阿莫林 (AEE) 2012 Q3 法說會逐字稿

Greetings and welcome to the Ameren Corporation's third quarter 2012 earnings call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation.

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Doug Fischer, Director of IR for Ameren Corporation. Thank you, Mr. Fischer, you may begin.

Thank you, and good morning. I'm Doug Fischer, Director of Investor Relations for Ameren Corporation. On the call with me today are Tom Voss, our Chairman, President, and Chief Executive Officer; Marty Lyons, our Senior Vice President and Chief Financial Officer; and other members of the Ameren Management team. Before we begin, let me cover a few administrative details.

This call is being broadcast live on the Internet and the Webcast will be available for one year on our website at ameren.com. Further, this call contains time sensitive data that is accurate only as of the date of today's live broadcast. And, redistribution of this broadcast is prohibited. To assist with our call this morning we have posted a presentation on our website that will be referenced by our speakers. To access this presentation, please look in the Investor Section of our website under Webcasts and Presentations and follow the appropriate link.

Turning to page 2 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 statements section in the news release we issued today and the forward-looking statements and risk factors sections in our filings with the SEC.

Tom will begin this call with an overview of third quarter 2012 earnings and 2012 guidance, followed by a discussion of recent regulatory and business developments. Marty will follow with more detailed discussions of third quarter 2012 financial results and regulatory and other financial matters. We will then open the call for your questions. Here's Tom who will start on page 3 of the presentation.

Thanks, Doug. Good morning, and thank you for joining us. Before I discuss our earnings, I would like to acknowledge the terrible impact Hurricane Sandy has had on our fellow citizens in the Northeast. This storm has reminded us again how the forces of Mother Nature can change lives. Sandy will no doubt go down as one of the worst storms ever to hit our country. Our thoughts and prayers go out to all those who have lost loved ones from this devastating storm. And, also to those affected in so many other ways by the storm, including those whose homes and businesses have suffered severe damage and lost power.

At the request of Public Service Electric and Gas of New Jersey, Ameren Missouri and Ameren Illinois dispatched crews to respond to the storm even before it hit the region so that our teams would be in position to restore power as soon as possible. Currently, there are more than 660 Ameren Electric and Gas employees and Ameren contractors, and nearly 250 pieces of heavy equipment deployed in New Jersey. I want to personally thank all of the Ameren personnel who are working long hours to restore power in the Northeast.

Now, I would like to turn to a discussion of our earnings and update you on other important matters. Today, we announced third quarter 2012 core earnings of $1.33 per share, compared to third quarter 2011 core earnings of $1.57 per share. The third quarter was solid from an operations perspective with our system and people performing very well under extended severe weather conditions. Overall earnings were in-line with our expectations despite a challenging Illinois Electric delivery rate order. The decrease in third quarter 2012 core earnings compared to third quarter of 2011 core earnings reflected lower results from both our regulated utility and Merchant Generation businesses.

Ameren Illinois' earnings were negatively impacted by the Illinois Commerce Commission September 2012 rate order for the electric delivery service and a change in the quarterly distribution of revenues and earnings resulting from formula rate-making. In addition, Ameren Missouri's core earnings declined due to lower electric sales and a higher effective income tax rate partially offset by the benefit of a 2011 electric rate adjustment. Third quarter 2012 temperatures, while warmer than normal, were similar to those experienced in the third quarter of 2011. Core earnings from our Merchant Generation business also declined compared to the third quarter of 2011, reflecting lower power prices and higher fuel costs. Marty will provide more details on our earnings in a few minutes.

Turning to page 4. Today, we also affirm that the $2.40 per share midpoint of our 2012 core earnings guidance and narrowed the range of that guidance to $2.35 to $2.45 per share from our prior range of $2.25 to $2.55 per share. The midpoints of core earnings guidance for our regulated utilities and our Merchant Generation business remain $2.30 per share and $0.10 per share, respectively.

I am pleased to also report that in addition to our solid operating performance during this past summer's extended heat wave, two of our coal fired Missouri Energy Centers recently earned positive national recognition. The Labadie and Rush Island Energy Centers were honored as the Best Performers for 2011 by the Electric Utility Cost Group. This honor demonstrates that our commitment to performance, cost efficiency, and reliability is benefiting our customers. In addition, our Callaway Nuclear Energy Center has been performing well, running continuously since its fall 2011 refueling outage.

Moving from earnings results and recent operational successes, I would like to update you on regulatory matters at our utilities. Turning to page 5 of our presentation and Illinois regulatory matters. As I previously mentioned, in September of this year we received a disappointing order from the ICC in response to our initial filing for formula electric delivery rates. In response, we asked the ICC to re-hear certain key issues in the rate order because we believe they misapplied the Illinois Energy Infrastructure Modernization Act. However, the ICC denied our re-hearing request last month and we have appealed the order to the state's 4th District Appellate Court.

