阿莫林 (AEE) 2009 Q2 法說會逐字稿

Greetings, ladies and gentlemen, 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, Thomas Voss, our Senior Vice President and Chief Financial Officer, Marty Lyons, and other members of the Ameren management team.

Before we begin, let me cover a few administrative details. 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 carries 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 statement 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 investor section of our website under presentations and follow the appropriate link.

Turning to Slide 3, 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 questions. Here is Tom.

Thanks, Doug. Good morning all and thank you for joining us. Moving to Slide 4 of the presentation on our website, I am pleased to report that this morning we released second quarter 2009 non-GAAP or 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. These results were in line 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 service rates in Illinois and Missouri as well as lower plant operations and maintenance expenses and warmer weather. The favorable earnings impact of these factors was reduced by higher net fuel costs, reduced sales to industrial customers including sales to nor Noranda Aluminum, higher storm repair costs and higher depreciation and financing costs. In addition, core GAAP quarter-to-quarter comparisons were negatively impacted as a result of the income recognized in the second quarter of 2008 related to the termination of a coal contract during that period.

Turning now to Slide 5, 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. Rate relief, cost control and actions taken to reduce our exposure to price fluctuations in the wholesale energy markets are helping us weather a difficult economic and market conditions affecting our industry and the entire country. Marty will provide more details on second quarter earnings and 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 1 of this year. I immediately engaged our management team in an ongoing strategic planning effort to insure our company is positioned for long-term success. Moving to Slide 6 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 prospective earnings growth.

Presently, our regulated utilities businesses are earning well below their allowed rates of return largely as a result of regulatory lag associated with investments and utility infrastructure to improve customer service as well as higher operating and financing costs 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 costs by $350 million to $400 million.

Now through our recent planning efforts, we've identified further possible opportunities to tighten our belt in 2010 and beyond for the good of all stakeholders. These opportunities include reductions of both planned capital expenditures and in operations of 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 requests 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 costs associated to generating and delivering electricity, higher financing costs, 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 rates. However, current rate levels in both Illinois and Missouri are simply not adequate during 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 environmental controls among other things.

Turning to our non-rate regulated generation business segment, which we now call our merchant generation segment on Slide 7. 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 or that we have locked in through our 2010 and 2011 forward sales. These lower power prices are very much linked to weak economic conditions which are reducing the demand for power and other energy commodities. We believe that when the economy recovers, these prices will rise.

Nonetheless, we are 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 costs by $400 million to $450 million. This was achieved through both spending cuts and deferrals.

This spring 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 MTS. These rule changes which are now final allow us to defer to subsequent years approximately $300 million of merchant generation capital expenditures, originally planned for the 2009-2011 time frame. 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 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 unplanned outages and this should improve the net availability of our core base load power plants.

In addition, we are 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 are 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 costs in this business segment will result in 2010 non-fuel operations and maintenance costs 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 committment to maintaining and enhancing Ameren's financial strength, credit quality, and earnings with a series of concrete and aggressive actions. We are 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 and each of our business segments with substantial borrowing capacity through mid 2011. In June and July, we filed rate increase requests 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're also looking carefully at planned operation and maintenance expenditures across our organization. We are especially focused on our merchant generation business, but we know that it is appropriate to tighten our belts 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 and 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.

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 expectations. 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 or $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 2009 that we have excluded from our core earnings. These items are the net costs associated with the Illinois comprehensive Electric Rate Relief and Customer Assistance Settlement Agreement reached in 2007 which reduced 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 a Missouri storm related accounting order and the out of period benefit of a coal contract settlement. You may recall that the coal contract settlement had two parts. One which reimbursed us for higher expected costs in 2009 which was excluded from our core earnings and the other part which reimbursed us for higher costs in 2008. The 2008 portion was considered core since we did incur those higher costs throughout 2008. However, the receipt of the benefit in Q2 2008 does affect quarterly comparison.

