阿莫林 (AEE) 2010 Q4 法說會逐字稿

Greetings, and welcome to the Ameren Corporation's year-end and fourth quarter 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, Douglas Fischer, Director of Investor Relations for Ameren Corporation. Thank you, Mr. Fisher, 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 our Chairman, President and Chief Executive Officer Tom Voss; our Senior Vice President and Chief Financial Officer Marty Lyons, and other members of the Ameren management team.

Before we begin, let me cover a few administrative details. The call will be available by telephone for one week to anyone who wishes to hear it by dialing a playback number. The announcement you received in our news release include instructions for replaying the call by telephone. This call will also be broadcast live on the Internet and the webcast will be available for one year on our website at www.ameren.com. This call contains time sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited.

To assist with our call this morning, we have posted a presentation on our website to which we will refer during this call. To access this presentation, please look in the Investor section of our website under "Webcasts and Presentations" and follow the appropriate link. Turning to page two of the presentation, I need to inform you that comments made during this conference call may contain statements that are commonly referred to as Forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated and described in the Forward-looking statements.

For additional information concerning these factors, please read the Forward-looking 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 2010 earnings and 2011 guidance followed by a discussion of recent business developments. Marty will follow with more detailed discussions of 2010 financial results, our 2011 guidance and regulatory and financial matters. We will then open the call for questions. Here is Tom, who will start on page three of the presentation.

Thanks, Doug. Good morning, and thank you for joining us. The past year was marked by significant accomplishments at our Company. I am pleased to report that 2010 core earnings reached $2.75 per share, within the upper end of our most recent earnings guidance range issued in late October and nearly equaling 2009 core earnings of $2.79 per share.

Improved earnings at our regulated utilities nearly offset a decline in core results from our Merchant Generation business. Factors favorably affecting 2010 core earnings included a 9% increase in electric kilowatt hours sales to native load customers, new electric utility rates, lower financing costs, and disciplined cost management. The increase in kilowatt hour sales was the result of favorable weather, a recovering economy and the return to full service of a large customer's aluminum smelter plant. Total kilowatt hours sales to industrial customers rose 16% and even after excluding sales to the aluminum smelter plant, industrial sales increased 8%. Kilowatt hours sales to residential and commercial customers rose 7%.

Items offsetting these favorable factors included lower Merchant Generation margins due to lower power prices and higher fuel and related transportation costs, and higher Company-wide depreciation and amortization expenses. Overall our non-fuel operations and maintenance costs increased only slightly reflecting cost of the refueling out age at our Callaway Nuclear Plant offset by disciplined cost management across all of our business segments. You may recall that our nuclear plant did not have a refueling outage in 2009.

Per share results also reflected an increased average number of common shares outstanding. Turning to page four, you will find a list of other accomplishments in 2010. We have discussed many of these with you previously so I won't touch on each of them, however, I would like to highlight the fact that free cash flow reached a positive $341 million in 2010. In addition, our safety and customer satisfaction showed improvement compared to 2009 as both power plant and distribution system reliability remained solid. We returned our newly rebuilt Taum Sauk pump storage Hydroelectric plant to service and placed scrubbers into service at three of our power generating units, and we launched plans for growing our transmission business. All of the accomplishments listed were the result of a focused and dedicated workforce.

Moving now to page five, today we also announced 2011 GAAP and core earnings guidance of $2.20 to $2.60 per share. The expected decline in 2011 core earnings per share compared to 2010 primarily reflects an assumed return to normal weather and expected lower margins at our Merchant Generation business. I'm pleased to report that we expect positive free cash flow in 2011. In fact, our Merchant Generation business expects positive free cash flow even though 2011 capital expenditures for this segment are expected to increase compared to prior guidance.

This increase in capital expenditures reflects our plan to accelerate the installation of scrubbers at our Newton plant and the addition of an equipment upgrade at one of our large Merchant Generation plants. We have moved up the in-service dates of the two scrubbers at Newton by approximately one year to late 2013 and spring 2014. This decision was driven by our plans for complying with the US EPA's proposed Clear Air Transport Rule. Installing scrubbers at Newton is also a key part of our plan for complying with the Illinois multi-pollutant standard.

Shifting to capital spending plans at our regulated businesses, the five-year budget that Marty will discuss in a few minutes now includes the costs of installing scrubbers at two of our Missouri Coal-fired units. These scrubbers are projected to enter service by late 2015. Marty will provide further details on our 2010 earnings and cash flow and our 2011 earnings and cash flow guidance including budgeted capital expenditures. Before Marty speaks, I would like to review recent regulatory developments at our utilities.

Turning to page six, we have been authorized to increase rates at both our Missouri and Illinois utilities over the past 12 months. In mid-2010, our Missouri utility obtained approval from the Missouri Public Service Commission to increase Electric rates by $230 million annually, and then in February of this year to increase Gas rates by $9 million annually. These rate increases have been necessary to recover the cost of infrastructure investments, higher fuel costs and other operating expenses.

While on the topic of prior rate orders, I would like to comment on ongoing litigation surrounding appeals of certain aspects of the two most recent Missouri electric orders. As disclosed in an 8-K filed last Friday afternoon, on Wednesday of last week the Missouri Office of Public Counsel made a filing with the Missouri Public Service Commission arguing that a late December Missouri Circuit Court stay of our 2010 Electric rate increase as it applies to four Industrial customers should now be effective for all customers. Needless to say this would be unprecedented and we adamantly disagree with the OPC's argument.

In late December, a Missouri Circuit Court found that four Industrial customers appealing the 2010 Electric rate increase could pay the portions of their bills representing increases from previously approved levels into the court's registry pending resolution of these appeals. This effectively stayed the rate increase for those parties. We disagree with the court's ruling granting these industrial customers a stay and we do not believe any of the issues being appealed by the parties are probable of loss based on the merits. Given that this is an active legal matter, we won't be able to comment further on this call but we will be responding to the arguments of the Office of Public Counsel and supporting arguments made by certain Industrial customers in filings with the Missouri Public Service Commission this week.

Turning now to Illinois. In November 2010, our Illinois delivery utility received an order on rehearing from the Illinois Commerce Commission on issues arising from the Commission's amended order of May 2010. This rehearing order brought the total annual revenue increase in this case to $53 million. Moving to pending rate cases, in September 2010 our Missouri utility filed for a $263 million annual electric revenue increase. On February 8, other parties filed their initial testimony.

