阿莫林 (AEE) 2010 Q3 法說會逐字稿

Greetings, and welcome to Ameren Corporation's third quarter 2010 earnings conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Douglas Fisher, Director of Investor Relations for Ameren Corporation. Thank you, Mr. Fisher. You may begin.

Thank you. Good morning. I'm Doug Fisher, Director of Investor Relations for Ameren Corporation. On the call with me today are our Chairman, President, and Chief Executive Officer, Tom Voss, our Senior Vice President and Chief Financial Officer, Marty Lyons, and other members of the Ameren management team.

Before we begin, let me cover a few administrative details. The call will be available by telephone for one week to anyone who wishes to hear it by dialing a playback number. The announcement you received in our news release included instructions for replaying the call by telephone. This call is also being broadcast live on the Internet, and the website will be available for one year on our website -- the webcast will be available for one year on our website at www.ameren.com. This call contains time-sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. To assist with our call this morning, we have posted presentation pages on our website to which we will refer during this call. To access this presentation, please look in the Investor section of our website under Webcasts and Presentations and follow the appropriate link.

Turning to page two of the presentation, I need to inform you that comments made during this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated and described in the forward-looking statements. For additional information concerning these factors, please read the Forward-looking Statement section in the news release we issued today and the Forward-Looking Statements and Risk Factor sections in our periodic filings with the SEC.

Tom will begin this call with an overview of third quarter results and our updated 2010 core earnings guidance followed by a discussion of recent business developments. Marty will follow with a more detailed discussion of third quarter financial results, our 2010 guidance, and regulatory and financial matters. We will then open the call for questions. Here is Tom who will start on page three of the presentation.

Thanks, Doug. Good morning, and thank you for joining us. I am pleased to report that third quarter 2010 core earnings were $1.40 per share, a $0.24 per share increase over third quarter 2009 core earnings. These strong results, driven by warm weather and a continued focus on cost-control, raised our expectations for full-year 2010 core earnings. Our GAAP results for the third quarter of 2010 included after-tax non-cash charges of $522 million, or $2.19 per share, related to goodwill and other asset impairments associated with Ameren's merchant generation operations. These charges did not impact the Company's liquidity position and have been excluded from core earnings.

Key drivers of the increase in our third quarter core earnings included a 16% increase in kilowatt hour sales of electricity to native load utility customers compared to the third quarter of 2009. Sales to residential customers rose 28%, and sales to commercial customers rose 11% reflecting warmer weather as well as underlying growth. The improving economy also contributed to the 18% increase in kilowatt hour sales to industrial customers. A significant portion of this 18% increase was due to the return to full capacity in March, 2010 of our Missouri utility's largest electricity customer, the Noranda aluminum smelter plant. However, even after excluding Noranda's contribution, industrial sales rose 10% at our regulated utilities. New utility rates and lower financing expenses also contributed to the earnings improvement.

Our year-over-year results reflect continued disciplined cost management and strong operating performance across all of our business segments. I'm pleased to report that our power plants performed well during the hot weather of the third quarter. Our coal and nuclear units were available for service 90% of the time, equaling the solid availability achieved in the prior-year quarter. The favorable impact of these factors on the third quarter earnings comparison was mitigated by an expected reduction in merchant generation segment margins. Lower realized power prices and higher fuel and related transportation costs contributed to this decrease.

Turning to page four, I am pleased to announce that for the second quarter in a row, we have raised our 2010 core earnings guidance reflecting strong year-to-date core earnings. We now expect core earnings to be in the range of $2.60 to $2.80 per share, an increase from our prior guidance range of $2.50 to $2.80 per share. Marty will provide further details on our third quarter results and our updated guidance in a few minutes.

Moving now to page five, on October first, we completed the reorganization of our Illinois businesses by merging our three Illinois electric and natural gas delivery utilities into a single legal entity now called Ameren Illinois Company. We also moved the generation subsidiary that had been held under AmerenCILCO under Ameren Energy Resources Company with other merchant generation company assets. We believe consolidation of our Illinois utilities will over time lower costs and increase our efficiency, provide greater convenience to our customers, and improve financial reporting transparency for our investors. Also on October first, we applied the geographic naming convention to our Missouri utility. Union Electric Company is now doing business as Ameren Missouri. We believe the use of the Ameren Illinois and Ameren Missouri names will bring greater clarity to our communications with customers in the two states.