Continuing with the second quarter reconciliation on Slide 10, 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 service rates effective October 1, 2008, boosted second quarter 2009 earnings by $0.14 per share compared to the second quarter of 2008. We estimate warmer 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 for 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 operations excluding the impact of weather and the lost Noranda sales decreased earnings by $0.20 per share. Of this decrease, $0.14 per share was the result of higher net fuel costs at Ameren UE 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 costs by quarter. We expect the increase in revenues to exceed the next fuel cost 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 normalized 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 low 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 the 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. 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 partially offset by higher fuel and related transportation costs. 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 2009 versus the second quarter 2008, primarily because of reduced scheduled plant outages. The remaining six lines on the reconciliation combine to reduce second quarter 2009 earnings by $0.08 per share, primarily reflecting higher depreciation expense on increased plant investments and higher financing costs 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 pinpoint estimates, but instead the estimated impacts of the various earnings drivers. Actual results are expected to be in a range around these estimates. While our 2009 share guidance is unchanged, we have 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 an offsetting decrease in expected other operations and maintenance costs including bad debt expenses, due to cost control measures and recent Illinois legislation authorizing a bad debt writer among other things. I would also note that in the weather line item we have included an estimate of the impact of mild weather conditions 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 earnings, but is 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 markets. 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 assumes normal weather from August through the balance of the year and is subject to among other things regulatory decisions and legislative action, plant operations, energy and capital and credit market conditions, economic conditions, severe storms, unusual or otherwise unexpected gains or losses, and other risks and uncertainties outlined or referred to in the forward-looking statement 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 items as well as additional drivers of our earnings and cash flows. As mentioned earlier, we recently filed rate increase requests totaling over $600 million in both Illinois and Missouri. The outcomes of these rate cases will obviously be key drivers of our financial results beginning in mid 2010. Slide 12 outlines key aspects offer 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 a $100 decline in annual Electric rates for a typical residential customer which would offset the Electric delivery rate increase we are requesting for such customers. As part of our continuing effort to reduce the sensitivity of revenues to volumetric fluctuation, we've requested regulators approve moving more of the electric delivery charges into fixed monthly rates similar to the gas rate redesign change approved the Illinois Commerce Commission in 2008. The Illinois Commerce Commission is required to issue a rate decision in 11 months and new rates are expected to be effective in May 2010.

Slide 13 outlines key aspects of our Missouri rate increase request. I would highlight that the request includes approximately $227 million of anticipated increases in normalized net fuel costs. These costs would have been eligible for recovery through the fuel adjustment clause. Ameren UE's filing also includes for the first time, a request for interim rate relief which if approved would place into effect approximately $37 million annually of the requested increase on October 1, 2009 subject to refund with interest based on the final outcome of the rate proceeding. The amount of this interim increase request reflects the revenue requirement associated with rate base additions made between October 2008 and May of 2009.

As part of its filing, the Company also requested the Missouri Public Service Commission approved the implementation of an environmental cost recovery mechanism or ECRM and the continued use of the fuel adjustment clause or FAC that the commission authorized in its January 2009 order. The ECRM if approved would allow Ameren UE to adjust electric rates up to two times per year outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with federal, state or local environmental laws, regulations or rules above or below the amount set in base rate.

ECRM rate adjustments are limited no more than an annual amount equal to 2.5% of UE's gross jurisdiction all electric revenue. Further, the Company filed for approval to revise the tariff for Noranda Aluminum, Ameren UE's largest electric customer to prospect every address the significant lost revenue that UE can experience due to Noranda's operational issues at its smelter plant. The 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 sale at an average price of $48 per megawatt hour. For 2011, we've 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 sale. As you can see, our capacity sales are approximately 70% hedged in 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 segments 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 and our merchant generation segments fuel and related transportation hedges. As you see on this slide, we are well hedged for 2010 and 2011. Our hedge costs are increasing from average costs 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. Similar to our previous slide dealing with merchant generation revenues, we have a pie chart that breaks down forecasted 2009 all in fuel costs to provide a perspective on how each component contributes to our overall cost.

