Douglas Fischer – Director, IR Thomas Voss – Chairman, President and CEO Martin Lyons – SVP, Principal Accounting Officer, and CFO Warner Baxter – President and CEO, Ameren Services and CFO, Ameren Corp.

Julien Dumoulin-Smith – UBS David Paz – Banc of America Merill Lynch Erica Piserchia – Wunderlich Securities Paul Patterson – Glenrock Associates Robert Howard – Prospector Partners Michael Lapides – Goldman Sachs

Greetings, and welcome to the Ameren Corporation Second Quarter Earnings. 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, Mr. Douglas Fischer, Director of IR for Ameren Corporation. Thank you, Mr. Fischer. 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 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. The call is also being broadcast live on the Internet, and the webcast will be available for one year on our website 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 have posted a presentation on our website to which we will refer during this call. To access this presentation, please look in the Investors 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 sections in our filings with the SEC. Tom will begin this call with a brief overview of second quarter 2011 earnings and updated 2011 guidance, followed by a discussion of recent regulatory and other business developments. Marty will follow with more detailed discussions of second quarter 2011 financial results and guidance, as well as regulatory and financial matters. We will then open the call for questions. Here is Tom, who will start on page three of the presentation.

Thanks, Doug. Good morning, and thank you for joining us. Today we announced second quarter 2011 core earnings of $0.59 per share, compared to second quarter 2010 core earnings of $0.73 per share. These results were on track with our expectations. The decline in second quarter 2011 earnings, compared to second quarter 2010 earnings reflected a 4% decrease in kilowatt hour sales to regulated utility native load customers. The lower sales were due in part to milder temperatures through June. Second quarter 2011 earnings also included a charge to earnings resulting from an April 2011 Missouri Public Service Commission order associated with our fuel adjustment clause or FAC. You will remember from our first quarter call that a PSC order required the net margins associated with certain long-term, partial requirement sales included in the FAC calculation and, therefore, be credited to customers. Other factors reducing second quarter 2011 earnings included increased storm-related expenses, higher property taxes as well as our higher effective income tax rate. Factors that favorably contributed second quarter 2011 earnings compared to second quarter 2010, included rate increases, the absence of a nuclear refueling and maintenance outage at our Callaway energy center and lower interest expense. Turning to page four. We were challenged by an unusually large number of storms in the first half of this year but in every instance, in Illinois and in Missouri our employees responded aggressively and effectively to quickly and safely restore service and meet our customer’s expectations. Our management team also took action during the quarter to align client spending with business conditions. Further while we estimate that about half of the second quarter 2011 decline in electric sales to native load customers compared to the second quarter of 2010 was due to milder weather, economic conditions and customer’s conservation efforts have also impacted sales. As a result of our first half sales trends we have lowered our weather normalized sales growth expectations for the remainder of the year. To offset these reduced sales expectations we have reduced our spending plans. In addition we are taking actions to better align our overall spending with rate orders and related regulatory policies. As a result today we’re able to essentially reaffirm our 2011 core earnings guidance with a narrow range of $2.30 to $2.55 per share. This narrowed guidance incorporates the impacts of our recently concluded Missouri rate case. And I would note that this guide also assumes normal weather conditions for the second half of 2011. So far we are on track for a very hot summer. We also remain on track to generate positive free cash flow this year. Marty will provide more details on our earnings and cash flow guidance in a moment. Moving to page five. I would like to provide an update on our compliance plans recently proposed and recently finalized environmental regulations. We have completed our initial review of the Cross-State Air Pollution Rule or Casper, which was issued in July of 2011 and have updated our strategy and capital expenditure estimates for meeting the requirements of this rule, the Illinois multi-pollutant standard and the proposed hazardous air pollutant maximum achievement control technology or HAPs-MACT. Casper requires significant reductions in sulfur dioxide or SO2 and nitrogen oxide or NOx emissions beginning in 2012 with additional reductions required in 2014. Casper standards for reduced SO2 emissions were generally in line with the rules we expected the EPA to adopt. With the standards for reduced NOx emissions were more stringent than we had expected. For many years, we have proactively worked to reduce our emissions of both SO2 and NOx in innovative and cost effective ways to improve air quality and keep generation costs low. These steps have included making modifications to our energy centers several years ago to burn low sulfur coal. NOx emissions have been lowered through the use of low NOx burners, stage combustion over-fire air systems, combustion control technology, selective catalytic reduction and rich reagent selective non-catalytic reduction systems. Recently, we’ve installed a total of five scrubbers with three at our merchant generation energy centers in Illinois and two at our regulated energy centers in Missouri. Just last year, we put into service wet scrubbers at our Missouri Sue energy center at a total cost of approximately $600 million. These proactive steps have significantly reduced our SO2 and NOx emissions over time and offered us greater flexibility as we analyze and explore options for compliance with these new rules. For our Missouri operations, compliance with these more stringent SO2 emission reduction levels might have required costly new equipment by 2014 or forced us to significantly reduce generation levels at our energy centers absent these proactive steps. However, today I’m very pleased to announce that at our Missouri regulated operations we’re moving ahead with the third option to meet the stringent environmental standards for SO2 emissions, the purchase of ultra-low sulfur coal. We recently entered into a coal purchase contract for approximately 90 million tons of ultra-low sulfur coal to be delivered between 2012 and 2017 at fair market prices. Not only is the purchase of this coal consistent with our expected coal supply needs to serve our Missouri customers. But most importantly, this strategy will entirely eliminate the need for dry sorbent injection or fabric filters and will allow us to delay the installation of additional scrubbers in our Missouri fleet until after 2017. We have also entered into additional rail transportation contracts at market rates to deliver coal supplied under the new coal purchase contract through 2017. This compliance strategy is a win for our customers, our shareholders, and the State of Missouri. As a result of this strategy, we will be able to avoid estimated rate increases for our customers of approximately 15% to 20% by 2017 that might otherwise have been required to meet the SO2 emission standards of this rule. We believe that this strategy will benefit the State of Missouri by keeping Ameren Missouri’s electric rates among the most competitive in the nation helping the State better retain and attract new businesses. As a result of this strategy, we’re able to reduce our planned Missouri capital expenditures for the period 2011 to 2015 by approximately $500 million compared to our first quarter 2011 10-Q disclosures. This reduction primarily reflects the removal of scrubbers for two of our generating units from our five year capital expenditure estimates. This strategy also meaningfully reduces potential increases in operations and maintenance expenses related to meeting the SO2 emissions standards of this rule. Overall, this strategy provides us greater flexibility to manage our spending as we seek to combat regulatory lag and earn a fair return on our investments in Missouri. Moving to our merchant generation business in Illinois. Our SO2 compliance strategy continues to include the already