Doug Fischer - Director, Investor Relations Tom Voss - Chairman, President and CEO Marty Lyons - Senior Vice President and CFO Warner Baxter - Chairman, President and CEO, Ameren-UE

Steven Byrd - Morgan Stanley Paul Patterson - Glenrock Associates Julien Dumoulin-Smith - UBS Michael Lapides - Goldman Sachs Alex Tai - Standard General Ashar Khan - Visium

Greetings. And welcome to the Ameren Corporation’s Third Quarter 2012 Earnings Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder, this is conference is being recorded. It is now my pleasure to introduce your host, Doug 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 Tom Voss, our Chairman, President and Chief Executive Officer; Marty Lyons, our Senior Vice President and Chief Financial Officer, and other members of the 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 ameren.com. Further, this call contains time sensitive data that is accurate only as of the date of today’s live broadcast and 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 by our speakers. 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 factor sections in our filings with the SEC. Tom will begin this call with an overview of third quarter 2012 earnings and 2012 guidance, followed by a discussion of recent regulatory and business developments. Marty will follow with more detailed discussions of third quarter 2012 financial results and regulatory and other financial matters. We will then open the call for your questions. Here is Tom, who will start on page three of the presentation.

Thanks, Doug. Good morning and thank you for joining us. Before I discuss our earnings, I would like to acknowledge that terrible impact Hurricane Sandy has had on our fellow citizens in the Northeast. The storm has reminded us again, how the forces of Mother Nature can change lives. Sandy will no doubt go down as one of the worst storms ever to hit our country. Our thoughts and prayers go out to all those who have lost love ones from this devastating storm and also to those effected in so many other ways by the storm including those whose homes and businesses has suffered severe damage and loss power. At the request of Public Service Electric and Gas of New Jersey, Ameren Missouri and Ameren Illinois dispatched crews to respond to the storm even before hit the region, so that our teams would be in position to restore power as soon as possible. Currently, there are more than 650 Ameren electric and gas employees and Ameren contractors, nearly 250 pieces of heavy equipment deployed in New Jersey. I want to personally thank all of the Ameren personnel who are working long hours to restore power in the Northeast. Now I would like to turn to a discussion of our earnings and update you on other important matters. Today we announced third quarter 2012 core earnings of $1.33 per share, compared to third quarter 2011 core earnings of $1.57 per share. Third quarter was solid from an operations perspective with our system and people performing very well under extended severe weather conditions. Overall, earnings were in line with our expectations despite a challenging Illinois electric delivery rate order. The decrease in third quarter 2012 core earnings compared to third quarter 2011 core earnings reflect a lower results from both our Regulated Utility and Merchant Generation businesses. Ameren Illinois’ earnings were negatively impact by the Illinois Commerce Commission September 2012 rate order for electric delivery service and a change in the quarterly distribution of revenues and earnings resulting from formula ratemaking. In addition, Ameren Missouri’s core earnings declined due to lower electric sales and a higher effective income tax rate, partially offset by the benefit of our 2011 electric rate adjustment. Third quarter 2012 temperatures while warmer than normal or similar to those experience in the third quarter of 2011. Core earnings from our Merchant Generation business also declined compared to third quarter of 2011, reflecting lower power prices and higher fuel costs. Marty will provide more details on our earnings in a few minutes. Turning to page four, today we also affirmed that the $2.40 per share midpoint of our 2012 core earnings guidance and narrow the range to that guidance to $2.35 to $2.45 per share from prior range of $2.25 to $2.55 per share. The midpoints of core earnings guidance for our Regulated Utilities and our Merchant Generation business remained $2.30 per share and $0.10 per share, respectively. I’m pleased to also report that in addition to our solid operating performance during this past summer’s extended heat wave, two of our coal-fired Missouri Energy Centers recently earned positive national recognition. The Labadie and Rush Island Energy Centers were honored as the best performers for 2011 by the Electric Utility Cost Group. This honor demonstrates that our commitment to performance, cost efficiency and reliability is benefiting our customers. In addition, our Callaway Nuclear Energy Center has been performing well, running continuously since its fall 2011 refueling outage. Moving from earnings results and recent operation success, I would like to update you on regulatory matters at our utilities. Turning to page five of our presentation in Illinois regulatory matters. As I previously mentioned in September of this year, we received a disappointing order from the ICC in response to our initial filing for formula electric delivery rates. In response we asked the ICC to rehear certain key issues in the rate order because we believe they misapplied the Illinois Energy Infrastructure Modernization Act. Where the ICC denied our rehearing request last month and we have appeal the order to the States 4th District Appellate Court. Unfortunately, this disappointing ICC order jeopardizes Ameren Illinois ability to implement advanced metering and other infrastructure improvements, and create jobs to the extent and on the timetable envision by the General Assembly. Until the uncertainty surrounding how the Illinois law will ultimately being implemented is removed, Ameren Illinois is reducing its capital spending with corresponding negative effects on the job creation that the legislative -- legislature sought to achieve with the law. Specifically, Ameren Illinois expects to reduce our deferral of total $30 million of previously planned 2013 electric distribution capital spending. Besides appealing the recent rate order to the court, Ameren Illinois is also reviewing potential legislative remedies to ensure that the goals of the Energy Infrastructure Modernization Act are realized. Turning now to page six in Missouri regulatory matters. Our pending electric rate case is nearing a conclusion and our updated filings now support a $323 million annual increase. In this proceeding we are seeking recovery of costs and investments that we have already made to serve customers. Further, we are asking the Missouri Public Service Commission to approve to enhancements to the existing regulatory framework in the state. First, we are requesting approval of storm cost tracking mechanism that will 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 requesting approval of a new plant in-service accounting proposal. This proposal designed to reduce the impact of regulatory lag on earnings and future cash flows related to assets placed in service between rate cases. Approval of this proposal would encourage prudent incremental discretionary investments in our energy infrastructure and help meet our customer’s number one priority, reliability. Of course, these incremental investments would also help sustain and create new jobs. The evidentiary hearings in front of the Missouri PSC were completed last month. The PSC plans to issue an order in early to mid-December of this year with new rates expected to be effective in early January of next year. As Marty will discuss in further detail the largest revenue related issue and dispute in this case the allowed rate of return on equity. Moving to page seven, I will conclude my prepared comments on our Regulated Utility businesses by updating you on a key driver of our expected future growth a single largest plan investment, the Ameren Transmission Company Illinois River project. This important MISO approved regional multi-value project involves construction of the new high-voltage transmission line across the State of Illinois. We will enhance reliability and create new construction jobs in the state. Like all our Illinois transmission projects both those at Ameren Illinois Company and Ameren Transmission Company, the Illinois Rivers project will benefit from the Federal Energy Regulatory Commissions constructive rate making. This rate making provide for annual formula based updating of rates and a competitive return on investment. Further, last year, this project received FERC approval a constructive regulatory treatment, such as the inclusion of construction work in progress in rate base. I’m pleased to report that just last month we completed 98 Stakeholder Public Meetings on the route design for this project. And Wednesday of this week we filed with the ICC for a Certificate of Public Convenience and Necessity for the approximately 400-mile transmission line route, but the decision on this certificate reissued by July of next year. Once receive the certificate from the ICC we will begin to acquire right of away for the transmission line. Preliminary construction may start as early as next year with the full range of construction activities expected in 2014. Turning to page eight, in the discussion of our Merchant Generation business, continue to act to adjust this business to weak power prices in an uncertain timeline for their recovery. Earlier this year, our Merchant Generation business filed the request for a variance in Illinois Multi-Pollutant Standards or MPS with the Illinois Pollution Control Board. In our petition, we outlined our need for additional time to comply with sulfur dioxide emissions standards which were to become effective June 1, 2015. In exchange for delaying compliance with these standards until 2020, we propose an alternate compliance plan that restricted our sulfur dioxide emissions through 2014 to levels lower than those required by the existing MPS, thereby offsetting the environmental impact of granting the variance relief. I’m pleased to report that in September of this year the Pollution Control Board unanimously approved our variance request, subject to traditions that we have accepted. As a result, through 2019 we do not expect to have to de-rate or shutdowns any of our currently operating energy centers in order to comply with the state sulfur dioxide emission limits. Further, we have reduced our 2012 through 2016 Merchant Generation environmental capital spending plans by approximately $35 million, compared to our prior plans with 20 million of the reduction occurring this year. This reduction is primarily due to the vacated Cross-State Air Pollution Rule and the impacts of the MPS variance. To be clear, these spending plans are sufficient to meet the milestone conditions through 2016 that were included in the variance. That being said, we recognized that even with the relief granted by the Illinois Pollution Control Board, low power and capacity prices are impacting Ameren’s earnings outlook. We continue to look for every opportunity to reduce operating costs and enhance margins. With that, I will now turn the call over to Marty.

