash flow of $341 million in 2010. For 2011, we anticipate free cash flow of approximately $100 million. Cash from operations included the benefits of bonus depreciation, actual for 2010 and expected for 2011. For 2011, cash from operations includes a planned incremental contribution to Ameren Illinois post-retirement benefit plan of up to $100 million. The amount is expected to be confirmed in the course of Ameren Illinois rate case. Despite lower expected earnings and higher capital expenditures at our Merchant Generation business, we anticipate that free cash flow from this business will be positive in 2011. Our only long-term debt maturity in 2011 is a $150 million senior secured note at our Illinois regulated utility which we planned to redeem using available cash on its balance sheet. Our total available liquidity was a solid $1.7 billion at the end of January 2011. This includes cash on hand as well as available borrowing capacity under our revolving credit facilities. Moving now to an update on key pending regulatory matters, on page #12, we provide a summary of the pending Missouri electric rate case. As Tom mentioned, we’ve filed a request with the Missouri Public Service Commission for $263 million rate increase that incorporates a 10.9% return on equity, a 51% equity ratio and rate base of $6.8 billion. The vast majority of the rate increase request is driven by rate-based investments and higher net based fuel cost. By the time rates go into effect, we’ll put into service an excess of $1 billion of new investments to improve reliability and provide cleaner air for our customers. The filed rate base is approximately $850 million higher than the level used to set rates in the May 2010 order. Approximately, $73 million of the revenue request relates to increased net base fuel cost. On page #13, on February 8, other parties filed their initial recommendations in this case. The Missouri Public Service Commission staff recommended a $72 million annual revenue increase using the 8.75% midpoint of their recommended return on equity range and a 51% equity ratio. The most significant drivers of the difference between our request and the staff’s recommendation are, return on equity, which accounts for about $125 million of the difference at the staff’s midpoint; rate base adjustments, including $32 million proposed Sioux scrubber disallowance, which in total account for about $25 million of the revenue requirement difference; various operations and maintenance expense differences of about $25 million to $30 million; and net base fuel cost adjustments of $15 million to $20 million. Also, the staff recommended that the fuel adjustment clause be changed to pass-through to customers 85% of deviations between actual net fuel cost and the level of net fuel cost included in base rates. Currently, 95% of deviations are passed through. Other particulars of the staff’s recommendations are listed on page #13. Several other parties also filed recommendations in the case. The Missouri Industrial Energy Consumers recommended $147 million of downward adjustments to our requested revenue requirement. These downward adjustments included approximately $65 million related to a 9.75% midpoint return on equity, approximately $26 million related to income and property taxes and approximately $24 million related to lower net-based fuel costs and various amortizations. As is typical, MIEC did not directly address every element of our rate filing. The Missouri Energy Group, which represents certain other business customers, filed testimony supporting a 10.2% midpoint return on equity. Finally, the Office of Public Counsel has recommended disallowance of the approximately $90 million of Taum Sauk power plant investment, which we’ve included in our filed rate base. We are asking for a recovery of only the portion of Taum Sauk costs that are related to enhancements or that would have been incurred in the absence of the upper reservoir breach that occurred several years ago, consistent with our 2007 settlement agreement with the State of Missouri. We’ll soon update our filing for operating and financial data through the end of the true-up period, which is the 28th of this month. As a result, it is likely that many of the numbers put forward by parties to the case including those of Ameren Missouri will be adjusted. We expect that the updated numbers will be reflected in an April 20th public filing by the Public Service Commission staff and evidentiary hearings are scheduled to begin on April 26th. A Public Service Commission order is expected in July with new rates expected to be effective in early August. Turning then to page #14, on February 18th our Illinois utility filed a request with the Illinois Commerce Commission to increase electric and gas delivery rates by $111 million annually. The request incorporates returns on equity of 11.25% for electric service and 11% for gas service. Filed capitalization is 53% equity with aggregate rate base of approximately $3 billion. The request is based on a future test year ended December 31, 2012. Amongst other items, we’re asking for a pension expense rider that synchronize the amount of pension expenses recovered in rates to the actual of each year’s pension expenses. We are also requesting the authority to defer the impact of the increase in the