Douglas Fischer – Director, IR Tom Voss – Chairman, President and CEO Martin Lyons – SVP, CFO

Paul Patterson – Glenrock Associates Julien Dumoulin-Smith – UBS Tom Rebinoff – Fore Research and Management David Paz – BofA/Merrill Lynch Reza Hitucki – Decade Capital Michael Lapides – Goldman Sachs Greg Reiss – Catapult John Murphy – Green Arrow

Greetings, and welcome to the Ameren Corporation’s Fourth Quarter Earnings Conference 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 IR for Ameren Corporation. Thank you, sir. You may now begin.

Thank you, and good morning. I’m Doug Fischer, Director of Investor Relations for Ameren Corporation. On the call with me today are our Chairman, President, and Chief Executive Officer, Tom Voss; our Senior Vice President and Chief Financial Officer, Marty Lyons; and other members of Ameren management team. Before we begin, let me cover a few administrative details. This call is being broadcast live on the Internet and the webcast will be available for one year on our website at www.ameren.com. Further, 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 have posted a presentation on our website that will be referenced during this call. To access this presentation, please look in the Investor section of our website under webcasts and presentations and follow the appropriate link. Turning to page two 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 section in our filing with the SEC. Tom will begin this call with an overview of 2011 earnings and 2012 guidance, followed by a discussion of recent business and regulatory developments. Marty will follow with more detailed discussions of 2011 financial results, our 2012 guidance and regulatory and other financial matters. We will then open the call for questions. Here’s Tom, who will start on page three of the presentation.