Turning to page six, I would like to highlight regulatory procedures that are pending in our various jurisdictions. At Ameren Missouri, we filed an electric rate case on September third of this year. In this case, we are requesting a $263 million, or 11% annual revenue increase. The request is primarily driven by the need to recover investments made to improve the reliability of our [antique] infrastructure, comply with environmental regulations, and recover higher net fuel costs. By the time new rates from this case go into effect, more than $1 billion of new energy infrastructure will be in operation and serving customers as compared to our last rate case. This includes investments related to the scrubber project at the Sioux power plant. A decision from the Missouri Public Service Commission is required by August of 2011.

Earlier this year, Ameren Missouri also requested a $12 million, or 7%, annual increase in natural gas delivery rates. A Missouri Public Service Commission decision on that request is required by May of 2011. For details regarding these pending Missouri rate cases, I refer you to our September 2010 Investor Presentations which are archived on our website and to our filings with the SEC.

We also have an important regulatory matter pending in Illinois. We are in the midst of the Illinois Commerce Commission's rehearing of several significant issues related to the rate order our Ameren Illinois electric and natural gas delivery businesses received this past spring. You may recall that we significantly reduced planned spending levels at our Illinois utility to align such spending with the revenues and related cash flows resulting from that order. The total additional annual revenue we are now requesting in conjunction with the rehearing is $32 million. Our prior request had been for $52 million. The reduction in our request reflects a recent Illinois Appellate Court decision involving Commonwealth Edison on an issue that was also in dispute in our rehearing case. On October sixth, the ICC Administrative Law Judges issued their proposed order in the case. The ALJs recommended that Ameren Illinois be granted an additional $25 million of annual revenue beyond the $15 million annual authorized in the May order. If the ICC adopts the ALJs proposed order, the 2010 delivery rate increase would total $40 million annually. You may recall that the ICC's May order also provided for recovery of an additional estimated $13 million annually of electric and gas supply-related costs via riders. The ICC is not bound by the ALJ's order. The ICC must issue a decision by November 12th. We stand ready to restore important reliability enhancements we cut from our plans based on the additional revenues we received as a result of the rehearing process.

In addition to these rate cases in Missouri and Illinois, we have a transmission case pending at the Federal Energy Regulatory Commission. Specifically, we have applied for preapproval of supportive rate treatment for Phase One of our Grand Rivers electric transmission projects, a series of proposed Greenfield regional projects we announced in early August. We filed our response to intervener's comments on September 15th, and we are awaiting an order. As discussed on our August call, the investment associated with the Grand Rivers Phase One projects could total more than $1.3 billion through 2021 with a potential investment of $125 million over the 2011 to 2014 period. Our investment is contingent upon constructive FERC action in the pending case. In addition, for us to move forward, the projects would need to be approved by the Midwest Independent Transmission System Operator, or MISO. When appropriate, we will also seek state approvals for the projects. We are excited about the customer and investor benefits we expect to achieve with these projects.

On the environmental controls front, Ameren's Missouri scrubber project at the Sioux power plant is nearing completion. We anticipate the scrubbers for both Sioux units will be in service by the end of the year. These scrubbers are expected to remove nearly 100% of the sulfur dioxide emissions resulting from coal burned at the plant, or about 45,000 tons per year. The scrubbers are also expected to materially reduce nitrogen oxide and mercury emissions. We believe that the operation of the Sioux scrubbers will significantly improve our Missouri utility's ability to comply with more stringent environmental standards.

Before I conclude my comments, I would like to emphasize that at our Missouri and Illinois utilities, our management teams remain committed to improving earned returns and exercising disciplined management of both operating and capital costs. As I discussed, we are also aggressively, but prudently, pursuing strategic investment opportunities in regional electric transmission projects. Further, at our merchant generation business, we continue to aggressively manage operating and capital costs so that this business remains well positioned to weather current low power prices and benefit from an expected power price recovery. And at both our regulated and merchant businesses, we remain focused on operating safely and reliably. Now, I will turn the call over to Marty.

