阿莫林 (AEE) 2011 Q3 法說會逐字稿

Greetings, and welcome to the Ameren Corporation's third quarter 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 IR for Ameren Corporation. Thank you, Mr. Fisher. You may now begin.

Thank you, and 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 Ameren's management team. Before we begin, let me cover a few administrative details. This call will be available by telephone for 1 week to anyone who wishes to hear it by dialing a playback number. The announcement you received in our news release include instructions for replaying the call by telephone. The call is also being broadcast live on the Internet, and the webcast will be available for 1 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 call. Redistribution of this broadcast is prohibited. To assist with our call this morning, we have posted a presentation on our website to which we will refer during this call.

To access this presentation, please look in the Investors section of our website under Webcast and Presentations and follow the appropriate link. Turning to page 2 of the presentation, I need to inform that comments made during this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those of our 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 statements section in the news release we issued today and the forward-looking statements and risk factors section in our filings with the SEC.

Tom will begin this call with a brief overview of third quarter 2011 earnings and updated 2011 guidance followed by a discussion of recent business and regulatory developments. Marty will follow with a more detailed discussion of third quarter 2011 financial results and guidance, as well as updates on regulatory and other financial matters. We will then open the call for questions. Here's Tom, who will start on page 3 of the presentation.

Thanks, Doug. Good morning, and thank you for joining us. Today we announced strong third quarter 2011 core earnings of $1.57 per share compared to third quarter 2010 core earnings of $1.40 per share. The increase in third quarter 2011 core earnings compared to third quarter 2010 core earnings, reflected Illinois and Missouri electric rate increases, and lower non-fuel operations and maintenance expenses as a result of continued cost discipline. The improvement in earnings was also due to lower interest expense, driven by debt reduction, and also weather that was slightly warmer than that of the year-ago quarter. These positive factors were partially offset by reduced margins in the merchant generation segment due to lower realized power prices and higher fuel and transportation-related expenses. While temperatures in the third quarter of 2011 were not significantly different from those experienced in the third quarter of 2010, they were much warmer than normal.

Before I move on to a discussion of earnings guidance, I would like to comment on our operating performance during the third quarter of 2011. I am proud to report that our energy centers performed exceptionally well during the summer months. Equivalent availability at our base load energy centers was a strong 94% and the net capacity factor was a strong 84% in the third quarter of 2011. This performance included our Callaway Nuclear Energy Center which operated continuously from its last refueling, which ended in June of 2010 until the beginning of its current refueling in mid-October 2011, a period of 489 days. This was the facility's second longest breaker-to-breaker run since it began operating in 1984.

Turning to page 4, reflecting our strong third quarter earnings, today we are raising our 2011 core earnings guidance range to $2.50 to $2.60 per share, up from our prior range of $2.30 to $2.55 per share. Marty will provide further details regarding our third quarter of 2011 earnings and 2011 guidance later in this call. Moving to page 5, we now expect 2011 positive free cash flow to reach approximately $325 million, an increase of $100 million from the estimate we provided on our second quarter conference call. We have been using our free cash flow to reduce outstanding borrowings. This has included not only the June 2011 maturity of $150 million of Ameren Illinois Company long-term debt, but also a significant amount of short-term debt. In fact, at September 30, 2011, cash and equivalents exceeded short-term debt and we expect this also be the case at year end.

These reductions in debt contributed to a common equity ratio that stood at a solid 53.9% of total capitalization at the end of the third quarter. Reflecting the steps we have taken over the last few years to strengthen our financial performance in position, on October 14, 2011, Ameren's Board of Directors declared a quarterly dividend payment to common shareholders of $0.40 per share, a 3.9% increase over the prior quarterly dividend rate. This new annualized equivalent rate of $1.60 per share is a level that is well covered by earnings and cash flows from our regulated business segments. This new annualized rate represents a 70% payout of 2011 core earnings from our regulated business segments based on the midpoint of our guidance range.

Turning to page 6, in addition to the positive news I have shared with you regarding earnings, cash flows, and dividends, I'm also here to report significant progress on important strategic initiatives. This progress is the result of our focused and sustained efforts to improve the performance of our Company for the mutual benefit of our investors and customers. On several occasions, I have stated that we are committed to seeking and obtaining constructive regulatory frameworks that allow us to recover our costs in a timely fashion and that provide a reasonable opportunity to earn a fair return on our investments. As important, constructive regulatory frameworks provide us with the necessary cash flows to invest in our energy infrastructure so we can meet our customer's expectation and create good-paying jobs in our communities.

I am very pleased that just last week, the Illinois General Assembly approved a new constructive regulatory framework that provides electric delivery utilities in that state with the opportunity to choose performance-based formula rate-making. The legislature enacted into law Senate Bill 1652, the Energy Infrastructure Modernization Act, and approved trailer bill that will amend Senate Bill 1652. Governor Quinn has 60 day to act on the trailer bill; if he does nothing by the end of the 60-day period, the trailer bill becomes law. If he vetoes the trailer bill, it will come back to the House and Senate for further consideration. This legislation is a win for the economy of the state of Illinois, a win for our Illinois electric delivery customers and a win for our Ameren Illinois utility.