On Slide 17, we summarize our plan to further reduce total Ameren capital expenditures from our prior disclosure. As previously stated, in total we have identified approximately $2 billion of opportunities to reduce Ameren consolidation planned capital expenditures for 2010 through 2013 as compared to earlier plans. This amount includes approximately $1 billion of planned capital expenditure reductions in our merchant generation business for this period. In our regulated businesses, we've identified approximately $1 billion of potential reductions and are carefully evaluating which projects may be eliminated or deferred. On Slide 18, we provide a little more detail specific to our merchant generation businesses 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 evaluating opportunities to reduce 2010 non-fuel operations and maintenance expenses to a level that is currently expected to be close to 2008 levels. Planned and potential cost containment actions include reduced scheduled merchant power plant outages, wage and workforce reductions, and other cost reductions and business support functions.

Turning now to Slide 20, as Tom discussed earlier, we have successfully renewed our credit facilities, completing new, multi-year agreements with a large and diverse group of lenders providing Ameren and its operating units with substantial liquidity. The extended and new facilities 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 remains strong standing at approximately $1.4 billion on June 30, 2009.

All of the actions we've taken, not only demonstrate our committment 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 of Ameren Corporation issuer ratings and solid investment grade credit ratings at all of our rated Ameren companies. Even with the potential of reduction in capital expenditures as compared to prior plans, 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 maintain solid capital structures at our regulated businesses that approximate 50% to 55% equity.

Summing up, our second quarter earnings were in line with our expectations. We have reaffirmed our 2009 earnings guidance. We are working aggressively to position Ameren for long-term success and we remain committed to maintaining and enhancing Ameren's financial strength, credit quality and earnings. We will now be happy to take your questions.

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 we look at Slide 16 as compared to Slide 14, you're basically telling us that your hedges are matched up in '09. You're a bit longer on coal than you are on what you hedged in 2010 and also -- but shorter on coal relative to what you hedged in 2011. Is that the right interpretation?

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

And just to be sure I'm reading the footnote on Page 16 correctly, these are all in delivered costs per megawatt hour including rail?

That's correct.

Great. Thank you.

Thank you, Greg.

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

How should we think about -- it sounds like the coal plant sales are off the table, but we've got significant CapEx reductions. When do you envision the timing of potential equity financing?

This is Marty. In terms of our overall plans obviously throughout this year, we've really taken some aggressive actions, as you can see, to reduce our capital expenditures, really twice going back to last year and then again now. We've also as you know reduced the dividend earlier this year. All of those actions are going to I think 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 cap structures in our regulated businesses in the range of 50% to 55%. It's been a target of ours. We're also targeting maintaining investment grade credit ratings. As we think about the future, obviously a lot of things are changing, a lot of things have changed in terms of the economy, power prices, capital markets, and our business plans are changing as well. As we look out to the future, we're going to be evaluating our financing plans and the timing of both debt and equity offerings. As we've said in the past, as we make investments in our business over the long term, we certainly are 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, 5% to 10%, could you give us an idea about quantitatively what that number is? Also on the fuel costs in the open positions, how do those look compared to what you've actually hedged at, when we look at the forward curve for delivering 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 the overall. What we tried to do, Paul, was quantify -- there was about 5% to 10% below the 2008 levels so you can go back and take a look at what those levels were. Paul, could you repeat your second question?

The second question was on the fuel costs. When we look at Slide 16, in terms of the open position that you guys have in more 2011 than in 2010, what are you guys looking at in terms of what the market price is out there for the coal versus what you've got hedged? You've got hedged at $26 a megawatt hour and $23.50 for 2010. How do those compare to the market prices that are out there?

Yes, Paul. I think as you look at those market prices, obviously the spot prices of coal have been lower. But in terms of the long term contracts, oftentimes they don't match exactly what the spot prices are. I would generally expect -- I probably wouldn't want to venture a guess on that. We may want to get back to you on that.