Thanks, Doug. Good morning and thank you for joining us. Core earnings for 2011 were $2.56 per share in line with the increased guidance range we provided in November of last year. As expected, these 2011 results were below the $2.75 of core earnings per share achieved in 2010. This reflected lower electric sales to native load utility customers due in part to summer temperatures that while warmer than normal were below those very hot 2010. In addition, merchant generation margins decline as a result of lower realized power and capacity prices, as well as higher fuel and transportation related expenses. These factors were offset in part by increased electric utility rates in Missouri and Illinois. Further, core non-fuel operations and maintenances expenses were lower, reflecting continued disciplined cost management, and interest cost fell as we used our free cash flow over the last two years to reduce outstanding debt. Beginning on page four you will find a list of our key accomplishments in 2011. These accomplishments are clear evidence of our commitment to providing customers with safe, reliable, environmentally responsible, and reasonably priced energy while at the same time enhancing value for our shareholders. To put these accomplishments into context it is important to summarize some of our key financial objectives. At our regulated utilities, we seek to earn fair returns on our investments, which allow us to attract on competitive terms the capital we need to provide the level of service our customers expect. We are working around fair returns by maintaining solid operating performance while improving our regulatory frameworks and seeking rate release as needed. Further we are committed to allocating capital to those projects on which we expect to earn fair returns and aligning our spending with regulatory outcomes and economic conditions. At our merchant generation business we seek to protect and enhance shareholder value by minimizing operating and capital spending during the current period of low power prices while advocating for regulatory policies and power market improvements that will lead to improved economics. While I’ll not touch on each of the 2011 accomplishments listed on pages four and five, I would like to summarize and highlight a few of our successes. At Ameren Missouri and Ameren Illinois, we posted another year of solid distribution system reliability. At Ameren Missouri and our merchant generation business availability of our energy centers remained high. Our restoration efforts following severe storms in both Missouri and Illinois won praise from government officials. In addition, in 2011, we actively pursued legislative and regulatory agendas that we expect will improve predictability and level of earned returns at our regulated utilities. The most notable development on this front was the enactment by the State of Illinois of legislation established on performance based formula ratemaking for electric delivery service. Further, we thought and obtained electric and gas rate increases in Missouri and a gas rate increase in Illinois, the latter of which was authorized in January of 2012. Continuing on page five, at our merchant generation business we updated our environmental compliance strategy during 2011, leading to reductions in capital spending plans and expected future operating costs compared to our prior plans. Ameren Transmission Company also notched important successes allowing us to move forward with our plans to improve the region’s electric transmission system and also create jobs. In May, the Federal Energy Regulatory Commission or FERC approved requested constructive rate treatment for two transmission projects. And in December, the Midwest Independent Transmission System Operator or MISO approved three major transmission projects. On the financial front, we concluded another year of successful cost management with a decline in core non-fuel operations and maintenance expenses. In addition, we generated enough cash flow from operations to fund more than $1 billion of investments. And the common dividend while also reducing outstanding borrowings and more than 85% of these investments were for infrastructure at our regulated utilities. Finally, in October of 2011, Ameren’s Board of Directors increased the quarterly common dividend by3.9% per share. Moving now to page six in a forward focus, today we announced 2012 GAAP and core earnings guidance of $2.20 to $2.50 per share. The projected decline in 2012 core earnings per share compared to 2011 is primarily due to expected lower margins at our merchant generation business and an assumed return to normal temperatures. These factors are expected to be partly offset by increased utility rates as well as reduced non-fuel operations and maintenance expenses in Missouri. Turning to page seven on pending regulatory matters, in January of 2012, Ameren Illinois elected to participate in Illinois’ new performance based formula ratemaking process for electric delivery service by making an initial filing with the Illinois Commerce Commission. As a result, we expect Ameren Illinois’ electric delivery earnings in 2012 and beyond to reflect formula ratemaking, which will enable us to invest in a state improving infrastructure and creating jobs. The improved infrastructure will enhance reliability and provide customers with the energy usage options made possible by smart meters. Turning to Missouri, we are focused on modernizing the existing regulatory framework. Our modern regulatory framework that allows us to recover and earn fair returns on our investments on a timely basis, will improve our ability to bring aging infrastructure up to 21st standards, allowing us to meet customer expectations and create jobs. Earlier this month, Ameren Missouri filed an electric rate case with the Missouri Public Service Commission seeking to recover its operating and capital costs and to earn a fair return on investments it has made to serve its customers. Marty will provide details of the filings in a few minutes. However, I would like to highlight two proposals we have made in this case to enhance the existing regulatory framework. First, we are seeking approval of a storm cost tracking mechanism that wd provide the opportunity to recover costs to restore service after major storms in a manner that is fair to both our customers and our investors. Second, we are seeking approval of a new plant-in-service accounting proposal. This proposal is designed to reduce the impact of regulatory lag on earnings and future cash flows related to assets placed in service between rate cases. In addition to the pending electric rate case, in January 2012 Ameren and Missouri filed its first request with the Missouri Public Service Commission for approval of new and expanded energy efficiency programs under the Missouri Energy Efficiency Investment Act. Our proposed energy efficiency programs are expected to provide significant long-term benefits to our customers. The energy efficiency legislation was designed to enable utilities to pursue cost effective energy efficiency programs by requiring that the regulatory framework properly align the utility’s financial incentives with those of customers. Ameren Missouri’s ability to move forward with these proposed energy efficiency programs will require a regulatory frame work consistent with this legislation. And our energy efficiency proposal is consistent with the legislation and industry best practices. Before I conclude my comments on pending regulatory matters, I want to mention that we support the MISO’s filing at the FERC for an annual capacity construct, as a first step although we continue to advocate for a multi-year capacity construct to ensure properly functioning power markets. Further, we strongly support MISO’s effort at FERC to increase the amount of capacity that can be shared across the MISO, PJM seen. Constructive action on these matters is the right thing for FERC to do because it’d lead to prices that more accurately reflect the value of capacity, improve efficiency and reliability, and benefit customers over the long-term. Turning to page eight. Our merchant generation business has produced positive free cash flows in recent years including over $200 million in 2011. This reflects the benefit of our forward power sales in hedging programs and actions we have taken to control spending. For 2012, we’ve again sold forward or hedged nearly all of our expected 2012 merchant generation output at prices above current market levels. As a result, we expect our merchant generation segment to be free cash flow positive in 2012 and for Genco with the benefit of existing money pool receivables to provide for its own cash needs. As we look beyond 2012, we cannot ignore the potential negative impact of lower prices on our cash flows. As most of you are aware, since late 2011, there has been a sharp decline in forward power prices. We attribute this most recent price decline to the U.S. Court of appeals order staying the Cross-State Air Pollution Rule or CSAPR, as well as the recent decline in natural gas prices. It is unclear to us exactly when legal and regulatory uncertainties related to CSAPR will be resolved and when natural gas and power prices will recover. This decline has prompted us to again revise capital spending plans for our merchant generation business. As a result, we have decided to immediately decelerate construction of the Newton scrubber project postponing installation until such time as the incremental investment necessary for completion is justified by the visible market conditions. In addition, we are moving from our forward five-year expenditure plans to previously planned Edwards 3 helper electrostatic precipitator. We believe that these actions are the best path to ensuring appropriate returns on incremental environmental investments and achieving continued positive free cash flow at our merchant generation business segment during this period of low power prices. We estimate that these actions will reduce 2012 through 2014 capital needs by a total of approximately $270 million compared to prior plans. As we work to ramp down the Newton Scrubber Project, we will do so in a manner that preserves the value of work commissioned to-date. We plan to take delivery and place the various completed components and materials into a safe store condition over the remainder of this year. Thereafter, we’ll perform minimal amounts of ongoing construction activity, such that when the economics merit completing the Newton Scrubber Project in earnest, we’ll able to do so in an orderly and cost effective manner. We have already initiated discussions with our partners and vendors on the task, timelines, and cost, associated with decelerating the project. Based on these discussions we have removed the vast majority of capital spending related to the Newton Scrubber Project from our 2013 and 2014 plans and we have reduced our expected 2012 spending level on the Newton Scrubbers to approximately $150 million reflecting work commissioned to-date. These developments highlight the critical need for a viable multiyear capacity market in the MISO region, as well as a need for portability of capacity between MISO and PJM. The current state of uncertainty arising from low power prices and uncertain environmental rules has a potential in my view to negatively impact electric reliability within MISO and elsewhere in the nation. Moving now to page nine, we remain very excited about our plans to symmetrically grow our investments in FERC regulated electric transmission projects. In fact, Ameren expects to invest a total of approximately $1.7 billion in such projects over the five-year period ending in 2016. Customer should benefit from improved reliability in a more efficient electric system. Our investors should benefit because we expect to earn fair returns on such investments. At this time, we are investing in FERC regulated transmission through two different entities, Ameren Illinois Company and ATX. Ameren Illinois has significant opportunities to invest in projects that are focused on local load growth and reliability needs. This business expects to invest nearly $900 million in such projects over the five-year period. ATX plans to build Greenfield regional transmission projects initially within Illinois and Missouri and to invest approximately $750 million in such projects over the next five years. In December of 2011, MISO’s Board of Directors approved three of ATX projects as multi-value projects. These projects represent more than $1.2 billion of ATX investments over eight years and we are moving ahead with development of these projects. In fact, for the largest of these the $800 plus million Illinois Rivers project we are moving forward with the line routing and siting process. I will now turn the call over to Marty.