Unfortunately, this disappointing ICC order jeopardizes Ameren Illinois' ability to implement advanced metering and other infrastructure improvements, and create jobs to the extent and on the timetable envisioned by the general assembly. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is removed, Ameren Illinois is reducing its capital spending with corresponding negative effects on the job creation that the legislature sought to achieve with the law. Specifically, Ameren Illinois expects to reduce or defer a total of $30 million of its previously planned 2013 electric distribution capital spending. Besides appealing the recent rate order to the courts, Ameren Illinois is also reviewing potential legislative remedies to ensure that the goals of the Energy Infrastructure Modernization Act are realized.

Turning now to page 6 and Missouri regulatory matters. Our pending electric rate case is nearing a conclusion and our updated filings now support a $323 million annual increase. In this proceeding we are seeking recovery of costs and investments that we have already made to serve customers. Further, we are asking the Missouri Public Service Commission to approve two enhancements to the existing regulatory framework in the state. First, we are requesting approval of a storm cost tracking mechanism that would provide the opportunity to recover costs to restore service after major storms in a manner that is fair to both our customers and our investors.

Second, we are requesting approval of a new plant and service accounting proposal. This proposal is designed to reduce the impact of regulatory lag on earnings and future cash flows related to assets placed in service between rate cases. Approval of this proposal would encourage prudent incremental discretionary investments in our energy infrastructure and help meet our customers' number one priority, reliability. Of course, these incremental investments would also help sustain and create new jobs. The evidentiary hearings in front of the Missouri PSC were completed last month. The PSC plans to issue an order in early to mid-December of this year, with new rates expected to be effective in early January of next year.

As Marty will discuss in further detail, the largest revenue related issue in dispute in this case is the allowed rate of return on equity. Moving to page 7. I will conclude my prepared comments on our regulated utility businesses by updating you on a key driver of our expected future growth, our single largest planned investment, the Ameren Transmission Company Illinois Rivers Project. This important MISO approved regional multi-value project involves the construction of a new high voltage transmission line across the state of Illinois. It will enhance reliability and create new construction jobs in the state.

Like all our Illinois transmission projects, both those at Ameren Illinois Company and Ameren Transmission Company, the Illinois Rivers Project will benefit from the Federal Energy Regulatory Commission's constructive rate-making. This rate-making provides for annual formula based updating of rates and a competitive return on investment. Further, last year this project received FERC approval for constructive regulatory treatment such as the inclusion of construction work in progress in rate base.

I am pleased to report that just last month we completed 98 stakeholder public meetings on the routes designed for this project. And, Wednesday of this week we filed with the ICC for a Certificate of Public Convenience and Necessity for the approximately 400-mile transmission line route with the decision on the certificate to be issued by July of next year. Once we receive this certificate from the ICC, we will begin to acquire right of way for the transmission line. Preliminary construction may start as early as next year, with a full range of construction activities expected in 2014.

Turning to page 8 and a discussion of our Merchant Generation business. We continue to act to adjust this business to weak power prices and an uncertain time line for their recovery. Earlier this year our Merchant Generation business filed a request for a variance from the Illinois Multi-Pollutant Standard, or MPS, with the Illinois Pollution Control Board. In our petition, we outlined our need for additional time to comply with sulfur dioxide emission standards which were to become effective January 1, 2015.

In exchange for delaying compliance with these standards until 2020, we proposed an alternate compliance plan that restricted our sulfur dioxide emissions through 2014 to levels lower than those required by the existing MPS, thereby offsetting the environmental impact of granting the variance relief. I am pleased to report that in September of this year, the Pollution Control Board unanimously approved our variance request subject to conditions that we have accepted. As a result, through 2019, we do not expect to have to derate or shut down any of our currently operating Energy Centers in order to comply with the state's sulfur dioxide emission limits.

Further, we have reduced our 2012 through 2016 Merchant Generation environmental capital spending plans by approximately $35 million, compared to our prior plans, with $20 million of the reduction occurring this year. This reduction is primarily due to the vacated Cross-State Air Pollution Rule and the impacts of the MPS variance. To be clear, these spending plans are sufficient to meet the milestone conditions through 2016 that were included in the variance. That being said, we recognize that even with the relief granted by the Illinois Pollution Control Board, low power and capacity prices are impacting Ameren's earnings outlook. We continue to look for every opportunity to reduce operating costs and enhance margins. With that, I will now turn the call over to Marty.