Thanks, Tom. Turning to page seven, in the third quarter 2010 column, today we reported a third quarter 2010 net loss in accordance with generally accepted accounting rules, or GAAP, of $167 million, or $0.70 per share compared to third quarter 2009 GAAP net income of $227 million, or $1.04 per share. Excluding certain items in each year, Ameren recorded third quarter 2010 core net income of $333 million, or $1.40 per share, compared to third quarter 2009 core net income of $255 million, or $1.16 per share. Third quarter 2010 core earnings exclude two items that are included in GAAP earnings. The first item is goodwill and other asset impairment charges associated with our merchant generation business. These charges reduced third quarter 2010 GAAP results by $522 million, or $2.19 per share. These charges reflected a decline in the market value of merchant generation businesses, including our own, principally as a result of sustained lower forward power prices as well as the potential enactment of more stringent environmental action. All of the goodwill formerly assigned to the merchant generation segment was written off as part of this charge. These charges also included a reduction in the carrying amounts of certain of our merchant generating assets and our SO2 allowance inventory. The goodwill and other asset impairment charges are non-cash and did not result in the violation of any Ameren or Ameren subsidiary debt covenants or counterparty agreements. These charges did not have an impact on current liquidity and are not expected to affect future operations.

The second item excluded from third quarter 2010 results in arriving at core earnings is $0.09 per share of gains representing the net effect of unrealized mark-to-market accounting. The net unrealized mark-to-market activity was primarily caused by power and fuel hedges for our merchant generation segment that do not qualify for hedge accounting treatment.

Moving then to page eight, we highlight the key factors that drove the $0.24 per share increase in third quarter 2010 core earnings compared to the third quarter 2009 core earnings. Regulated electric and gas margins, excluding the impact of rate changes, increased $0.40 per share compared to the year-ago quarter reflecting higher electricity sales. We estimate that warm weather increased third quarter 2010 results by $0.10 per share compared to normal weather. New utility rates over the past year in Missouri, Illinois, and for FERC electric transmission increased earnings by a combined $0.19 per share compared to the third quarter of 2009. Financing costs declined $0.05 per share in the third quarter of 2010 compared to the year-ago quarter, partially reflecting increased capitalization of construction financing costs and improved cash flow.

Key factors negatively impacting the comparison of third quarter 2010 core earnings to third quarter 2009 core earnings included a decline in merchant generation margins of $0.16 per share. This margin decline reflected lower realized power prices and higher fuel and related transportation costs compared to the third quarter of 2009. An increased average number of common shares outstanding, primarily due to our September, 2009 stock offering, reduced third quarter 2010 results by $0.16 per share compared to the third quarter of 2009. Because the additional common shares issued in the September, 2009 public offering are now fully reflected in the average share count, prospective 2010 per share dilution will be limited to the relatively small number of shares issued through our dividend reinvestment and 401(k) plan. Non-fuel operations and maintenance expenses increased $0.08 per share in the quarter, excluding non-core items. This increase in expenses primarily reflects the absence in the third quarter of 2010 of a benefit from anticipated recovery of previously expensed bad debts that was recognized in the third quarter of 2009.

Moving to page nine, and a discussion of our increased 2010 core earnings guidance. We now expect 2010 core earnings from our Missouri and Illinois regulated utility businesses to be in the range of $2.25 to $2.35 per share. This new range is $0.10 per share higher at the bottom and $0.05 per share higher at the top of the range, reflecting stronger than expected third quarter results driven by warm summer weather. Key drivers and assumptions behind our updated earnings guidance are listed on this page. We continue to expect our regulated utility businesses to achieve a 2010 weather-normalized return on equity of approximately 8% to 8.5% on a combined basis. This expected return on equity range is still well below our allowed returns of approximately 10% in both states but is an improvement over our 2009 earned return on equity of approximately 7%.