Thanks Tom. Turning to page 10 of the presentation, today we reported 2011 earnings in accordance with Generally Accepted Accounting Principles or GAAP of $2.15 per share compared to 2010 GAAP earnings of $0.58 per share. Excluding certain items in each year Ameren recorded 2011 core earnings of $2.56 per share compared with 2010 core earnings of $2.75 per share. 2011 core earnings exclude three items that are included in GAAP earnings. The first of these non-core items is employee separation charges related to the 2011 voluntary retirement offer, which reduced earnings by $0.07 per share. The second non-core item is $0.02 per share loss from the net effect of unrealized mark-to-market activity. The third of these full year 2011 non-core items is goodwill, impairment and other charges, taken into the third quarter of $0.32 per share. These charges were the results of Missouri Public Service Commission’s disallowance of cost of enhancements related to the rebuilding of the Taum Sauk Pumped-storage hydroelectric energy center as well as our decision to cease operations at the Meredosia and Hutsonville merchant generation energy centers. Turning to page 11, here we highlight key factors driving the variance between core earnings per share for 2011 and 2010. Key factors adversely affecting the comparison include a decline in margins at our regulated utilities of $0.30 per share after excluding rate changes. We estimate that $0.13 of this decline was due to lower weather-normalized loads and $0.10 was primarily the result of temperatures that were below those – very hot 2010. Another $0.05 of the decline was due to a second quarter 2011 charge, related to Missouri public service commission requirement that certain revenues be flow-through the fuel adjustment clause. A decline in margins at the merchant generation business reduced 2011 earnings by $0.21 per share. The reduced margins reflected lower realized power and capacity prices and higher fuel and related transportation costs. Several severe storms in the first half of 2011 reduced earnings by $0.09 per share, with $0.06 of this related to Ameren Missouri and $0.03 related to Ameren Illinois. Key factors favorably impacting the comparison of 2011 core earnings to 2010 core earnings, included electric rate increases in Missouri and Illinois. Changes in electric and gas rates net of certain related expenses increased earnings by $0.23 per share. These rate changes included higher electric rates in Illinois effective in 2010, and an electric rate increase in Missouri effective in late July 2011. The other key factor positively impacting earnings was lower core non-fuel operations and maintenance expenses, which benefited 2011 earnings by $0.20 per share excluding the previously discussed storm restoration costs. Turning to page 12, I would now like to discuss the key drivers and assumptions behind our 2012 earnings guidance for our Missouri and Illinois regulated utility businesses of $2.20 to $2.40 per share. In 2012, we expect to achieve an earned return on equity of approximately 9% to 9.6% on average regulated utility common equity of approximately $6 billion. This guidance assumes a return to normal weather reducing earnings by an estimated $0.16 per share compared to 2011 results. While 2011 summer temperatures were milder than those experienced in 2010, 2011 summer temperatures were much hotter than normal. Weather normalized margins are expected to increase as a result of the 2011 Missouri electric rate increase and the 2012 Illinois natural gas delivery rate increase. Our guidance also reflects the implementation of the new formula ratemaking process for our Illinois Electric delivery business. Our earnings expectations for this business assume a formulaic midpoint allowed return on equity of 9.2%, which incorporates a forecasted 2012 average 30-year treasury yield of 3.3%. This treasury yield forecast is based on the blue chip consensus estimate as of February 1st, 2012. Finally, our outlook for regulated margins assumes little growth in weather normalized electricity sales. Regulated utility earnings guidance for 2012 incorporates increased non-fuel O&M spending at our Illinois utility as we begin to implement our electric delivery modernization action plan. At our Missouri utility, we expect 2012 non-fuel O&M spending to be lower than that experienced in 2011. Headcount in Ameren Missouri and Ameren Services declined by approximately 340 at the end of 2011 as a result of the voluntary retirement program. In addition, the absence of a scheduled refueling and maintenance average at the Callaway Nuclear Energy Center in 2012, is expected to lower O&M expenses by $0.10 per share. Callaway is refueled approximately every 18 months. Finally, we expect 2012 regulated earnings to be impacted by increased depreciation and amortization expenses. Moving to page 13, let’s now shift to a discussion of the key drivers and assumptions behind our 2012 earnings guidance for our merchant generation business. We expect this segment to post earnings of zero to $0.10 per share this year. The most significant driver of the expected earnings decline in 2012 compared to 2011, is a decrease in margins of $0.20 to $0.30 per share due to lower realized power and capacity prices and higher fuel and transportation related costs. We expect our Merchant plans to generate approximately 27 million megawatt hours in 2012 with approximately 25 million megawatt hours of this sold or hedged at an average of $44 per megawatt hour. Our guidance assumes that un-hedged expected generation is sold at current market prices. In 2012, we anticipate having available generation of up to 32.5 million megawatt hours from our coal-fired merchant generation energy centers in the event power prices rise and support higher generation levels. Our base load fuel and transportation related costs are about 93% hedged at approximately $24 per megawatt hour. Finally, we project 2012 merchant generation non-fuel operations and maintenance expenses will be essentially flat with those of 2011 or approximately $290 million. Regarding key Ameren wide assumptions, our earnings guidance reflects an effective consolidated income tax rate of approximately 36% and the number of common shares outstanding in 2012 is expected to average $242.6 million. In 2012, we plan to purchase shares on the open market for a dividend reinvestment in 401-K plans. During the past several years, we have issued new shares to fund these plans. As I close our discussion of 2012 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 earnings guidance because the company is unable to reasonably estimate the impact of any such gains or losses. Core non-GAAP earnings and guidance also exclude any net unrealized mark-to-market gains or losses. Further, earnings guidance are subject to the risks and