Thanks, Tom. Turning to page 9 of the presentation. Today, we reported third quarter 2012 GAAP earnings of $1.54 per share, compared to third quarter 2011 GAAP earnings of $1.18 per share. Excluding certain items in each year, Ameren recorded third quarter 2012 core earnings of $1.33 per share, compared with third quarter 2011 core earnings of $1.57 per share. Core earnings for the third quarter of 2012 excluded two items that are included in GAAP earnings.

The largest of these non-core items was an increase in income tax benefit as a result of the first quarter 2012 non-cash asset impairment charge at our Merchant Generation business and the GAAP requirement to recognize quarterly income tax expense using the annual estimated effective income tax rate. This item increased net income by $0.18 per share in the third quarter of 2012, entirely reversing the $0.18 per share decrease in income tax benefit recorded in the first half of 2012. We expect this item to have no impact on full year 2012 earnings. The second non-core item is a $0.03 per share gain from the net effect of unrealized mark-to-market activity.

On page 10, we note key factors that drove the $0.24 per share decrease in third quarter 2012 core earnings compared to third quarter 2011 core earnings. Looking first at results of our regulated utilities. Ameren Illinois' September 2012 electric delivery rate order and the change in the quarterly distribution of revenues and earnings under formula rate-making, reduced core earnings by $0.12 per share compared to the third quarter of 2011.

Moving to Ameren Missouri, electric sales margin reduced earnings by $0.04 per share, compared to the third quarter of 2011, reflecting lower electric sales, attributable at energy efficiency measures, and customer conservation efforts. While we do estimate that warm third quarter 2012 temperatures benefited earnings by $0.10 per share as compared to normal temperatures, these temperatures did not materially impact the earnings comparison to the third quarter of 2011, because third quarter 2011 was similarly warm. Ameren Missouri earnings were also impacted by higher effective income tax rate which reduced earnings by $0.04 per share.

The July 2011 Missouri Electric rate adjustment partially offset the electric sales and tax rate impacts benefiting earnings by $0.05 per share, compared to the third quarter of 2011. Finally, Merchant Generation segment earnings were impacted by a $0.10 per share decline in margins, compared to the third quarter of 2011, reflecting lower power prices and higher fuel costs. This was partially offset by $0.05 per share of lower depreciation expense and $0.02 of lower plant operations and maintenance expense.

Turning now to page 11. We have updated our 2012 cash flow projection. We now expect 2012 negative free cash flow of approximately $205 million, a decrease in free cash flow of approximately $15 million compared to the projection we provided on our August call. Our negative free cash flow projection includes $138 million of premiums for long-term debt repurchases for our regulated utilities, Ameren Illinois and Ameren Missouri, which were paid during the third quarter. These premium payments were part of debt refinancing that reduced the weighted average interest rates on our utility debt and enhanced our debt maturity profile. As a result, we expect to recover these premiums over the life of the newly issued debt through the regulatory process.

As shown on this page, we calculate free cash flow by starting with our projected cash flows from operating activities, and subtracting from it expected capital expenditures, other cash flows from investing activities, dividends, and net advances for construction. Adjusting for the premiums paid on long-term debt, our adjusted free cash flow expectation is a negative approximately $67 million. While we anticipate the 2012 free cash flow will be negative for Ameren as a whole, we expect that our Merchant Generation business will cover its own 2012 cash needs. Moving from a discussion of earnings and cash flow, I would like to provide further details on the regulatory matters that Tom previously discussed.

Turning to page 12 of our presentation. I will begin with the earnings impacts of Illinois Electric delivery formula rate-making. Under this rate-making, reported Illinois Electric delivery earnings for a given year reflect a true-up for that year's rate base, actual cost of service, and formula based return on equity as well as ICC rate-making adjustments. Also, it is important to recognize that quarterly revenues and earnings are impacted by the timing and amount of operating cost. As Tom previously mentioned, the ICC issued its order in our initial electric delivery formula rate case this September, and we have incorporated the impacts of that order into the 2012 core earnings guidance that Tom shared with you.

To assist you in thinking about 2012 Illinois Electric delivery business earnings, we have provided, on this slide, key inputs into the rate formula including impacts of the recent ICC order. Despite our belief that the Illinois Energy Infrastructure Modernization Act calls for the use of year end rate base and year end capital structure, the ICC ordered the use of average rate base and the use of a hypothetical capital structure and we have reflected these ICC decisions in our guidance. Also, our guidance now incorporates an estimated average 2012 30-year Treasury Bond yield of 2.9%, down 10 basis points from the expectation we shared on our August call.

Further, our guidance reflects the fact that several types of costs are not recoverable in rates. These non-recoverable costs include approximately $9 million of ICC rate-making adjustments. In addition, we expect to spend about $7.5 million this year on certain electric system rework that is non-recoverable in rates. Finally, approximately $9 million of donations were required under the Energy Infrastructure Modernization Act. Of this total, $7.5 million was a one-time 2012 only donation to the Illinois Science and Energy Innovation Trust.