While we strongly disagree with elements of the staff's and other parties' initial recommendations, this case is still in its early stages. We look forward to presenting our case to the Missouri Public Service Commission beginning in April. The Public Service Commission order is expected in July. A few days ago, our Illinois electric and gas delivery utility filed with the Illinois Commerce Commission for our $111 million increase in annual revenues. This request is based on a test year ending December 31, 2012 with an ICC decision expected in January of 2012.

The use of a future test year is designed to better match our 2012 rate levels to our expected 2012 costs reducing regulatory lag and providing an improved opportunity to earn a fair return on investments. Marty will provide further details on the intervener's initial recommendations in Missouri electric case and the Illinois delivery rate filing. In addition to these developments in our state jurisdictions, we are awaiting action from the Federal Energy Regulatory Commission on our filing for pre-approval of supportive rate treatment for Phase I of our proposed Grand Rivers regional electric transmission projects.

We continue to position our Company for long-term success. On February 9, we announced changes in assignments for several members of our executive management. Chuck Naslund, who did a tremendous job of better positioning our Merchant Generation business to weather this period of low power prices, will assume the role of Senior Vice President Generation and Environmental projects at Ameren Missouri. Chuck will also lead our Ameren wide generation initiative which includes evaluation and optimization of environmental compliant strategies.

In Chuck's career at Ameren he has at one time or another overseen the operation of all our power plants, and has been instrumental at optimizing the performance of our Merchant fleets' existing scrubbers and reevaluating and lowering projected costs of compliance with the Illinois multi-pollutant standard. Over the coming months, we expect to see a host of proposals and rules from the US EPA ,and I believe that having Chuck's focused time and attention on Ameren wide compliance planning efforts will ensure that we make the best decisions for our future.

Steve Sullivan, our Corporate Secretary and General Counsel, succeeds Chuck as President and CEO of Ameren Energy Resource. In addition to his many years of legal, regulatory and financial experience, Steve has also been responsible for overseeing government and regulatory relations at both the state and federal levels, fuel purchasing, and our electric transmission organization. We're making these changes and others within our organization to take full advantage of our leadership expertise and bring new ideas to the evolving business conditions we face. As I mentioned, this could be a pivotal year in the area of environmental regulation.

The EPA is scheduled to finalize its proposed Clean Air Transport Rule which is aimed at reducing emissions of Sulfur Dioxide and Nitrogen Oxide. Further, the Agency is scheduled to propose requirements for retrofitting power plants with maximum achievable control technologies to reduce hazardous air pollutants such as Mercury and Acid gases. The EPA is also expected to issue cooling water standards and rules for reducing greenhouse gas emissions. These rules are expected to propose additional costs that could be substantial to our Company and, therefore, our customers.

I want to assure you that we have a team of experts in place who are continually anticipating and evaluating changing and environmental standards for our power plants and are focused on meeting these requirements in the most cost effective manner possible. In addition, we are actively working to shape new environmental rules for the benefit of our customers and shareholders. Our strategy for financial success is unchanged.

Our regulated utilities remained focused by earning fair returns on investment by seeking consistent, constructive regulatory outcomes including mechanisms that reduce regulatory lag like the use of a future test year in our Illinois rate filing. Further, we continue to focus on disciplined cost management including aligning our spending with the levels of rates authorized by our regulators. In 2010, our regulated utilities narrowed the gap between their core earnings and their allowed returns on equity by almost 300 basis points and by more than 100 basis points on a weather normalized basis.

Our 2011 regulated utility earnings guidance equates to a return on equity of 8% to 9%, in line with the improved level we achieved in 2010 on a weather normalized basis. Let me be clear that this return continues to be below our authorized level and what we consider to be appropriate. We believe our pending rate cases, our cost control efforts and ongoing work to improve our regulatory frameworks will allow us to further narrow the gap between our earned and allowed returns. Our Merchant Generation business continues to aggressively manage operating and capital costs so that this business remains well positioned to weather current low power prices and benefit from an expected power price recovery.

In 2010, our Merchant Generation business further lowered its cost structure to enhance its long-term competitiveness. At the same time, we have increased the resources we are dedicating to marketing and delivering higher value energy projects to large retail customers in the Midwest region where we compete. And at both our Regulated and Merchant businesses we remain committed to operating in a safe, reliable and environmentally responsible manner. Now, we'll turn the call over to Marty.

Thanks, Tom. Turning to page seven of the presentation, and the Year 2010 column. Today, we reported 2010 earnings in accordance with Generally Accepted Accounting Principles, or GAAP, of $0.58 per share compared to 2009 GAAP earnings of $2.78 per share. Excluding certain items in each year, Ameren recorded 2010 core earnings of $2.75 per share compared with 2009 core earnings of $2.79 per share.

2010 core earnings exclude three items that are included in GAAP earnings. The first of these is goodwill and other asset impairment charges associated with our Merchant Generation business. We recorded these charges in the third quarter. These non-cash charges reduce 2010 GAAP results by $522 million or $2.19 per share. The second item excluded is an $0.08 per share gain from the net effect of unrealized mark-to-market activity. The third item excluded in arriving at 2010 core earnings is a charge for the deferred tax impact of new Federal Healthcare laws which decreased earnings by $0.06 per share.

On page eight, we highlight key factors driving the variance between core earnings per share for 2010 and 2009. Factors favorably impacting this comparison included increased regulated Electric and Natural Gas margins, excluding the impact of rate changes. These margins lifted earnings by $0.71 per share driven by the previously discussed increase in electricity sales. Warmer summer, and to a lesser extent colder winter weather, increased 2010 earnings by an estimated $0.40 per share compared to 2009, and by an estimated $0.24 per share compared to normal weather.

New Utility rates increased 2010 earnings by $0.36 per share net of certain related expenses compared to 2009 results. Reduced financing expenses, primarily reflecting increased capitalization of construction financing costs, or AFUDC, improved 2010 earnings by $0.10 per share. Factors adversely impacting the comparison between 2010 and 2009 core earnings included a decline in 2010 margins at the Merchant Generation business of $0.79 per share compared to 2009. This reflected lower realized power prices and higher fuel and related transportation costs.