operating scrubbers at our Duck Creek and Coffeen energy centers as well as two scrubbers at our Newton energy center. However, we no longer plan to installed dry sorbent injection, our DSI at our Joppa energy center. Instead we will use DSI at our Edwards energy center in conjunction with the addition of a new baghouse to achieve overall system compliance. Like the two scrubbers at Newton, this baghouse has been included in our previously disclosed compliance and spending plans. As I mentioned a moment ago the new CSAPR standards for NOX emission reductions are more stringent than we or the industry at large had expected and the required reductions must be achieved beginning in just five months on January 1, 2012. Both in our Missouri regulated operations and in our merchant generation business, we are evaluating all options for compliance, so at this time we do not expect that the ultimate plans will materially increase our capital expenditure requirements over the next five years. We will update you when we firm up our compliance plans for the NOX component of the CSAPR rule. As a result of our continued optimization of environmental compliance plans and reductions of discretionary non-environmental spending our merchant generation team has reduced our merchant generation 2011 to 2015 planned capital expenditures by approximately $200 million from the level we provided you in our first quarter of 2011 10-Q disclosures. We are happy to have greater clarity on some of our environmental compliance plans and we are pleased to report anticipated savings versus previous cost estimates, but it is critical that policy makers carefully consider the cumulative economic cost of complying with these environmental rules in relation to their benefits. We will continue to proactively work to help shape pending rules, so we can realize progress on the environmental front yet minimize to the greatest extent possible the impact of these rules on our operations and on our customers. Moving now to page six. I would like to discuss recent and pending developments across our regulatory jurisdictions. In Missouri, the Public Service Commission recently issued a decision on our electric rate case, authorizing a $173 million rate increase. In general, we consider the rate order to be fair and reasonable in most respects. Importantly, it included in rates our full investment in the Sioux scrubbers and related operating costs and property taxes. Further the decision maintained our existing fuel adjustment clause as well as the vegetation management, infrastructure inspection, pension, and OPEB cost trackers, all of which are important cost recovery mechanisms. The allowed return on equity of 10.2% was a bit better than the level we received in our prior order and is close to the national average. However, it is still below the level we consider appropriate, in part because of the regulatory lag we experience in Missouri. In addition while the commission continued to permit full recovery of our energy efficiency investments, we would have liked them to make more progress on the regulatory treatment of such investments to better align our companies and our customer’s interests in energy efficiency. Finally, we are clearly disappointed in the Missouri Commissions disallowance of $89 million of cost related to the rebuilding of the Taum Sauk energy center. The opportunity to seek recovery of these costs was consistent with our settlement with the State of Missouri, which allowed for costs for enhancements or costs we would have occurred absent the reservoir breach. We believe this disallowance was not supported by the record in the case and we have appealed the matter to the Missouri Court of Appeals, Western District. Our filing at the Court of Appeals is consistent with newly enacted Missouri legislation that eliminates the ability of any party to stay a commission order while the appeal is pending. As we have stated we will take appropriate actions to align our overall spending both operating and capital with this electric rate order in its policies it reflects. With better alignment of our spending to both this order and our sales growth expectations, we expect to make significant progress toward closing the gap between our earned and allowed returns on equity at Missouri – Ameren Missouri in 2012 from the 2011 levels. Before I finish my discussion on Missouri, I want you to be aware we filed the request in late July with the Missouri Public Service Commission for an accounting order. If approved, this accounting order would allow us to defer for potential future recovery $36 million of fixed costs, not recovered as a result of the loss of random aluminum load due to a severe ice storm that occurred in January of 2009. At this time, there is no timetable set for the Commission to consider this matter. Turning now to Illinois regulatory matters, we filed our rebuttal testimony in our pending electric and natural gas slurry rate cases on July 26th. We are now requesting a $90 million annual increase in these delivery rates. Recall that our filing is based on a 2012 test year to provide an improved opportunity to earn a fair return on investment. Marty will provide more on the status of these cases. On the Illinois legislative front, we continue to be proactively engaged in supporting Senate Bill 1652, The Energy Infrastructure Modernization Act, in late May the Bill passed both chambers of the Illinois General Assembly with strong majority. The bill is expected to be forward to Governor Quinn shortly, and he will then have 60 days to act on it. If the governor vetoes the bill we will continue to work for an override in the legislature’s fall veto session. This legislation would benefit the State of Illinois and its electric customers by providing a more predictable rate making system. The additional investments required by the legislation would modernize and upgrade electric systems and improve service reliability. These investments would also create additional employment opportunities within and outside of Ameren Illinois. The more predictable rate making system incorporates formulaic ratemaking for qualifying utilities, including a rate of return on equity of 600 basis points above an average of 30 year treasury bond yields. It allows for annual adjustment of rates while still providing appropriate regulatory oversight by the Illinois Commerce Commission to insure that the investments made in the costs incurred are prudent. Finally, moving to the federal jurisdiction, in May the Federal Energy Regulatory Commission approved requested rate treatments for more than $1 billion of our planned transmission projects. We anticipate that the Board of Directors of the Midwest Independent Transmission System Operator will prove several of our projects in its December meeting and we are set to move ahead with engineering and construction upon approval. While we expect the FERC’s recent order Number 1000 to have various impacts on transmission planning and cost allocation going forward, we do not expect that the order will delay or impede our plans to construct the projects that are now before MISO. Another matter before the FERC is MISO’s July filing of a plan to replace the current monthly construct for the capacity power market with an annual construct. This plan is in response to FERC’s June 2010 order directing MISO to develop a plan that incorporates vocational capacity market mechanisms into its resource adequacy plan. We were studying MISO’s filing and will file comments at FERC this September. That said, we continue to support a multi-year procurement construct, one that is efficient and effective, sending appropriate price signals for the development of new generation and the removal of barriers between markets. While MISO’s filing is a step forward, we believe it falls short of these objectives and we will continue to work with MISO on further developing the market. Before I turn the call over to Marty, I want to reaffirm our dedication to maintaining a sharp focus on customer satisfaction and on managing our expenditures in a disciplined manner. We remain committed to seeking constructive regulatory frameworks and outcomes that allow us to recover our costs in a timely fashion and that provide a reasonable opportunity to earn a fair return on our investments. These regulatory frameworks provide us with the necessary cash flows to invest in our energy infrastructure to meet our customer’s expectations and create jobs in both Missouri and Illinois and at both our regulated and merchant generation businesses, we remain dedicated to operating in a safe, reliable and environmentally responsible manner. Now, I’ll turn the call over to Marty.