Utilities will have the opportunity to benefit from more predictable rate making that will allow them to invest in their businesses, receive timely cash flows from these investments, and have greater confidence that they are able to earn close to their allowed return on such investments. This law is designed to create nearly 2,500 additional good paying jobs throughout the state. And further, the additional investments required of participating utilities should provide customers with improved service, quality, and reliability, as well as long-term savings. The legislation includes a number of customer protections and other benefits, many of which are listed on this page. These protections include regulatory oversight by the Illinois Commerce Commission to ensure that the investments made and costs incurred are prudent.

Page 7 provides highlights of the new regulatory framework. Ameren Illinois plans to withdraw its pending electric delivery rate case and is developing plans for filing for performance-based formula electric delivery rates under Senate Bill 1652. However, our pending gas delivery rate case will continue to move forward. Senate Bill 1652 does not apply to the gas utility business.

Moving to page 8, of course, our commitment to earnings, fair returns of our investment also extends to Missouri. Ameren Missouri expects to make significant progress towards closing the gap between its earned and allowed return on equity in 2012. On October 21, we announced a voluntary retirement offer, as part of Ameren Missouri's efforts to tighten its belt during this challenging economic period. This action should lower overall costs for customers, as well as allowing spending with regulatory outcomes and economic conditions, and improve earned returns at our Missouri utility. The voluntary retirement offer has been made to approximately 715 management and union employees of Ameren Missouri and Ameren Services. Ameren Services provides support services to Ameren and all of its subsidiaries.

Those accepting the offer are expected to retire by year end 2011. While we do not know how many employees will accept this offer, a similar offer in 2009 had an acceptance rate of approximately 30%. In connection with this program, there's one thing I want to be clear about. We will not reduce our work force to a level that will impact our employees' ability to deliver safe and reliability service to our customers.

Looking ahead in Missouri, we'll continue to explore options to reduce regulatory lag to enhance our cash flows and earned returns and thereby, facilitate more timely investments in our energy infrastructure. Facilitating such investments would improve reliability and create jobs to the benefit of all our stakeholders in the entire state of Missouri. In addition to these developments at our regulated utilities, our merchant generation business recently took steps that are expected to further reduce operating costs and capital spending plans. These steps are part of our ongoing efforts to ensure that this business is well positioned to weather the current period of low power prices, and benefit from the expected improvement in such prices.

In early October, our merchant generation business announced that it will cease operating the Meredosia and Hutsonville Energy Centers in Illinois by the end of 2011. These 2 smaller, older energy centers provided approximately 4% of our merchant generation segment's total generation over the last 2 years. The closings are primarily the result of complying with the Cross-State Air Pollution Rule, or CSAPR, issued by the US Environmental Protection Agency in July of 2011. CSAPR tightened sulfur dioxide and nitrogen oxide emission levels -- emission limits to the point that continued operation of these facilities is not economic. Closure of Meredosia and Hutsonville will reduce our merchant generation fleet emission levels, although we will retain the emissions credits for SO2 and NOx associated with these plans through 2015.

As a result, we no longer plan to use dry sorbent injection at our Edwards plant to comply with the SO2 limitations of the Illinois Multi-Pollutant Standard and CSAPR. Removing dry sorbent injection from our compliance strategy at Edwards eliminated one of the reasons for planned bag houses at that energy center. The other reason for bag houses was, of course, for a particular control in anticipation of the HAP MACT rules. However, as a result of further testing, we now expect that upgrade in the existing electrostatic precipitator's at Edwards will allow us to achieve the anticipated particular compliance requirements without the need for bag houses at a reduced net capital cost. As a result, we have further reduced our expected 2011 through 2015 merchant generation segment capital expenditures by approximately $70 million. These reductions are in addition to the approximately $200 million of lower planned merchant generation capital expenditures for the 2011 to 2015 period, which we announced on the second quarter conference call.

In summary, we believe that the following recent developments, approval of a new constructive regulatory framework for Illinois electric delivery businesses, receipt of new electric rates in Missouri this past July, disciplined cost reductions at our Missouri utility to align our spending with business conditions, reduced environmental capital spending plans for our merchant generation business, along with plans that we have discussed in detail in prior presentations, or significantly growing our investments in Federal Energy Regulatory Commission regulated electric transmission projects, together place Ameren in an improved position for future success. Finally, we believe that to be successful, we must, and we will remain dedicated to operating in a safe, reliable, and environmentally responsible manner. Now, I'll turn the call over to Marty.

Thanks, Tom. Turning to page 9 of the presentation, today we reported third quarter 2011 earnings in accordance with Generally Accepted Accounting Principles, or GAAP, of $1.18 per share compared to a third quarter 2010 GAAP loss of $0.70 per share. Third quarter 2011 core earnings improved to $1.57 per share compared with third quarter 2010 core earnings of $1.40 per share. The following items were excluded from third quarter 2011 and 2010 core earnings, a charge for the Missouri Public Service Commission's July 2011 disallowance of costs of enhancements related to the rebuilding of the Taum Sauk Energy Center, which reduced third quarter 2011 earnings by $0.23 per share. This disallowance was appealed to the courts.