Higher depreciation and amortization expenses reduced 2010 earnings by $0.09 per share reflecting increased investment in our businesses. These investments included scrubbers placed in service in late 2009 and early 2010 at the Coffeen Merchant Generation plant. Higher non-fuel operations and maintenance expenses decreased 2010 earnings by $0.02 per share compared to 2009. Expenditures in 2010 reflected the cost of the Callaway refueling outage. There was no refueling out age in 2009. As Tom mentioned, these costs were mitigated by disciplined cost management across all our business segments.This included reduced non-fuel O&M spending at our Merchant Generation business. Last, an increased average number of common shares outstanding reduced 2010 earnings as compared to 2009 on a per share basis. This increase in shares primarily reflected our September 2009 stock offering.

Turning to page nine, I would now like to discuss the key drivers and assumptions behind our 2011 earnings guidance for our Missouri and Illinois regulated utility businesses of $2.05 to $2.30 per share. In 2011, we expect to achieve an earned return on equity of approximately 8% to 9% on regulated average utility common equity of about $6.2 billion. This guidance for our regulated utilities assumes a return to normal weather, reducing EPS by an estimated $0.24 compared to 2010 results. Weather normalized margins are expected to increase as a result of moderate growth in weather normalized electricity sales volumes, new Missouri Natural Gas delivery rates effective in February, and new Missouri Electric rates expected to be effective in early August.

Regulated utility earnings guidance for 2011 incorporates increased non-fuel operations and maintenance costs as well as increased depreciation and amortization expenses. From a timing perspective, this year's Callaway Nuclear plant refueling and maintenance outage is scheduled for the fall compared to the spring refueling in 2010 and the 2011 cost is expected to be slightly less than the 2010 level. In 2011, financing costs are expected to increase because of lower equity related capitalization, capitalized financing costs I should say, or AFUDC. This lower equity related AFUDC is expected to reduce earnings by $0.11 per share compared to 2010.

Among other things, the Post-construction accounting treatment authorized for the Sioux scrubbers in the 2010 Missouri Electric rate order, provides for Ameren Missouri to continue to capitalize for regulatory purposes its full financing costs including equity related costs through the date when the new Electric rates go into effect. However, accounting rules do not permit the recognition of current income for the equity portion of carrying costs being capitalized. That income will be recognized over the regulatory recovery period.

Moving to page ten, let's now shift to a discussion of the key drivers and assumptions behind our 2011 Merchant Generation business earnings guidance. We expect this business segment to post earnings of $0.15 to $0.30 per share this year. The largest driver of the expected earnings decline in 2011 compared to 2010 is a decrease in margins of $0.10 to $0.20 per share due to lower realized power prices and higher all-in fuel costs. We expect our Merchant plants to generate approximately 29.5 million megawatt hours in 2011 with approximately 26 million megawatt hours of this sold or hedged at an average price of $46 per megawatt hour.

Our guidance assumes that all non-hedged expected generation is sold at current market prices. In 2011, we anticipate having base load capacity available to generate up to 34 million megawatt hours in the event power prices rise in support of higher generation levels. Further, we estimate that a $5 per megawatt hour improvement in 2011 market power prices, as compared to current prices, would increase our 2011 generation output by approximately 2 million megawatt hours and our 2011 Merchant Generation margin by approximately $30 million.

Our all-in base load fuel costs are about 90% hedged and we expect the all-in cost of such volume to be approximately $23.50 per megawatt hour. We project non-fuel operations and maintenance expenses will approximate $310 million in 2011. Depreciation expense at the Merchant Generation business is expected to be essentially flat while interest expense is expected to decline, increasing earnings by approximately $0.06 per share. This lower projected interest expense primarily reflects the benefit of redeeming $200 million of Genco debt in late 2010.

Regarding key Ameren wide assumptions, our earnings guidance reflects an effective consolidated income tax rate of approximately 36.5% to 37% , which incorporates the expected impact of higher Illinois State income taxes. The average number of common shares outstanding in 2011 is expected to approximate 242 million, up from approximately 239 million in 2010, reflecting the use of new issue shares for our dividend reinvestment and 401(k) plans.

As I close our discussion of 2011 earnings guidance, I'll remind you that any net unrealized mark-to-market gains or losses will affect our GAAP earnings but are excluded from our GAAP and core earnings guidance because the Company is unable to reasonably estimate the impact of any such gains or losses. Further, our earnings guidance for 2011 is subject to the risks and uncertainties outlined or referred to in the Forward-looking statements section of today's press release.

Turning then to page 11, we provide both our actual 2010 and projected 2011 cash flow information. As Tom mentioned, we were able to achieve free cash flow of $341 million in 2010. For 2011, we anticipate free cash flow of approximately $100 million. Cash from operations includes the benefits of bonus depreciation, actual for 2010 and expected for 2011, and for 2011, cash from operations includes a planned incremental contribution to Ameren Illinois' Post-retirement Benefit Plan of up to $100 million.

The amount is expected to be confirmed in the course of Ameren Illinois' rate case. Despite lower expected earnings and higher capital expenditures in our Merchant Generation business, we anticipate that free cash flow from this business will be positive in 2011. Our only long-term debt maturity in 2011, is a $150 million Senior secured note at our Illinois Regulated utility, which we plan to redeem using available cash on its balance sheet. Our total available liquidity was a solid $1.7 billion at the end of January 2011. This includes cash on hand as well as available borrowing capacity under our revolving credit facilities.

Moving now to an update on key pending regulatory matters. On page 12, we provide a summary of the pending Missouri Electric rate case. As Tom mentioned, we have filed a request with the Missouri Public Service Commission for a $263 million rate increase that incorporates a 10.9% return on equity, a 51% equity ratio and rate base of $6.8 billion. The vast majority of the rate increase request is driven by rate base investments and higher net base fuel costs. By the time rates go into effect, we will have put into service in excess of $1 billion of new investments to improve reliability and provide cleaner air for our customers.

The filed rate base is approximately $850 million higher than the level used to set rates in the May 2010 order. Approximately $73 million of the revenue request relates to increased net base fuel costs. On page 13, on February 8 other parties filed their initial recommendations in this case. The Missouri Public Service Commission staff recommended a $72 million annual revenue increase using the 8.75% mid-point of their recommended return on equity range and a 51% equity ratio.