Illinois corporate income tax rate which climbed from 7.3% to 9.5% on January 1, 2011 and to collect the resulting regulatory assets over a two-year period. Key drivers of the rate request are listed on this page. They include higher operating expenses, net of reductions at administrative and general and pension and benefits expenses. Other drivers are higher income and other taxes and the cost of capital reflecting proposed rates of return and an updated capital structure. In addition, we’re requesting revenues to reflect higher depreciation and amortization expenses. Expected low growth mitigates the requested rate increase. The Illinois Commerce Commission is required to issue a rate decision in 11 months and new rates are expected to be effective by mid-January 2012. We are certainly aware that higher utility rates are difficult to some of our customers to absorb, especially in the current economic environment. At both our Illinois and Missouri utilities, we’ve taken many proactive steps to help our customers manage their energy costs. These steps have included reductions in planned operating and capital spending. Our cost control efforts benefit utility customers by holding down the amount of rate increases we need to request. Other steps that help customers manage their energy costs include our active energy efficiency programs in both Illinois and Missouri. On page #15, we detail Ameren’s updated five-year capital expenditure outlook. Over the 2011 through 2015 period, cumulative capital spending is projected to range between $6.4 billion and $8.2 billion with an annual target range of between $1.3 billion and $1.7 billion. I’d characterize the environmental expenditures embedded in this outlook as those required to meet current environmental rules and regulations as well as our assessment of the likely impact of the proposed Clean Air Transport Rule and coal combustion byproduct rules. As Tom discussed, this five-year budget includes the estimated cost of installing scrubbers at each of the two units of our Merchant Generation Newton plant and at two units of a Missouri regulated plant. On this page we also provide a percentage breakdown of our five-year infrastructure investment budget for our regulated businesses by jurisdiction and type, be it FERC-regulated transmission, Missouri regulated environmental controls, or Illinois Regulated. Moving now to page #16, we outline our expected capital expenditures for our Merchant Generation business for each of the next five years, showing the breakdown between expenditures for maintenance and for environmental compliance. The amounts on this graph reflect the previously mentioned acceleration of the in-service states for scrubbers at the Newton plant and the previously mentioned equipment upgrade. These Merchant Generation numbers are included in the total Ameren-wide capital expenditures that I discussed a few minutes ago. Of course, we’ll continue to review and adjust our Merchant Generation spending plan in light of evolving outlooks for power prices, delivered fuel cost, environmental standards and compliance technology among other factors. Moving now to page #17, we provide an update on our 2011 and 2012 forward power sales and hedges and introduce our 2013 hedge data. As you can see we’ve significant hedges in place at power prices above current market levels. We already discussed our 2011 power hedges. For 2012, we’ve hedged approximately 15 million MWh at an average price of $50 per MWh. Further for 2013, we’ve hedged approximately 7.5 million MWh at an average price of $42 per MWh. I’d note that about 55% of the MWh hedged in 2013 are associated with long term contracts and the remainder of our financial contracts. None of the financial contracts hedged in 2012 and 2013 expected sales are Sinhub [ph] contracts and the pricing reflected has already been basis adjusted as necessary to Illinois generation node pricing, based on two years historical average basis differentials. Our capacity sales are approximately 75% hedged for 2011 appropriately 44% hedged for 2012 and approximately 22% hedged in 2013. To assist you in understanding our Merchant Generation business segments margin drivers we’ve provided a pie chart that breaks down our 2011 expected revenue by type. Turning to our final page, no. 18, we update our Merchant Generation segment’s fuel and related transportation hedges. We previously discussed our 2011 fuel hedges. For 2011, we’ve hedged approximately 16 million MWh at about $25 per MWh. For 2013, we’ve hedged approximately 4 million MWh at about $28.50 per MWh. These 2013 co-hedges include a large proportion of our expected burn of Illinois basin coal and a much smaller proportion of our expected burn of Powder River basin coal. To provide perspective, our typical burn is 3% Illinois and 97% Powder River basin coal. The embedded cost of coal in this 2013 hedge price is approximately $24 per ton which is approximately $7.50 per ton higher than current 2013 broker quotes for PRB coal. Similar to our previous slide, dealing with Merchant Generation revenues we’ve included a pie chart that breaks down forecasted 2011 all-in fuel cost to provide a perspective on how each component contributes to our overall cost. This completes our prepared remarks. We’ll now be happy to take your questions.