Thanks, Tom. Turning to page seven of the presentation, today we reported second quarter 2011 earnings in accordance with Generally Accepted Accounting Principles or GAAP of $0.57 per share, compared to second quarter 2010 GAAP earnings of $0.64 per share. Second quarter 2011 core earnings were $0.59 per share compared with second quarter 2010 core earnings of $0.73 per share. Core results excluded net unrealized mark-to-market losses from the second quarters of 2011 and 2010 of $0.02 and $0.09 per share respectively. These mark-to-market impacts are primarily related to non-qualified power and fuel related hedges. Moving now to page eight, we highlight key drivers of the variance between core earnings per share for the second quarter of 2011 and for the second quarter of 2010. Factors adversely affecting the comparison included the decline in margins at our regulated utilities of $0.14 per share after excluding rate changes and net of certain related expenses compared to the second quarter of 2010. Five of these $0.14 were due to milder temperatures compared to the second quarter of 2010. Another $0.05 were due to the previously discussed charge for the Missouri Public Service Commission, fuel adjustment clause related order and while mentioning this charge I do want to let you know that we have appealed this PSC order to the courts. Regarding weather cooling degree days were 13% fewer in the second quarter of 2011 than in the very hot second quarter of 2010. Expenses for the numerous 2011 storms that Tom mentioned earlier reduced earnings by $0.04 per share. Tax related items reduced second quarter 2011 earnings by $0.04 per share. Half of this variance reflected higher property taxes and the other half was due to a higher effective income tax rate. The second quarter 2011 earnings comparison was also negatively impacted by reduced equity related capitalized financing costs of $0.02 per share. The lower AFUDC equity primarily reflected the 2010 completion of the scrubbers at Ameren Missouri’s few Energy Center. Lower margins for our merchant generation business segment reduced earnings by $0.02 per share in the second quarter of 2011. This was primarily the result of lower generation levels and higher fuel and transportation related costs. Key factors favorably affecting the core earnings variance between the quarters included lower plant operations and maintenance expenses. This had $0.08 per share impact. This lower plant O&M reflects the absence of the Callaway Nuclear refueling outage in the second quarter of 2011, last year’s refueling outage reduced second quarter 2010 earnings by $0.11 per share. Callaway’s typically refueled every 18 months with the 2011 refueling scheduled for this fall. Planned outages at some of our fossil plants lead to operations and maintenance expenses which mitigated the Callaway reduction. Rate changes, net of certain related expenses, increased second quarter 2011 earnings by $0.04 per share. These rate changes included electric rate increases in Illinois and Missouri, both effective in 2010 and a gas delivery rate increase in Missouri effective in early 2011. A final key factor favorably impacting the comparison of second quarter 2011 earnings to those of the second quarter of 2010 was lower interest expense of $0.03 per share. This reflected reduced levels of both long-term and short-term debt. As Tom mentioned, we have essentially reaffirmed our 2011 core earnings guidance within a narrow range of $2.30 to $2.55 per share. This reflects a narrowing of core guidance for our combined Ameren Missouri and Ameren Illinois segments to $2.10 to $2.25 per share from our previous range of $2.05 to $2.30. The core guidance range for our merchant generation segment has also been narrowed to $0.20 to $0.30 per share from our prior range of $0.15-$0.30. The $0.05 per share increase from the lower end of the range reflects better than expected year-to-date margins and lower costs. Before I leave the subject of guidance, I would like to note the earnings impact of the July Missouri PSC rate order disallowance of $89 million of our Tom Sauk investment. As a result of this disallowance we will take a third quarter 2011 charge estimated at $0.23 per share. This charge is excluded from our 2011 core earnings guidance but will of course be included in our GAAP results. As I close our discussion of 2011 earnings guidance, I need to remind you that our guidance assumes normal weather for the second half of the year. Further 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 for the full year. Core earnings and guidance exclude any net unrealized mark-to-market gains or losses. Further, our earnings guidance for 2011 is subject to the risks and uncertainties outlined first or referred to in today’s press release including the forward-looking statement section of that release. Turning now to page nine, and our recently decided Missouri Electric rate case. Here we provide some of the details of the Missouri Public Service Commission’s July order. As Tom mentioned, we were authorized to increase electric rates effective July 31st by a total of $173 million with 121 million of this being for non-fuel related revenues. This compares to our revised total rate increase request of 211 million with 159 million being for non-fuel related expenses or excuse me, non-fuel related revenues. The decision was based on a 10.2% return on equity which comprised 52.2% of capitalization. Further, the order reflected an electric rate base of $6.6 billion. The decision continued our fuel adjustment clause and its current 95% pass through to customers of deviations between actual net fuel costs and the level of net fuel costs included in base rates. Other key aspects of this order are provided on this page. Before we leave our discussion of the Missouri rate order I would note with new rates now effective we have stopped deferring depreciation and interest financing costs associated with the approximate $600 million Sioux scrubber investment. Sioux scrubber depreciation will be approximately $21 million annually. Turning now to page 10 and our pending delivery rate cases in Illinois. As previously