Greetings ladies and gentlemen, and welcome to the Ameren Corporation 2009 Second Quarter Earnings Call. At this time all participants are in a listen-only mode. A 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 Investor Relations for Ameren Corporation. Thank you Mr. Fischer, you may begin.

Thank you, Claudia and good morning. I'm Doug Fischer, Director of Investor Relations for Ameren Corporation. On the call with me today is our President and Chief Executive Officer, Tom Voss; our Senior Vice President and Chief Financial Officer, Marty Lyons, and other members of the Ameren team -- management team. Before we begin, let me cover a few administrative details. This call will be available by telephone for one week to anyone who wishes to hear it by dialing a playback number. The announcement you received in our news release carry instructions on replaying the call by telephone. This call is also being broadcast live on the Internet and the webcast will be available for one year on our website www.ameren.com. This call contains time sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives events, conditions and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated in the forward-looking statements. For additional information concerning these factors, we ask you to read the forward-looking statements section in the news release we issued today and the forward-looking statements and risk factors sections in our periodic filings with the SEC. To assist in our call this morning, we have posted presentation slides on our website that we will refer to during this call. To access this presentation, you may look in the investors' section of our website under presentations and follow the appropriate link. Turning to slide three, Tom will begin this call with an overview of second quarter 2009 earnings, and 2009 earnings guidance followed by a discussion of our plans for positioning Ameren for long term success. Marty will follow with a more detailed discussion of our second quarter 2009 financial results, our 2009 earnings guidance and commentary on key financial drivers for 2010 and beyond. We will then open the call for question. Here's Tom. Thomas R. Voss: Thanks, Doug. Good morning all and thank you for joining us. Moving to slide four of the presentation on our website, I'm pleased to report that this morning we released second quarter 2009 non-GAAP of core earnings per share of $0.75, an increase from the $0.67 per share of core earnings we posted in the same period a year ago. This is also inline with our expectations. The increase in core earnings per share in the second quarter of 2009 over the same period in 2008 was principally because of new utility services rates in Illinois and Missouri, as well as lower plant operations and maintenance expenses and vulnerable weather. The favorable earnings impact of these factors was reduced by higher net fuel cost, reduced sales to industrial customers including sales to Noranda Aluminum, higher storm repair cost, and higher depreciation in financing cost. In addition core and GAAP quarter-to-quarter comparisons were negatively impact, as result of income recognized in the second quarter of 2008 related to the termination of a coal contract during that period. Turning now to slide five, and I'm also pleased to announce the company's strong operating performance allows us to reaffirm our core 2009 earnings guidance of $2.70 to $3.05 per share. Break relief, cost control and actions taken reduced our exposure to price fluctuations in the wholesale energy markets are helping us weather the difficult economic and market conditions that are affecting our industry and the entire country. Marty will provide more details on second quarter earnings in our reaffirmed guidance in his remarks. As most of you likely know I assumed the post of President and Chief Executive Officer of Ameren on May 1st of this year. I immediately engaged our management team in an ongoing strategic planning effort to ensure that our company is positioned for a long term success. Moving to slide six, today we will share some of the opportunities we have identified to improve our financial strength and flexibility over the coming years not only to weather the current economic and related power market challenges, but to position our company for perspective earnings growth. Presently our regulated utility business is earning well below their allowed rates of return, largely as a result of regulatory lag associated with investments in utility infrastructure to improve customer service, as well as higher operating and financing cost and lower customer demand. Industrial demand has fallen considerably over the past 12 months, while residential and commercial demand has been relatively stable. As you know last fall, we identified cost control measures in our regulated businesses designed to reduce 2008 and 2009 capital and operating expenses, as compared to prior plans and we took action to reduce such cost by 350 million to $400 million. Now through our recent planning efforts, we have identified further possible opportunities to tighten our belts in 2010 and beyond for the good of all stakeholders. These opportunities include reductions of both planned capital expenditures and in operations and maintenance expenses across our organization. We are carefully evaluating these opportunities which will help lessen the impact of expected future cost increases on our customers while strengthening the financial profiles of the regulated utilities. However we will not reduce cost to a level that would prevent us from providing safe and reliable service. In addition to identifying further possible opportunities to control cost, we have recently filed rate increase request in both of our state jurisdictions. These total over $600 million. The rate request reflect our need to recover the significant investments we have made in utility infrastructure to improve reliability, increases in cost associated to generating and delivering electricity, higher financing cost and in Missouri, rising net fuel costs. We are very aware that this is a difficult time for our customers to face the prospect of higher utility rate. However current rate levels in both Illinois and Missouri are simply not adequate to earn reasonable returns in these businesses and produce the cash flows needed to maintain sound financial health. Adequate returns on investment are essential to our ability to attract the capital needed to continue to make investments required for reliability and environment controls among other things. Turning to our non-rate regulated generation business segment which we now call our merchant generation segment on slide seven. First I would like to say that our merchant generation assets are highly competitive