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

Yes, Paul. This is Marty again. We have with us this morning Chuck Naslund who is the president of that business unit and I'll let him address those capital expenditure reductions.

Good morning, Paul. The CapEx reductions were all related toward planned capacity additions to our existing units during the next five years, such things as turbine upgrades and then boiler upgrades to support those turbine upgrades. Those plans were put into place back during a time period where the foreign market price afforded those investments. Obviously with a significant client, it didn't make sense to continue with that plan, so all of those projects have been removed from the budget. That's where all of those reductions come from.

Okay. Would that indicate that you guys are looking at a less robust outlook going forward because clearly, we have at least a temporary depression here or recession. Would look like you guys are more cautious about the long-term outlook for power prices?

No. I would not say that. I would say that the reality of the moment is that we have to make prudent investments. It wouldn't be prudent at this time to spend that money, given the marketplaces where they're at today and being the commodity business we're in. Also, I would touch on your previous question you asked, the level reductions in O&M for the merchant business. Basically approximately $355 million in '09 down to $315 million in 2010. About $40 million in reductions.

Thank you very much.

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

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

Good morning, Michael. This is Marty. Also, fortunate to have with me here today, Warner Baxter, who you know is the head of the Union Electric operations. I'll let him touch on that question from a UE perspective.

Good morning, Michael. How are you?

I'm fine. How are you, Warner?

Great, thanks. There's several things we're looking at in terms of the capital expenditure reductions. One thing we're looking at relates to some of our environmental projects. We believe obviously with some of the changes 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 a scrubber at our plant that will go in place at the end of 2010. And you couple that with our strong bank of allowances, we have the opportunity to move some of those projects around.

Second thing is that we're looking at as you know, we had some expenditures in our forecast associated with our potential second nuclear unit at Callaway. Things for like the cola and those types of things. Those clearly have now been eliminated and can be taken out.

Things then beyond that include things like IT projects, but also carefully assessing some of the 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're going to continue to carefully assess those and see what flexibility we have around those.

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

Yes, Michael. This is Marty. That 35 million is an availability number for the next couple of years.

Okay. Thank you.

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

Good morning.

Good morning.

I have a few questions related to Slide 13 on your Missouri rate case. You're filing for a number of writers -- this CCRM and then you mentioned also I think a storm cost tracker and a pension [OPEB] tracker. I was curious, are any of those authorized in the legislation? Or have they approved those type of writes for any other utilities in Missouri or are these first time proposals?

Yes, I think the answer to your question there is -- your question I believe is have all of those been authorized by the legislature. In fact, they have been. We actually been using for a couple of -- after the last couple of rate cases, the pension and OPEB cost tracker. We also did get in the last rate case the vegetation management tracker. We had legislation a couple of years ago with the time when the legislature authorized the use of the fuel adjustment clause. And 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? It took them a while to complete the rule making for the fuel clause I know.

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

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

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

Okay. Thank you.

Thank you.

Our next question is coming from Raymond [Lowe] with Goldman Sachs.

Hi, guys. Can you talk a little bit about your debt financing plans? It looks like you have about $1 billion in short-term debt. There's been some movement in your CapEx. I think previously you indicated you needed to do about $600 million at the Genco and IP needs to do $300 million to $400 million. Can you just refresh us on that?

Yes. 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 a reduced CapEx materially in our merchant generation business. We're also -- we've identified opportunities and we're looking carefully at some of those opportunities in the regulated business. 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 Michael's question about availability number. Is that based off what percentage 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 plants in our merchant business.

Assuming like 100% availability?

It's about -- no, no. It's about 86% overall availability.

Okay. Great. Thank you.

Thank you.

The next question is coming from [Scott Engstrom with Glenarm Capital Management].

Good morning. Paul Patterson must have been looking at my notes. He asked the same questions. But I'm going to come at them a little bit differently. First on the merchant O&M reduction, in 2008 at Ameren Energy generating O&M was $175 million. I think there will be some O&M embedded in CILCORP as well as at the parent for EEI. But if I added all that up, would it be a little bit south of $200 million? Would that be a ballpark 2008 O&M merchant level?