Turning to page ten, we now expect our merchant generation business segment to post core earnings of $0.35 to $0.45 per share in 2010. This represents a reduction of $0.05 per share at the top end of the range, and it reflects refined margin expectations as year-end approaches. This page lists the key drivers and assumptions behind our 2010 merchant generation core earnings guidance. The assumptions are largely unchanged from those disclosed during our second quarter 2010 earnings call. Our 2010 core earnings guidance excludes the first quarter 2010 charge of $0.06 per share related to the deferred tax impact of new federal healthcare laws and the third quarter 2010 charge of $2.19 per share related to goodwill and other asset impairments associated with the merchant generation business. Any net unrealized mark-to-market gains or losses recorded in 2010 will impact GAAP results but will be excluded from our core earnings. I want to remind you that our earnings guidance for 2010 assumes normal weather for the fourth quarter of the year and is subject to the assumptions, risks, and uncertainties outlined -- or referred to in today's press release.

Moving to page 11, we provide an undate of our cash flow outlook for 2010. I am pleased to report that we are raising our cash flow outlook for the second quarter in a row. As you can see, we now expect positive free cash flow of approximately $415 million, an increase from our August fifth guidance of $330 million. This improvement in our expected free cash flow is the result of additional expected cash tax savings and the previously discussed increase in earnings expectations.

Moving from 2010 earnings and cash flow to a discussion of our merchant generation segment, please now turn to page 12. Here we provide an update on our forward power sales hedges as of September 30th. As you can see, we have significant hedges in place through 2012 at power prices greater than current market prices. As we noted on our merchant generation core earnings guidance page for 2010, we have sold or hedged approximately 28.5 million megawatt hours at an average price of $47 per megawatt hour. For 2011, we have now hedged approximately 24 million megawatt hours at an average price of $46 per megawatt hour. And for 2012, we have hedged approximately 14.5 million megawatt hours at an average price of $51. Our capacity sales are approximately 86% hedged in 2010, approximately 67% hedged in 2011, and approximately 40% hedged in 2012. Our ownership of iron in the ground, low cost coal-fired baseload and coal and gas-fired intermediate antiquing generation gives us a solid position from which to work to achieve premiums greater than visible forward power prices for negotiated customized contracts. As we move forward to hedge our open positions in 2011 and beyond, we continue to target wholesale and large retail opportunities with customized and value-added load-shaped products that allow us to enhance margins by leveraging our capability.

On page 13, we update our merchant generation segment's fuel and related transportation hedges. As we disclosed on our merchant generation core earnings guidance page for 2010, our expected baseload, all-in fuel costs are hedged at approximately $22.50 per megawatt hour. For 2011, we have now hedged approximately 23 million megawatt hours at about $25 per megawatt hour. For 2012, we have hedged approximately 13 million megawatt hours at about $26 per megawatt hour. After funding expected capital expenditures of $120 million in 2010, we continue to anticipate that free cash flow from our merchant generation segment will be positive in 2010, allowing us to reduce outstanding merchant generation borrowing. This completes our prepared remarks, and we will now be happy to take your questions.

Thank you. (Operator Instructions) Our first question comes from Gregg Orrill with Barclay's Capital. Please proceed with your question.

Thanks a lot. Good morning.

Good morning, Gregg.

I wanted to touch on your writedown of the merchant generation. Just two things there. The first being, I haven't seen another company take a writedown with part of the rationale being anticipated environmental rules. And I was just wondering specifically what you were touching on there? And how much that impacted your thought process? And then also, if you could comment on whether or not the -- a decision to explore sale of the assets factored in? Thank you.

Sure, Greg. Thanks for the question. The impairment charge overall really has nothing to do with rumored sales processes. Really, it does have to do with the things that we outlined in our call. You are right. We mentioned anticipated environmental regulations. I guess the thing I'd point to there that had the most pronounced effect is that we did have proposed rules -- transportation rules -- that came out from EPA in July. I think you saw that those did have a negative impact on the value of emission allowances. The charge we took which was a gross $589 million charge. Of that, about $68 million was for an emission allowance writedown. Obviously, those transport rules aren't finalized yet. But the market value of emission allowances did drop. In our estimation, the allowances we had plus the allowances we would be granted in the future would not be fully utilized in operations, and as a result, we did write those down to their fair value.