Impairment and other charges related to Ameren's merchant generation segment reduced earnings by $0.09 per share in the third quarter of 2011. Goodwill, impairment and other charges also related to the merchant segment, reduced earnings by $2.19 per share in the third quarter of 2010. The 2011 charges were related to the decision to cease operations at the Meredosia and Hutsonville Energy Centers by the end of 2011 and finally, the net effect of unrealized marked to market activity primarily related to non-qualified power and fuel-related hedges reduced third quarter 2011 earnings by $0.07 per share, and increased third quarter 2010 earnings by $0.09 per share.

Moving to page 10, here we highlight key drivers of the variance between core earnings per share for the third quarters of 2011 and 2010. Key factors driving the earnings improvement included rate changes net of certain related expenses. This factor increased third quarter 2011 earnings by $0.10 per share compared to the third quarter of 2010, reflecting an electric rate increase in Illinois effective in November of 2010 and an electric rate increase in Missouri effective in late July 2011. A second key driver was lower core non-fuel operations and maintenance expenses, which increased third quarter 2011 earnings by $0.09 per share compared to the third quarter of 2010. The lower O&M reflect disciplined cost management across all of our business segments. Lower interest expense was also a factor behind the improvement in third quarter 2011 earnings compared to the third quarter of 2010. This increased earnings by $0.03 per share.

Weather was significantly warmer than normal in the third quarter of 2011, and slightly warmer than that of the year-ago quarter. This boosted earnings by an estimated $0.02 per share compared to the third quarter of 2010, and by an estimated $0.14 per share compared to normal. The primary factor negatively affecting the comparison between third quarter 2011 earnings and third quarter 2010 earnings was lower margins in our merchant generation segment, which reduced earnings by $0.05 per share. These lower margins reflected lower realized power prices and higher fuel and transportation-related expenses. While margins were down, merchant generation energy center operations were strong. The equivalent availability was 92%, and the net capacity factor was 80% at this segment's base load energy centers in the third quarter of 2011.

As Tom mentioned, we have raised our 2011 core earnings guidance range to $2.50 to $2.60 per share, up from our prior range of $2.30 to $2.55 per share. This increase in guidance reflects strong third quarter core earnings driven by warmer than normal weather, and continued disciplined cost management. The core earnings guidance for our combined Ameren Missouri and Ameren Illinois segments is raised to a range of $2.25 to $2.30, up from our prior range of $2.10 to $2.25. The core guidance range for our merchant generation segment was narrowed to a range of $0.25 per share to $0.30 per share in the upper half of our prior range. Before I leave our discussion of 2011 earnings guidance, I would like to remind you that fourth quarter earnings results will be impacted by costs related to the scheduled 2011 Callaway Nuclear Energy Center refueling and maintenance outage, which is currently in progress. In addition, I would like to discuss appending regulatory matter in Missouri that could impact fourth quarter GAAP and core earnings.

In Missouri, the staff of the Public Service Commission is required to initiate a prudence review of costs subject to the fuel adjustment clause, at least every 18 months. The staff recently initiated its second such review since implementation of Ameren Missouri's fuel adjustment clause. This second review covers the period from October 1, 2009 through May 31, 2011. In its first review, the staff of the Missouri Public Service Commission recommended and the PSC ruled in April of 2011 by a 3-to-2 vote, that Ameren Missouri flowed through the FAC and credit the customers all margins associated with certain long-term partial requirement sales that were made by Ameren Missouri due to the loss of load from Noranda Aluminum's Missouri smelter plant.

You'll recall this loss of load was caused by a severe ice storm in January of 2009. As a result of this order, we recorded a second quarter 2011 pre-tax charge of $18 million to core earnings, or about $0.05 per share. We continue to disagree with the PSC's order and its classification of these sales and believe that the terms of the FAC tariff did not provide for margins from these sales to be flowed through the FAC. Therefore, we have appealed this decision to the courts.

As we have previously disclosed, Ameren Missouri recognized additional margins associated with the same long-term partial requirement sales contracts subsequent to September 30, 2009. The recently initiated second FAC prudence review covers this subsequent period. On October 28, the staff of the Missouri Public Service Commission recommended that the PSC require these additional margins, which it calculates to be $26 million, also be flowed through the FAC, and therefore credited to customers. The staffs report that only with this issue and it plans to file a report on the balance of its FAC review by the end of February 2012. The PSC has not indicated whether it will rule on the treatment of this $26 million before it receives the staff's report from the balance of its review.

If the PSC rules that this $26 million should be flowed through the FAC, and the courts have not overturned the PSC's prior FAC prudence review decision, we would expect to take a charge to core earnings of approximately $0.07 per share in the period when such a decision is issued. Such a potential charge has not been assumed in our 2011 earnings guidance. As I close our discussion of 2011 earnings guidance, I need to remind you that our guidance assumes normal weather for the fourth quarter of this year. Further, any charge that may result from the recently announced voluntary retirement offer to certain employees, as well as any net unrealized marked to market gains or losses, will impact GAAP earnings, but are excluded from GAAP earnings guidance, because the Company is unable to reasonably estimate the impact of any such gains or losses for the full year. Core earnings and guidance exclude any charge resulting from the voluntary retirement offer and any net unrealized marked to market gains or losses. Further, our earnings guidance for 2011 is subject to the risks and uncertainties outlined or referred to in today's press release, including the forward-looking statements section of that release.