Thanks, Tom. Turning to page 9 of the presentation, today we reported third quarter 2012 GAAP earnings of $1.54 per share, compared to third quarter 2011 GAAP earnings of $1.18 per share. Excluding certain items in each year, Ameren recorded third quarter 2012 core earnings of $1.33 per share, compared with third quarter 2011 core earnings of $1.57 per share. Core earnings for the third quarter of 2012 excluded two items that are included in GAAP earnings. The largest of these non-core items was an increase in income tax benefit as a result of the first quarter 2012 non-cash asset impairment charge at our Merchant Generation business, and the GAAP requirement to recognize quarterly income tax expense using the annual estimated effective income tax rate. This item increased net income by $0.18 per share in the third quarter of 2012, entirely reversing the $0.18 per share decrease in income tax benefit recorded in the first half of 2012. We expect this item to have no impact on full-year 2012 earnings. The second non-core item is a $0.03 per share gain from the net effect of unrealized mark-to-market activity. On page 10, we note key factors that drove the $0.24 per share decrease in third quarter 2012 core earnings, compared to third quarter 2011 core earnings. Looking first at results of our regulated utilities, Ameren Illinois’ September 2012 electric delivery rate order and the change in the quarterly distribution of revenues and earnings under formula ratemaking reduced core earnings by $0.12 per share, compared to the third quarter of 2011. Moving to Ameren Missouri, electric sales margin reduced earnings by $0.04 per share, compared to the third quarter of 2011, reflecting lower electric sales attributable to energy efficiency measures and customer conservation efforts. While, we do estimate that warm third quarter 2012 temperatures benefited earnings by $0.10 per share as compared to normal temperatures, these temperatures did not materially impact the earnings comparison to the third quarter of 2011, because third quarter 2011 was similarly warm. Ameren Missouri earnings were also impacted by higher effective income tax rate, which reduced earnings by $0.04 per share. The July 2011 Missouri electric rate adjustment partially offset the electric sales and tax rate impacts, benefitting earnings by $0.05 per share, compared to the third quarter 2011. Finally, Merchant Generation Segment earnings were impacted by a $0.10 per share decline in margins, compared to the third quarter of 2011, reflecting lower power prices and higher fuel costs. This was partially offset by $0.05 per share of lower depreciation expense and $0.02 of lower plant operations and maintenance expense. Turning now to page 11, we have updated our 2012 cash flow projection. We now expect 2012 negative free cash flow of approximately $205 million. The decrease in free cash flow of approximately $15 million, compared to the projection we provided on our August call. Our negative free cash flow projection includes $138 million of premiums for long-term debt repurchases for our regulated utilities, Ameren Illinois and Ameren Missouri, which were paid during the third quarter. These premium payments were part of debt refinancing that reduced the weighted average interest rates on our utility debt and enhanced our debt maturity profile. As a result, we expect to recover these premiums over the life of the newly issued debt through the regulatory process. As shown on this page, we calculate free cash flow by starting with our projected cash flows from operating activities, and subtracting from it expected capital expenditures, other cash flows for investing activities, dividends and net advances for construction. Adjusting for the premiums paid on long-term debt, our adjusted free cash flow expectation is a negative, approximately $67 million. While we anticipate the 2012 free cash flow will be negative for Ameren as a whole, we expect that our Merchant Generation business will cover its own 2012 cash needs. Moving from a discussion of earnings and cash flow, I would like to provide further details on the regulatory matters that Tom previously discussed. Turning to page 12 of our presentation, I will begin with the earnings impact of Illinois electric delivery formula ratemaking. Under this ratemaking, reported Illinois electric delivery earnings for a given year reflected throughout for that year’s rate base, actual cost of service and formula-based return on equity, as well as ICC ratemaking adjustment. Also, it is important to recognize that quarterly revenues and earnings are impacted by the timing and amount of operating costs. As Tom previously mentioned, the ICC issued its order in our initial electric delivery formula rate case this September, and we’ve incorporated the impacts of that order into the 2012 core earnings guidance that Tom shared with you. To assist you in thinking about 2012 Illinois electric delivery business earnings, we’ve provided on this slide key inputs into the rate formula, including impacts of the recent ICC order. Despite our belief that the Illinois Energy Infrastructure Modernization Act calls for the use of year-end rate base and year-end capital structure, the ICC ordered the use of average rate base and the use of a hypothetical capital structure and we have reflected these ICC decisions in our guidance. Also, our guidance now incorporates an estimated average 2012 30-year treasury bonds yield of 2.9%, down 10 basis points from the expectation we shared on our August call. Further, our guidance reflects the fact that several types of costs are not recoverable in rates, these non-recoverable costs include approximately $9 million of ICC ratemaking adjustments. In addition, we expect to spend about $7.5 million this year on certain electric