The most significant drivers of the difference between our request and the staff's recommendation are return on equity ,which accounts for about $125 million of the difference at the staff's mid-point, rate base adjustments, including a $32 million proposed Sioux scrubber disallowance which in total account for about $25 million of the revenue requirement difference, various operations and maintenance expense differences of about $25 million to $30 million, and net base fuel cost adjustments of $15 million to $20 million. Also, the staff recommended that the fuel adjustment clause be changed to pass through to customers 85% of deviations between actual net fuel costs and the level of net fuel costs included in base rates. Currently, 95% of deviations are passed through.

Other particulars of the staff's recommendations are listed on page 13. Several other parties also filed recommendations in the case. The Missouri Industrial Energy Consumers recommended $147 million of downward adjustments to our requested revenue requirement. These downward adjustments included approximately $65 million related to a 9.75% mid-point return on equity, approximately $26 million related to income and property taxes, and approximately $24 million related to lower net base fuel costs and various amortizations. As is typical, MIEC did not directly address every element of our rate filing.

The Missouri Energy Group, which represents certain other business customers, filed testimony supporting a 10.2% mid-point return on equity. Finally, the Office of Public Counsel has recommended disallowance of the approximately $90 million of Taum Sauk Power Plant investment which we have included in our filed rate base. We are asking for recovery of only the portion of Taum Sauk costs that are related to enhancements or that would have been incurred in the absence of the upper reservoir breach that occurred several years ago, consistent with our 2007 settlement agreement with the State of Missouri. We will soon update our filing for operating and financial data through the end of the true-up period which is the 28th of this month.

As a result, it is likely that many of the numbers put forward by parties to the case including those of Ameren Missouri will be adjusted. We expect that the updated numbers will be reflected in an April 20th public filing by the Public Service Commission staff and evidentiary hearings are scheduled to begin on April 26. A Public Service Commission order is expected in July with new rates expected to be effective in early August.

Turning then to Page 14. On February 18, our Illinois utility filed a request with the Illinois Commerce Commission to increase Electric and Gas delivery rates by $111 million annually. The request incorporates returns on equity of 11.25% for electric service and 11% for gas service. The filed capitalization is 53% equity with aggregate rate base of approximately $3 billion. The request is based on a future test year ended December 31, 2012.

Among other items, we are asking for a pension expense rider that would synchronize the amount of pension expenses recovered in rates to the actual level of each year's pension expenses. We are also requesting authority to defer the impact of the increase in the Illinois corporate income tax rate which climbed from 7.3% to 9.5% on January 1, 2011, and to collect the resulting regulatory asset over a two-year period. Key drivers of the rate request are listed on this page. They include higher operating expenses net of reductions, and administrative and general and pension and benefits expenses. Other drivers are higher income and other taxes and the cost of capital reflecting proposed rates of return and an updated capital structure.

In addition, we are requesting revenues to reflect higher depreciation and amortization expenses. Expected load growth mitigates the requested rate increase. The Illinois Commerce Commission is required to issue a rate decision in 11 months and new rates are expected to be effective by mid-January 2012. We are certainly aware that higher utility rates are difficult for some of our customers to absorb, especially in the current economic environment. At both our Illinois and Missouri utilities, we have taken many proactive steps to help our customers manage their energy costs. These steps have included reductions in planned operating and capital spending.

Our cost control efforts benefit utility customers by holding down the amount of rate increases we need to request. Other steps that help customers manage their energy costs include our active energy efficiency programs in both Illinois and Missouri. On page 15, we detail Amerens' updated five-year capital expenditure outlook. Over the 2011through 2015 period, cumulative capital spending is projected to range between $6.4 billion and $8.2 billion with an annual target range of between $1.3 billion and $1.7 billion. I would characterize the environmental expenditures embedded in this outlook as those required to meet current environmental rules and regulations as well as our assessment of the likely impact of the proposed Clean Air Transport Rule and Coal Combustion Byproduct rules.

As Tom discussed, this five-year budget includes the estimated cost of installing scrubbers at each of the two units of our Merchant Generation Newton plant and at two units of a Missouri regulated plant. On this page, we also provide a percentage breakdown of our five-year infrastructure investment budget for our regulated businesses by jurisdiction and type, via FERC regulated transmission, Missouri regulated environmental controls or Illinois regulated.

Moving now to page 16. We outline our expected capital expenditures for our Merchant Generation business for each of the next five years, showing the breakdown between expenditures for maintenance and for environmental compliance. The amounts on this graph reflect the previously mentioned acceleration of the in-service dates for scrubbers at the Newton plant and the previously mentioned equipment upgrade. These Merchant Generation numbers are included in the total Ameren wide capital expenditures that I discussed a few minutes ago. Of course, we will continue to review and adjust our Merchant Generation spending plans in light of evolving outlooks for power prices, delivered fuel costs, environmental standards and compliance technology among other factors.

Moving now to page 17. We provide an update on our 2011 and 2012 forward power sales and hedges and introduce our 2013 hedge data. As you can see, we have significant hedges in place at power prices above current market levels. We already discussed our 2011 power hedges. For 2012, we have hedged approximately 15 million megawatt hours at an average price of $50 per megawatt hour. Further, for 2013 we have hedged approximately 7.5 million megawatt hours at an average price of $42 per megawatt hour.

I would note that about 55% of the megawatt hours hedged in 2013 are associated with long-term contracts and the remainder are financial contracts. None of the financial contracts hedged in 2012 and 2013 expected sales are [sin hub] contracts and the pricing reflected has already been basis adjusted as necessary to Illinois generation node pricing based on two-year historical average basis differentials. Our capacity sales are approximately 75% hedged for 2011, approximately 44% hedged for 2012, and approximately 22% hedged in 2013. To assist you in understanding our Merchant Generation business segment's margin drivers we have provided a pie chart that breaks down our 2011 expected revenue by type.