Turning now to page 13. Ameren Illinois' first annual update case for electric delivery formula rates is nearing a conclusion. On Wednesday of this week, the ICC administrative law judges hearing this case issued their proposed order. While we are still reviewing the proposed order, it appears to be in line with the order the ICC recently issued in the initial formula rate case. The deadline for an ICC decision in the update case is December 16, with new rates scheduled to be effective in early January 2013.

Moving to page 6 (sic, see slide presentation "page 14"), the ICC is also currently reviewing Ameren Illinois' modified smart grid Advanced Metering Infrastructure, or AMI, deployment plan to determine if it is cost beneficial. We believe our filings strongly supports the cost beneficial nature of our plan. Installing smart grid equipment and advanced two way electric meters is critical to meeting the infrastructure enhancements required under the Illinois Energy Infrastructure Modernization Act that authorized formula rates. And, such expenditures are a significant portion of the increase in capital spending required by the Act. The ICC is scheduled to rule on our modified plan this month. Assuming ICC approval, we plan to begin construction of infrastructure in the third quarter of 2013 with the first meters to be installed in the second quarter of 2014.

Turning to page 15, and our pending Missouri Electric rate case. We have requested an updated $323 million annual rate increase, down from our original request of $376 million. This change is the result of the normal rate case true-up process, a reduction in our requested return on equity to 10.5%, and the settlement of certain rate case issues. Our updated request includes $73 million related to higher net fuel costs, $80 million already approved by the Missouri PSC related to recovery of costs for enhanced energy efficiency programs that will begin in 2013, and $170 million for other non-fuel costs. In addition, we are seeking approval of a new storm cost tracking mechanism and a new plant and service accounting proposal, as Tom has already discussed.

The Missouri PSC staff updated filing in this case supports a $210 million increase. The primary driver of the $113 million difference between Ameren Missouri's position and that of the staff is allowed return on equity. The staff's 9% recommendation compared to our 10.5% request accounts for $88 million of the difference. On this page we also list other key drivers of the difference between our request and the staff's positions. Regarding other rate case issues, the staff supported continuation of the pension, OPEB, vegetation management, and infrastructure inspection cost tracking mechanism. However, the staff called for changing the FAC sharing mechanism to an 85/15 split from the current 95/5 split. This proposed change in the sharing percentages is similar to what the staff has recommended in past rate cases.

Further, the staff has recommended that transmission costs should no longer be recovered through the fuel adjustment clause but instead should be recovered in base rates. We opposed this potential change as we believe it is appropriate to recover transmission costs through the FAC. These costs can be volatile and are unavoidable and outside of Management's control. Further, recovery through the FAC better matches the costs of being a member of MISO with the benefits the customers receive through all system sales which are included in the FAC.

If the PSC decides to make such a change, we believe a full cost tracker mechanism without any limiting conditions should be put in place to avoid regulatory lag resulting from under recovery of cost increases between rate cases. Finally, the staff has recommended that the Missouri PSC reject our storm cost tracking mechanism and plant and service accounting proposal. In addition to the staff, other parties have filed testimony on several issues in the pending case. For example, Missouri Industrial Energy Consumers and the Office of Public Counsel have recommended returns on equity of 9.3% and 8%, respectively. The Missouri PSC is expected to issue its order in early to mid-December of this year with new rates expected to be effective in early January 2013.

Shifting to our Merchant Generation business. On page 16 we provide updates on our 2012 through 2014 forward power sales and hedges. As noted last quarter, as a result of falling power prices, which reduced economic generation levels in 2012, we hedged an amount greater than our ultimate expected generation. This hedging in excess of generation has been, or will be, settled on a profitable basis by either using purchased power or existing generation to the extent that power prices improve. For 2013, we have now hedged approximately 24 million megawatt hours at an average price of $36 per megawatt hour. Further, for 2014, we have now hedged approximately 13 million megawatt hours at an average price of $38 per megawatt hour.

Finally, turning to page 17 and an update of our Merchant Generation business fuel and related transportation hedges. For 2013, we've hedged approximately 22 million megawatt hours at about $23.50 per megawatt hour, unchanged from our August call. And, for 2014, our hedges now total approximately 13 million megawatt hours at about $24 per megawatt hour. Our reduced coal hedge level in 2014 reflects a rebalancing of our mix of coal hedges to reflect desired coal quantities and an amount overall matching our forward power hedge position. This completes our prepared remarks. We now invite your questions.

(Operator Instructions)

Stephen Byrd, Morgan Stanley.

Good morning.

Good morning, Stephen.