uncertainties outlined or referred to in the forward-looking statements section of today’s press release. Turning then to page 14, we provide both our actual 2011 and projected 2012 cash flow information. As shown on this page, we calculate free cash flow by starting with our cash flows from operating activities and subtracting from it our capital expenditures, other cash flows from investing activities, dividends and net advances for construction. In 2011, free cash flow reached $381 million, $56 million more than our November guidance. For 2012, we anticipate free cash flow will be negative by approximately $230 million. The decline in free cash flow primarily reflects lower cash flow from operations and higher capital spending plans. Cash flow from operations is expected to decline in 2012 compared to 2011, as a result of lower projected core earnings at our merchant generation segment, reduce tax refunds and greater utility spending subject to deferred rate recovery amongst other matters. The higher 2012 capital expenditures reflect increased expected spending primarily at our regulated utilities. We anticipate that our merchant generation business will be free cash flow positive in 2012 despite expected lower earnings and higher capital expenditures. Our only material long-term debt maturity in 2012 is $173 million senior secured note at Ameren Missouri. Moving now to page 15, impending rate cases. As Tom mentioned, in January Ameren Illinois made its initial filing under the new performance based formula rate making framework for its electric delivery business. This initial filing is for a $19 million annual rate decrease because it is based on 2010 cost. This rate change is to be effective in late October 2012. However, 2012 electric delivery service earnings will reflect a true-up for 2012 year-end rate base and 2012 actual cost of service, and include historical ICC rate making adjustments. The allowed return on equity will be based on the prescribed formula I discussed earlier. Moving to page 16, in Missouri, in February we filed for $376 million increase in annual electric rates with the Missouri PSC. The filing incorporates a 10.75% return on equity, a 52% equity ratio and rate base of $6.8 billion. $103 million of this request is related to higher net fuel cost. Note that 95% of these higher net fuel cost would be reflected in fuel adjustment clause or FAC rate adjustments absent this filing. The request also includes $81 million to recover the annual cost including revenues to offset throughput disincentives of the three-year energy efficiency programs, Ameren Missouri proposed in its MEEIA filing which Tom mentioned earlier. As he stated, our ability to move forward with our proposed energy efficiency programs will require a regulatory framework consistent with the energy efficiency legislation. In addition to recovery of higher fuel cost and cost associated with our proposed energy efficiency programs, the rate request includes recovery of investments made to improve the reliability of our aging infrastructure and to comply with renewable energy regulations as well as other cost increases. A PSC order is expected in December of 2012 with new rates expected to be effective in January of 2013. On page 17 we detail our new five-year regulated utility capital expenditure outlook. In 2012, we plan to invest approximately $1.2 billion and over the four-year period, from 2013 through 2016 the midpoint of aggregate capital spending is projected to be approximately $5.7 million with an annual target range of $1.3 billion to $1.5 billion. The environmental expenditures embedded in this outlook are those required to meet current environmental rules and regulations including the State CSAPR and the recently issued MATS as well as our assessment of the likely impact of the coal combustion by product rules. The pie chart on the right side of this page breaks down our five-year regulated capital spending plan by business segment and activity. A little less than half is for Missouri with almost 30% targeted for our Illinois electric and gas delivery businesses, and almost a quarter slated for FERC regulated transmission projects. The Illinois regulated capital spending numbers reflect additional investments to modernize its electric distribution system as required by our participation in Illinois performance based formula rate program. Moving now to page 18, here we provide an update on our 2012 and 2013 forward power sales and hedges and introduce our 2014 hedge data for our merchant generation business. As you can see we have significant hedges in place at power prices greater than current market levels. We already discussed our 2012 power hedges. For 2013, we have hedged approximately 14 million megawatt hours at an average price of $40 per megawatt hour, further for 2014, we have hedged approximately 7 million megawatt hours at an average price of $44 per megawatt hour. To assist you and understanding our merchant generation business segment’s margin drivers, we have provided a pie chart that breaks down our 2012, expected revenue by type. Turning to page 19, here we update our merchant generation segment’s fuel and related transportation hedges. We previously discussed our 2012 fuel hedges. For 2013, we have hedged approximately 12 million megawatt hours at about $25.50 per megawatt hour. For 2014, we have hedged approximately 5 million megawatt hours, also at about $25.50 per megawatt hour. Similar to our previous slide detailing merchant generation revenues, we’ve included a pie chart that breaks down forecasted 2012 all in fuel cost to provide a perspective on how each component contributes to our overall cost. On our final page, number 20, we outlined 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. As Tom mentioned, in light of current forward power and capacity prices as well as uncertain environmental regulations, we are decelerating construction of our Newton Scrubber project and removing the Edwards Helper Electrostatic Precipitator from our five-year spending forecast. The estimated environmental expenditures in 2012 include approximately $150 million of spending on the Newton Scrubber project. And capital expenditures in 2013 through 2016 assume approximately $20 million per year of ongoing external construction costs for this project. Newton Scrubber project related capitalized interest and overheads are not included in the 2013 through 2016 numbers. As you can see on this page, projected environmental expenditures are quite limited over the 2013 through 2016 period. Of course, we will continue to review and adjust our merchant generation spending plans in light of evolving outlooks for power and capacity prices delivered fuel cost, environmental standards and compliance technologies among other factors. This completes our prepared remarks.