and are very well positioned on the dispatch curve. Our proactive forward sales of expected generation is protecting 2009 earnings in the sharp drop in market prices for power. Further we have hedged a substantial portion of our 2010 and 2011 forecasted generation. However recent prices for electricity for 2010 and 2011 are lower than the prices we are realizing in 2009, power that we have locked into our 2010 and 2011 forward sales. These lower power prices are very much link to weak economic conditions which are reducing the demand for power and other energy commodity. We believe that when the economy recovers, these prices will rise. Nonetheless, we're positioning our merchant generation business to operate in this lower power price environment. We instituted aggressive cost control measures last fall to reduce 2008 and 2009 capital and operating expenditures as compared to prior plans and we took action to reduce cost by 400 million to $450 million. This was achieved through both spending cuts and deferrals. This bring the Illinois Pollution Control Board and subsequently the Illinois Joint Committee on Administrative Rules, reviewed and approved amendments to the Illinois multi-pollutant standard or MPS. These rule changes which are now final allows defer to subsequent years approximately $300 million of merchant generation capital expenditures, originally planned for the 2009 to 2011 timeframe. We have now analyzed further our plans for 2010 to 2013 and put in place significant, additional spending reductions. Including the MPS rule changes, approximately $1 billion of capital expenditure reductions have been made from our previous 2010 to 2013 estimates. These reductions will be achieved by eliminating virtually all capital expenditures other than mandatory environmental and maintenance type projects. While we cannot expect to realize the efficiencies that may have otherwise resulted from the expenditures we have eliminated we do not believe such expenditures are cost justified in the current power market and credit environment. However, as a result of eliminating these capital expenditures we expect to reduce scheduled outage time to more than compensate for increased and unplanned outages and this should improve the net availability of our core base load power plants. In addition, we're also right-sizing our support organization for the merchant generation business. On July 22, we announced a reduction of 55 positions in its business support organization. We're also continuing to evaluate the current economics of our small non-core generating facilities which we do not currently expect to sell. Presently we are considering alternative operating modes for these small plants to improve their profitability. It is our expectation that actions we are taking to address cost in this business segment will result in 2010 non fuel operations and maintenance cost that are meaningfully lower than 2008 levels. Moving to slide 8 at Ameren we understand that financial strength and flexibility is critical at all times but especially in the current environment. I believe that we continue to demonstrate our commitment to maintaining and enhancing Ameren's financial strength, credit quality and earnings with a series of concrete and aggressive actions. We're convinced that these actions will benefit both our investors and our customers. In February of this year our Board of Directors reduced our common stock dividend to strengthen our financial flexibility and free up approximately $215 million annually for reinvestment into our businesses. In June we renewed our credit facilities providing Ameren in each of our business segments with substantial borrowing capacity through mid 2011. In June and July we filed rate increase request in our Illinois and Missouri utility jurisdictions respectively. Further, we have identified approximately $2 billion of potential opportunities to reduce planned capital expenditures for 2010 to 2013 as compared to earlier plans which should substantially improve our cash flows. We are also looking carefully at planned operations and maintenance expenditures across our organization. We are especially focused on our merchant generation business but we know that it’s appropriate to tighten our belt across the company. Finally, we still see growth in our regulated businesses through investing to support customer needs and closing the gap in regulatory lag. And we see growth in the merchant generation business through recovery in power prices and related higher sales levels. I will now turn the call over to Marty to walk you through the details of our second quarter 2009 earnings, review our full year 2009 earnings guidance, provide more color on the cost control opportunities we have identified and discuss key earning drivers for 2010 and 2011. Martin J. Lyons: Thanks Tom. Turning to slide 10, I direct you to the Q2 column which reconciles second quarter 2008 earnings to second quarter 2009 earnings. As Tom mentioned, our Q2 results were in line with our expectation. Second quarter 2009 net income in accordance with Generally Accepted Accounting Principles was $165 million or $0.77 per share, compared to second quarter 2008 GAAP net income of 206 million or $0.98 per share. Excluding certain items in each year Ameren recorded second quarter 2009 core net income of $161 million of $0.75 per share, compared with second quarter 2008 core net income of 142 million or $0.67 per share. There are two items in the second quarter of 2009 that we have excluded from our core earnings. These items are the net costs associated with the Illinois comprehensive electric rate release and customer assistance settlement agreement reached to 2007, which reduced the second quarter 2009 GAAP earnings by $0.02 per share and the net effects of mark-to-market activities which increased second quarter 2009 GAAP earnings by $0.04 per share. These items were also excluded in the prior year. In addition in 2008, we excluded the benefit of the Missouri storm related accounting order and the out of period benefit of our coal contract settlement. You may recall that the coal contract settlement had two parts; one which reimbursed us for higher expected cost in 2009, which was excluded from our core earnings and the other part which reimbursed us for higher cost in 2008. The 2008 portion was considered core, since we did incur those higher costs throughout 2008. However the receipt the benefit in Q2 2008 does affect quarterly comparisons. Continuing with the second quarter reconciliation on slide ten, the Missouri electric rate increase which took effect March 1, 2009, raised second quarter 2009 earnings by $0.12 per share, net of amortization compared to the second quarter of 2008. The net increase in Illinois electric