Turning to page 11, I would now like to provide updated 2011 projected cash flow information. We now expect to achieve free cash flow of approximately $325 million, up from our prior guidance of approximately $225 million. The improved cash flow outlook reflects increased 2011 earnings expectations, lower capital expenditures, and updated working capital expectations. Turning now to page 12, and a discussion of our pending delivery rate cases in Illinois, in October, the parties filed initial and reply briefs in these cases. Our rate increase request continued to total $89 million annually, with $39 million of this related to electric delivery service, and $50 million related to gas delivery service. We plan to withdraw our electric delivery case as permitted by the recently passed trailer bill, and move to the newly authorized performance-based formula rate-making. However, the gas rate case will still proceed to completion.

On this page and the next, we have provided a breakdown of the electric and gas service numbers included in our and other parties' positions. The ICC staff is now recommending a combined revenue increase of $33 million, with $29.5 million of this related to the gas rate case. By far, the most material difference between our position and that of the staff is related to return on equity. On page 13, we outlined key points of the Attorney General's and Citizen Utility Board's rebuttal positions, as well as those of the Illinois industrial energy customers. The administrative law judges are expected to issue their proposed order on November 15 of this year, and the deadline for an Illinois Commerce Commission Decision is January 12 of 2012, with new rates expected to be effective shortly thereafter.

Moving now to page 14 and our merchant generation business, I would like to provide additional details on the financial impact of shutting down Meredosia and Hutsonville by year-end 2011. Combined, these energy centers are expected to be about breakeven in 2011 from a cash flow perspective. Going forward, we expect the closure of these facilities in the resulting 2011 impairments will improve prospective earnings by about $0.01 to $0.02 per share annually. Tom already mentioned the ceasing operations at these 2 energy centers enable us, in part, to reduce our planned merchant segment capital expenditures, due primarily to the elimination of the previously planned bag houses at Edwards. On this page, we provide you with our revised lower merchant generation planned capital expenditures for 2011 through 2015 by year.

On page 15, we provide an update on our forward power sales and hedge data as of September 30, 2011. We continue to expect our merchant generation business to generate approximately 29.5 million-megawatt hours in 2011, with approximately 27.5 million megawatt-hours of this coming from our 5 largest coal-fired energy centers ; Coffeen, Duck Creek, Edwards, Joppa, and Newton facilities. These 29.5 million-megawatt hours do include 100% of the expected generation of the Electric Energy Inc., or Joppa Energy Center, a facility in which Ameren owns an 80% interest. As you can see, our projected 2011 power sales are very close to fully hedged. For 2012, we have now hedged approximately 21.5 million-megawatt hours at an average price of $46 per megawatt hour. Further, for 2013, we have hedged approximately 11 million-megawatt hours, an average price of $41 per megawatt hour, our capacity sales are approximately 63% hedged for 2012, and approximately 42% hedged in 2013.

Turning to the last page of our formal presentation, page 16, here we provide an update of our merchant generation segment's fuel and transportation-related hedges. For 2011, we have hedged essentially all of our expected generation. For 2012, we have now hedged approximately 25 million-megawatt hours at about $24 per megawatt hour. For 2013, we have now hedged approximately 9 million-megawatt hours, at about $26.50 per megawatt hour. This hedging information then completes our prepared remarks and we will now be happy to take your questions.

(Operator Instructions) Scott Senchak, Decade Capital Management.

Hi, thank you. Just a question on slide 15, your 2013 hedge price, how should we think about that? Is that a full requirements hedge? Is it block power, or --?

Sure, Scott. This is Marty. So on slide 15, 2013, you're looking at the $41 per megawatt hour, I guess, for those 11 million or so megawatt hours that we sold. The way you ought to think about '13 in terms of what's in there is, an around-the-clock product usually has about 47% to 48% on peak. Our generation profile is typically more about 52% on peak, and basically what you see in there is megawatt hours that have been sold, more like our generation profile, more like that 52% on peak, 48% off peak. And that does include any hedges or forward sales we've made. So whether they be financial products or physical products, most of that, I would say in that period of time, does represent physical contracts that we have with counter parties. It would include then some energy, some capacity and some other services.

Got you, thanks. Then just turning to Illinois, with this new Illinois legislation, how should we think about the ROEs there now at this legislation? Is the -- and I know it's matched to the 30-year treasury yield. In 2012, will your ROE be within the band of the average treasury yield in '12, or is it off of the treasury yield in '11?

Yes, Scott, this is Marty again. Good question. It's my understanding that, that would be based on the 2012 treasuries and a spread over the average 2012 treasuries.

Got you, got you. And then also, I'm not sure if I missed this. The impact of weather versus normal for the year at Ameren Illinois and Ameren Missouri this year?

I don't know that I gave it out necessarily by legal entity, but basically, the effective temperature for this year. In the third quarter, we talked about it being about $0.02 positive versus last year. We estimate that it was about $0.14 positive versus normal. And then for the full year, on a year-to-date basis, it was probably a positive $0.21 versus normal conditions year-to-date. Actually, down about $0.05 versus last year based on strong weather we had primarily in the second quarter of last year.