Thanks.

You're welcome.

Our next question comes from Julian Endimullen Smith from UBS. Please proceed with your question.

Thank you. Good morning. I wanted to find out, year-to-date, your free cash flow seems to have just enhanced with every quarter. I just wanted to get a sense of what you intend to do with that free cash flow? And then maybe secondarily to the extent you can comment, potential proceeds if you hypothetically were to move forward with the sale of your merchant generation business?

Well, I will take the second one first. Certainly, no comments on the rumors that have been out there. I wouldn't speculate on that.

With respect to the cash flows, they have been very positive this year. We have been very pleased. We, as a Company, really tightened the belt on spending, both operations spending as well as capital spending. We have also taken advantage of opportunities to reduce our cash taxes, and as a result, we have had significant improvement in free cash flow. We are utilizing that to pay down debt. We are paying down both long-term debt as well as reducing our short-term borrowing. That's gone -- that has been our use of proceeds and is lowering our financing costs and helping our credit metrics across the business.

Great. Would it be a safe assumption, say, that you would use substantially all of the free cash flow either to pay down those notes this year, or the short-term debts that you have against your facility? From a modeling perspective?

I think you are basically repeating the answer that I gave to the question. Yes, we are certainly utilizing the cash to pay down long-term debt as well as to reduce short-term debt. One of the things we mentioned on our prior call was the expectation that this fall is when the Genco series matured, that we would pay that down using the cash available. Yes, there is a modeling assumption using that to pay down debt.

Thank you.

Our next question comes from Jeff Coviello with Duquesne Capital. Please proceed with your question.

Good afternoon. I had a few questions on topics people touched on earlier. The writedown in the merchant business. What is the remaining book value of equity there? Is my first question.

Jeff, I think as you look at some of our previous disclosures around the goodwill issue I think you could have backed into an overall book value in the range of $3.3 billion. If you roll that forward for the year and take into account the impairment charges that we have recorded, you are probably in the range of $2.8 billion or $2.9 billion.

Got it. And as a follow-up, you mentioned the cash flow. I know you had been clear about this. Some of the cash flow was going to be used to pay down the short-term maturity at Genco. Just to be clear, that's cash -- I just want to understand -- is that cash that was being generated by Genco? Or is there any cash flowing from the utilities to support the debt at Genco?

Yes, Genco has been cash flow positive this year, and when you see their balance sheet, when we file it our 10-Q, you will see a little over $200 million of funds available in cash or in short-term loans to the money pool. It will be able to draw on that too to satisfy its obligation.

Okay. So it is using its own resources to pay down its debt?

That's correct.

My final question was how should we think about the dividend at the Company now that the cash flow has been strong this year. The dividend is nicely below the utility earnings. Are we in a position now where you think you can grow the dividend going forward?

I think when you look at the dividend -- certainly, we are very focused on the dividend. We know it is a meaningful part of the value equation for our shareholders. What we are doing, and I think you see this in results, is we are very focused on improving and growing the earnings from our regulated businesses. We are taking actions across the Company to improve the earned ROEs. Those are coming closer to the allowed, and we are very focused on continuing to close that gap. You are also seeing us fund transmission investments to grow in that area -- to grow the regulated portion of our earnings. And that's really key to long-term, our ability to grow the dividend. In the short-term, we believe where our dividend is provides already a very attractive dividend to potential investors. And it would be as we grow those regulated earnings over time and bring the payout down as a percentage of our regulated earnings that we would give consideration to the -- or the Board might give consideration, I should say, to considering a dividend increase.

Okay. Thank you very much, Marty.

Our next question is from Dan Jenkins with the State of Wisconsin Investment Board. Please proceed with your question.

Good morning. I had a few questions on your regulatory -- the rate cases in Missouri and Illinois. I was just curious, what is the requested ROE for the Missouri case? And then how -- what is the Delta on the rate request based on a 1% change in that ROE?