and natural gas delivery services rates effective October 1, 2008, boosted second quarter 2009 earnings by $0.14 per share compared to the second quarter of 2008. We estimate normal weather boosted earnings by $0.07 per share compared to the year ago quarter and by $0.09 per share versus normal. Cooling degree days in the second quarter of 2009 were 23% greater than in the corresponding period in 2008. Moving to the next line, in our second quarter earnings reconciliation, reduced sales in Noranda aluminum lowered second quarter 2009 earnings by $0.03 per share versus the year ago quarter. You may recall that Noranda's aluminum plant sustained damage because of the power interruption on non Ameren owned lines this past January. Other electric and gas margins for regulated utility operation excluding the impact of weather and the lost Noranda sale decreased earnings by $0.20 per share. Of this decrease $0.14 per share was a result of higher net fuel cost at AmerenUE as compared to the year ago period. These higher net fuel costs were reflected in the rate increase we received in Missouri this past March. Although the timing of the receipt of the increase in revenues does not exactly match the increase in net fuel cost by quarter. We expect the increase in revenues to exceed the net fuel cost to increase in the second half of the year due to this timing. The remaining $0.06 per share decline in other electric and gas margins and our regulated operations principally reflects a decline in weather normalize sales reducing earnings by $0.04 per share. Regulated industrial electric sales decreased by 13% in the second quarter of 2009, compared to the second quarter of 2008 excluding sales to Noranda. This decrease in industrial sales had a modest impact on earnings because of the loan margins on these sales and fixed demand charges. Next on the quarterly earnings reconciliation is the earnings impact of the absence of the year ago 2008 portion of a lump sum payment from a coal supplier that I previously mentioned. Again the full benefit of this settlement was reflected in Q2 2008, while the costs were incurred throughout the year. Other electric margins for the Merchant Generation business increased by $0.05 per share in the second quarter of 2009, as a result of higher realized revenues per megawatt hour partly offset by higher fuel and related transportation cost. This benefit reflects the sales prices we locked in when power prices were higher. Plant operations and maintenance expenses were $0.10 per share less in the second quarter of 2009 versus the second quarter of 2008. Primarily because of reduced scheduled planned outages. The remaining six lines on the reconciliation combined to reduce second quarter 2009 earnings by $0.08 per share, primarily reflecting higher depreciation expense on increased plant investment and higher financing cost offset in-part by lower bad debt expenses and lower non-plant O&M expense. Moving on to our 2009 earnings guidance on slide 11. Tom stated that we are reaffirming our core earnings guidance range for 2009 of $2.70 to $3.05 per share. As you know, these line items are not meant to be pin point estimates but instead the estimated impacts to various earnings drivers. Actual results are expected to be in a range around these estimates. While the 2009 earnings per share guidance is unchanged, we've updated a few line items of the reconciliation. Notable updates include a reduction in our expectation of regulated electric and gas margins by approximately $0.07 per share to reflect expected reduced customer demand, and increase in expected distribution system reliability expenditures due in part to storm related expenditures and offsetting decrease and expected other operations and maintenance costs including bad debt expenses due to cost control measures and recent Illinois legislation authorizing a bad debt rider among other things. I'd also note that in the weather Line item, we have included an estimates of the impact of mild weather condition in our service territory during July. Our 2009 GAAP earnings guidance includes the estimated $0.07 per share negative impact of the Illinois comprehensive electric rate relief and customer assistance settlement agreement. Any net unrealized mark-to-market activity will impact GAAP earning, but it’s excluded from our GAAP and core earnings guidance because the company is unable to reasonably estimate the impact of any such gains and losses due to the volatility of market. We expect our 2009 GAAP earnings will be in the range of $2.63 to $2.98 per share. Our segment contributions have also been updated and reflect the items I just mentioned. Ameren's earnings guidance for 2009 seems a normal weather from August through the balance of the year and are subject among other things, regulatory decisions and legislative actions, plant operations, energy and capital and credit market condition, economic conditions, severe storms, unusual or otherwise unexpected gains or losses and other risks and uncertainties outlined or referred to in the forward-looking statements section of our press release today. Turning to 2010 and beyond, Tom discussed the actions we are taking to successfully position Ameren for the current environment as well as future economic recovery. I'll provide a little more detail on some of these of items, as well the traditional drivers of our earnings in cash flow. As mentioned earlier we recently filed rate increase request totaling over 600 million in both Illinois and Missouri. The outcome of these rate case will obviously be key drivers of our financial results beginning in mid-2010. Slide 12 outlines key aspects of our Illinois electric and gas delivery rate request. You can read the details on the slide so I am not going to go through all of it. A couple of things I would highlight. We are sensitive to the impact the increase will have on our customers. Coincidentally the recently completed and successful Illinois power agency procurement process resulted in $100 decline in annual electric rate for a typical residential customer, which would offset the electric delivery rate increase we are expecting for such customer. As part of continuing effort to reduce the sensitivity of revenues to volumetric fluctuations we have requested that regulators approve moving more of the electric delivery charges into fixed monthly rate, similar to the gas rate redesigned change approved by the Illinois Commerce Commission in 2008. The Illinois Commerce Commission is required to issue a rate decision in 11 month and new rates are expected to be effective in May 2010. Slide 13 outlines key of our Missouri rate increase request. I would highlight that the request includes approximately 227 million of anticipated increases in normalized