(Operator instructions) Our first question comes from Paul Ridzon with KeyBanc. Please proceed with your question. Paul Ridzon - KeyBanc: $522 million write-down at Merchant, but depreciation is flat, what’s driving that? Is it really just all goodwill?

Yes, Paul. If you recall, there was goodwill, there was also some plant impairment, but largest part was goodwill, which, of course, for accounting purpose isn’t amortized or depreciated. The power plant write-off piece was much smaller, but what we also did is took a look at the lives of the power plants within the fleet. So while our write-off of some power plant expense we typically decreased depreciation, we’ve also taken a look at the lives of our other units and net, it came out to no net positive or negative impact from depreciation expenses. Paul Ridzon - KeyBanc: What drove the acceleration of Merchant CapEx? Is there something fundamental in the market, or are you trying to take advantage of bonus depreciation?

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

The bonus depreciation for 2010 that came out in that law companywide expected to help cash in 2011 by about $100 million to $150 million. Paul Ridzon - KeyBanc: How much for ‘12?

Yes. I don’t have the ‘12 numbers at this point. Paul Ridzon - KeyBanc: The breakdown between Merchant and Regulated?

The $100 million and $150 million, I don’t have the breakdown overall on the $100 million, $150 million between the segments. Paul Ridzon - KeyBanc: Okay, thank you very much.

Our next question comes from Reza Hatefi from Decade Capital. Please proceed with your question. Reza Hatefi - Decade Capital: Thank you. Just wanted a couple of clarifications on your hedging, fuel per MWh in 2011 and ‘12 went down versus your third-quarter slide by about $1 to $1.50 per MWh, what drove that?

Yes, it’s a good point. In both cases, we pointed out for some time that the hedges we’ve in place for coal were at prices that we believe were above current market prices for coal. So as we’ve layered in additional hedges for both 2011 and 2012, we’ve brought down the average cost per MWh of the blended generation. In ‘11, however, in addition to the benefit of those lower cost hedges we put in place, we’re also benefiting as we look to these numbers and refine them, lower emission allowance cost as well as lower expected taxes that we pay on our delivered fuel cost. So in 2011, we’re getting the benefit of, I’d say all three of those factors. In 2012, it was largely driven by the lower cost coal we put in place. Reza Hatefi - Decade Capital: And then your 2013 hedges, $42, are they around the clock, or are they weighted more towards peak as of now? How should we think about that?

I think as you look at those hedges, the 2012 hedges look very much like an around the clock kind of product, the ATC typically about 47% to 48% on peak. The 2013 hedge profile is a little more weighted to our base load generation mix, which tends to be about 52% on peak. Reza Hatefi - Decade Capital: And just finally, could you comment on, I guess, strategically your thoughts on the Merchant segment and with the forward curve being as weak as it is any thoughts there in terms of this segment continuing to be part of Ameren?

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

Our next question comes from Paul Patterson with Glenrock Associates. Please proceed with your question. Paul Patterson - Glenrock Associates: Good morning, guys.

Good morning.

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

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

This is Tom Voss. We’ve been working with MISO to develop a better capacity market, so it’s looks more like PJM’s market, capacity market and we expect MISO to file sometime later this year a plan to the FERC that would show a better capacity market than what currently exist. So our plans right now are to work with MISO on improving it. Paul Patterson - Glenrock Associates: How soon should we think about the changes that MISO might propose actually flowing through to the bottom-line of generators in MISO?

We think right now that if everything goes right and everything keeps moving it should be in the 2012 year. Paul Patterson - Glenrock Associates: Okay. Thanks a lot.