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Ladies and gentlemen, thank you. We will now be conducting a question and answer session. Thank you our first question is from Paul Patterson with Glenrock Associates. Please proceed with your question. Paul Patterson – Glenrock Associates: Good morning, can you hear me?

Yeah, Paul. This is Marty Lyons. Yes, we can hear you now. Paul Patterson – Glenrock Associates: Listen I want to ask you...

I apologize. Paul Patterson – Glenrock Associates: That’s fine. I just want to ask about these the delay in these merchant generation CapEx projects one in Newton and the precipitator. Is there a operating earnings impact that’s associated with any of these MEEIAs which do you have to buy emissions or anything, I mean is there any operational issue we should be thinking about in terms of this significant change in CapEx.

Right Paul. I understand. It’s Marty still. No, not in the near-term, these projects really design to help with compliance really when you get out into the 2015 timeframe so, in the near-term really no impact on operating earnings or cash flows as a result of decelerating the projects. Paul Patterson – Glenrock Associates: Okay and then with respect to just the capital expense itself delaying this and what have you, is there any change in terms of the total capital expense that you would be expecting?

Well I guess that’s – it’s teasing to tell I guess whether the ultimate cost of the project will change but just to give you a sense, so with respect to the Newton Scrubber project through the end of 2011, we had invested about $100 million roughly in that project. As we said on the call this coming year as we decelerate the project, we do plan to take materials that have been built or material that have been commissioned a lot of those to be completed take those to the site, put them in a safe store condition. So we expect to incur about another $150 million this year in doing that. At that point we’ll be taking the capital expenditures down to more of the minimum levels that we described in the call and continued to monitor changes in power market conditions, capacity markets, changes environmental rules and the like. And certainly asses how we might absence reacceleration of that project go about complying with environmental rules out in that 2015 timeframe. But I think Paul when you look back to the guidance we gave last fall, I think the total project cost that was sort have embedded in the guidance was somewhere around $490 million for the Newton Scrubber project. If we move to reaccelerating it some point in the future, we’ll certainly provide an update on what we think the costs are that time to complete the project. We are estimating as we sit here today if we were to reaccelerate the project at some point in the future, it would probably take in the range of say 20 months to 24 months to complete the project. Paul Patterson – Glenrock Associates: Okay, great. Thanks a lot.

You are welcome.

Our next question comes from the line of Julien Dumoulin-Smith with UBS. Please proceed with your question. Julien Dumoulin-Smith – UBS: Hi, good morning. Can you hear me?

Yes, we can. Julien, this is Marty. Thanks for joining. Julien Dumoulin-Smith – UBS: Yes, of course. I just wanted to clarify a little bit more on the Merchant CapEx front, just what you’re thinking about compliance with MATS and your own Illinois State specific standards, 2015 and beyond, I mean, status quo I would imagine that it would result in some sort of operational impairment of the assets rate without putting in the CapEx, I mean there is some sort of reaction in your ability to dispatch some certain units? Is that the right way to think about that?

Yeah Julien. This is Martin again. That’s a fair assessment. I think without the Newton Scrubbers being reaccelerate out in 2015 timeframe, it’s frankly, it’s really the Illinois multi-polluting standard that becomes the challenging standard for us to comply with. As you know out in that timeframe in our fleet wide SO2 emissions need to be reduced down in the 2015 timeframe. Between now and then, we really don’t expect that we would have any forced reductions in generation levels as a result of CSAPR or multi-polluting standard or other rules. When you get onto 2015, as it relates to MATS compliance, absent the Newton Scrubber we think we have other ways to comply activated carbon and precipitators, low sulfur coal and the like compliance there. And as it turns out with the CSAPR rules obviously they’re uncertain right now because they’ve been stayed. But based on the allowances that came out in the final rules, based on our decision to shutdown Meredosia and Hutsonville, the CSAPR rules really aren’t seen as a significant limitation either. Julien Dumoulin-Smith – UBS: Great. So if I were to kind of hit between lines here, frankly from a compliance perspective, a couple of years, you could decide, let’s say, a couple of years down the road and still they’ll move forward. You said 20 to 24 months there to complete the Newton Scrubber, so there is still a couple of years latitude all in give or take, is that kind of the right way to think about that in order to...

Yeah. That’s fare. We feel like, as we decelerate today that we’ve got some optionality for a while before what actually impact future general levels and in the meantime we can also look at how we might go about alternatively complying with some of those rules and again assess whether a reacceleration is appropriate. Julien Dumoulin-Smith – UBS: Excellent and then just a final question here on the Genco, a guidance the breakeven cash flow for this year. Are there any exceptional items there to bear in mind as we’re looking at your EPS guidance translating then to free cash flow guidance anything notable to take note of?

I don’t know that there is anything notable to take note of in the – in that regard as you reconcile. Julien Dumoulin-Smith – UBS: Okay. So EPS guidance should equate to positive free cash flow?

Yeah. I think so. I mean nothing has come into mind off hand. We’re certainly, as we mentioned in the call, we’re expecting positive free cash flow overall at the Merchant business. And I guess one think of note early in this first quarter we did sell one of our assets with Medina Valley co-gen facility, a fairly small facility. I think about $17 million and cash flow coming from that. So, that may factor into our net CapEx for this year, but other than that earnings should translate into cash flow. Julien Dumoulin-Smith – UBS: Great and then just tiny clarification here in terms of your guidance that for coal. It seems like that came down a buck a megawatt hour in 2013, just wanted to clarify is that basically a lower PRB price or lower transport price.