Turning to our final page, number 18, we update our Merchant Generation segment's fuel and related transportation hedges. We previously discussed our 2011 fuel hedges. For 2012, we've hedged approximately 16 million megawatt hours at about $25 per megawatt hour. For 2013, we've hedged approximately 4 million megawatt hours at about $28.50 per megawatt hour. These 2013 coal hedges include a large proportion of our expected burn of Illinois Basin coal and a much smaller proportion of our expected burn of Powder River Basin coal. To provide perspective our typical burn is 3% Illinois and 97% Powder River Basin coal. The embedded cost of coal in this 2013 hedge price is approximately $24 per ton which is approximately $7.50 per ton higher than current 2013 broker quotes for our PRB coal.

Similar to our previous slide dealing with Merchant Generation revenues, we have included a pie chart that breaks down forecasted 2011 all-in fuel costs to provide a perspective on how each component contributes to our overall costs. This completes our prepared remarks. We will now be happy to take your

Thank you. We will now be conducting a question-and-answer session.(Operator Instructions) One moment, please, while we poll for our first question. Our first question comes from Paul Ridzon with KeyBanc. Please proceed with your question.

Yes, you had a $522 million write-down at Merchant but depreciation is flat. What's driving that? Is it really just all goodwill?

Yes, Paul. If you recall there was goodwill, there was also some plant impairment, but the largest part was goodwill which, of course, for accounting purposes and amortized or depreciated, the power plant write-off piece was much smaller but what we also did is took a look at the lives of the power plants within the fleet, so while a write-off of some power plant expense would typically decrease depreciation, we've also taken a look at the lives of our other units and net it came out to no net positive or negative impact from depreciation expense.

What drove the acceleration of Merchant CapEx? Is there something fundamental in the market or are you trying to take advantage of bonus depreciation?

Well, bonus depreciation is part of it. That certainly helps in terms of the returns on those projects. But as we mentioned in the call, when you look at the CapEx for Merchant, the biggest driver you see there is moving up the in-service date of the Newton scrubbers. Previously, we had forecast that as 2014 and 2015. We've moved that up to late 2013, early 2014, and as we said on the call primarily because of the expected impact that the Clean Air Transport Rules will have on our fleet. So we believe it's prudent to move that investment up and that's the big driver of the cash flows. But you're right, there is also then the benefit that we'll get from bonus depreciation.

And how much is bonus depreciation and how much is regulated?

Well, I guess the bonus depreciation for 2010 that came out in that law Company-wide is expected to help cash in 2011 by about $100 million to $150 million.

How about for 2012?

Yes, I don't have the 2012 numbers at this point.

Is there a breakdown between Merchant and regulated?

Of the $100 million to $150 million, I don't have the breakdown overall between, on the $100 million to $150 million between segments.

Okay, thank you very much.

Okay.

Our next question comes from Reza Hatefi from Decade Capital. Please proceed with your question.

Thank you. Just wanted a couple of clarifications on your hedging. Fuel per megawatthour in 2011 and 2012 went down versus your third quarter slide by about $1 to $1.50 per megawatthour. What drove that?

Yes, it's a good point. In both cases, we've pointed out for some time that the hedges we had in place for coal were at prices that we believe were above current market prices for coal, so as we've layered in additional hedges for both 2011 and 2012, we have brought down the average cost per megawatthour of the blended generation. In 2011, however, in addition to the benefit of those lower cost hedges we put in place, we're also benefiting as we've looked at these numbers and refined them lower emission allowance costs as well as lower expected taxes that we pay on our delivered fuel costs, so in 2011, we're getting the benefit of I'd say all three of those factors. In 2012, it was largely driven by the lower cost coal we put in place.

And then your 2013 hedges, $42, are they around the clock or are they weighted more towards peak as of now? How should we think about that?

You know, I think as you look at those hedges, the 2012 hedges look very much like an around the clock kind of product. ATC typically about 47% to 48% on peak. The 2013 hedge profile is a little more weighted to our baseload generation mix which tends to be about 52% on peak.

And just finally, could you comment on, I guess, strategically your thoughts on the Merchant segment and with the forward curve being as weak as it is, any thoughts there in terms of this segment continuing to be part of Ameren?

Well, this is Tom Voss. We think that it's one of our core businesses, it's what we know how to do. We know how to generate electricity at the power plants. We think we do it very well. We think those Merchant plants are well positioned. They've got recent environmental upgrades. They have very good heat rates. They dispatch well on the MISO stack, so we think generally they are positioned well for a recovery of power prices in the future.

Thank you very much.

Our next question comes from Paul Patterson with Glenrock Associates. Please proceed with your question.

Good morning, guys.

Good morning, Paul.

Good morning.

On the 8-K that you guys filed late Friday, it wasn't clear to me what the actual case is about with those four customers. If you look at the 10-Q, or at least when I looked at it, it just said they are appealing certain aspects of it. I guess what I'm trying to get a sense of here is what is it that the merits of the case that, I guess, OPC apparently feels as well has got some issue there? Can we get any sense as to what the impact of that would be versus just the stay which seems to be sort of a more generalized or perhaps a bigger impact, do you follow me?

Hi, Paul. This is Warner Baxter. Let me try and address your questions. I think there are probably two of them in there. Number one, as you saw in the 8-K filing, basically the Office of Public Counsel and some of our industrial customers are arguing that a stay of our rate increase which was granted to four of our industrial customers in a December 2010 Circuit Court order should essentially be applied to all customers, and that is essentially what they've asked the Commission to address.

They have not addressed the Commission to address the essential merits of those two rate orders which are on appeal before the various courts. And those orders probably had anywhere from eight to ten issues which are still pending.

And so in the bigger picture of things when you look at those issues which are being appealed they are obviously a much smaller subset compared to the overall rate increase and as was stated on the call we do not believe that any of those issues on the merits are probable of loss at this time and we will continue to address those appropriately in the courts.

And, of course, as Tom said in the call, we strongly disagree with the positions taken by both the Office of Public Counsel and the industrial customers in their interpretation of that Circuit order, as well as the overall stay order that was issued in December of 2010. And you can plan of us to vigorously defend our position before the Public Service Commission and the courts as appropriate and you can expect our complete response to those matters no later than February 25.

Okay, and then just we've seen some companies move from MISO to PJM, partly, I think, because of capacity pricing differentials. I was wondering if you guys were thinking about anything like that or how you're looking at the capacity markets going forward in your area versus what you might be seeing otherwise if you were in PJM?