Okay, great. Thank you very much.

Thank you. Michael Lapides from Goldman Sachs.

Hi, guys. Congrats on a great quarter and a good update. Real quick, two questions. One, can you walk us through, of the rate increases that you received in both Missouri and Illinois, how much you've already taken and what's left to be taken in the coming quarters?

Yes, I don't know, when you say what's left to be taken or to be taken, I can tell you this. When you look at slide 10, we talked about it on the quarter that, the impact of rate changes was about $0.10, and that broke down in the quarter, Michael, about $0.08 for Missouri and about $0.02 for Illinois. So as you know, the Missouri rate case didn't go into effect until very last part of July. So maybe that information's helpful to you.

Okay, and do you -- just quickie on that one, do you have the year-to-date for that as well? Meaning what the electric and gas rate changes mean on a year-to-date basis?

We did. Maybe somebody can dig that out and provide that information. I don't have it here in front of me.

That sounds fine. One last one. Non-fuel O&M, you guys have done a great job in managing O&M, and the $0.09 benefit in this quarter, that does not reflect the impact of the voluntary severance plan you just announced. This is before that goes into effect as well?

Yes, I guess you're asking in terms of, you know -- I think you're asking the overall benefit of voluntary plan, when we recognize that, Michael, or --?

No, I'm trying to think about the -- did you -- are you already receiving some of the benefits of the cost reduction related to that voluntary severance plan, or is that in addition to the $0.09 of O&M savings that you've already [seen] this quarter?

Yes, I think we're on the same page. No, the voluntary severance offer/retirement offer that's been made is really outstanding. So employees have until around the end of the year to decide whether they are going to accept that or not. Our historical experience with this program has gotten to a 30% type opt-in rate, hard to tell whether you'll get that or not. Let's say a 30% to 40% type opt-in rate might be expected but the benefits of that in terms of cost savings would actually be realized next year. We're not realizing any of that right now because none of those employees have yet retired.

Got it, okay. Thanks, guys. Once again, congrats on a great quarter.

Thanks, Michael.

Thank you. Erica Piserchia from Wunderlich Securities.

Hi, just following up a little bit on the operating cost savings here, just more broadly, when you think about the business as far as the cost structure, I mean, is your cost structure now optimally configured? Or are there more opportunities for this or do you feel like where you are now is where you'd like the business to be from that perspective?

Yes, Erica, thanks for the question. I think that we're certainly committed to doing, as you know, is improving our earned returns. And so we're going to stay focused on disciplined cost control, disciplined investment as we seek to improve those earned returns. You've asked the question on the past couple of calls about sales levels. And as you know, the economy has, in part, caused our sales levels to be fairly sluggish. In fact, as you know, we've seen some declines in residential and commercial sales this year when you strip out the impacts of weather.

And so, as a result of that, we've certainly been looking to tighten our belt, keep costs under control, and importantly, that also helps to help contain costs for our customers as we recently have been going in for rate cases. And of course, the benefits of those cost savings eventually accrue to the customer in terms of lower rate increases. So that's what we're doing. I would say looking forward, given Senate Bill 1652, certainly in Illinois, we're going to be looking to add employees as we look to make investments in that state, to improve service reliability, service quality, and roll out some of the smart grid plans that we laid out, that are laid out in the legislation. So just those are some of the thoughts, I guess, on how we're trying to manage the business.

Okay. And just, I guess a follow-up to that, does that -- does where you stand now, given some of these optimization efforts that you've put through on the cost side, does that change your view as far as just what -- where you think you can be? I mean, I think in the past you talked about, obviously, reducing that regulatory lag, and obviously on the Illinois side, we have this legislation. But I'm thinking on the Missouri side as well. Does that increase your confidence in your ability going forward, or was this optimization something that you had contemplated when you initially started to -- maybe not initially, but earlier this year, when you were talking about that. Did you have this more optimal cost structure in mind, I guess?

Well, good questions, Erica. I think with respect to -- we'll start with Illinois. I think one of the benefits of Senate Bill 1652, as we talked about with the formulaic rates, is it does give you more confidence to be able to make investments, to be able to add to your work force and feel confident that you're going to be able to earn something close to your allowed return. So certainly that does give us greater confidence. And then in Missouri, we talked about last quarter, making significant progress in terms of closing the gap between our weather-normalized earned returns this year, and our allowed returns, as we look to go from 2011 into 2012. And what we're doing is executing on plans that we believe will allow us to achieve that goal.

Thanks.

Paul Patterson from Glenrock Associates.

All right. Let's just go over the Illinois thing. I'm afraid I might have been distracted slightly when you were going over it with a few other people. What was your ROE? Given the guidance that you have here, we're in the fourth quarter, what should we think about as your ROE that you guys are going to earn roughly speaking in 2011 in Illinois on the electric side?

Yes, we really haven't broken that down, Paul. I can tell you that overall, based on the guidance we've given from the regulated segments, the implied ROE there is about 9%, 9.2%, but that, of course that includes the impacts of weather. If you strip that out, the weather, you're probably talking about an implied ROE of around an 8.2%.