mentioned, we filed our rebuttal testimony on July 26, 2011. Our combined electric and gas rate increase request has been lowered to $90 million annually from our initial request of $111 million, primarily reflecting lower requested returns on equity and a correction related to insurance expense. We are now requesting returns on equity of 11% for electric delivery and 10.75% for natural gas delivery. Each of these numbers is a 25 basis point reduction from our initial request, reflecting an updated assessment of capital market conditions. On June 29th, before we filed a rebuttal testimony, the Illinois Commerce Commission staff and other interveners filed their direct testimony in the rate cases. While these parties positions will be updated in the rebuttal testimony, which is due August 23rd, this page outlines their initial position in the cases. The ICC staff recommended a combined revenue increase of $6 million based on electric rate decrease and a natural gas rate increase. Of the $84 million difference between their position and our rebuttal position, return on equity is by far the most material at $39 million. The second largest difference relates to the staffs view of savings and costs related to the recent merger of our three Illinois utilities. This represents a $19 million variance. As you can see on page 10 we’ve also noted a few of the other differences between the staff and our positions. Moving into Page 11, we outline key points of the Attorney Generals and Citizen Utility Board’s initial positions as well as those of the Illinois industrial energy consumers. The Administrative Law Judges are scheduled to issue their proposed order on November 15th of this year with an Illinois Commerce Commission’s decision expected in mid-January 2012. Turning now to Page 12. I would like to provide updated 2011 projected cash flow information. We now expect to achieve free cash flow of approximately $225 million up from our prior guidance of approximately 100 million. The largest single reason for the improved cash flow outlook is the $45 million of cash flow proceeds we received from the sale in June of a remaining interest in the Columbia Energy Center. This amount is netted in the capital expenditure line. Recall from our 2011 cash from operations includes an incremental contribution to Ameren Illinois’ postretirement benefit plan of $100 million which we plan to make this month. On this page we also have a breakdown of our consolidated capitalization which is now solid 52% equity. Further, we provide a breakdown of our debt balances by reporting segment as of June 30, 2011. On page 13, we update Ameren’s five-year capital expenditure outlook to incorporate the previously discussed improvements in our capital spending plans. We now project that the four year 2012 through 2015 cumulative capital spending will range between 5.2 billion and 6 billion with an annual target range between 1.3 billion and 1.5 billion. This brings down the midpoint of our capital spending range for the 2012 to 2015 period by about $400 million versus our first quarter 2011 10-Q disclosures. On this page, we also provide a percentage breakdown of our five-year infrastructure investment plan for our regulated businesses by jurisdiction and type. As a percentage of planned investment, you’ll note that FERC regulated transmission has grown. This is in part due to reduced spending expectations and other categories coupled however with accelerated transmission spending. We now expect to invest approximately 1.15 billion over the five-year period to harden and replace existing aging transmission infrastructure as well as to expand the transmission system. Moving now to page 14, 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. These merchant generation numbers are included in the total Ameren-wide capital expenditures that I discussed a few minutes ago. Of course, we will continue to review and adjust our merchant generation spending plans in light of evolving outlooks for power prices, delivered fuel costs, environmental standards and compliance technologies among other factors. Moving now to page 15, we provide an update of our forward power sales and hedge data. As you can see we have significant hedges in place which are at power prices above current market levels. We now expect our merchant generation business to generate approximately 29.5 million megawatt-hours in 2011. These 29.5 million megawatt-hours include 100% of the expected generation of the Electric Energy Inc. or Joppa Energy Center, a facility in which Ameren owns an 80% interest. For 2011 approximately 27.5 million megawatt-hours of this generation are sold or hedged at an average price of $45 per megawatt-hour. For 2012, we have hedged approximately 19.5 million megawatt-hours at price of $47 per megawatt-hour. Further for 2013, we’ve hedged approximately 10 million megawatt-hours at an average price of $41 per megawatt-hour. Our capacity sales are approximately 80% hedged for 2011, approximately 54% hedged for 2012, and approximately 26% hedged for 2013. You will note that while capacity hedge percentages stayed flat or rose slightly, expected revenues dropped a bit in each year. This is due to the sale of the Columbia Energy Center which had provided capacity revenues offset in part by increased capacity revenues associated with our Elgin Energy Center which is located in the PJM West power market. Turning now to page 16, we update our Merchant Generation segments fuel and related transportation hedges. For 2011 we’ve hedged approximately 29 million-megawatt hours at about $23 per megawatt hour. This cost is approximately $0.50 per megawatt hour lower than the figure we disclosed in May of 2011. For 2012 we’ve hedged approximately 18 million-megawatt hours at about 2350 per megawatt hour which is approximately $1 per megawatt hour lower than our May disclosure and for 2013, we have now hedged approximately 7 million-megawatt hours at about $26.50 per megawatt hour which is approximately $0.50 per megawatt hour lower than the previous disclosures. This hedging information completes our prepared remarks. We will now be happy to take your questions.