net fuel cost. These costs would have been eligible for recovery through the fuel adjustment log. AmerenUE's filing also includes for the first time a request for interim rate relief which if approved would place into effect of approximately 37 million annually of the requested increase on October 1, 2009 subject to refund with interest based on the final outcome of rate proceeding. The amount of this interim increase request reflects revenue requirement associated with rate base addition made between October 2008 and May of 2009. As part of this filing the company also requested that Missouri Public Service Commission approve the implementation of and Environmental Cost Recovery Mechanism or ECRM and the continued use of the Fuel Adjustment Clause or FAC that the commission authorized in January 2009 order. The ECRM if approved will allow AmerenUE to adjust electric rates up to two times per year outside of general rate proceedings to reflect changes in its prudently incurred cost to comply with federal, state or local environmental laws, regulations or rules above or below the amount that in base rate. ECRM rate adjustments are limited to no more than an annual amount equal to 2.5% of UE's gross jurisdictional electric revenue. Further, the company filed for approval to revive the tariff for Noranda Aluminum, AmerenUE's largest electric customer, to prospectively address the significant lost revenue that UE can experience due to Noranda's operational issues at its smelter plant. A storm cost tracker was also requested. The Missouri Public Service Commission is required to issue a rate decision in 11 months and new rates are expected to be effective in June 2010. Now let's move to a discussion of our merchant generation business and the outlook for key drivers of revenues and expenses. For revenue drivers, please turn to slide 14. We have significant hedges in place for 2010 and 2011 and power prices well above the current market. For 2010, we have hedged approximately 23 million megawatt hours of our forecasted generation sales at an average price of $48 per megawatt hour. For 2011, we have hedged approximately 15 million megawatt hours of our forecasted generation sales at an average price of $51 per megawatt hour. Slide 14 also provides an update on our hedged capacity sales. As you can see, our capacity sales are approximately 70% hedged to 2010 and approximately 40% hedged in 2011. As noted a significant portion of our hedged capacity sales reflect capacity embedded in full requirements contracts. The revenue from these embedded capacity sales is reflected in the prices we provided for hedged power sales. Already hedged capacity only revenues are expected to be approximately 60 million in 2010 and approximately 45 million in 2011. Of course we have additional capacity available for sale, that is expected to add to these revenues. To assist you in understanding our Merchant Generation Segment's earnings potential, we've provided a pie chart that breaks down our forecasted 2009 merchant revenue by type. Turning to slide 15. Actual generation levels in 2010 and 2011 will be significantly impacted by market prices for Power in those years among other things. With very few scheduled outages for 2010 and 2011, we expect to have available generation of 35 million megawatt hours in each year. Now turning to slide 16, in our Merchant Generations segments fuel and related transportations hedges. As you see on this slide we are well hedged for 2010 and 2011. Our hedge costs are increasing from average cost of about $20.50 per megawatt hour in 2009 to approximately $23.50 per megawatt hour in 2010 and $26 per megawatt hour in 2011.Similalry to our previous slide dealing with Merchant Generation revenues, we have a pie chart that breaks down forecasted 2009 all in fuel cost to provide a perspective on how each component contribute to our overall cost. On slide 17 we summarize our plans to further total Ameren capital expenditures from our prior disclosures. As previous stated in total we have identified approximately 2 billion of opportunities to reduce Ameren's consolidated planned capital expenditures for 2010 through 2013 as compared to earlier plans. This amount includes approximately one billion of planned capital expenditure reductions in our Merchant Generation business for this period. In our regulated business, we have identified approximately one billion of potential reduction and are carefully evaluating in which project may get eliminated or differed. On slide 18, we provide a little more detail specific to our Merchant Generation business's new annual capital expenditure plan through 2013. Moving to slide 19, we outline our targets for further non-fuel operations and maintenance cost management. In 2010 we expect a 5 to 10% decline in non-fuel O&M as compared to 2008 levels. Our regulated businesses are also carefully evaluated on opportunities to reduce 2010 non-fuel operations and maintenance expenses to a level that is currently expected to be close to 2008 level. Planned and potential cost containment actions include reduced scheduled merchant power plant averages, wage and workforce reductions, and other cost reduction in business support function. Turning now to slide 20. As Tom discussed earlier, we have successfully renewed our credit facility completing new multi-year agreements with a large and diverse group of lenders providing Ameren and its operating units with substantial liquidity. The extended the new facility cumulatively provide 2.1 billion of credit through July 14, 2010 reducing to approximately 1.9 billion through June 30, 2011. As shown on slide 21 our net available liquidity remained strong standing at approximately $1.4 billion on June 30, 2009. All of the actions we have taken not only demonstrate our commitment to credit quality but also position us for long term growth. These actions are summarized on slide 22. We continue to target BBB flat and BAA2 Ameren Corporation issuer rating and solid investment grade credit rating in all of our rated Ameren companies. Even with the potential of reduction in capital expenditures as compared to prior plan we continue to make meaningful investments in our regulated businesses. As we have said in the past we intend to finance those investments with a blend of equity and debt so that we remain -- so that we maintain solid capital structures at our regulated businesses at approximately 50 to 55% equity. Summing up our second quarter earnings were in line with our expectations we have affirmed our 2009 earnings guidance we are working aggressively to position Ameren for long term success and we remain committed in maintaining and enhancing Ameren's financial strength credit quality and earnings. We will now be happy to take yours.