Okay, well that helps though, so we're at 9.2% right now. Now you're going to be opting for this legislation and withdrawing your rate case, et cetera. So that means that -- I guess what it sounds like to me though, is I guess we should assume that there's not going to be -- you don't expect much of a lag, I guess, beginning in 2012, the ROE and given the fact that it's now lower the -- with the mechanism and stuff, we really shouldn't expect all that much out of, in terms of growth at least in 2012. Does that make sense?

I don't know if that exactly makes sense or not. I mean, I think the question that came up earlier is, ultimately I think what we'll earn in Illinois in 2012 will be somewhat, well, not somewhat, but will be -- yes, somewhat in part dictated by what the treasuries are in 2012. So the question came earlier ultimately when you go through the formulaic rate-making in 2012, what is the formulaic rate tied to? And it's going to be based on an average of treasuries, 2012 plus the [adder].

Yes, but just we don't know what they are going to be, obviously. But I mean, I'm just looking at where they are now, I guess, is what I'm saying. Looking at -- just assuming that like interest rate stay flat, which obviously is a little bit -- is obviously quite a leap, but just assuming that though, we wouldn't necessarily expect -- depending on what interest rates do, you wouldn't be making that much more if interest rates stayed flat. And regardless of weather or whatever, it would seem to me that you guys would pretty much be in the same category, or am I missing something?

Well, again, I think the thing is that when you look at it, I guess we haven't said exactly what our earned ROE is going to be in Illinois this year. But I guess what I'm trying to say, is ultimately what it is next year, you're right. We don't know what treasuries it will be. It will be based on whatever the average of the 30-year treasuries are next year plus the adder. If you took a 12-month history of treasuries today, you would get a different answer than where the treasuries are today at this point in time. Paul, the complete answer to your question, when you look at Ameren Illinois, I would also not forget that the gas rates will be reset based on the forecasted [test year] we filed. And so that will have an impact on the earned ROE. And it's also important to remember that we have a decent size transmission rate base in Ameren Illinois as well.

Okay, no, I was just trying to isolate the electric, I'm sorry. I was just trying to get the -- I don't want to belabor it either. I think I've got a pretty good sense here. The other thing I wanted to ask you about is the write-off. What Was behind that, the merchant generation write-down?

Sure. The merchant generation write-down, really, as you know, had to do with the closure of Meredosia and Hudsonville. When we had our last quarterly call, we talked about the fact that we felt like we were getting pretty good clarity, get our arms around our environmental capital expenditures, and what was necessary to comply with the various rules that were out there. And the one unknown really was in how we were going to comply with respect to the tightened NOx emission standards. And so, as we looked at specifically that, the tightened NOx emission standards, ultimately, it was decided that we were forced to really shut down Meredosia and Hudsonville to be able to comply with those CSAPR rules, the NOx component of CSAPR rules. So that was the big driver there.

But then, Paul, as we talked about on the call, what that allowed us to do is, once that decision's made, you look at your overall SO2 and NOx allowances, given that those plants are no longer in the mix, and that allows you to re-look at your overall compliance strategy for SO2 for your fleet. That led us to the conclusion that we could actually reduce our capital expenditures or -- excuse me, eliminate the use of DSI, I would say, at Edwards, and then that triggered, basically, our ability to re-look at the baghouse's and the need for those versus upgrades to our precipitator's. So I would say the CSAPR rules were certainly the cause of the decision to shut down Meredosia and Hudsonville, but that did lead to a chain of decisions that led to reduced capital costs at our Edwards facility.

Okay, and then with the [PGN] portability of the capacity, the seams that you guys were -- are obviously looking at and given the big disparity in capacity pricing, any more thought -- I know I asked this last quarter. And I know it's a little early, but just wondering if you guys have any more thoughts about what might be happening there?

No, I don't think there's any meaningful update. I mean, we've certainly filed our positions with FERC that are in line with the positions that we articulated on our second quarter call. So I wouldn't say at this point there's any meaningful update to report.

Okay, great. Thanks a lot.

Thank you. David Paz from Bank of America Merrill Lynch.

My question on the dividend, can you give us a flavor of what your target payout ratio on regulated earnings will be going forward? Clearly, you're comfortable with the current 70% based on the midpoint of 2011 guidance, but I guess just what that range could be. Is that 70% on the high end, the low end? Anything you can say there?

This is Tom Voss. I think, generally, that we would be a little bit on the high end of the regulated earnings, but our goal is just try and get somewhere between 55% and 70% of the regulated earnings as a payout range. The important thing about this particular time was that we thought it was good to reaffirm that the dividend is solid, that it's not at risk. We think it's in good shape. We've had very positive cash flows and we thought it was a good time to raise dividend.

Okay, and those regulated earnings includes transmission earnings as well, right?

Yes, David, it includes all of our regulated earnings, Missouri, Illinois in transmission.

And as we look forward, any earnings from Ameren Transmission Company?

Yes, correct.

Okay, and then on Illinois, can you actually, 2 things, on what is the baseline electric distribution spend that you're looking per the law, I believe it was an average of 2008, 2010? I just -- we're just not clear on whether that includes transmission, excludes transmission. Just what is that baseline to which you can add the $625 million over a 10-year period?