Thank you. (Operator Instructions) Our first question comes from the line of Julien Dumoulin-Smith with UBS. Please proceed with your question. Your line is live. Julien Dumoulin-Smith – UBS: Can you hear me?

Yes Julien, we can. Julien Dumoulin-Smith – UBS: Hi, good morning. So I wanted to ask on your comments regarding environmental CapEx. It seems like a pretty favorable move here to reduce it in Missouri. Just curious to see or get some more flavor as to exactly how you were able to do that. What is it about the coal, what is it about the technology of the plants or perhaps what is it about the policy that’s changed quarter-over-quarter that gave you the flexibility here?

Hi Julien, this Warner Baxter. I would say a couple things gave us the flexibility. One, frankly is really what we’ve been doing for several years and that is really converting our plants to burn the low sulfur coal. But secondly, the thing that gave us quite a bit of flexibility was the proactive installation of our Sioux scrubbers which we just installed late last year. That gave us the option to take a look at this ultra-low sulfur coal strategy and consequently in looking at that and looking at our system we’re able to purchase this coal through 2017 and execute not only our coal purchase which is necessary for our customers’ needs but frankly is going to avoid significant capital expenditures for things like fabric filters, as well as DSI and brought significant savings for our customers. So I wouldn’t say it’s a meaningful change. It’s something we’ve been doing for some time to try and anticipate where these regulations were going to come and we were able to execute the strategy successfully. Julien Dumoulin-Smith – UBS: Just as a follow-up, is it that you’re using treated coal of any sorts to avoid any kind of mercury complications?

No. Simply put we’re using ultra low sulfur coal and we’re able to enter into a contract for the term that Tom had laid out a little bit earlier today. Julien Dumoulin-Smith – UBS: And just a clarification. Is 2017 just the term of the contractor is there some meaningful regulatory change at that point in time that would alter this decision?

No meaningful change in the regulatory framework. It is – that was the term of the contract. Of course, we have the option to look even and purchase ultra-low sulfur coal beyond that should we want to, but nothing beyond that. That was just the appropriate term we felt to enter into the contract given that the – what we – we renewed not only were the regulations were but also obviously the tenure of such a long-term contract. Julien Dumoulin-Smith – UBS: Thanks, guys.

Thank you. Our next question comes from the line of David Paz with Banc of America Merill Lynch. Please proceed with your question. Your line is live. David Paz – Banc of America Merill Lynch: Good morning.

Good morning, David. David Paz – Banc of America Merill Lynch: Thanks for the environmental disclosures. It’s very helpful. Just had some questions. What are your environmental plans for the Joppa, Meredosia, and Huntsville plants?

Well, I think overall what we’ve sketched out is, the plans for compliance as we said on the call with the Multi-Pollutant Standard, as well as the Cross State Air Pollution Rules, as well as HAP MACT, et cetera. Our compliance plans have very much focused on keeping our overall fleet compliant and I think when we look at these rules as we outlined on the call, the thing we’re still obviously taking a look at are the NOX compliance components of the – excuse me, the CSAPR rule. So as it relates to the rules and it relates to our plans, our focus has been keeping all of those plants intact. Of course when you look at the Multi-Pollutant Standard rule, you look at CSAPR, you look in at fleet wide averages, and so controls on certain power plants say other than those ones can help to keep the whole fleet running. David Paz – Banc of America Merill Lynch: Okay. But before you guys were intending to use DSI, Joppa, and now you are not, so I guess should we assume, what...

Yes, sure. I think with respect to Joppa, I think what you’re looking at there is simply moving the DSI from there to Edwards to get the compliance you need on the sulfur dioxide and mete your fleet wide emission reductions in a more efficient way where you’re taking advantage of that bag house that we have planned for Edwards. So the DSI is moving from Jappa to Edwards but as you look at the Jappa plant, for things like HAP MACT in particular matter control you’re probably still looking at things like ESP upgrades and the like. David Paz – Banc of America Merill Lynch: ESP upgrades, okay. And how much does the DSI raise costs even on a per ton or per megawatt hour basis?

Yeah, I don’t have the based on a per megawatt hour. There certainly will be some O&M expense related to that DSI, but I don’t have the per ton number with me. David Paz – Banc of America Merill Lynch: Okay, all right. Thank you.