Well, it’s really a little off each Julien, so the price dropped I guess from about $26.50 to $25.50. We did increase the amount of transportation that we have hedged. We also increased the amount of coal we have hedged and as you saw a little bit of fuel surcharge, so frankly all three of those things would have gone into the mix. Julien Dumoulin-Smith – UBS: Okay. Thanks.

Our next question comes from the line of Tom Rebinoff with Fore Research and Management. Please proceed with your question. Tom Rebinoff – Fore Research and Management: Hey, guys. Good morning. Can you hear me.

Yeah, we are little bit flank, but we think we can hear you okay. This is Marty. Tom Rebinoff – Fore Research and Management: Great. Hey, Marty. So I had a question on your cash flow going forward basically it sounds like that you have indicated that basically in 2012, you Merchant business would cash flow positive, and I think you have mentioned that you’re going to get the benefit of the money pool receivables there to kind of help you with that. So I’m kind of curious as to what that number is that that’s going to become from the Manipur receivables. But really more interested in 2013, when obviously you’ve kind of given where the current strip is and where prices are today, that Merchant business will burning, I’ll call it a $100 million plus of cash. So are you going to explicitly support that business going forward and you’ll kind of bridge that shortfall or like what’s the thinking in terms of actually helping with the casual situation post 2012.

Sure. So let me start with the 2012, so when we talked about the Merchant business overall being cash flow positive in 2012, I’m talking about Ameren Energy Resources overall, which has Genco subsidiary as well as the eight AERG subsidy area assets and overall that would be cash flow positive. And then as you point out we said Genco which is a subsidiary of the Merchant Segment would utilize some of its Manipur receivables. As of yearend, it had about $74 million of Manipur receivables. And we project some more in the neighborhood of around half of that might be utilized this year by Genco. As you look out in 2014 and beyond we certainly haven’t given any cash flow guidance. We have said before and we’ve repeated that and our goal is for the Merchant segment as well as for Genco to be able to support their cash flow needs. And we feel like the decisions we have made here with respect to decelerating the Newton Scrubber project and deferring the precipitator at Edwards are certainly very helpful to us in achieving that goal. Tom Rebinoff – Fore Research and Management: Got it. So maybe then the question really is – I mean at the end of the day I am kind of running my own math and I am sure you guys have your own projections, but maybe the right question then to ask is assuming that the business is cash flow negative in 2013. Then how would you think about the Merchant business at that point in time, like you know just help us kind of think through the various options.

Well, I think in the various options first of all have to do with the segment and with the way the segment operates its business. So, we are certainly going to be looking for further opportunities to reduce operating expenses, to carefully and continually examine even the capital expenditures that we still have in the forecast and we’re continuously seeking opportunities to market the power that we have at above market prices. So, first and foremost, we’re going to be look into that segment to provide for its own needs And like I said I do think that these capital expenditure reductions that we’ve made go a long way to helping that business cover its own cash needs over at least the next couple of years. Tom Rebinoff – Fore Research and Management: Got it. Got it. And then what about my another question as in terms of coal to gas switching, Calpine last week obviously said that they were definitely seeing that in PJM, are you guys seeing something similar in MISO at this point?

No. I think within MISO at least within certainly our part of MISO gas prices being as low as they are we’re seeing maybe a little bit of gas fire generation coming into the mix. Certainly as we look ahead ourselves to this coming year, we’ve talked about having about 25 million megawatt hours that we’re going to generate. I think our coal-fired plants are going to produce about 26.5 million megawatt hours and maybe 0.5 million megawatt hours coming from our gas assets, so we’re expecting a little bit more contribution this year from our gas assets. Overall though within MISO, in our part of MISO, the low cost delivered PRB coal is still pretty competitive with the gas assets that exist in our part of the country. So, certainly will – with these low gas prices, there will be more gas generation, but I think to a lesser extent than you may be seeing in other parts of the country. Tom Rebinoff – Fore Research and Management: Okay. Thank you, guys. I appreciate the color.

Our next question comes from the line of David Paz with Bank of America Merrill Lynch. Please proceed with your question. David Paz – BofA/Merrill Lynch: Hi. Good morning. I just had a question on the parent level note, the $425 million note, are there any covenants in there that prevent you from divesting any of your segments particularly in your Merchant segment.

David, it’s Marty. I am certainly not aware of any covenants in that indenture. David Paz – BofA/Merrill Lynch: Great. And then on the Merchant power hedges and forgive me if you went through this earlier, I might have missed this, but just was trying to get a feel for the three to four terawatt hours that you added in your hedges in 2012 and 2013 as well as your 2014 hedges, particularly 2014, was the 7 terawatt hours at the average price of $44 entered into last year or are these part of like a multiyear contracts that predate post September 30, 2011.

Yeah. David, I think look we’ve been entering into those over all those periods of time, so some of the contracts date back to probably pre 2012. I don’t have the exact date, but other hedges that are embedded in that mix have been entered in 2010, 2011. We have been building that hedge block and that hedge piece up over time. David Paz – BofA/Merrill Lynch: Okay. So, can you give me a percentage [indiscernible].

No. I don’t have it, I don’t have a percentage breakdown. David Paz – BofA/Merrill Lynch: Okay. And on the capacity-only hedges that just closed, I’m sorry, did you say why that is not in the current presentation.