Just curious, first on your outlook for power prices. There's an ongoing debate about the impact of upcoming environmental regulations on the price of power and whether the forward price of power is really fully accounting for all those environmental costs. Particularly post election, the question's coming up a lot.

I was just curious, as you think about the Midwest and the amount of potential economic retirements that we're seeing out there, and as you look at the forward power markets, do you have any general comments on what you're seeing out there?

Yes, Stephen, it's a good question. I think it's always been -- this is Marty, by the way.

It's always difficult to speculate on what's going to happen with forward power prices. Our view, I think, along with others, is that forward power prices today are obviously pretty low, certainly reflecting the continued weak economy and low gas prices. We do expect that, over time, especially when you look out to the MATS rules that take effect out in the 2015, 2016 time frame, that you will see the need for folks to either make additional expenditures or for higher cost generation, to shut down. I think MISO has estimated as much as 12,000-megawatt hours of reduction across the MISO footprint. So those types of things will certainly, I think over time, put pressure on capacity prices, if not power prices.

Okay, great. Thank you.

A related question -- just as you think about the merchant business, you've laid out for 2012 the business is able to fully fund itself. It's not cash-flow negative. And, as you think about the outlook for that business, from a strategic point of view, is there a sense that through strategic activity that cost cutting could be achieved, greater scale could be achieved? Is there a view that greater scale is needed in general in the merchant generation business? If you wouldn't mind just giving an update on how you think about, strategically, your merchant business.

Stephen, I think a couple things. First of all, you talked about cash flows; and I think, as we said in the call, certainly we're expecting the business to cover its cash needs this year. From time to time, we get questions about GenCo in particular.

They started the year out with about $82 million of cash and advances to the money pool. As of September 30 they still had about $57 million of either cash -- cash and advances to the money pool combined -- about $57 million. And, as you know, have the ability to sell gas-fired assets or exercise put option for liquidity purposes. So, those options are out there. As well as they certainly expect, going forward, to have the benefit of certain net operating losses that they've got as well.

So, there are some tools in the tool kit in terms of liquidity and cash flows in the short term. Longer term, strategically -- I think it's something that we will continue to evaluate. Obviously, I think the larger the scale platforms that are out there, there are certain synergies that you can have. I think, as we have managed this business over time, we've certainly gotten some synergies by the overall combination of the entities that we have. But, going forward it's something that we'll continue to consider -- the nature of our overall hybrid mix.

Great. Thank you, very much.

Paul Patterson, Glenrock Associates.

Good morning.

Good morning, Paul.

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

I don't know about the other company you're referring to, Paul, but I can certainly -- this is Marty again. I can certainly comment overall.

We did estimate about $0.10 per share of positive impact from weather in the third quarter versus normal. We also mentioned, in our prepared remarks, that overall we thought Missouri Electric sales negatively impacted earnings by about $0.04 versus last year. And that's because, while it was $0.10 versus normal of positive weather impact in the quarter, as we looked at the weather this year versus last year we thought the impact was about flattish or no impact.

You may recall that we had a warm summer last year. It was a persistent warm summer, whereas this year we had some heat in June, extreme heat in July, and then it dropped off to more normal conditions for the remainder. What we saw this year is that, as we had those extremes in heat and we quantified, as I said, the impact to be about $0.10, when we looked at the weather-normalized sales they were actually down. And so, when you look at the statistics page we've provided, you'll actually see that residential and commercial sales were down year-over-year. And, again, remember that we believe that overall, weather was about flat. So, the sales declines that you're seeing are weather-normalized sales declines.

Now, as we know, weather normalization is somewhat art and somewhat science. That's why we say, in particular, in our talking points, that some of that reduction in overall weather-normalized loads may be because of customer conservation efforts as they receive some of the higher bills from the June and July time frame.

But, getting back to your question -- I mean, I think that's a backdrop. What we're actually seeing, then, in Missouri for the quarter was -- in Missouri, residential sales on a weather-normalized basis, down between 1.5% and 2%. Same pattern in the commercial sector. In Illinois, we saw a little bit greater decline in residential usage and commercial was actually a slight positive.

So, overall, for Ameren in the quarter, what we saw on a weather-normalized basis was residential sales down a little over 2%, commercial sales down between 0.5% and 1%. So, we saw some, again, some weather-normalized declines in the quarter. And, again, how much of that may have been a reaction to the extreme weather and some of the bills people received is difficult to know.

We expected, coming into the year, to have about -- residential commercial sales -- about 0.5% to 1% of growth. What we're now expecting for the year, Paul, is that residential sales to be down somewhere around 0.5% for the year; still expecting to see some commercial growth, however, of up to 0.5%. I think on the industrial side we're seeing pretty flat loads in terms of industrial sales in Missouri. While we're still seeing some growth in Illinois. We're seeing growth year-to-date in Illinois of about 3.9%, and we're expecting for the year all across Ameren to have growth of about 2.7%.