system rework that is non-recoverable in rates. And finally, approximately $9 million of the donations were required under the Energy Infrastructure Modernization Act. Of this total, $7.5 million was a one-time 2012 only donation to the Illinois Science and Energy Innovation Trust. Turning now to page 13, Ameren Illinois’ first annual update case for electric delivery formula rates is nearing a conclusion. On Wednesday of this week, the ICC administrative law judges, hearing this case issued their proposed order. While, we are still reviewing the proposed order, it appears to be in line with the order the ICC recently issued in the initial formula rate case. The deadline for an ICC decision in the update case is December 16th, with new rates scheduled to be effective in early January 2013. Moving to page 6, the ICC is also currently reviewing Ameren Illinois’ modified smart grid advanced metering infrastructure, or AMI deployment plan to determine if it is cost beneficial. We believe our filing strongly supports the cost beneficial nature of our plan. Installing smart grid equipment and advanced two-way electric meters is critical to meeting the infrastructure enhancements required under the Illinois Energy Infrastructure Modernization Act that authorized formula rates. And such expenditures are a significant portion of the increase in capital spending required by the act. The ICC is scheduled to rule on our modified plan this month. Assuming ICC approval, we plan to begin construction of infrastructure in the third quarter of 2013 with the first meters to be installed in the second quarter of 2014. Turning to page 15 in our pending Missouri electric rate case, we have requested an updated $323 million annual rate increase, down from original request of $376 million. This changes the result of the normal rate case true-up process, a reduction in our requested return on equity to 10.5%, and the settlement of certain rate case issues. Our updated request includes $73 million related to higher net fuel costs, $80 million already approved by the Missouri PSC related to recovery of costs for enhanced energy efficiency programs that will begin in 2013 and $170 million for other non-fuel costs. In addition, we are seeking approval of a new storm cost tracking mechanism and a new plant in-service accounting proposal as Tom has already discussed. The Missouri PSC staff updated filing in this case supports a $210 million increase. The primary driver of the $113 million difference between Ameren Missouri’s position and that of the staff has allowed return on equity. The staff’s 9% recommendation compared to our 10.5% request, accounts for $88 million of the difference. On this page, we also list other key drivers of the difference between our requests and the staff’s positions. Regarding other rate case issues, the staff supported continuation of the Pension/OPEB, vegetation management and infrastructure inspection cost tracking mechanism. However, the staff called for changing the FAC sharing mechanism to an 85-15 split from the current 95-5 split. This proposed change in the sharing percentages is similar to what the staff has recommended in past rate cases. Further, the staff has recommended that transmission costs should no longer be recovered through the fuel adjustment clause, but instead should be recovered in base rates. We opposed this potential change as we believe it is appropriate to recover transmission costs through the FAC. These costs can be volatile and are unavoidable and outside of management’s control. Further, recovery through the FAC better matches the cost to be a member of MISO, with the benefit to customers received through off-system sales, which are included in the FAC. If the PSC decides to make such a change, we believe a full cost tracking mechanism without any limiting conditions should be put in place to avoid regulatory lag, resulting from under recovery of cost increases between rate cases. Finally, the staff has recommended that the Missouri PSC reject our storm cost tracking mechanism and plant in-service accounting proposal. In addition to the staff, other parties have filed testimony on several issues in the pending case. For example, Missouri industrial energy consumers and the Office of Public Counsel have recommended returns on equity of 9.3% and 8% respectively. The Missouri PSC is expected to issue its order in early to mid-December of this year, with new rates expected to be effective in early January 2013. Shifting to our Merchant Generation business, on page 16, we provide updates on our 2012 through 2014 four power sales and hedges. As noted last quarter, as a result of falling power prices, which reduced economic generation levels in 2012, we hedged an amount greater than our ultimate expected generation. This hedging in excess of generation has been or will be settled on a profitable basis by either using purchase power or existing generation to the extent that power prices improve. For 2013, we have now hedged approximately 24 million megawatt hours at an ever price of $36 per megawatt hour. Further for 2014, we have now hedged approximately 13 million megawatt hours at an average price of $38 per megawatt hour. Finally, turning to page 17, an update of our Merchant Generation Business fuel and related transportation hedges. For 2013, we’ve hedged approximately 22 million megawatt hours at about 2,350 per megawatt hour, unchanged from our August call. And for 2014, our hedges now totaled approximately 13 million megawatt hours at about $24 per megawatt hour. Our reduced coal hedged level in 2014, reflects a rebalancing of our mix of cool hedges to reflect desired cool quantities and an amount overall matching our four power hedge position. This completes our prepared remarks. We now invite your questions.