Thank you. Our next question comes from the line of Erica Piserchia with Wunderlich Securities. Please proceed with your question. Your line is live. Erica Piserchia – Wunderlich Securities: Hi, thanks. Just a couple of questions. First, just I guess on the environmental to continue with that, I guess, you mentioned you’re considering some options as far as NOx control are concerned and I’m just wondering if you can clarify, are you talking about refined coal options on that side. I know Julien, was asking about the Sox side, but I know there’s some options on the refined coal side on NOx to treat that and derive some tax benefits and such out of that. Can you just provide a little bit more color there on options you’re considering?

Hi, Erica. This is Warner Baxter. I can speak for the Missouri side of the house. We are looking at a variety of options. Some of those options would not include purchasing different types of coal from a NOx perspective. What we would be looking at would be things like doing some more over-fired area that some of our power plants, potentially some reinjections. Of course we now have the ability to potentially look at NOx allowances with this potential – with this rule. Those types of things and of course, you can always look at SCRs. All those things are I guess part of the portfolio of things that we’ll look at. We’re going to continue to assess those through the course of this year and make a determination towards the end of this year and execute that, but it would not include a different purchase of coal. Erica Piserchia – Wunderlich Securities: Okay.

On the merchant side of the house, Erica, we already have substantial controls that are in place. We have low NOx burners in all of our non-cycle plants, over fire air at our cycling plants, combustion optimization technology, we have selective catalytic reduction at Duck Creek, Coffine , Edwards so we already have substantial controls in place for reduction of NOx because of course, the Illinois multi-pollutant standard has been requiring us to reduce those emissions and positions us well for compliance with these Casper rules but we are still looking at additional options like selective non-catalytic reduction, combustion optimization, some of the things that Warner talked about as well. Erica Piserchia – Wunderlich Securities: Got you, okay. And then on the sales side you mentioned you adjusted your weather normalized expectations for sales demand. Can you share what level of sales growth you’re now assuming?

Sure, Erica. Thanks for the question. I recall you asking a question about this last quarter. As we’ve gone through the year, what we certainly have seen is that while weather has played a role as we talked about, we did have much milder temperatures this year than last. They’ve been warmer than normal this year, but certainly lower than last. We had a very hot June last year. And we estimate weather and strip that out. For the six months year-to-date, we are still seeing declining sales trends as it relates to our residential and commercial categories. And so, we have revised our expectations for the year. I think Erica, you’ll recall that we had talked about some very modest growth plus or minus 1% expectations in residential commercial when we talked last quarter, but as we’ve gone through the six months and looked at the data, we felt it more prudent to lower our forecast and what we’ve now got built in is sales declines of around 1% on residential with the expectation of really no growth in commercial this year. We’re still seeing overall for the company positive trends in industrial primarily on the Illinois side of our business and we’re still expecting to see low to mid single-digit kind of growth in industrial, but we felt it prudent to lower those sales forecast expectations and again, as we talked about, align our spending plans to make sure we’re able to deliver on the earnings guidance that we’ve provided so we have built those in. Looking back at last year, it’s interesting. Last year, we had pretty solid growth in 2010 over 2009 levels, residential came in about 1.2% up, commercial about 2.6% up, so what we’re seeing here in the six months, we feel like we need to adjust to and we’ll continue to assess it. Erica Piserchia – Wunderlich Securities: Okay. And just maybe one last kind of bigger picture question here. Can you share any thoughts on where you expect you can earn on an ROE basis this year or maybe put another way, what sort of what coming out of this Missouri case and obviously the Illinois case, but sort of what maybe at least on the Missouri side is kind of left to help you reduce regulatory lag that you’d have to seek in a future case?

Sure, Erica. Let me take a stab at that. If you look at our guidance range that we’ve got, we’ve provided $2.10, $2.25 for the regulated portion of our business. I think that implies an ROE range in the neighborhood of 8.3% to 8.9% and so if you take the midpoint of that for example, obviously you’re right around 8%, 8.6%. As you look ahead we’ve just completed the Missouri rate case so we’re only getting a partial benefit of that rate case this year and as you point out, we’ve got a rate case pending in Illinois that would adjust rates in January of 2012 and of course that’s based on a forecasted test year. And also our commitment to continue to align our spending to the overall business conditions we face. We are focused on improving our earned returns and on the call we talked about for instance in Missouri expecting to significantly narrow that gap between our earned returns this year and our allowed returns, so that’s what we’re focused on and just as a metric, I mean if we improve the earned returns from say that mid-point I gave you around 8.6% by 100 basis points to 9.6%, that adds about $0.20 to $0.25 of earnings year-over-year to the guidance that range that I gave you. Erica Piserchia – Wunderlich Securities: Right. Okay. Okay, thank you.

Thank you. Our next question comes from the line of Paul Patterson with Glenrock Associates. Please proceed with your question. Your line is live. Paul Patterson – Glenrock Associates: Good morning, guys.

Good morning. Paul Patterson – Glenrock Associates: On the Casper rule, you guys mentioned that it was more stringent than you thought it was but that you didn’t expect NOx CapEx to be meaningfully higher as a result of it or are you expecting any difference in operational costs and I’m talking particularly on the merchant side with respect to compliance with that or SO2 or is there any sense that what we might see there in terms of a potential increase on operational expenses?