This is Tom Voss. We have been working with MISO to develop a better capacity market so it looks more like PJM's market, capacity market, and we expect MISO to file sometime later this year a plan to the FERC that would show a better capacity market than what currently exists, so our plans right now are to work with MISO on improving that.

How soon should we think about the changes that MISO might propose actually flowing through to the bottom line of generators in MISO?

Well we think right now that if everything goes right and everything keeps moving it should be some time in the 2012 year.

Okay, thanks a lot.

Our next question comes from Erica Piserchia with Wunderlich Securities. Please proceed with your question.

Hi, I just have a couple questions. Wondering first if on the Merchant if you can talk a little bit about shaping? I know historically, you've gotten shape on, I think, anywhere from 20% to 40% of your megawatthour sales product and it looks like you've locked in some shape on 2012, 2013 relative to what the ATC price is in that market. I'm just wondering if you can talk about what percentage of your sales are currently getting shape and how we should think about that kind of going forward?

Well, I think, Erica, as we look out over time, we, frankly, try to sell as much as we can with the shape product and we haven't really given a breakdown per year but you're right. I mean, our sales strategy is to go after the higher margin customer segments in the areas that, where we have generation as those opportunities present themselves and lock in margins above which is, sorry, there's some noise on the line, I'm not sure where that's coming from but we're seeking to lock in higher margins than you can see in those visible power prices.

Okay, and then, I guess, just you talked about potentially being able to ramp up your generation output, I believe you mentioned you could potentially ramp up to as high as 34 million megawatthours. Just looking back over the last couple years you sort of kept the output, obviously, sort of flat. When you talk about potential market recovery, what levels would you need to see in the market to kind of get you more incented towards doing that? Are we talking about going back to pricing that was in existence a couple years ago or clearly, probably a little bit longer term? What are your thoughts on that?

Well, what we tried to provide in the script was a little bit of a metric in terms of if we saw a $5 move in power prices based on our open and available generation for 2011, that could produce up to $30 million of additional margins, and we provide that metric to give you a sense of given the available capacity that we have, these power prices were to move, what kind of incremental generation we would have and what those margins are. Any given year, the amount of generation that we've got available, obviously, is dictated by the outage schedule we have for that year, but we think that metric may be helpful to you as you look at how or where our incremental generation is in terms of cost and if it were to be dispatched at those higher prices what kind of margins they could get.

Sure, okay, so [the sensitivity.] Last question, just on your 2011 guidance for the regulated end of the business. Does the low end of the range encompass sort of the, on the Missouri side the staff's recommendation, and on the Illinois side sort of the existing status, well, I guess, it would because your new rates there wouldn't take effect until 2012. But on the Missouri side is the staff sort of end of the recommendation sort of included in that low end or how do we think about that?

Well, I wouldn't really tie it to that necessarily as much as just to say that we think it's a reasonable range given a variety of things, estimates and expectations that we make and certainly regulatory outcomes is one of those but also sales growth, operating spending levels, storms and plant outages and the like, and certainly our goal remains to improve our earned returns over time.

We made good progress in 2010. We plan to make incremental progress in 2011 and continue to align spending with regulatory outcomes that we receive, so I wouldn't tie the ranges to anybody's recommendations in our case particular but, again, a range that incorporates those elements of our estimates that I laid out.

Okay, thank you.

Okay.

(Operator Instructions)Our next question will come from Ashar Khan with Visium. Please proceed with your question.

Good morning. Marty, can I just ask you, when were the 2013 hedges put in place, because the new data, were they put in place during the last three or six months? Could you give us some timing of those hedges?

You know, Ashar, we've been working on hedges for some time, so some of those were put on in 2010 timeframe, and others were put on from periods prior, but we've been working at those over time. We're never kind of sitting on our hands, we're always looking at sales opportunities as they present themselves. We've talked about our strategy of going after retail customers and you have to act on those when they are available in the market and they arise from time to time and we execute on those.

Okay. And if I can remember, the contract with the Illinois rate ends in 2012, am I right?

Yes, that's right.

Okay. Thank you very much.

You're welcome.

Our next question comes from Julien Dumoulin-Smith with UBS. Please proceed with your question.

Good morning, thank you.

Hello, Julien.

So I just wanted to first touch on sort of the Com Ed side of the -- or the Illinois side of the House and ask about the Com Ed legislative proposal. Just on your side, are you guys supportive of it and any kind of expectations out of the process this year, more confidence in certain aspects relative to the others?

Good morning. This is Scott Cisel. I'll respond to your question. Concerning the rate formula bill, we certainly are very supportive of the bill as its been presented. As you know, it would enable utilities to continue to make prudent and reasonable investments into the systems and then be allowed to realize a reasonable return on the investment.

The amendment is the rate formula bill will be introduced this afternoon in a committee hearing and then from that point on it will begin the process of discussions and eventually consideration. It's very early in the session to give any sort of a prediction but we and others will participate and we will strive to see if we can end up with a workable compromise and do so yet this spring legislative session.

Great, and then secondly, on the regulated side of the house, with regards to the stay order, perhaps could you discuss some of the levers that you might be able to pull to resolve the pending litigation, be it in the Appeals Court, at the Commission, perhaps just walk through some of the -- where to from here if, you will?

Yes, this is Warner Baxter. I'll respond. I think as we've stated, we're going to be filing our position by the end of this week with the Missouri Public Service Commission on the Office of Public Counsel and the Industrial Consumers pleadings and really beyond that I'm really not in a position to address really any other specific questions or positions or strategies that we're going to take for this pending litigation matter.

Great. Thank you. And then finally just quick last question. More detail oriented, on the O&M side for Merchant Gen, I notice that's a little bit of a rise year-on-year. Just could you walk through that very quickly if you don't mind?

Yes, I think that as you look at the Merchant Generation business at 310, slightly up from where we were last year and some of the things in there are nuts and bolts items like increases in benefits expenses year-over-year, increases in wages for employees, so I think there's just some of those nuts and bolts items in there. We also do have, however, an outage at one of our power plants planned for this year where we're looking to do both some maintenance and capital work and that too is impacting the figures.

Wonderful. Thanks, again.

Yes, no problem.

Our next question comes from Robert Howard with Prospector Partners. Please proceed with your question.