Thank you. (Operator Instructions) Our first question comes from Steven Byrd with Morgan Stanley. Please proceed with your question. Steven Byrd - Morgan Stanley: Good morning.

Good morning, Steven. Steven Byrd - Morgan Stanley: I was just curious. First, on your outlook for power prices, there’s sort of an ongoing debate about the impact of upcoming environmental regulations on the price of power and weather. The four price of power is really fully accounting for all those environmental costs, particularly post election the questions are coming up a lot? I was just curious, as you think about the Midwest and the amount of potential economic retirements that we are seeing out there. And as you look at the four power markets, do you have any general comments on what you’re seeing out there?

Yeah. Steven, I mean it’s a good question. I think it’s always been. This is Marty by the way. It’s always difficult to speculate on what’s going to happen with forward power prices. I mean, our view, I think along with others is that forward power prices today are obviously pretty low, certainly, reflecting the continued weak economy and the low gas prices. We do expect that over time, especially when you look out to the MATS rules that take effect out in 2015-2016 timeframe that you will see the need for folks to either make additional expenditures or for higher cost generation to shut down. I think, MISO has estimated as much as 12,000 megawatt hours of production across the MISO footprints. So those types of things will certainly, I think, over time put pressure on capacity prices, if not power prices. Steven Byrd - Morgan Stanley: Okay. Great. Thank you. And so related question, just as you think about the merchant business, you’ve laid out for 2012. The business is able to fully fund itself. It’s not cash-flow negative. As you think about the outlook for that business, from a strategic point of view, is there a sense that through strategic activity, cost cutting could be achieved, greater scale could be achieved. And is there a view that greater skill is needed in general in the merchant generation business or just -- if you won’t mind just giving an update on how you think about strategically your merchant business?