Thank you. (Operator Instructions). Our first question is coming from Greg Gordon with Morgan Stanley. Please state your question.

Thank you, good morning.

Good morning Greg.

As I look at the slide 16 as compare to slide 14. You're basically telling us that your hedges are sort of matched up in '09, you're a bit longer on coal than you are on what you've hedged in '10 and also but shorter on call relative to what you have hedged in '11 is that the right interpretation?

Greg this is Marty. Yeah I think that is the right interpretation. As you look at slide 14 and you look at the megawatt hours that are hedged, you see there the 23 million megawatt hours of hedged power and as you say in 2010 in terms of fuel hedges about 29. So you're right a little longer on the coal side in 10. And then 2011, about 15 million megawatt hour is hedged on the coal side. But that matches up with 2011 power hedge is about 15 million.

Just to be sure I'm reading the foot note on page 16 correctly, these are all in delivered costs per megawatt hours including rail?

That's correct.

Great. Thank you.

Thank you Greg.

Your next question is coming from Paul Ridzon with KeyBanc Capital.

How should we think about -- looks sounds as if the coal plans sales are after table but we got significant CapEx reductions. When do you envision the timing of potential equity financing?

Paul this is Marty. Yeah in terms of our overall plans obviously throughout this year we've really taken some aggressive actions as you can say to reduce our capital expenditures really twice going back to last year and when again now. We've also as you know reduced the dividend earlier this year and all of those actions are going to reduce our need to access the capital markets as well as enhance our credit profile. That said as we look out to the future as I mentioned earlier in my talking points we do seek to maintain cash structures in our regulatory businesses in the range of 50 to 55% has been a target of ours. We're also targeting and maintaining investment grade credit ratings. And so as we think about the future, obviously a lot of things are changing. A lot of things have changed I should say in terms of the economy, power prices, capital markets and our business plans are changing as well as. And so as we look out in the future, we're going to be evaluating our financing plans and the timing of both debt and equity offerings. As we said in past, as we make investments in our business over the long term, we're certainly anticipating the need for both debt and equity offerings to finance our business.

Okay, thank you.

You’re welcome.

Our next question is coming from Paul Patterson with Glenrock Associates. Please state your question.

Hi guys. Can you hear me?

Yes Paul.

The O&M reductions for 2008 in the merchant side I mean for 2010 prior to 10%, can you just give us an idea about quantitatively what that number is? And also on the fuel cost in the open position, how do those look compared to what you've actually hedged at, when you look at the four group delivering power besides coal to your plant?

Yes. Paul, this is Marty. On the first question, I don't think I have the exact dollar amount in terms of overall. What we tried Paul was quantify that was about 5 to 10% below the 2008 level. So you can go back and take a look at what those levels were and Paul could your repeat your second question?

The second question was on the fuel cost. When we look at slide 16 in terms of the open position that you guys have in -- is more 11 than in 10. What are you guys looking at in terms of what the market prices out there for the coal versus what you got hedged. You got hedged at $26 a megawatt hour and 23.50 for 2010. Where do those and how are those compared to the market prices that are out there?

Yeah. You know, Paul I think as you look at those market prices obviously the stock price of the coal has been lower. But in terms of the long term contracts often times they don't match exactly with the spot prices are. I would generally expect -- well I probably wouldn't want to venture it against on that we may want to get back to you on that.

Okay. And the nature of the merchant CapEx reduction other than then stuff that you guys have previously identified? What's helping you out there with all that CapEx reduction, what is it that you guys are doing?

Yeah Paul, this is Marty again. We have with us this morning Chuck Naslund who is the President of that business and I'll let him address those capital expenditure reduction.

Yes good morning Paul. The CapEx reduction were all related to our planned, capacity additions to our existing units here in the next five years and such things in the turbine upgrade and then boiler upgrade to support those turbine upgrade. And those plans were put in the place back during the time period where the core market price supported those investments and obviously with the significant clients didn't make through the containment of that plan of that plan also all of those projects were better removed from the budget and that's where all of those reductions come from.

Okay would that indicate that you guys looking at a less robust with going forward. I mean clearly we have at least temporary depression here or recession. I mean it looked like you guys are more cautious about the long term outlook for power plant?

No I would not say that, I would say that just for the reality of the moment is that we have to make prudent investment. It wouldn't be prudent at this time to spend that money given the market price is where they're at today, being in the commodity business we are in. Also I would touch on your previous question you asked the level of reduction are in for Merchant business, basically approximately 355 million in '09 down to 315 and $0.20. So about 40 million reduction.

Thank you very much.

Your next question is coming from Michael Lapides with Goldman Sachs.