Yes, David, I do believe that it does include the transmission. Doug, do you have the baseline number, or no?

The baseline number for electric delivery only is --

This is Scott Cisel. The baseline on the electric side is $275 million.

Okay. So that doesn't include transmission, then?

That's right. I -- you're correct about that, David. I missed it.

That's fine. That's fine. So then on your 2011 CapEx for Ameren Illinois, I believe you don't provide any further breakout, but on your 2011 plan CapEx, what percentage is fine? What is the breakout for electric [distribution] -- or sorry, electric delivery, transmission, and gas?

Boy, David, I don't have that here in front of me in terms of that breakout. Are you trying to get a sense for how much of that $625 [million] is going to be incremental or invested?

Yes, yes.

Yes, I mean, look, we'll end up filing with the ICC. We've got some work to do to put together our exact spending plans. But I think it's safe to assume that out of that $625 [million] over the next five years, you would see about one-half of that invested over the next five years I think is a safe assumption. And when I say invested, I think that, that would be incremental to what has been disclosed in terms of our capital spending plans.

Okay, all right. And are there any similar efforts, whether it's legislative, or on the regulatory front in Missouri? And maybe not a bill similar to this, but any other efforts to reduce regulatory lag there in Missouri, such as reducing the time between filing a rate case and an actual rate case decision?

David, this is Warner Baxter. How are you doing? Good, how are you, Warner? I'm terrific, thanks. As Tom stated a little bit earlier, in Missouri, we're going to continue to explore several options for it to reduce regulatory lag. And certainly, one of those options could be a legislative route. And potentially, one like SB 1652, which I believe in Missouri would yield many of the same benefits as they really are in Illinois. Now (inaudible) as Tom said, reducing regulatory lag, it enhance our cash flows and returns, but most importantly, facilitate greater investments in our energy infrastructure and improve reliability and create good paying jobs and ultimately benefit our customers in the state. But I think, now that's a legislative -- I think it's important that we also consider other alternatives to reduce lag, including seeking ways to reduce lag potentially through the regulatory process.

So we'll look at both of those. In the interim, as Marty said what we're doing, we're taking steps to better align our spending to be consistent with the regulatory outcomes and economic conditions in order to reduce lag and make significant progress towards closing that gap. So we are looking at both a regulatory approach, a legislative approach, and really, an operational approach. We're very focused on it.

Great. Thank you so much, guys.

Thank you. Julien Dumoulin-Smith from UBS.

First question on the timing of the implementation with the comment, Bill. Wanted to get a sense there, I mean, what months should we assume now these, quote-unquote, new rates go into effect?

Yes, new rates, you wouldn't expect new rates to go into effect until sometime in the second half of 2012.

All right, great. And then secondly, I understand there's an energy procurement element of the bill. Just wanted to get your sense as to your participation and what you see that product coming out as initially?

Yes, I don't know about, quote-unquote, product, but as we look ahead, obviously one of the things we have to do with respect to that business is manage our overall plans, whether it be for capital expenditures or procurement of power, to be mindful of the 2.5% cap on increases in rates. We feel pretty good about our ability to achieve that through the 2014 mark that's in the legislation, based upon a lot of the hedges that we already have in place, power procurement hedges for Ameren Illinois. So as we move forward, we're in pretty good shape with those, but we'll be very mindful of that 2.5% cap as we put together our plans for the future.

Right. Also, I've seen some comments recently talking about energy efficiency and reductions and your planned spending on that front in Missouri. Just wanted to get a sense, why pull back on that, what load reduction was it leading to? And then what are the financial ramifications, if you will?

Julien, this is Warner Baxter. We learned from the outset -- one thing I want to make clear. We have supported and continued to support statewide efforts to increase energy efficiency for our customers. But we also stated that we need to make progress on the regulatory framework, not only to cover our energy efficiency program costs, but really, the fixed costs that we lose due to these power sales. So in our last rate case, we sought to put in a framework that would have addressed that. The Commission reviewed that and rejected our proposal.

And so while we really were left with no reasonable choice but to reduce those level of expenditures in the interim until we really get a framework that's in place. And we continue to explore that and we do expect to propose yet another framework that will address some of our concerns to really continue to move forward with energy efficiency in Missouri. But today, we are still spending millions of dollars on energy efficiency in Missouri, both when you combine both the electric and gas side. And we're going to continue to stay focused on trying to find a solution to this issue.

Great. And then lastly, more on the merchant side. With regards to retail switching in your service territory in Illinois, it seems like that started to take off somewhat. Do you anticipate broadening your retail ambitions in a sense that opportunities in front of you?

Julien, I would say that, to remind everybody, we've had a marketing effort over time associated with our generation. It's not a new thing. We've also had a retail marketing effort as well. I think you're right. We're seeing some increases in switching within the state and we're staying active in the state. I think if you look back at some of our sales over time, like if you look at this year, I would say about 45% of the sales we're making this year from our generation are going to physical, physical delivery, physical end use. So as far as our merchant business, that's something we're going to continue to focus on and we're going to target something greater than 50% of our generation to go to fiscal delivery customers as we move forward.