Stephen, I think a couple of things. First of all, you talked about the cash flows. And I think as we said in the call, certainly we’re expecting the business to cover its cash needs this year. From time-to-time, we get questions about Genco, in particular. They started the year out with about $82 million of cash and advances to the money pool as of September 30th. They still had about $57 million of cash and advances to the money pool combined by $57 million. And as you know, have the ability to sell gas-fired assets or exercise put option to -- for liquidity purposes. So those options are out there as well as they certainly expect going forward. They have the benefit of certain net operating losses that they’ve got as well. So there are some tools in the toolkit in terms of liquidity and cash flows in the short term. Longer term, strategically, I think it’s something that we’ll continue to evaluate -- obviously I think the larger scale platforms that are out there. There are certain synergies that you can have. I think as we’ve managed this business over time, we certainly gotten some synergies by the overall combination of the entities that we have. But going forward, it’s something that we will continue to consider the nature of our overall hybrid mix. Steven Byrd - Morgan Stanley: Great. Thank you very much.

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

Good morning, Paul. Paul Patterson - Glenrock Associates: Just quickly on whether, it sounds like there were $0.10 above normal for the quarter, I believe. Could you give us a sense as to what the weather-normalized growth is for the quarter and year-to-date in Illinois and Missouri. And whether or not, you’re seeing any decrease in weather-normalized sales, particularly, excuse me, in Missouri and the potential for regulatory lag in that jurisdiction. We heard something today that that might indicate that’s a potential with another company?

Yeah. I don’t know about the other company, you’re referring to Paul, but -- certainly, this is Marty. Again, I can certainly comment overall. We did estimate about $0.10 per share of positive impact from weather in the third quarter versus normal. And we also mentioned in our prepared remarks that overall, we thought Missouri electric sales negatively impacted earnings by about $0.04 versus last year. And that’s the case with $0.10 versus normal positive weather impact in the quarter. As we looked at the weather this year versus last year, we thought the impact was about flattish or no impact. You may recall that we had a warm summer last year. It was kind of a persistent warm summer whereas this year we have some heat in June, extreme heat in July and then it kind of, dropped off to more normal conditions for the remainder. What we saw this year is that as we have those extremes in heat and we quantified as I said the impact to be about $0.10, when we looked at the weather normalized sales, they were actually down. And so when you look at the statistics page we provided, you’ll actually see that residential and commercial sales were down year-over-year. And again remember, that we believe that overall weather was about flat. So those sales declines which you are seeing are sort of weather-normalized sales decline. Now, as we know weather normalization is somewhat art and somewhat science. So that’s why we say in particular talking point of some of that reduction in overall weather-normalized loads maybe because of customer conservation efforts as they receive some of the higher bills from the June and July timeframe. But getting back to your question, I mean, that’s in Missouri for the quarter was in Missouri residential sales on a weather normalized basis down between 1.5% to 2%, same kind of pattern in the commercial sector. In Illinois, we saw a little bit greater decline in residential usage and the commercial was actually a slight positive. So overall, for Ameren, in the quarter what we saw on a weather-normalized basis was residential sales down a little over 2%, commercial sales down between 0.5% and 1%. So we saw some -- again some weather normalized declines in the quarter and again how much of that may have been a reaction to the extreme weather in some of the bills people received is difficult to know. We expected coming into the year to have about residential, commercial sales about 0.5% to 1% of growth. What we’re now expecting for the year, Paul, is that residential sales to be down somewhere around 0.5% for the year, still expecting to see some commercial growth, however, up to 0.5%. I think on industrial side, we’re seeing pretty flat loads in terms of industrial sales in Missouri. While we’re still seeing some growth in Illinois, we’re seeing growth year-to-date in Illinois of about 3.9% and we’re expecting for the year all across Ameren to have growth of about 2.7%. Paul Patterson - Glenrock Associates: That means, in terms of regulatory lag and going forward, I mean with the conservation efforts that we’ve seen actually around the country for a while now, or whatever it is, least usage. How should we think, is your potential for regulatory lag in Missouri that you guys are -- or did not, I guess, and this really briefly on the merchant, depreciation went down about $0.05. Was that because of Duck Creek or was it anything else?

Let me have that one and then maybe I actually got Warner Baxter talk about Missouri but yeah, you may look back. When you look back to our beginning of the year guidance compared to now. Our actual guidance today is about $0.05 higher than it was at the beginning of the year. And in part that is because of the Duck Creek write-off which then positively impacted depreciation and that’s about $0.05 for the year. So that is part of that, Paul. Paul Patterson - Glenrock Associates: It looks like it was $0.05 for the quarter though.

Yeah. We also, I think the other thing that we did in the quarter that you’ll see in the 10-Q is we actually did adjust some of our asset retirement obligations for certain ash pond closures and that had a little bit of an impact as well. Paul Patterson - Glenrock Associates: Okay.