Yeah, I don’t think, Paul, thanks for the question. I wouldn’t say we’re expecting any operational cost increases either. We are as I said before, we’ve had good controls in place over time to reduce our NOx emissions. We are looking at a low cost kind of options like the selective non-catalytic reduction, combustion optimization, and really evaluating all options and other options obviously have to do with certainly you could look at reduced levels of generation and low margin periods or purchases of allowances which right now I would say we don’t have much of a clear indication of what the value of those kinds of things are going to be but we’ll certainly look at all options on the table. Paul Patterson – Glenrock Associates: Okay. So we look at this $200 million reduction. It’s kind of meaningful. You guys are lowering CapEx. Is that just because you guys have been invented and you found things or is there, I guess should we think of any change in the profit margin outlook, do you see what I’m saying? I just want to make sure it’s a tradeoff here?

There really wasn’t a tradeoff between those $200 million of reductions and profitability or margins and what the team has continued to do over time is look at spending plans both for environmental and non-environmental and some of the environmental what the team continues to do is to further design work, do further value engineering work and seek ways to drive costs out of the plans that we have in place and on the non-environmental same thing. Take a look at the planned spending we have in light of overall business conditions and look for opportunities to reduce bit plan spending and I’d note though when you look at our spending plans and you look at some of the investments we’re making this year, we are still investing in our power plants and making what we consider to be prudent necessary investments to keep those plants running well and in fact, this year they have been running very well. Paul Patterson – Glenrock Associates: Okay, that’s just great. Now, let me ask you on the MISO capacity thing, do you guys see any meaningful increase in capacity value as a result of what came out or you did mentioned that you weren’t completely happy with it but do you see any potential upside from that and also, if you don’t get a potential upside from it can you do what these other guys have done and go to PJM?

Yeah, I think is that – this is Marty. I’ll take the point about the capacity price themselves. I think, this is not all that we wanted to be as we outlined in the call, and we don’t necessarily believe that this proposed construct, which isn’t multiyear number one, and number two, we don’t think we’ll necessarily send the right price signals over time for investment in new capacity. So we do believe that it is, however, a good first foundational step for moving forward. We’re certainly going to provide comments to FERC with respect to MYSO’s proposal and obviously this isn’t the final rule. We’ll see what comes out of FERC. Paul Patterson – Glenrock Associates: Okay.

Yeah. And this is Tom Voss. We also hope that we’ll get portable that we’ll be able to put our capacity across markets and across seems, and so we’re going to work with MYSO on that option also. Paul Patterson – Glenrock Associates: Okay, great. And then just finally on the fuel FAC flow through, what’s the outlook for that going forward in terms of the impact on earnings?

Yeah, I think that – I believe what you’re asking about is the... Paul Patterson – Glenrock Associates: The $0.05?

Yeah, the $0.05. So what that related to was during a discrete historical period, while Noranda Aluminum was down, and we are seeing other industrial sales declines, we had made some sales off system, which the margins were held outside of the fuel adjustment clause, what the Commission ordered was that certain of those revenues beflow through the fuel adjustment clause, and so that was about $17 million $0.05 charge. There was, Paul, one period subsequent to that – period subsequent of that were similarly we held certain revenues outside the fact there’s about another $25 million exposure there, the Commission has not ruled on that at this time. However, beyond that there isn’t any exposure because after the last rate case we had, all of those types of revenues from those types of sales were through the rate making process, actually included in our base – net base fuel cost that go into the fuel adjustment clause. So it was really a finite or discrete period in time. It’s not something that is an exposure moving forward. Paul Patterson – Glenrock Associates: Then why not treat it like Taum Sauk and make it a one – and make it a non-core item, I guess is what I’m wondering. I mean, is it just a judgment call? I’m wondering is there any reason not to do that though I guess?

Well, sure it’s a judgment call. I think what we felt like, however, was that in prior periods, we had reported these revenues as part of our core earnings in revenues and we felt like the appropriate thing to do then was to – as we backed these revenues out essentially because they were flowing through the fuel adjustment clause that we would include those in our core earnings but certainly it’s a judgment item. When you look at the Taum Sauk charge that we have, it’s certainly large and unusual in nature. It’s a non-operating item and again in terms of differentiation, there are no prior earnings recognized for Taum Sauk. Paul Patterson – Glenrock Associates: Thanks for the clarity.

Thank you. Our next question comes from the line of Robert Howard with Prospector Partners. Please proceed with your question, your line is live. Robert Howard – Prospector Partners: Hi. Just wanted to check a couple things. This may have been kind of implied in some of your other answers but just the decision to use the ultra-low PRB Coal in Missouri versus in Illinois, I guess just wanted to kind of clarify the reasons is it really just the technologies in the various plants that is different enough, so that it works in Missouri versus it wasn’t a decision to do in Illinois?

This is Marty. Thanks, good question. It does have somewhat to do with the technology. Warner talked about in Missouri certainly having the benefit of the Sioux scrubbers on the merchant side, we have more extensive scrubber equipment in place with scrubbers at Coffin, Duck Creek scrubber, and we certainly are using low sulfur coal and plan to use low sulfur coal there as well. So there is a difference in some of the technologies that’s been deployed. I would also note that the other differentiation is that in the merchant side of our fleet we’re also complying with the multi-pollutant standard, so you’ve got the over layoff those rules on top of CSAPR that impacts your overall compliance decisions. And lastly when you look at the sales profile in Missouri, we certainly have steady regulated load growth to meet over time and in the merchant business, we do seek to line the hedging between our power sales and our fuel hedges over time, so those are some of the differentiating things that we think about. Robert Howard – Prospector Partners: Okay. So we can’t say, okay, anybody out there in the country whose got some new state-of-the-art scrubbers that stayed like the Sioux plant can be sort of meet these requirements with ultra-low sulfur there is lot of these other factors going in there?