Hi guys question for you. In the CapEx reductions on the regulated site of the business. Can you give just any flavor or color in terms of where that's actually occurring and is it major projects moving around or moving out or is it just lots of smaller ones?

Yes, good morning Michael, this is Marty. Also fortuned to have with me here today Warner Baxter who, you know is the Head of Union Electric Operations. I'll let him touch on the on that question from UE perspective.

Good morning Michael, how are you?

Yes I'm fine. How are you Warner?

I'm great thanks. There are several things that they were looking at in terms of those capital expenditure reductions. One thing that we are looking at relates to some of our environmental projects. We believe obviously with some of the in the rules that we have the opportunity to move some of those around. Especially in light of the fact that we are going to be installing scrubber at our plant. And that going in 2010 and the couple of that with our strong bank of allowances, we have the opportunity to move some of those projects around. Second things that we are looking at as you know that we had some expenditures in our forecast associated with our potential second nuclear unit at Calloway, things for like the color and those types of things. Those clearly are now -- have been eliminated and it can be taken out. Things then beyond that include things like -- excuse me IT projects. But also carefully assessing some of the plans, plans that we have associated with some of our power plants, as well as some of the other projects that we have throughout our operations. We are going to continue to carefully assess those to see what flexible we have around that.

Got it and a follow up on the non-regulated side generation to megawatt hours. The 35 million is that an availability or is that an expected output for the -- future years?

Yeah Michael this is Marty. That 35 million is an availability number for the next couple of years.

Okay, thank you.

Your next question is coming from Dan Jenkins with State of Wisconsin Investment Board.

Hi good morning

Good morning.

I have a few questions related to slide 13 on your Missouri rate case. You are filing for a number of riders, the CCRM and then you mentioned also I think of storm cause tracker and pension OPEB tracker. I was curious, are any of those authorized in the legislation or have they approved those type of writers for other utilities in the Missouri or are these kind of first time proposals.

Yeah I think the answer to your question there is your question I believe is have all of those been authorized by the legislature and in fact they have been. We actually have been using for a couple of after last of couple of rate cases the pension and OPEB cost tracker. We also did get in the large rate case, the vegetation management tracker and we had legislation a couple of years ago at the time when the legislature authorized these fuel adjustment clause. They at that time also authorized the ability to put in place environmental cost recovery mechanisms such as that one that we're seeking to utilize as part of this rate case.

Has the commission completed the rule making related to that? I know they took a while to complete the rule making for the fuel cost I know?

Yes your recollection is correct but they have completed that rule making.

Okay. Have they approved that for any other of the utilities in this area or will this be kind of a first time to look at it?

No. I think this is the first time that the commission will have an opportunity to look at this.

Okay, thank you.

Thank you.

Our next question is coming from Raymond Lowe (ph) with Goldman Sachs. Please state your question.

Hi, guys. Can you talk a little bit about your debt financing plans. Looks like you have about a $1 billion as your short-term debt and there's been some movement in your CapEx. I think previously you indicated that you needed to do about 600 million at the Genco (ph) and IT initiatives three to 400 million can you just refresh us on that?

Yeah, as I said before, I think in terms of our overall financing plans, we're going to take a fresh look at those. Obviously we've been through a significant business planning process and obviously reduced CapEx materially in our merchant generation business and we're also we've identified opportunities and we're looking carefully after some of those opportunities in regulatory business. And as we look at those and -- we'll also be thinking about what the appropriate financing plans are going forward.

Okay and just a follow up on Michaels question about availability number ratio? Is that based up on what percentage in of availability?

I'm not sure in terms of percentage what you mean but what that is; is the 35 million that you see there is our projected availability of all of our coal fired power plans in our merchant business.

Assuming like a 100% availability.

Its about no, no it's about 86% overall availability.

Okay great thank you.

Our next question is coming from Scott Angshun with Glendale Capital Management (ph). Please state your question.

Good morning. Paul Patterson must have been looking at my notes here. Same question. I'm going to come out on them a little bit differently. First on the Merchant O&M reduction, in 2008 and Ameren energy generating O&M was a 175 million, I think there will be some O&M embedded in Steel Corp. as well as at pair in (ph) for EEEI but if I added all that up would it be a little bit south of 200 million that the ball park 2008 O&M merchant level?

Yeah it seems that I think that information is in the 10-K and 10-Q but I don't think matches up with some of the information Chuck gave a second ago. Chuck would you want to repeat that?

Yeah, I -- the number I provided was all of our EEI, O&M and all Genco O&M all together, and that number you were quoting, it was just one of those entities.

Okay I'm sorry and I must not have been paying attention. What did you say the total number was then?

For 2009 for all entities, it’s approximately 355 million.

Okay.

And in 2010, 315.

Okay, alright thank you. I apologize.

Follow up, see if you look back at our segment disclosures that are in our 10-K, you can actually go on a column that's labeled non rate regulated generation and you can actually see the total O&M for that entire segment in there and it was about $356 million in 2008.