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

Well, I think, Erica, as we look out over time, we frankly try to sell as much as we can with the shaped product and we haven’t really given a break-down for year, which you are right, I mean our sales strategy is to go after the higher margin customer segments in the areas, where we’ve generation, as those opportunities present themselves (inaudible) to lock in the higher margins that you can see in those list of power prices. Erica Piserchia - Wunderlich Securities: Okay. And then I guess just you talked about potentially being able to ramp-up your Generation output. I believe you mentioned you could potentially ramp-up to as high as 34 million MWh. Just looking back over the last couple years, you kept the output obviously flat. When you talk about potential market recovery, what levels would you need to see in the market to get you more incentive towards doing that, we’re talking about going back to pricing that was in existence a couple of years ago, or clearly probably a little bit longer term, what are your thoughts on that?

Well, what we tried to provide in the script was a little bit of a metric in terms of, if we saw a $5 (inaudible) in power prices based on our open and available Generation for 2011 that that could produce up to $30 million of additional margins. We provide that metric to give you a sense of, given the available capacity that we’ve, if power prices were to move what kind of incremental generation we would have and what those margins are. Any given year the amount of generation that we’ve got available obviously is dictated by the outage schedule we’ve for that year, but we think that metric maybe helpful to you as you look at, where our incremental generation is in terms of cost, and if they were to be dispatched at those higher prices, what kind of margins we could get. Erica Piserchia - Wunderlich Securities: Sure. So like a sensitivity. Last question just on your 2011 guidance for the Regulated end of the business. Does the low-end of the range encompass sort of on the Missouri side of the staff’s recommendation and on the Illinois side, sort the existing state of, well, I guess it would because your new rates there wouldn’t take effect till 2012, but on the Missouri side is the staff end of the recommendation included in that low end or how do we think about that?

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

(Operator instructions) Our next question will come from Ashar Khan with Visium. Please proceed with your question. Ashar Khan - Visium: Good morning. Marty, can I just ask you, when were the 2013 hedges put in place? Because that was a new data. Were they put in place during the last three months or six months? Could you give us some timing of those hedges?

Ashar, we’ve been working on hedges for some time. So some of those were put on in 2010 timeframe, others were put on some periods prior, but we’ve been working at those over time. We’re never kind of sitting on our hands. We’re always looking at sales opportunities as they present themselves. We’ve talked about our strategy of going after retail customers and you have to act on those when they are available in the market and they arise from time-to-time, and we execute on those. Ashar Khan - Visium: If I can remember the contract with the Illinois rate that ends in 2012, am I right?

Yes, that’s right. Ashar Khan - Visium: Okay, thank you very much.

Welcome.

Our next question comes from Julien Dumoulin-Smith with UBS. Please proceed with your question. Julien Dumoulin-Smith - UBS: Good morning. Thank you. So just wanted to first touch on the Illinois side of the house and ask about the ComEd legislative proposal. Just on your side, are you guys supportive of it and any kind of expectations out of the process this year, more confidence in certain aspects relative to others?

This is Scott Cisel. I’ll respond to your question. Concerning the rate formula bill, we certainly are very supportive of the bill as it’s been presented. As you know, it would enable utilities to continue to make prudent and reasonable investments into the system and then be allowed to realize a reasonable return on the investment. The amendment is the rate formula bill will be introduced this afternoon in a committee hearing and then from that point on, it will begin the process of discussions and eventually consideration. It’s very early in the session to give any sort of prediction but we and other will participate and we’ll strive to see if we can end up with a workable compromise and do so yet this spring legislative session. Julien Dumoulin-Smith - UBS: Then secondly on the Regulated side of the house with regards to the stay order, perhaps could you discuss some of the levers that you might be able to pull to resolve the pending litigation, be it at an Appeals Court, at the Commission, I mean perhaps just walk through some of the way to from here if you will?