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

The number that I provided was all of our EEI O&M, all of our O&M and Genco O&M rolled together. 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 for 2010, it's $315 million.

Okay. Thank you. I apologize.

Another follow-up, too. If you'd look back at our segment disclosures that are in our 10-K, you can actually go in a column labeled non-rate regulated generation and you can actually see the total O&M for that entire segment in there. It was about $356 million in 2008.

Okay. Thanks very much. Then just a second question, getting back to the open position on the fuel hedging in 2011. I know you don't have a number there. But if you were to give the assignment to your traders today to go out and hedge the base load fuel cost for 2011, do you have a sense on whether it would be higher or lower than that $26 number you have in there right now?

Yes. Again, I declined to answer 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.

Good morning, guys.

Good morning, David.

Congratulations on a good quarter here.

Thank you.

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

David, I think based on the questions I got earlier -- I was responding to -- I think that again, we're looking over all of our financing plans over the next couple of years. We have obviously meaningfully reduced our capital expenditures. We've also identified some further opportunities as I mentioned. And consistent with our past practice though, David, as we look at our financings, we'll want to maintain solid investment grade credit ratings. We're going to want to maintain financial strength and flexibility, and make sure we have cushion for any unanticipated needs. As we think about our business going forward, we'll be thinking about all those things and considering what our best alternatives are in terms of capital markets, risk markets.

Would it be a fair assumption that there's no need for equity this year or next year?

David, again, 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. Marty, I know you talked about -- I think you said -- is it a consolidated equity to cap of 50/50, equity is that what you're looking at? Is that your target?

Yes, David. Over time, we've talked about maintaining equity in the cap structure for the utilities of 50% to 55%. That's been the stated goal for a while now.

Where if you would just -- I don't know what internal adjustments you might make to your cap structure -- that I may not know on 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's statistics. You can see that where the common equity ratios are there. You can also take a look at the slides that we've provided on the pending Illinois and Missouri rate cases and you can see where the equity was and the cap structure of those entities as we filed those rate cases.

Okay, so 46%, so this --

Our next question is coming from [Andrew Levy with Incremental Capital].

I don't think David got to finish. I think he was getting at the 50% to 55% versus your 46%, so I'll let you answer that question. And then I'll ask my own.

I think he was probably, too. David, if you're out there listening, I apologize for you getting cutoff. I'm not exactly sure how that transpired. Over time, to your question about the 50% to 55% equity in the cap structures; that has been our goal. It remains our goal.

We are not there today. As we look out at our future financial projections given some of these changing business plans, we'll evaluate how we get to that 50% to 55%. As I mentioned earlier, the reductions in the CapEx do reduce our need to access the capital markets. The dividend reduction we made earlier this year does add about $220 million per year to our equity. We'll be evaluating all those things as we look out at our prospective needs.

Okay, now it's my turn. A lot of my questions were asked. I was -- just based on some of your comments and based on some of the things even David just asked, it seems to me that -- sounds like you want to issue equity. If you go on the premise that you've cut CapEx, you've cut the dividend, looking at some of the numbers that you've outlined as far as hedge numbers and things like that, one of the things that I'm coming up with and I'm curious where your guys head is at -- is it's going to be very challenging to maintain the current level of earnings. Because of that, it offsets some of the CapEx savings and things like that relating to equity and your equity levels, plus your desire obviously to get to a higher level. Is that a fair statement that it's going to be challenging to maintain the current earnings level, based on the current commodity environment?

I'll tell you, we think we have some meaningful growth drivers as we look ahead to be honest with you. Even with -- assuming the potential reductions that we've identified in the regulated businesses were actually achieved, we do see meaningful growth still in our rate base and regulated utilities. As Tom mentioned in his talking points, we also today have a gap between our earned ROEs and 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 allow us to earn closer to our allowed ROE.