In terms of regulatory lag and going forward, I mean, with the conservation efforts that we've seen actually around the country for a while now, or whatever it is, at least usage -- how should we think -- is there a potential for regulatory lag in Missouri that you guys are -- or is there not? And, just really briefly, on the merchant -- depreciation went down about $0.05? Was that because of Duck Creek, or was it anything else?

Let me hit that one. Maybe I'll actually let Warner Baxter talk about Missouri.

Yes, you may look back -- when you look back to our beginning of the year guidance compared to now, our actual guidance today is about $0.05 higher than it was at the beginning of the year. And, in part that is because of the Duck Creek write-off, which then positively impacted depreciation; and that's about $0.05 for the year. So, that is part of that, Paul.

It looked like it was $0.05 for the quarter, though.

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

Paul, this is Warner.

Just a couple things to keep in mind. Number one, with regard to these lower sales, be mindful that we're in the middle of our current rate case. Consequently, we update our billing units for the lower sales levels. Those were done through June. A piece of the things that you're seeing, at least throughout 2012, are part of our overall rate increase request that you see today.

Secondly, what you have to be mindful of is that, as we go forward, I think Marty mentioned during the talking points, that we have a new energy efficiency regulatory framework that's been in put in place. We're going to be moving out on some additional energy efficiency programs, which obviously are going to be beneficial for our customers. But, also as part of that we're going to not only recover our program costs but also we'll be able to recover the lost fixed costs, or the lost revenues, associated with some of those. That's part of the existing rate case as well; and frankly, a settlement that the Commission has already approved.

I think there is still risk, to be clear, for regulatory lag associated with conservation efforts. We have taken steps with this rate case and with our new energy efficiency proposal to try and mitigate that to some extent.

I'll let other people ask questions. Thank you.

Thank you, Paul.

Paul Ridzon, KeyBanc Capital Markets. Please proceed with your question.

Paul, your line is live.

Julien Dumoulin-Smith, UBS.

Good morning.

Good morning, Julien.

First quick question -- on the quarter with regards to Illinois, the $0.12 -- could you break that apart in terms of the distribution, just the quarterly shift versus the earnings under the rate-making?

Well, I guess I'd break it down this way, Julien. I think about -- I'd attribute about $0.05 of that total of the $0.12 to the impacts of the rate order that we received. And the remainder of it really having to do with the distribution of revenues and earnings.

Great. Next year should we see this more normalized, given the fact that the rate-making has been in effect for the balance of this year? So, this will go away year-on-year?

Yes, I think it should normalize year-over-year. I think what we'll do as we move into next year is see whether we can -- if there is any variation that we can foresee and project, we'll certainly provide that. But, certainly, what it has to do with is, this year, what we're trying to do under the formula rate-making, is preserve some of the seasonality of the revenue requirement. But, as you go through the year and there are changes in the estimated overall revenue requirement for the year, then those are adjusted within the quarter, which is one of the things that impacted us here in this quarter.

I think, Julien, in terms of the drivers, on our slide 12, drivers of overall Electric DS earnings, we tried to lay out some of the overall drivers as we see them right now, given the impacts of the ICC order.

Great, quick follow-up there.

You discussed lower CapEx in Illinois, I believe, for '13. Can you provide a little bit of a sense on a go-forward basis what kind of capital expenditure reductions we could potentially see, depending on what happens upon re-hearing, et cetera? Where could this go, ultimately?

Well, I think that's something that we'll have to evaluate over time. Obviously, we gave the 2013 number. What impact there is on 2014 or beyond is something that we'll have to evaluate as we move through time. Our focus right now, as you heard in our talking points, is trying to get the legislative intent incorporated into the rate-making process.

We still do believe that over the long term, the formulaic rate model intended by the Energy Infrastructure Modernization Act is good for Ameren Illinois and its customers. We're certainly appealing the decision of the ICC to the courts. And, as we noted in our prepared remarks, again, considering what legislative remedies might be possible.

But, just to be clear, it wouldn't necessarily impact any of your commitments under the formula rate-making?

That's true. We've made commitments under the formula rate-making. And so, when we look at our capital expenditures, certainly to the extent we're participating in formula rate-making, we will fulfill our commitments under the law.

Great. Thank you.

Michael Lapides, Goldman Sachs.

Just curious, when you think structurally across both the Missouri and Illinois regulated businesses, what are the structural impediments to earning your authorized rate of return? Which ones tend to be the biggest drivers that keep you from being able to do so?

Yes, sure, Michael, this is Marty again.