Yeah, I think that there are a number of factors that go in there. Obviously the lower sulfur content in your coal is going to help you in terms of your overall emissions but what makes sense for any particular generator I think is a function of equipment they have in place and the various cost tradeoff they have. Robert Howard – Prospector Partners: Okay, and then for the ultra-low sulfur, how much of a premium is that in ballpark compared to what might be standard PRB coal?

Hi, this is Warner Baxter. Certainly, we don’t disclose the terms of our contracts but I’ll tell you that those arrived at fair market prices. Robert Howard – Prospector Partners: But I guess is it significant? I don’t, is it something that’s tradable or I’m just trying to get a feel for is this something you have to pay a 10% premium on or some kind of ballpark?

Yeah, as Warner said we aren’t going to comment on the specific pricing related to the contract. Robert Howard – Prospector Partners: Okay. Anyway, then your merchant fuel hedges, it looks like the new hedges were all kind of at lower prices. Is that just market prices declining, was there some other causes to get you better terms compared to the previous fuel hedges?

Sure. It is really related to market prices versus the coal costs that are embedded in the hedges that we put in place previously and so for I’d say a couple of quarters, we’ve been suggesting that as we layer on additional hedges based on market prices, broker quotes that you could go out and see that we would expect that the average price as we layered in additional hedges would come down. As we sit here today, I would say that those broker quote prices still look to be a little bit below the pricing that we have in the embedded contracts, a little more than below as it relates to 2013 frankly where the embedded costs are a bit higher because of the mix of some of the coal purchases that we actually have in the embedded hedges, so what you see on that fuel slide is as we’ve added megawatt hours hedged in terms of our coal, its brought the blended average price down. Robert Howard – Prospector Partners: Okay, great. Thanks a lot.

Thank you. Our next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question. Your line is live. Michael Lapides – Goldman Sachs: Hi guys. Thanks for the update on Missouri capital spending. Really two questions there. One, do you think the lower capital spending likely reduces regulatory lag and there for increases your ability to earn your authorized ROE in Missouri?

Michael, this is Warner. With regard to any type of spending especially with regard to capital expenditures to the extent you can mitigate especially mandated capital spending that tends to have a more favorable direction from a regulatory lag perspective but of course when you’re doing these major environmental projects much of that is done and the key is making sure that you align the timing of any of these major environmental controls with when you put rates into place, so there are actions you can take to mitigate that regulatory lag just as we did with the subscriber. We used unique approach to really mitigate some of that regulatory likes. So in a bigger picture it is helpful and no doubt, and certainly it’s a tremendous benefit for our customers.

This is Doug Fischer. We have time for one more question. We want to respect some of the other calls coming right after us.

Thank you. Our next question comes from the line of Dan Jenkins with the State of Wisconsin Investment Board. Please proceed with your question. Your line is live.

Hi, good morning.

Good morning, Dan.

First I was wondering on the Taum Sauk appeal. What was the revenue requirement related to the Taum Sauk disallowance?

Hello, Dan. This is Warner Baxter. That impact was approximately $11 million from a revenue requirement standpoint in total.

And what kind of timeframe would you expect on the appeal? Is there any way to know?

Yeah, with regard to the appeal to the courts, there is no set timeframe on that. Typically, it is several months and we’re not surprised to see that decision move out into 2012 but I can’t predict a lot of it depends upon the court’s docket in front of them and so we filed immediately as soon as we’re able to do that and so we look forward to presenting our case before the courts here in the near future.

And then you mentioned that you had I think a $0.11 positive benefit from no Callaway outage, and with the scope and scale of the upcoming outage be similar that we would expect about an $0.11 hit in the second half comparison?

Dan, this is Warner Baxter. I would say generally the scope and overall timing of the outage would be consistent and of course in any given outage you have sometimes the difference between the level of capital expenditures in O&M, but by and large it’s probably roughly in that ballpark.

Okay. And then just on the July weather I assume it was a lot hotter this year than it was last year; is that correct?

Yeah, it was, Dan. It’s one of the – I’d say one of the hottest Summers in the last 40 plus years, so it was very warm in July and August has started out pretty warm as well.

Okay. And then I guess, the last thing I was wondering was on industrial sales that looked for either slightly negative or flat in the second quarter. Did you have any impact from say auto plants or anything there or what are you looking for or seeing?

Yeah, it wasn’t so much auto plants, as you look through the various categories, one that’s certainly sticks out in Missouri and Illinois is some that related to I’d say the building or construction industry like cement certainly popped out, general manufacturing. Some refining, some of which we think is really temporary in nature in terms of just some specific plant outages in our service territory in the second quarter that we think will again short-term in nature that will be back online in the third quarter. So I think some of what we saw looks like it might be a function of the economy and others looks like spotty and had to do with just specific outages at certain major industrial customers, so that’s kind of what we’re seeing.

Okay. Thank you.

Okay. This is Doug. I’d like to wrap up. Thanks for participating in this call. Let me remind you again that this call is available through August 11th on playback and for one year on our website. Today’s press release includes instructions on listening to the playback. You may also call or email the contacts listed on the release, financial analyst inquiries should be directed to me, Doug Fischer. Media should call Susan Gallagher. Our contact information is on the press release we issued today. Again, thank you for your interest in Ameren.

Ladies and gentlemen, this concludes today’s conference. You may disconnect your lines at this time. And we thank you all for your participation. Good day.