Okay, thanks very much. And then just the second question getting back to the open vision on the fuel hedging in '11. Without, I know you don't have a number there but you were to sort of give the assignment to your traders today to go out and hedge the fuel cost for '11, do you have a sense of whether it would be higher or lower than that $26 number you have in there right now?

Yeah. Again I decline to answer to that question, not because I didn't want to. I just don't have that information readily available.

Okay thanks guys. Appreciate it.

Our next question is coming from David Frank with Catapult Capital. Please state your questions.

Hey good morning guys.

Good morning David.

Congratulations on a good quarter here.

Oh, thank you.

So this outlook looks much improved and I guess I mean given the tremendous reduction in CapEx, why are we even talking about issuing equity here. It would appear that if you cut it 2 billion of CapEx and you're looking at funding 50-50 debt equity, I mean I would think you just took at least 1 billion of equity off the table potentially?

Well Dave, based on the questions I got earlier it was refining to, I think that again we're looking overall at our financial plan over the next couple of years. We have obviously meaningfully reduced our capital expenditures we've also identified some further opportunities as I mentioned. Inconsistent with our past practice David, as we look at our financing we're going to try to maintain solid investment grade credit ratings. We are going to want to maintain financial strength and flexibility and make sure we have cushion for any unanticipated needs. So as we think about our business going forward we will be thinking all of those things and considering what our best alternatives are in terms of capital market issuances.

I guess then it will be fair assumption that there is no need for equity this year next year?

David Again I guess I didn't rule anything out specifically it's more as we look ahead. We'll take a look at what our needs are and how to appropriately finance the business

All right and Marty I know you talked about -- I think you said consolidated equity to cap of 50-50, 50-55 equity is that what you're looking at? Is that your target?

Yeah David. Over time we've talked about maintaining equity in the cap structure of the utility to 50-55% then that's been sort of the stated goal for a while now.

And where if you would just I don't know what other internal adjustments you might make to your cap structure that I may not my end but where is your current structure at?

I think if you look at the attachment to our press release David on the last page there is some specifics and you can see that where the common equity ratios are there. And you can also take a look at the slides that we have provided on the pending Illinois and Missouri rate cases. And you can see where the equity was in the cap structure of those entities as we follow those rate cases.

Okay so 46% so this fits...

Our next question is coming from Andrew Levy with Incremental Capital. Please state your question.

And I don't think David got to finish. I think he was probably kind of getting up a 50-55% versus your 46% so, I'd like you to answer that question. And then I'll ask my own.

I think he was probably filling in (ph) David you're out there looking -- getting cut off but not exactly sure how that transpired. But overtime I think your question about the 50 to 55% equity in cash structures. I mean that has been our goal, it remains our goal. We are not there today and as we look at our future financial projections given some of these changing business plans. We'll evaluate how we get to that 50-55%. As I mentioned earlier the reductions in the CapEx do reduce our need to access the capital markets and the dividend reductions we made over to this year does add about $220 million per year to our equity. So, we will be evaluating all those things as we look out our perspective.

Okay. Now it's my turn. I mean all of my questions are asked, but this kind of based on some of our comments, and based on some of things even David just asked; I guess it seems to me that sounds like you want to issue equity and if we kind of go in the premise cut CapEx, you've cut the dividend. Looking at some of the numbers that you have outlined and as far as you go hedged numbers and things like that. I just wonder things that I'm coming up with I was curious, where you guys have is that. It can be very challenging to maintain the current level of earnings and because of that it kind of offsets some of the CapEx savings and things like that related to equity and your equity levels plus your desire obviously the get to a higher level. Is that a fair statement that it's going to be challenging the kind of maintain current earnings level based on the current commodity environment?

I'll say, we think we have some meaningful growth drivers that we look ahead to be honest with you. Even the -- assuming that the potential reduction that we've identified in the regulated businesses or we're actually achieved, we did see meaningful growth still in our rate base and our regulated utilities. As Tom mentioned in his talking point, we also today have a gap between our earned ROEs and have allowed ROEs in both Illinois and Missouri that we're seeking to close in the rate cases that we filed, as well as through future rate cases. And through the use of some of these mechanisms that we've requested use of that allowed us to earn closer to our allowed ROE. And couple of that with the fact that we do expect to see economic recovery beginning in the later half of 2009 and into 2010 and with that we would expect to see increases in power prices which we believe will enhance the generation opportunities for our merchant business and the earnings opportunities for that merchant business. So, as we look ahead we do see a meaningful growth drivers on horizon.

And then just to understand those growth drivers are based on higher commodity prices and that are rate treatments I guess?

I think I say its fair treatment in the rate cases and again active management of our cost as we pursue our closing the gap between the earned and allowed ROEs. That's certainly a big part of it and we do believe we have generation assets in our merchant business, that are well positioned, that our competitive assets. And we do believe that with power price recovery we're positioned well to capitalize on that.

But absent on that just a kind of go back to my question was. It sounds like its gone be challenging based on the number that you have out there income grow at this point.

Again I just stated what I believe are meaningful growth drivers for our business.

Okay thank you.

Your next question is coming from Ben Sung with Luminus Management. Please state your question.