Dan, this is Warner Baxter. I didn't hear the second part of your question. This first part of your question is what is the requested ROE? And that's 10.9% with a capital structure of 51% of equity. Your second question -- I'm sorry, I didn't hear that?

The second part is how much does that rate request change based on a 1% change in the allowed ROE?

For Missouri?

Right.

A 1% change -- in the -- so the closing of the gap between the earned and the allowed ROE? Is that your question?

So say they allow a 9.9% versus a 10.9%? How much would that change the revenue (inaudible)?

It is approximately $50 million to $55 million for every 1% change. Pre-tax, that is.

Right. And then for Illinois. I was wondering if you can give us a little color on what was the Appellate decision related to the revision of your request? And then also, what's the difference remaining between your $32 million request and the proposed order is $25 million?

I think in terms of the Appellate Court decision -- I think what the impact there is to basically with respect to the ability to carry forward accumulated depreciation on --or not carry forward accumulated depreciation on plants. Basically, they struck that down, I believe. One of our arguments had been as to in our rate case and in our rehearing case would be to ask the Commission to not carry forward the accumulated depreciation on plant and service as of the test year through the end of the true-up period. The Appellate Court struck that down. If you look at our rehearing request, and what you see in our slides, we have reduced that request because of that Appellate Court decision. That has impacted the amount of our ask going forward.

How about -- you said you are still asking for $32 million though? And the proposed order has $25 million. Is there another issue there that makes up that $7 million difference?

I think that has to do with the calculation of the accumulated depreciation reserve adjustment and how that factored into the ALJ's decision.

Okay. And then I was curious if you could give us a little color on, you talked industrial sales were still up 10% ex-Noranda. Was that pretty much balanced throughout the quarter and going into or through October? Or have you seen any change during the quarter? Or has anything slowed down any more recently? Or are they still pretty much the same?

That's a good question. We really haven't seen any slowdown, nor do we really expect one. I think the economy has been recovering. When you look at those industrial sales, again, we have seen most of that growth, if not all of that growth, frankly in the Illinois portion of our business in industrial. We have had really robust growth throughout the year.

The year-over-year growth percentages are coming down. We did see a little bit of growth in the last part of last year. So the percentages year-over-year start to decline a little bit. We are not seeing a slowdown or pull back in the economy. We are still -- we are expecting when we get to the end of the year that excluding the impact of Noranda which was positive for Missouri, we are expecting about 10% industrial growth year-over-year when we get to year-end.

Okay. Thank you.

(Operator Instructions) Our next question comes from Steven Gambuzza with Longbow Capital Partners. Please proceed with your question.

Good morning. I just had a follow-up question on the goodwill charge which I think was $552 million. I saw that the goodwill balance came down by about 400 -- it looks like just a little bit over $420 million. You mentioned a $68 million impairment of emission allowances. So that would be $486 million with the difference of about $70 million versus the amount of the impairment. Is that the amount that the plant, the PP&E of merchant gen was written down?

Yes, you are pretty close. The actual gross charge was $589 million which after tax was $522 million. Of that, goodwill was $420 million. Emission allowances were $68 million, and the plant impairments were right around $100 million. It was $101 million.

Okay. I noticed that in your 10-K when you describe the impairment tests that you performed, you used the treasury strip as the discount rate and the impairment analysis. Is that still -- was that -- did you change anything in terms of the assumptions you used to calculate the impairment this time go around versus last time when you performed the impairment test?

I wouldn't say that the methodology changed. I think when we filed the Q what you see there -- I think the discount rate we used overall was around 8%.

Great. Thank you very much.

Our next question comes from Greg Reiss with Catapult Capital Management. Please proceed with your question.

Hello. Just had a quick question on the weather benefit. The $0.10, that was versus the prior quarter -- ?

Would you mind, we can't hear you at all?

Sorry. Can you hear me now?

Yes.

The $0.10, that was a year-over-year weather benefit? And if so, what was the normalized benefit associated with weather?