Good morning. Wanted to just ask about the Merchant Generation CapEx outlook slide. 2015, there's really a pretty dramatic drop. I guess I figure some of that, at least the environmental part would be those projects get done, but also the maintenance CapEx seems to be going down dramatically as well. Just sort of wondering what was happening there, if maybe maintenance CapEx was getting pushed into forward years or what's happening?

Yes, it's a good question. I think that's right. I would note that in 2010, the point of reference, we actually were able to limit the capital expenditures for that segment to $89 million, so certainly being able to keep maintenance and other as well pretty low is something that we think is doable. So when you look at 2015 levels, not too out of line with what we're seeing in 2010.

But our thought is actually, given some of the maintenance that's already been done and the years leading up to the present as well as the maintenance and other items that we've got planned for 2011 through 2014 that we will have done requisite maintenance on our big baseload facilities and feel like when we get out to 2015 the necessary efforts and expenditures will be behind us. So as we've said on the call, certainly as we move through time we'll look at the power price environment.

We'll pay close attention to our cash flows. Some of the expenditures in 2013 and 2014 could conceivably move out to 2015, but right now, I think this is a good snapshot of where we stand today.

And so are those low levels for 2015 something that could kind of continue out for the next couple years? It sounds like the 2015 numbers from a maintenance CapEx perspective is maybe a tiny bit lower than the long-run average because you pushed forward, but will you be able to kind of keep it low like that for a couple years before it gradually ramps up?

Well, I can't comment on 2016 and 2017. I think you're right over a long term. You're going to need to do and perform certain maintenance CapEx on your plants, but, again, as far as looking out to 2015, this is what we see.

Okay, thank you.

Our next question comes from David Paz with Bank of America. Please proceed with your question.

Good morning, thank you. I just had a question on your average utility book equity in 2010. You guys were saying last year it would be about $6 billion. What did it end up at?

Boy, I don't know. I would think it probably ended up somewhere close to that. David, I don't have the exact number.

Okay, so then as we look at the $6.2 billion for 2011 average equity, how much of that or what percentage of that is Missouri and what percentage of that is Illinois?

Yes, I don't have that breakdown either. I mean, it's obviously a roll forward of increased earnings among the regulated businesses less the dividends, it's pretty simple math, and I know you know that, but I don't have the breakdown between the regulatory jurisdiction.

Okay, and just quickly on the O&M growth, I know you said there's a Callaway refueling outage later this year and that the expected impact should be slightly less than what it was last year yet you have increased non-fuel O&M as one of the drivers. Can you get it, should we assume, I mean, I guess, what kind of growth in non-fuel O&M should we be looking at?

Well, I think as we look into 2011, we already talked about Merchant, the O&M is going up a little bit there.

Right.

And then we commented on regulated overall. Certainly, as you think about that, we said last year if we were successful in the rehearing under the Illinois rates that we would restore some of the spending in Illinois that had been reduced and we are following through on that. So we've got some incremental O&M spending in Illinois.

And then we do have some incremental spending in Missouri as well, both scheduled for our energy delivery business to continue to improve reliability there as well as in our power plants, but I don't have the exact percentage in front of me but we'll continue to look for opportunities to synchronize the spending with the regulatory outcomes that we get.

Great, thank you.

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

Hi, guys. Question for you just on the coal hedging at the Merchant Generation. I'm not positive I understood some of the comments about Illinois Basin and PRB. Does this imply you're starting to in the forward market to buy a bit more Illinois Basin so you benefit from the better heat content, or are you keeping the split kind of similar between PRB and IB?

You know, thanks, Michael. I wouldn't say the comment was about our strategy going forward in terms of fuel burn. We'll certainly buy what we believe is the most economical to burn. But what we were really trying to point out there is that the embedded cost of our coal hedges for 2013 are well above current PRB broker quotes. And so what I was really trying to convey there is similar to what we've seen in 2011 and 2012 as we've bought additional fuel, the average hedge price has come down and what I was trying to convey there is we have the same expectation with respect to 2013 is when we lay in additional hedges, if we were to lay them in today, we would bring down that average price per megawatthour.

And are you still expecting, you've talked in the past that kind of the rail transportation piece, or however you use transportation, will be roughly two-thirds of the total all-in cost of fuel?

Yes, we break that out, if you see on that slide, slide 18, you actually see that for 2011 the transportation, about 52% with fuel surcharges gets you to about 58%, so that's sort of our expectation for 2011. We've also commented over time that we do believe that while you look out, you see some of the rail contracts or rail hedges rolling off. We do believe that the contracts we have in place today are at about market rates, so we're not really expecting any major deviation as we lock in new rail contracts.

Got it. Okay, thank you, guys. Much appreciated. I'll follow-up with Doug offline.

Okay.

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

Hi, good morning.

Good morning.

I just wanted to clarify, I think you said that when you were talking about cash flows, did you say you're planning to pay off the Illinois, Ameren Illinois maturity of $150 million in June, or were you going to refinance that?

No, you're correct. Our plan is to pay that off.

Okay, and then will you continue to issue new shares for like the DRIP program and those programs and if so how much would you expect that to be?

We do expect to do that, to continue that through this year. That's embedded in our guidance and I guess that's in the range of $90 million or so.

Okay, will there be any other financing then given that you expect positive free cash flow?

At this time, we don't have any other plans.

Okay, thank you.

Our next question comes from Charles Studness with Studness Research. Please proceed with your question.

Good morning. I'm disturbed by the trend in CapEx. You spent $1.031 billion in 2010. You show here $1.250 billion for 2011 and the mid-point of your range for 2012 to 2015 is $1.5 billion. Why are you increasing your CapEx while the price to book is below one and how do you expect to get favorable rate decisions if you continue to invest shareholder capital when markets tell you not to do so?

Well, I think, Charles, as we look out certainly we've been cognizant about managing our capital expenditures. If you look back, we've brought those down considerably over the past couple of years. As you look out at our capital expenditures, say for the regulated businesses, and if you listen to what we talked about, we talked about having two additional scrubbers in place in the Missouri regulated business over that five-year period.

And if you look at our capital expenditures out over that five-year period versus prior disclosures we've given, they're about flat to down a little bit versus what we'd previously shown. So we are certainly managing our capital and we will continue to manage our capital investments in light of the regulatory outcomes that we receive.