You couple that with the fact that we do expect to see economic recovery, beginning in the latter half of 2009 and into 2010. With that, we would expect to see increases in power prices which we believe would enhance the generation opportunities for our merchant business and the earnings opportunities for that merchant business. As we look ahead, we do see meaningful growth drivers on the horizon.

To understand, those growth drivers are based on higher commodity prices and better rate treatment? Right?

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

But absent that, just to go back to what my question was. It sounds like it's going to be challenging, based on the numbers you have out there to grow earnings at this point?

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

Okay. Thank you.

Our next question is coming from [Ben Sung] with (inaudible). Please state your question.

Hi, guys. Based on the chart detailing the merchant CapEx, it looks as if the maintenance CapEx numbers are somewhere in the neighborhood of $10 million or something fairly minimal. We've recently heard different companies talk about how there's a difference in the way people look at CapEx or spending on their plants, whether you capitalize or expense. Is that something that's affecting that number? Do you tend to expense more than you capitalize because that looks like a fairly small number?

This is Marty. I couldn't tell you in terms of a 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. That's 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 timeframe.

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

Thanks. A follow-up, guys. Just to ask you a question that relates to some of this debate in the Q&A here. It would seem to me clearly that you need better rate treatment or more constructive rate treatment in both states. At the same time, you'd like to put the equity ratios and the utilities in both those states to grow to a level that's more comparable to where you want your overall credit profile to be.

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 to understanding and you need to earn a reasonable return. You should be [disinvesting] in these businesses, not investing in these businesses. Can you comment on how you plan for your capital -- how you plan your capital deployment around? Understanding that you need better rate treatment in order to support issuing equity because you're not earning reasonable returns there.

Greg, 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. Fundamental to our strategy is making sure that we do the right things to 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. 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 -- despite the fact that you're investing what you need to supply reliable service, you will continue to be put in a position where you were earning sub par returns, why would you even remotely considering fattening the equity of those businesses and under earn on that incremental capital?

I think that fundamental to having good regulatory outcomes is maintaining financial strength and flexibility. We believe that that's important to all the stakeholders of our regulated business. We really believe -- if you look back at the last rate cases, those were constructive rate cases. We believe that as 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.

Our next question is coming from [Steven Huiang with Carlson Capital].

Hi. Thanks for the call. Just a quick question on Slide 14. Can you help us understand on the hedges and the pricing that you guys gave, is this around the (inaudible) hedging or you did a lot more peak load hedging. Can you just help us understand what's in 2010 and 2011?

Yes, I don't really have the break down I'd say on the on peak and off peak. What these represent obviously -- well I don't know if it's obvious or not. But it's the price per megawatt hour of those overall megawatt hours that are hedged.

Right. I'm just trying to figure out -- because for example, in 2009 going to 2010, it drops by 3.5 million. And going into 2011, it drops by 8 million. But you have a step up in pricing. I'm trying to figure out if you're hedging more of the peak load or are you just doing around the clock hedging? I'm trying to get an understanding of the balance of where this hedging is coming from.

I'm sorry. Maybe I misunderstood your question. These are around the clock prices. I apologize.

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

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

Okay. The industries are comfortable with that, even with the utility and merchant 50/50 split on the earning level? They are comfortable with that? Because I thought they were raising the business risk profile. And all of the companies now days with the merchant -- the indication that I got from Exelon and everybody else.

I'm not sure I understood the question. Would you mind maybe rephrasing it?

The business risk profile on merchant companies, companies that generate large chunks of their earnings from merchant arms, are they taking a tighter look in terms of how they want it capitalized?

Yes, probably that's the case.

Okay. Then the last question I have is on your O&M numbers. Does that take into account all of the pension expense going forward?

Yes. We've tried to factor into our expectations current estimates on prospective pension and post-retirement medical expense.

Great. Thank you very much.

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

Thank you for participating in this call. Let me remind you again that this call is available through August 13 on playback and for one year on our website. The announcement carries instructions on listening to the playback.

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