I think -- we'll start with Illinois. I think when you look at the slide that we provided, slide 12, you see some of those impacts as it relates to the Illinois Electric delivery business in terms of rate-making adjustments, certain costs that are incurred that are non-recoverable which we've laid out again for the electric distribution business there on slide 12. Other things, I'd remind you, for instance, is weather, sometimes. For example, in our gas business this year in Illinois, earnings are down roughly $0.03 because of weather. So, that type of thing can certainly drive it down.

Then, I think, Michael, I think you and others have this baked in to your overall analysis in Illinois, but I'd just remind you that the goodwill in Illinois is deducted out for rate-making purposes, against equity in that overall business. So, that's always been the case. That's not something that's new, that's a historical rate-making adjustment. Again, I'd remind you of that.

Got it, okay. Thanks, guys. Much appreciated.

Alex Tai, Standard General.

Hello, guys, how are you doing?

Good morning.

I just had a question on -- I believe you commented on this previously, but I just wanted to see if we could get some more specifics -- on, in terms of you said previously that you would be able to comply with MATS without undertaking a scrubbing program for Newton in your merchant gen segment? Obviously, that's irrespective of the state variances recently granted. I was just wondering if maybe you could provide a little more detail on how you think you're going to get there in terms of compliance? And, is that baked within your current CapEx plan?

Sure, this is Marty again.

You're correct on all that. That is consistent with what we've said in the past. One of the reasons that we were pursuing the variance from the Multi-Pollutant Standard with the Illinois Pollution Control Board was, in fact, we were able to comply with the MATS rules without that scrubber. And, it was really the Illinois rules that were imposing the need to construct that scrubber.

So, we do believe that the capital expenditure plans that we've laid out will allow us to comply with MATS. It's really a function of a number of things. It's a function of the investments that we've already made in our plants over time. We've made significant investments in pollution control equipment. We also burn low-sulfur coal which helps with our overall emissions. And, as a result of compliance with the Multi-Pollutant Standard in Illinois, we're already using significant amounts of activated carbon for control of mercury. So, through the, I'd say, the compliance with the Multi-Pollutant Standard, we've actually built into our operations those things that are needed to comply with the MATS rules.

Okay, great. Thanks, guys.

Ashar Khan, Visium.

Marty, I just wanted to reconfirm what you're saying. As we look from '12 to '13, is this $0.12 recovered? Or is this just lost and there's no positive delta year-over-year?

Yes, it's not really the $0.12 year-over-year. I think that what is more permanent, I would say, until we get either some fix to the ICC rate-making to conform with the Act, or otherwise adjust our spending or capital structure -- I guess what I'm saying is, I'd point you back to slide 12 again. I think those are really the drivers of the earnings.

And, as I said earlier, that $0.12, when you break it down, was really $0.05 having to do with the ICC rate order. And then the remainder just really being seasonality of the revenue requirement earnings under formula rate-making. What we tried to provide on slide 12, though, was more of a straightforward build-up, or provide you with a straightforward building blocks to build up to the revenue requirement as we see it today, given the ICC's rate order.

Okay. Thanks.

Yes, Ashar, thank you.

Julien Dumoulin-Smith, UBS.

Good morning.

Just a couple quick ones on the GenCo side of the house, real quickly. In terms of fuel hedge, I noticed that the '14 number actually stepped up by $0.50 there. I suppose it's a little less than intuitive given some of the recent trends. I'd just be curious.

Yes, Julien, that's right. In our prepared remarks, I tried to provide a comment on this. What we did do in the quarter was rebalance our mix of our coal hedges a little bit. And in the rebalancing of the coal hedges it actually impacted the average price a little bit. As you see now, too, you might notice that the coal hedge percent -- or the coal hedge number dropped down from about 14 million megawatt hours to 13 million megawatt hours, which also aligns with the forward power sales that we've made, about 13 million megawatt hours.

So, it was a bit of a rebalancing of the coal hedge mix. You've got to remember too, these are -- we round off to the nearest $0.50, so there's a little bit of rounding in there. That coal hedge rebalancing wasn't a full $0.50 impact, but that was, I'd say, one of the drivers.

Great, and then, a second question here -- obviously you talked about free cash flow breakeven for GenCo. I'd be curious -- how do you think about execution of the put options? Specifically, your Q alludes to losing access to some of your other sources of liquidity at some point. Would you imagine execution of the put in tandem with some of the other liquidity source losses? Do you get what I'm saying?

Yes, I don't think it would necessarily be in tandem with the other liquidity source losses. Like I said, they've still, as we sit here -- well, at 9/30 they had about $57 million of both cash and money pool advances on the balance sheet. So, we'll be thinking about that as we look at the overall cash flows going into next year and the year beyond -- what the available cash is, as they, again, seek to cover their own cash needs, and then making a decision about what the right course of action is in terms of execution of that option.