So that said, what we're looking to do is improve the regulatory returns in both our primary Illinois and Missouri regulated businesses as well as deploy capital into transmission which is something you see as well in our five-year forecast. And our strategy for doing that, as we talked about in Illinois, using a forecasted forward test year in the current rate case to improve the returns and improve our ability to earn fair returns on the capital that we're deploying. And we've certainly got an active rate case in Missouri right now where we are working to achieve a constructive outcome and a constructive framework that will provide for going forward good returns on the investments we make in Missouri.

Okay, thank you.

Our next question comes from Sarah Akers with Wells Fargo Advisors. Please proceed with your question.

Hi, good morning.

Good morning.

I'm curious as to whether you're having conversations with the MISO about the potential for reliability must run contracts and whether that's something you expect would be addressed in a capacity filing with the FERC? And, also, just any comments or insight you could provide on your expectation as to what the MISO capacity proposal might look like?

We have talked to MISO, actually fairly recently, and they are in the process of studying as far as what's going to be required. Right now, the MISO footprint is, to say is an evolution of flux is an understatement, with First Energy and part of Duke system, leaving MISO, but I know they're looking at that, but that's all I can say on that topic specifically. And just add they are working on the seams issue between MISO and PJM and the portability, if you will, to transfer energy across that seam for all market participants.

Great. Thank you.

Our next question comes from Steven Gambuzza with Longbow Capital. Please proceed with your question.

Good morning.

Good morning.

The CapEx guidance that you provided is very specific for Genco. There's a rather wide range for the rest of the Company between 2015. I guess I was surprised to see point estimates for Genco within this wide range, and I was wondering if you could comment on the potential for the scope of the program, either at Genco or Union Electric to be changed to include additional controls and whether pending EPA rules on hazardous gases and mercury might significantly impact either the regulated or the unregulated forecasts?

Sure. Yes, I think that as Tom mentioned in his prepared remarks, we, as well as everybody else in the industry, I think, is anticipating to see some proposed rules coming out of EPA middle of March and we'll see what those require.

As Tom mentioned, we've put together a team of people that have been working diligently over the past year and will into the coming year to take a look at what comes out of the EPA and make the best decisions about what kinds of additional investments will or won't be made in plants we have and to try to make the most efficient economical investment decisions that we can for the best interests of the shareholders and the customers.

So could that require additional CapEx? Certainly so, but we are really going to make those decisions on a plant by plant basis across our fleet.

In your prepared remarks I heard you mention the coal combustion byproduct rule and the Clean Air Transport Rule.

Yes?

As the two primary regulatory issues that your CapEx forecast was taking into account. I didn't hear you mention the mercury or the hazardous gas rules, but we should assume that your expectation regarding those regulations are embedded in your forecast?

Yes, just to be clear. We, historically, when we've provided our CapEx, we've talked about it being consistent with current laws and regulations. And so what we've done here is we've seen proposed rules that have been out and just for the Clear Air Transport Rule as well as for coal combustion byproducts, and so based on our assessment of the likely outcome on those rules, we've updated our CapEx for both Missouri as well as for the Merchant business to reflect our expected outcome under those rules.

And then we'll see what comes out of the federal EPA. I would remind you, Steve, that in our Merchant part of our business, we are complying with also the Illinois multi-pollutant standard which already had requirements for certain of those elements that the federal EPA looks to regulate, so we'll see how those compare as those proposed rules come out and evolve.

Okay. And then finally, can you comment on which two units in Missouri you do intend to scrub?

No, that's something that's going to be assessed. We certainly will be getting some initial design work but that would be applicable to whatever units we decided to go forward with.

Okay, thank you.

This is Doug Fischer. We have time for just one or two more questions here.

Our next question comes from Daniele Seitz with Dudack Research. Please proceed with your question.

Thank you. I was going to ask exactly the same two questions, so at this point, your CapEx are really built on your estimates of what the EPA rules are going to come out with. It's not just on the Illinois multi-pollutant standards, is that correct?

Yes, and no, Daniele. I think, again, what we're saying was that it does incorporate an assessment of requirements that the Clean Air Transport Rule will impose as well as rule for coal combustion byproducts but nothing further than that from a federal EPS standpoint.

Okay, and on your side, are you trying to convince your regulators that actually in order not to file so many rate cases, it would be easier if you were operating under riders at this time or are they reluctant to allow these kind of rules?

Well, I think, Daniele, certainly we've been successful at getting some riders over the past few years and those can have the added benefit of being able to go for more extended time periods between rate cases and be able to recover your costs on a timely basis, so that is something that we have pursued and will continue to pursue in the future.

Obviously, the Com Ed legislative proposal would put it a step forward toward a more timely type of regulatory environment. Will that replace whatever ambitions you have regarding riders?

Well, I think as it relates to Illinois, the rate case that we filed on Friday incorporated a forward-looking test year. It also incorporated a request for a rider, or a tracker, a rider for pension expenses going forward, so we've made those filings. I think the legislative proposal that has been discussed, that Scott earlier said we are supportive of, if that was put in place, I think likely would supersede those other kinds of efforts.

And on the side of Missouri, do you see any new effort or progress in that area?

Could you repeat that? I know it was Missouri, but I couldn't tell what the --

Do you see any inroads that you may make regarding additional riders?

Daniele, this is Warner Baxter. I would comment on it in a couple ways. Number one, we certainly made good progress in our last rate case in maintaining some of the rider mechanisms as well as getting the construction accounting that we got for the Sioux scrubber project. And even in this case, this current rate case, we are seeking to enhance some of the recovery mechanisms that we have for some of our construction projects as well as for energy efficiency.

Beyond that, we continue to look at some of the regulatory rule makings. We continue to look at potential legislative efforts, aligning our spend. We're looking at a host of things to continue to mitigate the regulatory lag and improve our returns, and so that is an effort that was ongoing and we recognize the importance of that. Not just to our shareholders but also to our customers because they give us the necessary cash flows to invest in our infrastructure to deliver good reliability and cleaner energy for them.

I think at that point we're going to have to end here. We've gone a little bit longer than normal but we thank you for your participation in this call. Let me remind you again that this call is available through March 1 on playback and for one year on our website. Today's press release contains instructions for listening to that playback. You may also call the contacts listed on the release.

Financial analyst inquiries should be directed to me, Doug Fischer. Media should contact Susan Gallagher. 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.