And Paul, this is Warner. Just a couple of things to keep in mind, number one with regard to these lower sales. Be mindful, that we’re in the mindful of our current rate case. So consequently, we update our billing units for the lower sales levels. And so those were done through June. And so a piece of the things that you’re seeing at least throughout 2012 are part of our overall rate increase request that you see today. But secondly -- but you have to be mindful of is that as we go forward, I think Marty mentioned during the talking points that that we had a new energy efficiency regulatory framework that’s been put in place. So we’re going to be moving on in some additional energy efficiency programs which obviously going to be beneficial for our customers but also as part of that, we’re going to now recover our program costs but also will be able to recover the loss fixed costs or the loss revenues associated with some of those. That’s part of the existing rate case as well and frankly, a settlement that the commission is already approved. And so I think there is still risk to be clear for regulatory lag associated with conservation efforts. We have taken steps with this rate case and with our new energy efficiency proposal to try and mitigate that to some extent. Paul Patterson - Glenrock Associates: I’ll let other people ask question. Thank you.

Thank you, Paul.

Our next question comes from Paul Ridzon with KeyBanc Capital Markets. Please proceed with your question. Paul, you line is live Our next question comes from Julien Dumoulin-Smith with UBS. Please proceed with your question. Julien Dumoulin-Smith - UBS: Hi. Good morning.

Good morning, Julien. Julien Dumoulin-Smith - UBS: First, quick question on the quarter with regard to Illinois to $0.012. Could you break that apart in terms of the distribution versus the quarterly shift, versus the earnings under the rate making?

Well, I guess, we’ll break it down this way, Julien. I think about the -- I attribute about $0.05 of that total of the 12 to the impacts of the rate order that we received. And the remainder of it really having to do with the distribution of revenues and earnings? Julien Dumoulin-Smith - UBS: Great. And so next year, should we see this more normalized given the fact that the rate making has been in effect for the balance of this year. So this will kind of go away year-on-year?

Yeah. I think it should normalize year-over-year. And I think what we’ll do is we move into next year to see whether we can, if there is any variation that we can foresee and project, we’ll certainly provide that. But certainly, what it has to do with is, this year, what we’re trying to do under the formula rate making is preserve some of the seasonality of the revenue requirement. But as you go through the year and there are changes in the estimated overall revenue requirement for the year than those are adjusted within the quarter, which is one of the things that impacted us here in this quarter. I think Julien, in terms of the drivers on our slide 12, drivers have overall electric DS earnings, we try to lay out some of the overall drivers as we see them right now, given the impacts of the ICC order. Julien Dumoulin-Smith - UBS: Great. Quick follow-up there, you discussed lower CapEx in Illinois, I believe for ‘13. Can you, kind of, provide a little bit of a sense on a go-forward basis. What kind of capital expenditure reductions we could potentially see depending on what happens upon re-hearing et cetera. Where could this go ultimately?

Well, I think there is something that we’ll have to evaluate over time. Obviously, we gave the 2013 number. What impactor is on 2014 or beyond is something that we have to evaluate as we move through time. Our focus right now as you heard in our talking points is trying to get the legislative intent and corporate it into the rate making process. We still do believe that over the long-term, they formulate a great model attended by the Energy Infrastructure Modernization Act. It is good for Ameren Illinois and its customers and so we’re certainly appealing the decision of the ICC to the courts. And as we noted in our prepared remarks, again considering what legislative remedies might be possible. Julien Dumoulin-Smith - UBS: But just to be clear, it wouldn’t necessarily impact any of your commitments under the formula rate making?

That’s true, we’ve made commitments under the formula ratemaking and so we look at our capital ventures, so certainly to the extent we’re participating in the formula ratemaking. We will fulfill our commitments under the law. Julien Dumoulin-Smith - UBS: Great. Thank you.

Our next question comes from Michael Lapides with Goldman Sachs. Please proceed with your question. Michael Lapides - Goldman Sachs: Hi, guys. Just curious what are -- how you -- when you think how structurally across both the Missouri and Illinois regulated businesses, what are the structural impediments to earning your authorized rate of return. Which ones tend to be kind of the biggest drivers that keep you from being able to do so?

Yeah. Sure. Yeah. Michael, this is Marty, again. I think let’s start with Illinois. I think when you look at the slide that we provided, slide 12. You see some of those impacts as it relates to the Illinois electric delivery business in terms of ratemaking adjustments at certain costs that are incurred that are non-recoverable, which we’ve laid out again for the electric distribution business thereon on slide 12. Other things I remind for instance as weather sometimes. I mean, for example on our gas business this year in Illinois, earnings are down roughly $0.03 because of weather. So that type of thing can certainly drive it down. And then I think Michael, I think you and others have this baked into your overall analysis in Illinois. But I just remind you that the goodwill in Illinois is deducted out for ratemaking purposes, against the equity in that overall business. So and that’s always been the case that’s not something that’s new, that’s historical ratemaking adjustment. But again, I’d remind you of that. Michael Lapides - Goldman Sachs: Got it. Okay. Thanks, guys. Much appreciate it.