Right. So, effectively, to be clear, once you roll off of the existing cash balances, at that point you'll probably take a look at execution?

Well, that's right, to the extent that the cash balances roll down. And if we were in a position where we didn't see the ability for them to meet their own cash needs, certainly then we'd be in a position where we'd be executing the put option. But, again, right now, I mentioned the overall liquidity that they've got.

Right, absolutely.

And, just to be clear also -- if you were to execute the put option, you would expect to sell those assets in turn? Would this be a transitionary thing? Or would you effectively intend to keep those new assets at the new subsidiary?

I guess, Julien, at the end of the day, we'd have the option to do either. But, certainly the idea was that if GenCo exercised the put, obviously they get the $100 million immediately. They get the remainder of any excess in the fair value over the $100 million, as determined by the appraisals at closing. And then, AERG, who would actually then have those assets, would have the ability to sell one or all of those in order to reduce outstanding borrowings resulting from the put.

Right. Fantastic.

Yes, exactly.

Paul Patterson, Glenrock Associates. Please proceed with your question.

Paul, your line is live.

Sorry about that. Can you hear me?

Yes.

The ash pond ARO -- is that just for the quarter? Or is there an ongoing impact associated with that?

No, it's just for the quarter. We periodically actually update our estimates. These ones in particular, though, had to do with Meredosia and Hutsonville and some of the closure there as we're working through the closure of those facilities and had better estimates on the overall cost. So, it's really a one-time impact.

The severe weather that you mentioned in the release -- I gathered that, and also from your comments, that's this hot weather that you guys incurred in the summer. Were there any new peaks this summer, just in terms of -- I know you gave us megawatt hour declines, but was there any -- how was peak compared to megawatt hour volume, if you follow me?

I think we commented on some of the peaks, actually, last quarter. But, I'll let maybe Maureen Borkowski talk about the overall system peaks that we saw.

Yes, from a system standpoint, we did set a new all-time peak, being that 2008, I believe, was the previous all-time. Within the two individual systems, either Ameren Illinois or Ameren Missouri, Ameren Illinois set a new peak, but Ameren Missouri did not exceed its all-time peak.

Okay. Then just finally, given this outlook that we've seen around the country and memories of the gas industry, LBCs and how it took some to come around to decoupling. Any thoughts there about ways to mitigate the potential issue that we might be seeing here? Also, considering that it seems that Missouri seems to have -- and other jurisdictions around the country want to have -- conservation, and what have you -- any thoughts on decoupling? Or how should we think about that and how you guys are approaching that issue?

Paul, this is Warner, I can speak for Missouri.

Certainly we don't rule decoupling out. In fact, there's been discussions at the Commission as to whether decoupling is an approach forward. So, there's no formal docket on that, but that's certainly one thing we look at.

In part, that's why we took the steps that we did and were able to achieve a meaningful enhancement for energy efficiency. That was a meaningful step change, because absent that, those energy efficiency programs really could not have moved forward. So, you look at decoupling, you may look at other regulatory mechanisms that would try and address energy efficiency issues or conservation issues. It's not something that's imminent. But, it's certainly something that's on our list of things that we have to continue to look at; as is, as you rightfully point out, the environment changes a bit from what we've seen in the past.

Ultimately, what we're pushing for and trying to do in Missouri, and certainly Illinois, is to do what we can to promote economic development; to try and get growth, not just from our residential, commercial. But, also to get investment made in the state, so we can put people back to work and actually get electric sales growth from that perspective as well.

Great.

Yes, Paul, this is Marty.

A couple other things. Just a reminder, in Illinois, of course, with the formula rates, one of the benefits is that we do have the formula rates and there is a collar on the overall allowed ROE of plus or minus 50 basis points. So, certainly there is a provision within that overall formulaic rates that is certainly helpful.

The other thing, though, is, while this year -- again, I think maybe because of some of the weather, we're certainly seeing more flattish residential and commercial loads. Like I said, we are still seeing industrial loads grow in Illinois. As we look out over time, we do expect to see some level of GDP growth over time; and with it, even after the impacts of energy efficiency, do still expect to see growth in electric demand. It may be less than what we've historically seen, but nonetheless expect to see growth in electric demand, as a company anyway, going forward.

Do you have any ratio associated with GDP that you can share with us that you're expecting in terms of that? In terms of what percent -- if we have a 2% GDP growth, what that would translate in terms of electric growth -- do you guys have that estimation or --?

Yes, I don't have it at my fingertips, an updated one. But, like I said, I think overall we certainly are expecting net of energy efficiency that relationship, that ratio, to be less than it historically has been. But nonetheless still positive.

Okay. Thank you.

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

This is Doug Fischer.

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

Again, thank you for your interest in Ameren.

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