The $0.10 was actually the normalized benefit. The year-over-year benefit was about $0.27.

Okay. Thanks a lot.

Last year as you may recall, we had a pretty mild summertime.

Got it. Makes sense. Thanks.

Our next question from David Katz with Bank of America Merrill Lynch. Please proceed with your question.

Good morning. I had a question. Looking back at your Q2 call, I believe when you raised guidance then you said half of the guidance range was due to cost savings at your regulated -- I think you said the regulated [things] -- correct me if I'm wrong. I just want to know how much, if any, of the guidance raised in this quarter has to do with cost savings?

David, it's a good question. I think that when you look at -- what we projected at that time in terms of cost savings, we are still on track to achieve. We really haven't pulled back on those initiatives at all. We saw about a $0.10 positive impact from weather in the third quarter. Obviously, we were able to raise our guidance which we were happy with. One of the things you will see in the slides -- I think it is on the bottom of slide ten. We are experiencing a little bit of a higher expected effective tax rate than we expected at the end of the second quarter. That's really very much a function of two things. One, the higher earnings. As your earnings go up your effective tax rate goes up a little bit because of the effect of the permanent items. The other thing you see there, as we have -- as I've said before -- taken advantage of opportunities to reduce our cash taxes. Most recently with the President signing of the law that allows for additional bonus depreciation. We are certainly taking advantage of that. That's a timing item which on a present value basis is going to help us because of the cash that it provides. But it actually wipes out a permanent deduction, manufacturing deduction, which also raises the effective tax rate. In terms of cost savings, we are laser-focused on that and continue to be locked in. But our effective tax rate has come up a little bit from earlier expectations.

Okay, great. Thank you.

Our next question is from Michael Lapides with Goldman Sachs. Please proceed with your question.

Hello. Bigger picture question. Both combined with the regulated and non-regulated side. Are you seeing any change, directions, slow down, increase in rail transportation contracting versus what you saw a year and two years ago?

I don't know that I have got the knowledge to answer that one, Michael. I think we probably have to look into it and talk to some of our specialists that work in that area. Nothing has really been brought to my attention in the course of our normal business dialogue.

I was just curious with volumes down a little bit whether utilities have gained back some of the -- a little bit some of the pricing power at all? Or if that hasn't trickled through?

I don't know that I agree with that, Michael. It may or may not be true. I think one of the things we do like to point out is that we feel like the transportation contracts that we have for our merchant business are really at market. They have negotiated in recent periods. If there is any opportunity for pricing improvements, we would certainly be able to participate in that as our contracts roll off. But we think they are about at market right now.

Got it. In looking on the regulated side. Union Electric at the rate case filing and some of the items around the Sioux scrubber. Any concerns just that they will be pushed back given the original estimate from 2005 versus the final cost numbers coming in a couple -- around $600 million?

Hello, Michael. This is Warner. With regard to the Sioux scrubber project. Certainly, whenever you have a major addition in any rate case, that is going to have a thorough review. We certainly expect that in the context of this case. As you look at the various estimates that have occurred for the Sioux scrubber, we think, frankly, we have given good estimates. And any changes to the overall scope of the project have been driven by good learnings from other projects -- scrubber projects that we have increased the scope. As well as, certainly, changes in the capital markets which has certainly affected the overall project cost. Overall, we expect a thorough review. But we look forward to having that discussion as part of the overall rate case process.

Got it. And finally, the rate case time. Are you still expecting staff testimony later this fall? Or has that changed at all?

If you are speaking about the Missouri case, we would expect the first direct testimony probably some time after the first of the year. The final schedule has not been determined by the Commission. We would expect that in November. We would expect direct testimony probably some time in the February time period with hearings probably in the April time period. With as Marty said during the call, or perhaps it was Tom, that we do have to have a final decision by August then.

Thanks. I will see you next week.

Our next question is a follow-up question from Julian Endimullen Smith with UBS. Please proceed with your question.