Our next question comes from Alex Tai with Standard General. Please proceed with your question. Alex Tai - Standard General: Hi, guys. How you are doing?

Good morning. Alex Tai - Standard General: I just had a question on -- and I believe you commented on just previously, but I just, we can get more specific on in terms of -- and you said previously that you would be able to comply with [mac] without undertaking scrubbing program for Newton in your merchant gene segment and obviously that’s sort of irrespective of the deep variances recently granted. I was just wondering, maybe you could provide a little bit more detail on how you think you can there in terms of compliance and is that sort of baked within your current CapEx plan?

Sure. Yeah. This is Marty again, you are correct on all that. I mean that is consistent with what we said in the past. One of the reasons that we were pursuing the variance from the Multi-Pollutant Standard with the Illinois Pollution Control Board was in fact that we were able to comply with the match rules without that scrubber. And it was really these Illinois rules that were imposing the need to construct that scrubber. So, we do believe that the capital expenditure plans that we’ve laid out, will -- while as to comply with MATS. And it’s really a function of a number of things. It’s a function of the investments that we’ve already made in our plans overtime. We’ve made significant investments in pollution control equipment. We also burned low sulfur coal, which helps with our overall missions. And as a result of compliance with the Multi-Pollutant Standard Illinois we are already using significant amounts of activated carbon for control of mercury. So, through the -- I’d say the compliance with the Multi-Pollutant Standard, we’ve actually built into our operations of those things that are needed to comply with the MATS rules. Alex Tai - Standard General: Okay. Great. Thanks, guys.

Our next question comes from Ashar Khan with Visium. Please proceed with your question. Ashar Khan - Visium: Marty, I just wanted to reconfirm what you’re saying -- as you look from ‘12 to ‘13, is this $0.12 recovered or is this just lost and there’s no positive delta year-over-year?

Yeah. It’s not really the $0.12 year-over-year. I think that what is more permanent, I would say until we get either of some fixed to the ICC ratemaking to conform with the act or otherwise adjust our spending or capital structure. I guess what I am saying to that point you back to slide 12 again. I think those are really the drivers of the earnings and as I said earlier the $0.12 when you break it down was really $0.05 having to do with the ICC rate order, and then remainder just really been seasonality of the revenue requirement earnings under formula ratemaking. We try the provide on slide 12 though we are more -- it was more a straightforward build up or provide you with a straightforward building blocks to build up to the revenue requirement as we see it today, given the ICCs rate order. Ashar Khan - Visium: Okay. Okay. Thanks.

Yeah, Ashar. Thank you.

We have a follow-up question from Julien Dumoulin-Smith with UBS. Please proceed with your question. Julien Dumoulin-Smith - UBS: Hey, good morning. Just a couple of quick ones on the Genco side of the house real quickly. In terms of the fuel hedge I notice that the 14 number actually kind of stepped up by $0.50 there. I think, it’s little less than we’ve been intuitive given some of the recent trends to just be curious?

Yeah. Julien, that’s right. And so in our prepared remarks, we tried to provide a comment on this. What we did do in the quarter was rebalance our mix of coal hedges a little bit and then rebalancing of the coal hedges actually impacted the average price a little bit. As you see in that too, you might notice that the coal hedge present -- the coal hedge number dropdown from about $14 million megawatthours to $13, which also aligns with the forward power sales that we’ve made about $13 million megawatthours. So, it was a bit of rebalancing of the coal hedge mix. Yet remember, these are -- we round off to the nearest $0.50. So there is a little bit of rounding in there that coal hedge rebalancing wasn’t a full $0.50 sort of impact and -- but that was I’d say one of the drivers. Julien Dumoulin-Smith - UBS: Great. And then the second question here, I mean, obviously you talked about free cash flow break-even for Genco. I’ll be curious, how do you think about execution of the put options specifically your queue alludes to losing access to some of your other sources of liquidity at some point. Would you imagine execution that we put in tandem with some of the other liquidity source losses, do you get what I am saying?

Yeah. I know you would necessarily be in tandem with the other liquidity source losses. Like I said, they still as we figured well at 9/30, they had about $57 million of both cash and the money pool advances on the balance sheet. So, we will be thinking about that as we look at the overall cash flows going into next year and the year beyond what the available cash is, as they again seek to cover their own cash needs. And then making a decision about what the right course of action is in terms of execution of that option. Julien Dumoulin-Smith - UBS: Right. So effectively to be clear, once you roll off of the existing cash balances at that point you will probably take a look at execution.

Well, that’s right. To the extent that the cash balances roll down and if we were in a position where we didn’t see the ability for them to meet their own cash needs certainly then would be in a position where we would be executing the put option. But again, right now, I mentioned sort of the overall liquidity that they’ve got. Julien Dumoulin-Smith - UBS: Right. Absolutely, and just to be clearly also, if you would execute the put option, if you would you expect to sell those assets in turn, do you kind of -- would this be a transition or anything or would you effectively intend to keep those new assets at the new subsidiary?