No, I didn’t, but, yeah, you did notice change. Frankly, we took it out. I mean capacity revenues as you can see from the revenue breakdown at this point are unfortunately only about 1% of our overall revenue. So breaking that out didn’t seem all that necessary at this point in time. Certainly as those capacity revenues improve over time. We certainly maybe break it out again. I mean I think it’s safe David to be thinking about $15 million to $30 million of capacity only kind of revenues over the next couple of years given current prices. As you can see it from the pie chart, the majority of the capacity that we fell is embedded in some of our four requirements contact. So the capacity only sales like, I said about, $15 million to $30 million, is probably a safe number to put in your model. David Paz – BofA/Merrill Lynch: Great. Thank you. Thank you so much.

Our next question comes from the line of Scott Senshak with Decade Capital. Please proceed with your question. Reza Hitucki – Decade Capital: Thank you. It’s actually Reza Hatefi. Just I guess given your pretty solid CapEx program over the next few years, could you talk about need for trip or dribble or equity, how should we think about that over the next few years?

Good question. As you may you have picked up in our talking points, we – our stop in this year issuing shares for those programs, so you shouldn’t expect to see any dilution from those program this year. However, moving forward in time, we will assess that on a year-to-year basis as we look at our cash flow needs to in particular finance the regulated CapEx plans that we have. I think that to the extent that we can support these capital expenditures through reinvestment of earnings that we make in our regulated business we’ll certainly seek to do that, but also at all times thinking about maintaining sort of the financial strength that we have today. Certainly, we’d like to have the equity content and our cap structure somewhere between, I’d say 50% to 53% equity range. And so our goals as we move through time are to keep that equity content solid in their balance sheet, keep our credit profile strong and stable and fund these capital expenditures in a prudent way. Hopefully, you can see through time we are trying to be very careful and thoughtful about our allocation to capital and the returns we’re earnings on those capital investments. Reza Hitucki – Decade Capital: And just a follow-up on an earlier question, I guess the cash flow question on the Merchant segment, a lot of things can change going forward but is it in your tool box to use any cash from the corporate segment to fund any shortfalls at the Merchant segment, is that part of the potential equation?

Yeah, I mean it’s in the toolbox. It’s something that we could use to do. But as we’ve said repeatedly our goal is for the Merchant segment and for Genco to work to provide for their own cash need. So that remains our focus. Reza Hitucki – Decade Capital: Great, thank you.

Ladies and gentlemen, due to time constraints we ask that you limit yourself to one question and one follow-up question. Our next question comes from Michael Lapides with Goldman Sachs. Please proceed with your question. Michael Lapides – Goldman Sachs: Hey, guys. Actually a couple of questions of the regulated side of the house. First, in the transmission spending guidance that you give five year look, how backend or frontend loaded is that, and if you could touch on both AIC and at ATX. And follow up to that, in Missouri you talked about trying to get a clause in this rate case that reduces lag on kind of plant being put in service. Do you need legislative relief to actually get that done? I thought there was an used and useful clause in state regulation in Missouri.

Michael, this is Marty again. I’ll try to take both of those questions. With respect to the transmission spend what you really ought to see with respect to the Ameren Illinois utility spend with respect to transmission it’s being more ratable over the five year period. So you see in the pie chart that we’ve got $900 million of spend over the 2012 through 2016 period. And as we’ve said in the call I think it’s somewhere in the neighborhood of $180 million or so that we’re spending this year so in 2012. So you should see kind of a stable run rate over that period of time. With respect to the transmission company spend, however, that $750 million, that is more backend loaded. We’re going to be working through the routing process, the siding, we’re working on getting an ICC certificate in place and then moving forward and so that capital spending really starts to ramp up in 2014 and more so in 2015 and then 2016. Michael Lapides – Goldman Sachs: Got it. The Missouri regulation legislated question.

Yeah. Your Missouri question. What we’re proposing and I would say in this current rate case is, Michael somewhat similar to the accounting treatment that we got relative to scrubber investment that we had between the time that asset went to into service and the time we got into rates. You may recall that in that particular case we were allowed after it went into service to differ depreciation as well as caring cost on that asset from the time it went in service to the time rates became effective and what we are seeking here is something similar, but allowing us to have that kind of construction accounting on a broader basis with respect to plant put in service. Michael Lapides – Goldman Sachs: Got it. Okay, thanks guys and congrats on both a good quarter.

Thank you Michael.

Our next question comes from the line of Greg Reiss with Catapult. Please proceed with your question. Greg Reiss – Catapult: Hi guys, my questions have actually been answered already thanks.

Okay Greg, thank you.

Our next question comes from the line of Robert Howard with Prospector Partners. Please proceed with your question. Robert Howard – Prospector Partners: Hi, good morning. Wondering about just the latest decline in prices, is that kind of changed your hedging strategy at all for the Merchant business?

Yeah, Robert this is Marty. No, I wouldn’t say it really is affecting our hedging practices. What we’ve really tried to focus on over the past few years – several years is working to market our power to higher margin customers and when we hedge also looking at how we get the best location if you will to minimize basis risks. So we are still looking at putting on hedges as sales opportunities come along. We’re still pursuing those and certainly focusing on the more higher margin opportunities that we get, but we are continuing to put hedges on. I’d say for the past year or so we’ve been putting the hedges on and operating to sort of the lower end of our hedge policy parameters, but sitting here today certainly feel happy that that we did that that we’ve locked in some power prices in our hedge portfolio that are above current market prices. Robert Howard – Prospector Partners: Yeah. Okay. And then I think it was kind of related to Julien’s question earlier, slightly different though. Is there kind of a time limit that just delayed construction must be completed, I mean, if you don’t have it done by 16 or 17, some rule kick in that okay the plant can’t run or is there anything like that at all or can you just kind of delay indefinitely?