This is Warner Baxter. I’ll respond. I think as we’ve stated we’re going to be filing our position by the end of this week with the Missouri Public Service Commission on the Office of Public Counsel on the industrial consumers’ pleadings. Really beyond that I’m really not in a position to address really any other specific questions or positions or strategies, we’re going to take for this pending litigation matter. Julien Dumoulin-Smith - UBS: Then finally, just quick last question, more detail-oriented. On the O&M side from Merchant Gen I know that’s a little bit of rise year-on-year. Could you walk through that very quickly if you don’t mind?

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

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

A good question. I think that’s right. I mean I’d note that this in 2010 the point of reference, we actually were able to limit the capital expenditures for that segment to $89 million, so certainly being able to keep maintenance in other as well pretty low is something that we think is doable. So when you look at 2015 levels, not too in line with what we’re seeing in 2010, but our thought is actually given some of the maintenance that’s already been done in the years leading up to the present as well as the maintenance in other items that we got planned for ‘11 through ‘14 that we’ll have done requisite maintenance on our big base-load facilities. We feel like when we get out to 2015 the necessary efforts and expenditures will be behind us. So as we said on the call, certainly as we move through time we’ll look at the power price environment, we’ll pay close attention to our cash flows, some of the expenditures in ‘13 and ‘14 could conceivably move out to ‘15, but right now I think this is a good snapshot of where we stand today. Robert Howell - Prospectus Partners: And so are those low levels for ‘15 something that could kind of continue out for the next couple years, it sounds like the ‘15 number from a maintenance CapEx perspective is may be a tiny, but lower than the long on average because you pushed it forward, but will you be able to kind of keep it low like that for a couple years before it gradually ramps up or?

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

Our next question comes from David Katz with Bank of America. Please proceed with your question. David Katz - Bank of America: Good morning. Thank you. I just had a question on your average utility book equity in 2010. You guys were saying last year it would be about $6 billion. Where did it end up at?

I don’t know, I’d think it probably ended up somewhere close to that, David, I don’t have the exact number. David Katz - Bank of America: Okay. So then as we look at the $6.2 billion for 2011 average equity, how much of that or what percentage of that is Missouri and what percentage of that is Illinois?

I don’t have that break down either. I mean it’s obviously roll-forward of increased earnings and months to regulated businesses less the dividends it’s pretty simple math. I know you know but I don’t have the breakdown between the regulatory jurisdiction. David Katz - Bank of America: Just quickly on the O&M growth. I know you say there’s a Callaway refueling outage later this year and that expected impact should be slightly less than what it was last year. You have to increase nonfuel O&M as one of the drivers. What kind of growth in nonfuel O&M should we be looking at?

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

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

I wouldn’t say the comment was about our strategy going forward in terms of fuel burn. We’ll certainly buy what we believe the most economical to burn. But what we’re really trying to point out there is that the embedded cost of our coal hedges for 2013 are well above current PRB broker quotes. So what I was really trying to convey there is similar to what we’ve seen in ‘11 and ‘12. As we bought additional fuel, the average hedge price has come down. What I was trying to convey there is we’ve the same expectation with respect to 2013. When we lay in additional hedges, if we’re to lay today we would bring down that average price per MWh. Michael Lapides - Goldman Sachs: Are you still expecting you’ve talked in the past that the rail transportation piece, or however you use transportation, will be roughly two-thirds of the total all-in cost of fuel?

We break that out. If you see on that slide 18, you actually see that for 2011 the transportation about 52% with fuel surcharges, it gets you to about 58%, so that’s our expectation for ‘11. We’ve also commented over time that we do believe that while you look out you see some of the rail contracts or rail hedges rolling off. We do believe that the contracts we’ve in place today are at about market rates, so we’re not really expecting any major deviation as we lock in new rail contracts. Michael Lapides - Goldman Sachs: Got it, okay, thank you guys. Much appreciate it. I’ll follow up with Doug offline.

Our next question comes from Dan Jenkins with State of Wisconsin Investment Board. Please proceed with your question. Dan Jenkins - State of Wisconsin Investment Board: Hi, good morning.