Well, I guess only the end of the day we have the option to do either, but certainly the idea was that if Genco exercise to put, obviously they get $100 immediately. They get the remainder of any excess to the fair value over the $100 million as determined by the appraisals at closing. And then AERG, we would actually then have those assets, we’ll have the ability to -- so one or all of those in order to reduce outstanding borrowings resulting from the put. Julien Dumoulin-Smith - UBS: Right. Fantastic.

Yeah. Exactly.

Our next follow-up question is from Paul Patterson with Glenrock Associates. Please proceed with your question. Paul, your line is live. Paul Patterson - Glenrock Associates: Sorry about that. Can you hear me.

Yeah. Paul Patterson - Glenrock Associates: The ash pound ARO is that just for the quarter or is there an ongoing impact associated with that?

No. It just for the quarter. We periodically actually update our estimates. These ones in particular that had to do with Meredosia and Hutsonville and some of the closure there. As we are working through the closure of those facilities and had better estimates on the overall cost, it’s really one-time kind of impact. Paul Patterson - Glenrock Associates: The severe weather that you mentioned in the release. I gather that and also in your comments that’s this hot weather that you guys incurred in the summer, were there any new peak this summer, just in terms of I know what you gave us sort of megawatthour declines but was there any how to peak -- how was peak compared to megawatthour volume if you follow me?

I think we comment on some of the peaks. Actually, last quarter but I will let maybe Maureen Borkowski talk about the overall system peak …

Yeah. From our systems standpoint, we did set a new all time peak. Being at 2008, I believe was a previous all time. Within the two individual systems either Ameren Illinois or Ameren Missouri, Ameren Illinois set a new peak but Ameren Missouri did not exceed it’s all time peak. Paul Patterson - Glenrock Associates: Okay. And then just finally, given this outlook that we’ve seen around the country and the memories to serve the gas industry LBCs and how we took some to come around to decoupling just any thoughts there about way to sort of mitigate the potential issue that we might be seeing here. Also considering that it seems the Missouri seems to have and other jurisdictions around the country, Warner have conservation what have you any thoughts about decoupling or how should we think about that and how you guys approaching that kind of issue?

Hi, Paul. This is Warner. I can speak from Missouri. Certainly, we don’t rule decoupling out and in fact other than discussions at decommission as to whether decoupling is an approach forward. And so there is no formal docket on that but that’s certainly one thing we look. But in part, that’s why we took the steps that we did and we’re able to achieve a meaningful enhancement for energy efficiency that was a meaningful stuff change. Because absent that those energy efficiency programs really could not move forward. And so you look at decoupling you may look at other regulatory mechanisms that would try and address energy efficiency issues or conservation issues. It’s not something that’s imminent, but it’s certainly something that’s on our list of things that we have to continue to look at. As you right for the point out the environment changes a bit from what we’ve seen in the past. Ultimately, what we are pushing from trying to do in Missouri and certainly Illinois is we can promote economic development to try and get growth not just from our residential, commercial but also to get investment made in the state. So, we can put people back to work and actually get electric sales growth from that perspective as well. Paul Patterson - Glenrock Associates: Great.

This is Marty. Couple of other things, I mean, just a reminder, in Illinois of course with the formula rates, I mean one of the benefits is that we do have the formula rates and there is a caller on the overall earned ROE or the lot of ROE plus or minus 50% basis points. So certainly, there is a provision within that overall formulaic rates that’s certainly helpful. The other thing know is well -- this year again, I think maybe because of some of the weather we’re certainly seen more flattish residential and commercial loads. Like I said, we are still seeing industrial loads growing in Illinois. And as we look at overtime, we do expect to see some level of GDP growth overtime and with it even after the impact of energy efficiency, do you still expect to see growth and electric demand and maybe a less than what we’ve historically seen but nonetheless expect to see growth in the electric demand as a company anyway going forward. Paul Patterson - Glenrock Associates: Did you have any ratio associated with GDP that you can share with us that you are expecting in terms of that, I mean in terms of what percent I mean if you have 2% GDP growth what that would translate in terms of the electric growth, do you guys have this estimation or?

Yeah. I don’t have it in my finger tips… Paul Patterson - Glenrock Associates: Okay.

Updated one but like I said I think overall we certainly are expecting net of energy efficiency that relationship, that ratio to be less than that historically has been, but nonetheless they are all positive. Paul Patterson - Glenrock Associates: Okay. Thank you.

There are no further questions in queue at this time. I would like to turn the call back over to management for closing comments.

This is Doug Fischer. Thank you for participating in this call. Let me remind you again that this call is available for one year on our website. You may also call the contacts listed on the release. Financial analyst enquiry should be directed to me Doug Fischer or Matt Thayer, my associate. Media should call Brian Bretsch. Our contact numbers are on the news release. Again, thank you for your interest in Ameren.

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