You can’t. This is Martin again. You can delay in definitely, but the Julien’s question and hopefully I was responsive, but where you would start to see some reduction in terms of generation capability is out in the 2015 timeframe when the Illinois multi-pollutant standard has another ratchet down in terms of SO2 emission rates for the fleet. So out in that period, we absent other ways to comply might need to or would need to ratchet down to generation from our uncontrolled generating plants. Which plants would do that, how that might take place, that’s all something that we have to asses and examined here over the coming months in terms of again absent the Newton scrubbers, how we would best go about complying. Robert Howard – Prospector Partners: Okay. And that delay that – when you made the decision to delay, was that really driven by this latest decline in prices since your last call or was it kind of where you sort of on the track to come up to this decision anyways even with power prices being a little bit higher from like last fall’s levels.

Well, I would say that the power prices that we’ve seen here in the first quarter to us don’t look supportive of continuing with the investment at the space we were making at. So the prices did have a significant impact on the decision. But also the continued low capacity prices certainly about a capacity program within MISO. The other things though that also effected the decision where the stay of the CSAPR rules and the final match rule that came out as well as our decision last year to shut down Meredosia and Hutsonville. Those things – shut down of Meredosia and Hutsonville changed our emissions profile for a fleet, so that impacted our outlook. The stay of CSAPR affected our outlook, but again getting to your question, certainly the power prices were a very factor in the decision. Robert Howard – Prospector Partners: There hasn’t been, there’s been enough other things going on that is power prices were to certainly jump to where they were in October. So is it necessarily enough for you to say hey we’re going to put this back on schedule?

Right. So that’s a good point. I think that look we’re going to take the time that we’ve bought through this deceleration to really access the power markets, capacity markets, change in environmental rules and like I said, but very closely at how we might alternatively comply with the rules that exist and make a reassessment at some point in the future. Robert Howard – Prospector Partners: Okay, great. Thank you very much.

You are welcome.

Our next question comes from the line of John Murphy with Green Arrow. Please proceed with the question. John Murphy – Green Arrow: Hi guys, can you just give an update on what you’re seeing in the Illinois’ government aggregation market and what kind of opportunity that could be for you?

Yes, so that’s – good you broke up a little bit for folks that maybe couldn’t hear, I think the question was about municipal aggregation in Illinois and we do see that as an opportunity frankly for the Merchant business. We certainly as part for that business – we certainly have been very active as I said a little while ago offering our product to industrial customers, large commercial and municipal customers. And we certainly see this is an opportunity to some more generation to these aggregated municipal buyers through there are fee processes. So when you see there is an opportunity on the Merchant side of our business. And again we are very much focused on seeking opportunities to market and sell our power at prices that offer attractive margins about relative to say in the hub spot price. John Murphy – Green Arrow: Great. Excellent.

This is Doug Fischer, operator we have time for just one more question.

Thank you. Our last question comes from the line of Alex Tai with Standard General. Please proceed with your question. Alex Tai – Standard General: Hi, guys. How are you doing?

Good. Thank you. Alex Tai – Standard General: I just want to clarify a little bit on the timing of any decisions that’s going to be made on the CapEx spend. You had previously said that 2015 is sort of the timeframe that you sort of have to – you have that something in place and you also said that it would take about 20 month to 24 months to complete that project, if you were to reaccelerate the new scrubbers. Just rough math, at least maybe 12 months with which to decide whether or not to resume the project, is that correct, am I sort of thinking about this the right way?

Yeah. That’s right. I think, so as we will continue to asses I’d say that the timeframe to if we were to reaccelerate, reaccelerate the project, what the exact timeframe would be. But like I said sitting here today we’re thinking it’s 20 month to 24 months, so I’d say certainly sometime next year we’ll be at a point in time where we’ll be making some decision as it relates to compliance with those 2015 targets. Alex Tai – Standard General: Got it. And in terms of the some of the other options you had mentioned activated carbon or – I don’t specifically remember if you’ve mentioned this, but dry sorbent injections, what’s the lead time for converting to an alternative system for environmental combines.

I think one thing about Illinois as it relates to Mercury is we’re already are using a lot of activated carbon for compliance there already, so you know that sort of underway. In terms of DSI, I can’t really, sitting here today, give you a timeline on what it would take to put that in place. I think that is probably a shorter timeframe than the one we’re talking about in terms of the scrubber project. Alex Tai – Standard General: Got it and so I guess to get a little bit more clarification, if you decide to not resume the scrubber, what, I mean, can you sort of just layout I guess a roadmap of what the other options look like?

Not at this time. I think it’s really too soon and premature to say. I think that we’ll asses all alternatives we have with respect to compliance and look we’re talking about 2015 and certainly a lot can change in terms of forward power prices and capacity prices. And so we’ll be assessing all of those compliance options at the same time as we’re really watching how the power markets and environmental standards unfold. Alex Tai – Standard General: Okay. All right. Well, thank you very much.

Thank you.

Thank you for participating in our call and thank you especially for your patience with our technical difficulties today. This is Doug Fischer. Let me remind you again that this call is available on our website for one year. Today’s press release includes instructions on listening to the playback telephonically or accessing it on our website. You may also call the contacts listed on the release. Financial analyst inquiries should be directed to me, Doug Fischer. Media should call, Brian Bretsch. Our contact numbers are on the news release. Again, thank you for your interest in Ameren Corporation.

Ladies and gentlemen, this does conclude today’s teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.