Hey guys. Based on the chart you are detailing the cap -- the merchant CapEx. It looks as if the maintenance CapEx numbers somewhat in the neighborhood of $10 million or something fairly minimal. We recently heard different companies talk about how there's -- there is difference in the way the people look at CapEx or spending on finance whether you capitalize your spend. Is that something that's affecting that number I mean or do tend to expense more than you capitalize, just so its look like a fairly small number?

You know I -- this is Marty. I couldn't tell you in terms of our benchmarking how our capitalization policies might compare, or contrast with somebody else's capitalization policies. They are what they are and we stick to them and don't vary from them and I guess that about all I can say.

This is Doug Fischer. I think we have time for two more questions if we're going to stick to our scheduled hour time frame.

Okay our next question is coming from Greg Gordon with Morgan Stanley. Please state your question.

Thanks. Just a follow-up guys. Just to ask you a question that relates some of this debate in the Q&A here. It would seem too clearly that you need better rate treatment, more constructive rate treatment in both states. And at the same time you'd like that the equity ratios and utilities in both those states to grow to a level that's more comparable to where you want your overall credit profile to be. But -- and that all wraps into the question of whether you need equity and how quickly you may or may not want to tap the equity markets. But aren't we putting the cart before the horse here? The regulators don't come around understanding they need you to earn a reasonable return. You should be disinvesting in these businesses, not investing in these businesses. So can you comment on how you plan for your capital, how you plan your capital deployment around and understanding that you need better rate treatment in order to support issuing equity because you're not earning reasonable returns there?

Well I appreciate the follow up question. I think as we look at the capital investments in a regulated business, I think first and foremost, we're mindful of wanting to make sure we maintain safe and reliable service. I mean fundamental to our strategy is making sure that we do the right things, make the right investments to make sure that our customer service is solid and that our customers are satisfied. We do believe that that will translate into fair outcomes in our rate cases. So as we plan our business and we look forward, certainly we look for opportunities to tighten our belts in these difficult times for our customers and all of our stakeholders, but we are going to make the investments that are necessary to make sure we maintain safe and reliable service.

But if you were to continue to already to -- despite the fact that your investing the what you need to supply reliable service you would continue to be put in a position where you were earning sub par returns. Why would you even remotely consider patenting the equity investment in those businesses and under-earn on that incremental capital?

Well I think that fundamental to having good regulatory outcome is maintaining financial strength and flexibility. We believe that that's important to all the stakeholders of our regulated business. And we really believe if you look back at the last rate cases those were constructive rate cases and we believe that if we look ahead to our future rate cases that we will be treated fairly in those rate cases that we've got pending.

Thank you I hope you're right

Thanks Greg.

Your next question is coming from Stephen Huang with Carlson Capital. Please state your question.

Hi and thanks for the call here. Just a quick question on slide 14. Can you help us understand the -- on the hedges and the pricing that you guys gave is this around the clock that hedging or you guys did a lot more peak load hedging? Can you just help us understand what's in 10-11?

I don't really have the break down I'd say on the on peak and off peak what these represent obviously is the price per mega watt hour of the those overall mega watt hours that are hedged.

Right I'm just trying to figure out because for example in 2009 going to 10, it drops like 3.5 and going into '11 drops by 8 million but you have a step up in price. I'm just trying to figure out is this, you guys are just hedging more the peak load or you guys are just doing round the clock hedging. I'm just trying to get an understanding of the balance of where this hedging is coming from?

Yeah and I'm sorry. I think may be I misunderstood your question. These are around on the clock prices, I apologize.

Okay and secondly just going to back to kind of what Dave or Frank was talking about, on talking about the rating industry I know you are on the watch with a couple of them I think. On a consolidated basis, what type of equity capital structure you're looking at versus just on a subsidiary level?

I think over time we've been targeting around that 50-50 cap structure, debt-to-equity cap structure.

Okay and the agency that are comfortable with that you know the merchant and the utility and 50-50 split on the earnings level that they're comfortable with kind of their 50 because I thought they were raising the kind of the profile -- business risk profile and the all the companies have nowadays with the merchant company as kind of the indication you got from Exxon (ph) and everybody else?

I'm not sure. I guess I understood question. Would you mind may be...rephrase?

The business risk profile I guess on merchant companies, the companies that generate large chunks of their earnings from merchant arms, but they're taking a better look in terms how they want to capitalize?

Yes that probably is the case.

Okay. And the last question I have is on your O&M cut numbers. Does that take in to account all the pension expense you going forward?

Yes. We've tried to factor in to our expectations, current estimates on prospective pension and push accounted medical expense.

Great, thank you very much.

This does bring us to the end of Q&A session. I'd like to turn the call back over to management for any closing remarks.

Thank you for participating in this call. Let me remind you again that this call was available through August 13th on playback and for one year on our website. The announcement carries instructions on listening to the playback. You can also call the contact listed on our news release. Financial analyst should be directed to me, Doug Fischer. Media should contact Susan Gallagher. My number and Susan's contact numbers are on the news release. Again thanks for dialing in.

Ladies and gentlemen this does conclude today's teleconference. You may disconnect your line at this time and we thank you for your participation.