Good morning. Dan Jenkins - State of Wisconsin Investment Board: I just wanted to clarify. I think you said when you were talking about cash flows; did you say you’re planning to pay off that Ameren Illinois maturity of $150 million in June that you’re going to refinance?

You’re correct, our plan is to pay that off, redeem that. Dan Jenkins - State of Wisconsin Investment Board: Then while you continue to issue new shares like the DRIP program and those programs and they’re still how much would you expect that to be?

We do expect to do that, to continue that through this year that’s embedded in our guidance and I guess that’s in the range of $90 million or so. Dan Jenkins - State of Wisconsin Investment Board: Will there be any other financing then given that you expect a positive free cash flow?

At this time, we don’t have any other plans. Dan Jenkins - State of Wisconsin Investment Board: Okay, thank you.

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

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

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

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

Okay, thank you.

Okay, thank you.

Our next question comes from Sarah Eccles with Wells Fargo Advisors. Please proceed with your question. Sarah Eccles - Wells Fargo Advisors: Hey, good morning.

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

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

Our next question comes from Steven Gambuzza with Longbow Capital. Please proceed with your question. Steven Gambuzza - Longbow Capital: Good morning.

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

Sure, I think that’s as Tom mentioned in his prepared remarks, we as well as everybody else in the industry I think is anticipating to see some proposed rules coming out of EPA middle March. And we’ll see what those require. And as Tom mentioned we put together a team of people that have been working diligently over the past year and well into the coming year to take a look at what comes out of the EPA and make the best decisions about what kinds of additional investments will or won’t be made in the plants we’ve and try to make the most efficient economical investment decisions that we can for the best interest of the shareholders and the customers. So could that require additional CapEx? Certainly so. But we’re really going to make those decisions on the plant by plant basis across our fleet. Steven Gambuzza - Longbow Capital: In your prepared remarks, I heard you mentioned the coal combustion byproduct rule and the Clean Air Transport Rule as the two, I guess regulatory issues that your CapEx forecast was taking into account. I didn’t hear you mention the mercury or the hazardous gas rules, but we should assume that your expectation regarding those regulations are embedded in your forecast?

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

That’s something that is going to be assessed. We’re certainly beginning some additional design work, but that would be applicable to whatever units we decided to go forward. Steven Gambuzza - Longbow Capital: Okay, thank you.

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

Our next question comes from Daniele Seitz with Dudack Research. Please proceed with your question. Daniele Seitz - Dudack Research: Thank you. I was going to ask exactly the same questions and so at this point your CapEx really built on your estimates of what the EPA rules are going to come out whether it’s not just on the Illinois Multi-Pollutant Standard, is that correct?

Yes and no, Daniele. I think, again what we’re saying was that it does incorporate an assessment of requirements that the Clean Air Transport Rule will impose, as well as rule for coal combustion byproducts, but nothing further than that from a Federal EPA standpoint. Daniele Seitz - Dudack Research: Okay. On your side, are you trying to convince your regulators that actually in order not to file so many rate cases. It would be easier if you were operating under riders at this time, or are they reluctant to allow this kind of rules?

I think Daniele; certainly we’ve been successful at getting some riders over the past few years. Those can have the added benefit of being able to go for a more extended time periods between rate cases and be able to recover your cost on a timely basis, so that is something that we’ve pursued and will continue to pursue in the future. Daniele Seitz - Dudack Research: Obviously, the comment legislative proposal would put the step forward toward a more timely type of regulatory environment. Will that replace whatever ambitions you have regarding riders?

I think as it relates to Illinois, the rate case that we filed on Friday incorporated a forward-looking test year. It also incorporated a request for a rider for pension expenses going forward, so we’ve made those filings. I think that the legislative proposal that has been discussed, that Scott earlier said, we’re supportive of, if that was put in place, I think likely would supersede those other kinds of efforts. Daniele Seitz - Dudack Research: And on the side of the Missouri, do you see any new effort or progress in that area?

Could you repeat that? I know it was Missouri, but I couldn’t tell what the – Daniele Seitz - Dudack Research: Do you see any in-roads that you may make regarding additional riders?

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

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

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