Thanks again for the follow-up here. Just wanted to ask a second question here with regard to the sustainability of the O&M you are seeing thus far. Clearly, great success on O&M reductions year-to-date. Where is that trending into the back half of the year? And to what extent is that sustainable into 2011? I suppose, specifically looking at the merchant gen segment, would that directionally be up, flat, or down potentially next year? Or up? Or whatever you can say.

I think, obviously, we haven't provided guidance for next year. And as we look to next year, we are certainly, in terms of things that we have reduced spending for this year, in the merchant business and otherwise. We are looking to maintain that tight cost control and maintain those reductions. One of the things we have pointed to is we have the re-hearing process in Illinois. To the extend that we have additional revenues that are produced as a result of that, we are certainly going to put some of the spending back in that we had reduced early year this year. That is something we have talked about doing.

Otherwise, I think some of the spending that you will have from year to year and quarter to quarter will be driven by plant outages. As we look at the fourth quarter, again, the electric, for example, we do have the Sioux scrubber tie-in. And so as a result, you would expect to see a little bit higher O&M around an outage like that. Our O&M spending next year will certainly be influenced by that type of thing as well. I would mention next year we do have in Missouri another Callaway outage. We had a Callaway outage this year. And as you think about things, they are on an eighteen-month cycle as you probably know. But we do have another Callaway outage next year.

Anything you can say with regard to the merchant general side of the business? Is about a $300 million run rate a good one to assume going forward?

I don't know that I want to give that right now. Again, we are not getting into guidance for next year. You have got the right amount for this year, and we are going to stay very focused on cost control in that business. And obviously, it is a significant focus of ours to keep tight control on costs, both operating costs as well as capital investments. Again, year to year, it is going to be driven somewhat by outages that we have.

Great. If you don't mind my asking just another question here. Looking at the rehearing process, is this a matter of timing for filing another rate case next year? Or is there really a question whether you will file another rate case depending on the outlook -- or outcome of the rehearing process?

I think as it relates to the rehearing, we do want to take a look at the results of the rehearing and see how that plays out. It will certainly factor into our thoughts and decisions in terms of a rate cases going forward. As it relates to Illinois, we said for a while that we would expect to file about every 18 months in Illinois. We are coming up on that kind of a time frame. As you look ahead to next year, I think it would be a fair expectation that in the early part of the year we would be looking to file another case.

Thanks for the clarification.

Our next question is a follow-up from Steven Gambuzza with Longbow Capital Partners. Please proceed with your question.

Thanks. I just had a question on the cash flow change. I think you have had two fairly substantial increases in your cash flow guidance driven in part by tax planning. I think there were some very substantial changes to last year's cash flow guidance from tax planning. I was just curious if you could tell us prospectively as we look into 2011 and beyond, whether tax planning can continue to be a positive cash -- significant positive cash flow driver.

That's a good question. We have taken advantage this year of some opportunities to improve the cash tax flow. One of the interesting things is as a result of the amount of that that we have done in -- I mentioned the bonus depreciation deduction. Some of that benefit in terms of cash flow benefit will actually carry forward into next year. I won't comment on the amount, but some of the benefits of bonus depreciation -- while we are taking the deduction this year it is impacting our effective tax rate this year. Some of the cash tax benefit of that bonus depreciation deduction this year will actually help next year.

Okay. Aside from bonus depreciation, are there -- I think that you mentioned last quarter that some of the repairs and maintenance deductions were having incremental benefits in 2010. Will that be a positive driver in 2011 as well?

I think that there is some ongoing positive benefit from the change in the way we treat some of those expenditures for tax purposes. There will be some ongoing benefit, but I wouldn't expect another big benefit like the one we had this year for the same items.

Okay. Thank you.

Mr. Fisher, there are no further questions at this time. I would now like to turn the floor back over to you for closing comments.

Thank you for participating in this call. We look forward to seeing many of you at the EEI Financial Conference next week. Let me remind you again that this call is available through November fifth on playback and for one year on our website. Today's press release includes instructions on listening to the playback. You may also call the contacts listed on the release. Financial analysts' inquiries should be directed to me, Doug Fisher. Media should call Susan Gallagher. Our contact numbers are on the news release. Again, we thank you for your interest in Ameren Corporation.

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