Great, thank you for the time.

Thank you. Greg Gordon from ISI Group.

Hi, Greg, good morning. How have you been?

Good, good, looking forward to seeing you in paradise. (laughter)

Thanks.

Just some -- as high level question, as I look at how you guys have positioned the Company over the last 12 months, I mean, you've addressed the cost side in Missouri and you're -- through legislation, you'll hopefully be addressing the revenue side in Illinois on the utilities. And so you've gotten some visibility on an earnings trajectory that gets you to your authorized return and that's the signal with the dividends, which is great. And on the power generation side, you can control the denominator. You can't really do -- you have limited control over the numerator, but you're doing your darndest to reduce costs, so you don't have to invest and add leverage, right? So I mean, what's the current leverage that's allocated to the Genco? Is it about $1.5 billion? Is that right if I take a look at the parent debt and the Genco debt?

We talked about -- we broke down, I think, last quarter similar debt levels by segment and I think it was about $1.5 billion, $1.6 billion to the merchant segment overall. But you know, I would say as you look, Greg, at the balance sheet at the end of this quarter when we put out our Q, you look at it at year end, we have been generating, as we mentioned, positive free cash flows overall for the Company, projected to be $325 million this year. Of that free cash flow nearly $200 million of that coming from the merchant business, about $150 million from Genco itself. So that segment's been producing positive free cash flow and we've been using that to pay down parent company borrowings. So I guess my point of that is --

Well, I guess that, that's the rub, if you can -- if people got comfortable that this was a $200 million cash flow business, then it's more than covering the debt, and there's equity value. If they are not comfortable that it's a $200 million cash flow business, then it doesn't. Just using the 7 times to 8 times EBITDA as a rough multiple. I guess the last leg of the stool here from a strategic perspective, is you've done a fantastic job addressing the utility side of things and hopefully, you'll execute and get to the earned returns. You're really doing a great job controlling the investment on the cost side, but, and the gist of all the other questions I've heard on the Genco is, when are we going to see the offsetting revenues, notwithstanding how bad the forward curve looks?

Yes, yes, I hear you, Greg. We're [dealing] to your point, we're doing what we can to take the positive free cash flows we have to reduce our outstanding leverage. We've taken nearly, actually more than $250 million of costs out of our projected capital expenditures. We're keeping a lid on O&M costs in that segment, so we're doing what we can to control the costs. We're paying down debt, decreasing leverage, and we'll see what happens in terms of the market recovery. We certainly think that the impact of some of the environmental regulations that are out are going to have an impact on reserve margins in our region, and we think we've gotten our arms around our environmental compliance plans.

Great. One last question, just on follow-up on another question. That 9.2% ROE on, was that on book equity or rate base equity?

That is based on rate -- that would be based on book equity actually, the 9.2%.

It's tangible book at the utilities.

Great. Thanks, guys. See you soon.

Thank you. Ashar Khan from Visium.

Marty, can I just go -- so the rate case you're going to withdraw, and you said the new rates are going to get implemented, what, like June or something under this plan?

We were saying that the rate impacts would really be in the second half of 2012.

So, okay, second half. So, like what, July 1?

No, not necessarily July 1. I should have committed that to memory, but I don't have the exact date. Just and I think it will be based on when we are ready to file, frankly. I think that there's a lot of work that goes into actually making the filing, for the formulate rates, and whether it be the capital spending plans, the hiring plans, the smart grid rollout plans, the plans to measure the improvements in our service, et cetera. So there's a lot that goes into the filing. When we're ready to make that filing, we'll make it. But ultimately, the date that the rates would change would be somewhat dependent upon the filing.

And then if I read correctly, you said they're going to base the numbers from the FERC Form 1; is that correct?

Yes.

So what, like we have the FERC Form, so can you just guide us, what numbers are they going to take? They are going to take your net plan from the FERC Form 1 and then apply the ROE from there? Is that what they are going to do?

Ashar, this is Doug. I think that's a discussion maybe we can have offline as we go through the process. I don't think we -- I think we'll get bogged down if we get into all the details here.

Okay. Then if I can just follow up, as I look into next year, right, the Missouri rate case is going to, it's still not [fully rate], we got a decision late, so that should help earnings going forward because the full impact is not in there next year; is that correct?

That is correct. The new Missouri rates went into effect at the end of July of this year. So we will get the benefit of a full year of rates. I think --

May I ask one more question--

One last one, please.

Yes, and if I'm right, there's going to be no Callaway outage next year; is that correct?

That is correct.

And that is how much in earnings benefit?

This one we had last year was about an $0.11 impact, the cost of the outage back in 2010.

Okay, okay. So there's an $0.11 gain. Okay. Thank you so much.

Thank you, Ashar. I want to just bring the call to a close and thank everyone for participating. We're looking 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 11 on playback, and for one year on our webcast. Today's Press Release includes instructions on listening to the playback. You may also call or e-mail the contacts listed on the release. Financial analysts' inquiries should be directed to me, Doug Fisher. Media should call Brian Bretsch; our contact information is on the news release. Thanks again, thank you for your interest in Ameren.

Thank you. This does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation.