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Executives

Thomas Voss – Chairman, President, Chief Executive Officer

Martin Lyons – Senior Vice President, Chief Financial Officer

Doug Fischer – Director of Investor Relations

Analysts

Paul Ridzon – Keybanc

Paul Patterson – Glenrock Associates

Terran Miller – Cantor Fitzgerald

Ashar Khan – Visium Asset Management

David Paz – Bank of America

Reza Hatefi – Decade Capital Management

Michael Lapides – Goldman Sachs

Tom Rebinoff – Fore Research & Management

Alex Tai – Standard General

Julian Dumoulin-Smith – UBS

Raymond Leung – Goldman Sachs

Ameren Corporation (AEE) Q1 2012 Earnings Call May 4, 2012 10:00 AM ET

Operator

Greetings and welcome to the Ameren Corporation’s First 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. If anyone should require operator assistance during the conference, please press star, zero on your telephone keypad. As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Doug Fischer, Director of Investor Relations for Ameren Corporation. Thank you, Mr. Fischer. You may begin.

Doug Fischer

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. 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. 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 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 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 statement section in the news release we issued today and the forward-looking statements and risk factors section in our filings with the SEC.

Tom will begin this call with an overview of first quarter 2012 earnings and 2012 guidance, followed by a discussion of recent regulatory and business developments. Marty will follow with more detailed discussions of first quarter 2012 financial results as well as regulatory and other financial matters. We will then open the call for questions.

Here is Tom, who will start on Page 3 of the presentation.

Thomas Voss

Thanks, Doug. Good morning and thank you for joining us. Today we announced a first quarter 2012 net loss in accordance with generally accepted accounting principles, or GAAP, of $1.66 per share compared to first quarter 2011 GAAP net income of $0.29 per share. This first quarter 2012 GAAP net loss included a non-cash pre-tax asset impairment charge of $628 million related to the write-down of our Duck Creek merchant generation energy center which was triggered by the first quarter 2012 sharp decline in forward prices for electricity. Excluding the impacts of this charge, a related tax adjustment and mark-to-market activity, first quarter 2012 core results were positive with earnings of $0.22 per share compared to first quarter 2011 core earnings of $0.25 per share. The decrease in first quarter 2012 core earnings compared to first quarter 2011 core earnings primarily reflected the impact of warm winter weather on our regulated utility electric and natural gas sales.

First quarter 2012 winter temperatures were among the warmest on record with heating degree days approximately 30% fewer than those experienced in the year-ago quarter. As a result, kilowatt hour sales of electricity to weather-sensitive residential and commercial utility customers declined 9%. Natural gas sales were also negatively impacted by the much warmer weather with first quarter 2012 volumes down 21% compared to the first quarter of 2011. In total, we estimate that warmer temperatures reduced first quarter 2012 earnings by $0.13 per share compared to the first quarter of 2011, and by $0.10 per share compared to normal.

On a positive note, kilowatt hour sales to industrial customers rose 5% compared to the first quarter of 2011, a sign of economic improvement in our region. A second key driver of lower first quarter 2012 core earnings compared to the year-ago quarter was reduced margins in the merchant generation segment. The decreased margins reflected reduced generation to the merchant segment due to lower market prices for electricity.

The effects of the warm weather and lower merchant margins were partially offset by increased electric utility rates in Missouri, increased natural gas delivery rates in Illinois, and lower non-fuel operations and maintenance expenses, including reduced storm-related costs.

Turning now to Page 4, today we are affirming our core earnings guidance range of $2.20 to $2.50 per share for this year. The much warmer than normal weather led us to reduce core guidance for our regulated utility business by $0.05 per share at both the high and low ends of the range to $2.15 to $2.35 per share. This reduction in earnings guidance for the utilities is offset by an increase in the core guidance range for our merchant generation business segment of $0.05 per share at both the high and low ends of the range to $0.05 to $0.15 per share. The increase in merchant generation guidance primarily reflects lower expected depreciation expense due to the write-down of the Duck Creek energy center.

I would now like review some of our business plans and some recent business developments at our regulated and merchant generation businesses. Moving to Page 5 and our strategy for regulated businesses, we continue to believe that modern, constructive regulatory frameworks which provide timely cash flows and a reasonable opportunity to earn fair returns on investments are clearly in the best long-term interest of our customers in the states in which we operate. These frameworks support our ability to attract capital on terms which facilitate timely investment in order to modernize our regulated companies’ aging infrastructure. Such investments enhance reliability and the quality of service we can deliver to our customers and also help create good paying jobs.

Further, these investments help us meet our customers’ and states’ energy needs and expectations which ultimately drive higher levels of customer satisfaction. Constructive formula ratemaking is in place for both our Ameren Illinois electric delivery service and our FERC-regulated electric transmission business. As a result, we are able to move forward with plans to invest meaningful incremental capital in these businesses.

Over the next 10 years, our Illinois electric delivery business plans to invest $625 million over and above levels we have been spending in recent years and create 450 jobs during the peak program year. The improved infrastructure resulting from this investment will enhance reliability and provide customers with the energy usage options made possible by smart meters.

At our electric transmission businesses, the need to replace aging infrastructure and improve the capacity of the high-voltage highway in our region, coupled with the constructive formula ratemaking utilized by the FERC, are driving our plans to invest approximately $1.7 billion in transmission projects over a five-year period ending in 2016. I am pleased to report two recent positive developments related to these transmission growth plans. The Federal Energy Regulatory Commission approved forward test year rate treatment for Ameren Transmission Company, or ATX, effective March 1, 2012; and on May 1, we began our public participation process on route design for ATX’s $800 million-plus Illinois Rivers project, a MISO multi-value regional line. This process is required prior to our filing for a certificate of public convenience and necessity for the project with the ICC, a filing we plan to make in the fourth quarter of this year.

In Missouri, however, we continue to see the need to enhance the existing regulatory framework to support investments in our aging infrastructure and to meet our customers’ rising expectations, as well as to provide our company timely cash flows and a reasonable opportunity to earn a fair return on those investments. One approach we are pursuing is through the regulatory process. In particular, we’ve made several proposals in our pending electric rate case designed to enhance the existing framework. First, we are seeking 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 seeking approval of a new plant-in-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 cases. And finally, in January we made a filing under the Missouri Energy Efficiency Investment Act, or MEEIA, and requested an enhancement to the existing regulatory framework for energy efficiency programs and the related throughput disincentives that result from these programs. In the interim, we continue to better align the level of our spending with the monies provided through the existing regulatory process as well as with economic conditions.

In summary, if our utilities have modern, constructive regulatory frameworks in place, we will be able to increase investment to modernize aging infrastructure, allowing us to better meet customers’ expectations for higher quality service and create good paying jobs for our local economy. That is why we are allocating increasing amounts of capital to Illinois electric delivery service and FERC-regulated transmission projects. On Page 6, we illustrate our plans to allocate increasing amounts of investment dollars to these two businesses in the five-year period ending in 2016, compared to the prior five-year period ending in 2015. As you can see, we have increased our spending plans for the Illinois regulated electric and gas delivery services by approximately $400 million from the prior five-year period, primarily reflecting the increased spending on electric delivery service that I mentioned a few moments ago. We have increased our spending plans for transmission by approximately $500 million from the prior five-year period; meanwhile, our spending plans for the Missouri electric utility business for the five years ending in 2016 are essentially flat.

I want to be clear that I recognize that in all circumstances, it is our obligation to provide safe and adequate service to our customers, and we have certain minimum expenditures we must make. Those investments have been and will continue to be made.

Turning to Page 7, here we translate the capital spending plans we just discussed into regulated rate base. We expect growth of approximately 6% annually over the 2012 to 2016 period. Further, this growth is skewed toward regulatory jurisdictions with constructive formula ratemaking. We believe this will enhance our ability to earn fair returns on our utility investments.

Moving to Page 8, as we are taking steps today to address our aging infrastructure, keep our service reliable and our rates competitive, we are also looking to the future to be sure that our company is well positioned to meet our customers’ and our states’ long-term energy needs. In light of our aging coal fleet along with continued uncertainties with environmental regulations and commodity prices, we believe it is prudent to maintain effective resource options for the future. As a result, we announced just a couple weeks ago that Ameren Missouri has entered into agreement with Westinghouse Electric Company, a world leader in nuclear technology and development. Under our agreement, we will exclusively support Westinghouse’s application to the Department of Energy for funds to support the design and commercialization of American-made small modular reactors for the United States and for the rest of the world. This agreement is consistent with our commitment to maintain nuclear energy as an important option to meet Missouri’s future energy needs.

In addition, it presents Missouri with significant economic development and job creation opportunities. In essence, Missouri could ultimately become the hub for the design, development and manufacture of American-made small modular nuclear reactors. Our alliance with Westinghouse has broad statewide support, including every electric utility provider in the state, Governor Nixon, a bipartisan group of federal and state legislative leaders, labor, businesses, universities, and others. The potential DOE funding when combined with our investment to date in new nuclear development and our agreement with Westinghouse provides Ameren Missouri with the opportunity to obtain a nuclear combined construction and operating license, or COL, from the Nuclear Regulatory Commission for a small modular reactor at the Callaway site with minimal incremental investment. Obtaining a COL would preserve an important energy option for Ameren Missouri and its customers and be a viable long-term asset.

Pursuing and obtaining a COL does not obligate our company to build a nuclear plant, but it does preserve an important energy option and positions Missouri to move forward in a timely fashion should conditions be right to build a small modular reactor in the future. The grant application will be submitted this month and we expect the Department of Energy to make their decision later this summer.

Turning to Page 9, I will conclude my prepared remarks with an update on our merchant generation business. We have sold forward or hedged all of our expected 2012 merchant generation output at prices above current market levels. As a result, we continue to expect our merchant generation segment to be free cash flow positive this year and for Ameren Energy Generating Company, or Genco, to provide for its own cash needs with the benefit of existing money pool receivables. However, as we look beyond 2012, we cannot ignore the potential negative impact of low energy and capacity prices on our cash flows. As you are aware, in early 2012 there was a sharp decline in forward power prices. In response, in February we announced an approximately $270 million reduction in capital spending plans for our merchant generation business for the years 2012 through 2014. In the first quarter, decline in power prices also led to the write-down of our Duck Creek energy center, which I mentioned earlier. More recently, we have taken several additional actions to better position our merchant generation business to weather the current period of very low power prices.

In late March, Genco entered into a put option agreement with an affiliate. The agreement provides Genco with an additional source of liquidity if such liquidity is needed in the future. It remains our goal for the merchant generation business segment and Genco to provide for their own cash needs.

In a second recent action, just yesterday, 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 are seeking additional time to comply with sulfur dioxide emission levels, currently set to become effective January 1, 2015. In exchange for delaying compliance with these levels through 2020, we have proposed a plan that restricts our sulfur dioxide emissions through 2014 to levels lower than those required by the existing MPS, offsetting any environmental impact from the variance. We have indicated to the Pollution Control Board that if we are not granted the variance, or power prices do not materially increase, there is a significant risk that we’ll have to mothball some of our unscrubbed merchant generation coal-fired energy centers beginning in 2015. The Pollution Control Board is expected to rule on our request by late summer 2012.

Now I will turn the call over to Marty.

Martin Lyons

Thanks, Tom. Turning to Page 10 of the presentation, today we reported a first quarter 2012 GAAP loss of $1.66 per share compared to first quarter 2011 GAAP earnings of $0.29 per share. Excluding certain items in each year, Ameren recorded first quarter 2012 core earnings of $0.22 per share compared with first quarter 2011 core earnings of $0.25 per share.

First quarter 2012 core earnings excluded three items that are included in GAAP earnings. The largest of these non-core items was the non-cash asset impairment charge in our merchant generation business that Tom mentioned earlier. The triggering event for this impairment was the sharp decline in power prices which occurred during the first quarter of 2012. Specifically, we recognized a $628 million pre-tax non-cash impairment charge to reduce the carrying value of our Duck Creek energy center to its estimated fair value. This reduced earnings by $1.55 per share.

The second non-core item was a non-cash quarterly reduction in the income tax benefit recognized in conjunction with the Duck Creek asset impairment. This reduction in income tax benefit was the result of a combination of seasonally low first quarter earnings with the GAAP requirement to recognize income tax expense using the annual estimated effective income tax rate. This item decreased net income by $0.36 per share in the first quarter of 2012 and is projected to fully reverse over the balance of this year. I note that the effective tax rate for the quarter was approximately 24% on a GAAP basis while on a core basis we continue to expect a 2012 rate of approximately 36%.

The last non-core item is a $0.03 per share gain from the net effect of unrealized mark-to-market activity. On Page 11, we highlight key factors driving the variance between core earnings per share for the first quarter of 2012 compared to the first quarter of 2011. Key factors adversely affecting the comparison included a decline in margins at our regulated utilities of $0.14 per share after excluding rate changes. We estimate that $0.13 of this $0.14 decline in utility margins was due to lower retail sales as a result of the near-record warm winter temperatures. The decline in margins at the merchant generation business reduced earnings by $0.05 per share, reflecting reduced generation levels due to low spot market prices for energy and higher per megawatt hour fuel and transportation-related expenses.

The reduction in first quarter 2012 earnings compared to the first quarter of 2011 also reflected a one-time contribution to the Illinois Science and Energy Innovation Trust related to Ameren Illinois Company’s participation in the state’s electric delivery formula ratemaking framework. This $7.5 million pre-tax contribution, which is not recoverable in rates, reduced earnings by $0.02 per share.

Key factors favorably impacting the comparison of first quarter 2012 core earnings to the first quarter 2011 core earnings included changes in electric and gas rates net of certain related expenses, which increased earnings by $0.06 per share. These rates changes included an electric rate increase in Missouri effective in late July 2011 and a gas delivery rate increase in Illinois effective in January 2012. A second factor favorably impacting the earnings comparison was the recognition of revenue related to the Illinois electric delivery formula ratemaking. In the first quarter of 2012, Ameren Illinois recorded a regulatory asset of $12 million with a corresponding increase in electric revenues. The revenue recognized represents our estimate of future cash flows expected to be collected in order to recover first quarter operating costs and in formulaic returns on Illinois electric delivery investments.

We will continue to adjust revenues in the associated regulatory asset over the remainder of the year such that at the end of the year, these amounts represent Ameren Illinois’ estimate of future cash flows expected to be approved by the Illinois Commerce Commission through the annual formula rate update process. I’ll discuss this process more in a moment.

The final positive factor I would like to mention is lower core non-fuel operations and maintenance expenses which benefited the earnings comparison by $0.09 per share with $0.05 of this due to lower storm-related costs.

Turning now to Page 12, today we are also affirming our 2012 cash flow guidance. 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. For 2012, we continue to anticipate that free cash flow will be negative by approximately $230 million; however, as Tom stated, we are also continuing to expect that our merchant generation business will be free cash flow positive.

Turning now to Page 13 and back to a discussion of Illinois formula ratemaking – since January of this year, we have made a series of regulatory filings required by law based on Ameren Illinois’ election to participate in Illinois’ new performance-based formula ratemaking process for electric delivery service. While the results of certain of these filings, which I will discuss in a minute, will establish the level of rates charged to customers in late 2012 and 2013, I want to emphasize that full-year 2012 Illinois electric delivery earnings will reflect a true-up for 2012 rate base and actual cost of service, and include historical ICC ratemaking adjustments. The same will be true in 2013.

The return on equity recognized in 2012 will be based on the 2012 12-month average of 30-year treasury yields plus 590 basis points, with a plus or minus 50 basis point collar. To the extent that revenues and regulatory assets are recognized in 2012 in accordance with our formula ratemaking expectations, they will be subject to ICC review and recovery will occur in 2014, as shown on the timeline.

Moving now to Page 14, Ameren Illinois’ January initial filing under the performance-based formula ratemaking framework for electric delivery service was based on 2010 actual costs and 2011 and 2012 expected net plant additions. The filing called for a $19 million annual rate decrease. In April, the ICC staff and other intervenors filed their direct testimony in this case. The ICC staff has recommended that rates be decreased by $6 million annually more than Ameren Illinois has proposed. This variance between our request and the staff’s recommendation primarily reflects a lower calculation of 2010 capitalization, primarily lower 2010 average common equity.

On Page 15, we have summarized the positions of the other major intervenors in the case. The revenue requirement recommended by these parties range from 24 to $37 million lower than our filing with 14 to $22 million of this difference reflecting the incorporation of estimated 2011 and 2012 accumulated deferred income taxes, which are direct reductions to rate base Since rates and earnings will be trued up for actual rate base, these adjustments for accumulated deferred income taxes are not expected to impact our reported earnings; however, we and the intervenors in this case do have different views on another issue related to the rate base amount to be used in the eventual true-up calculation. We argue that the legislation specifies that the true-up for a given year should be based on actual rate base at the end of the year. The ICC staff and other intervenors recommend that the ICC use average rate base for that year for the true-up.

In an unrelated matter, the Attorney General has recommended an additional $7 million revenue reduction by crediting Ameren Illinois’ electric delivery cost to service with the benefit of the full amount of electric late payment revenue, including the over 50% related to power supply, rather than just the portion related to delivery service.

Finally, the Illinois industrial energy customers are recommending limiting the common equity ratio to 50% rather than the amount in our filing. We strongly believe that the rate formula does not permit such a limitation of the equity ratio and thus consider this proposed adjustment unjustified. The ICC administrative law judge are expected to issue their proposed order in this case in August with an ICC decision expected in late September and new rates to be effective in late October, 2012.

Turning to Page 16, in April Ameren Illinois made its initial annual electric delivery formula rate update filing. This filing calls for an incremental $15 million annual rate decrease compared to the rates filed in January and is based on 2011 actual costs and 2012 expected net plant additions. The rate filing calls for a reduction in rates beyond those filed in January primarily because of lower rate base and return on equity. The $128 million lower rate base in this filing compared to the January filing reflects the incorporation of 2011 accumulated deferred income taxes, including bonus depreciation.

Under the formula rate template, accumulated deferred income taxes for the prior year – in this case, 2011 – are not incorporated into rate base estimate until the spring update rate filing each year. However, once again it is important to understand that the earnings for a given year will be trued up to that year’s actual rate base, which will include the deduction for actual accumulated deferred income taxes for that given year. The electric delivery rates established in this case will be effective in January 2013.

On these next two pages, 17 and 18, we remind you of the highlights of the pending Missouri electric rate case. At the bottom of Page 18 are the key dates in the rate case schedule. The Missouri Public Service Commission staff and other intervenors are required to file direct testimony on revenue requirements by July 6 and a PSC order is expected in December 2012, with new rates expected to be effective in January 2013.

Moving now to Page 19, here we provide an update of our 2012 through 2014 forward power sales and hedges for our merchant generation business. Before we move to the updated hedge numbers, at the top of the page we indicate that expected 2012 merchant generation is approximately 25.5 million megawatt hours as of the end of the first quarter. This is down approximately 1.5 million megawatt hours from the estimate we shared with you on our February call and reflects our expectation that we will more aggressively cycle our base load generation stations in order to improve overall margins in this weak power price environment.

You will also note that for 2012, we have hedged an amount greater than our expected generation – approximately 27.5 million megawatt hours. This amount is hedged at an average price of $43 per megawatt hour. The approximately 2 million megawatt hours of hedging in excess of expected generation is expected to be settled on a profitable basis using financial instruments or additional generation to the extent power prices improve. Moving to 2013, we have now hedged approximately 19 million megawatt hours at an average price of $37 per megawatt hour. Further, for 2014 we have hedged approximately 11 million megawatt hours at an average price of $38 per megawatt hour. To assist you in understanding our merchant generation business segment’s margin drivers, we have provided a pie chart that breaks down our 2012 expected revenue by type.

Finally turning to Page 20, here we update our merchant generation segment’s fuel and related transportation hedges. For 2012, we have hedged approximately 25 million megawatt hours at about $24 per megawatt hour. For 2013, we have hedged approximately 18 million megawatt hours at about $24.50 per megawatt hour, approximately $1 per megawatt hour less than the number we provided in February. For 2014, we’ve now hedged approximately 9 million megawatt hours at about $24.50 per megawatt hour, again approximately $1 per megawatt hour less than the number we shared with you in February.

Similar to our previous slide detailing merchant generation revenues, we have included a pie chart that breaks down forecasted 2012 all-in fuel costs to provide perspective on how each component contributes to our overall cost. This completes our prepared remarks.

Question and Answer Session

Operator

Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star, one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star, two if you would like to remove your question from the queue. We ask that you please limit your time to one question and one follow-up as necessary. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for questions.

Thank you. Our first question is from the line of Paul Ridzon with Keybanc. Please state your question.

Paul Ridzon – Keybanc

Can you just give the drivers behind the revised guidance, kind of what drove merchant up? I guess it was weather that took the regulated down.

Martin Lyons

Sure, Paul, this is Marty. In terms of the overall guidance, obviously the guidance is affirmed and unchanged; but within the guidance, the regulated upper and lower ends came down about $0.05. In merchant, lower and upper ends went up by about $0.05, and they netted out, obviously.

The big driver for the quarter, really, in the regulated business was weather, as you heard on the call. Weather impacted our earnings negatively versus last year by about an estimated $0.13, and versus normal about $0.10. We had very warm winter weather, and it was that $0.10 weather variance versus normal that caused us to move our guidance down for the regulated businesses by about $0.05.

On the merchant side, our guidance had been zero to $0.10 of earnings. We moved it up to $0.05 to $0.15. As a result of the impairment of our Duck Creek energy center, depreciation expense will actually be lower going forward, and so the increase in our guidance for merchant reflects that reduction in depreciation expense.

Paul Ridzon – Keybanc

And is there any precedent for delaying the environmental that you’ve proposed?

Martin Lyons

This is Marty again. The Illinois Pollution Control Board, who we’ve filed with, has a history of weighing a number of things – impacts of a proposed variance to the environment, as well as the cost of coming into compliance and economic impacts of the compliance plan that is either planned or the alternatives to that plan. So they have a history of balancing environmental issues with economic issues, and there has been precedent in the state for variances to be granted. In fact, there’s some precedent even here with us where variances have in the past been granted by the Pollution Control Board. So we’re optimistic that our proposed plan will be received favorably by the Board.

Paul Ridzon – Keybanc

And how is the interplay with EPA regs?

Martin Lyons

Well, as you know, some of those EPA regs are a bit in flux, as we saw the appeal of the CSAPR rules and then the MATS rules come into play later down the line. You may recall as a result of our compliance with the Illinois multi-pollutant standard, we’ve made significant investments in environmental controls. We burn low-sulfur Powder River Basin coal. We control mercury through the use of activated carbon. We’ve got a lot of controls in our plants, and those controls, those investments are positioning us well in our merchant business for compliance with MATS, and then we’ll see how CSAPR evolves, although we feel like we were positioned well for compliance with the CSAPR rules that existed before as a result, again, of our use of Powder River Basin coal, the scrubbers we have on some of our plants, as well as the decision last year to shut down a couple of our older, uncontrolled plants.

Paul Ridzon – Keybanc

Thank you very much.

Operator

Thank you. Our next question is from Paul Patterson of Glenrock Associates. Please state your question.

Paul Patterson – Glenrock Associates

Good morning. Can you hear me?

Thomas Voss

Yes, Paul, we can. Good morning.

Paul Patterson – Glenrock Associates

With respect to the $0.36 of tax adjustment that gets fully reversed, is that going to be showing up in operating earnings going forward for the rest of the year?

Martin Lyons

No. Let me describe what that is. Basically what it is from a GAAP accounting standard, we’re required to book to the estimated end of year effective tax rate, which given the impairment charge that we took and projecting out to the end of the year, we’re forecasting about a 24.5% effective tax rate. So we’re required to book to that in the first quarter.

Because our earnings excluding the impairment charge are seasonal and heavily weighted towards the third quarter, the earnings in the first quarter excluding the impairment charge are pretty low. So when you take that impairment charge and you tax effect it at, say, a 40% kind of effective tax rate, it has the effect of really pushing the effective tax rate down for the quarter down to a very low level. So we had to—we described the decrease to the benefit of the Duck Creek impairment tax effect basically increased the effective tax rate up to that 24.5% level in the first quarter. But between now and the end of the year, and likely between now and the end of the third quarter, that will reverse out.

Paul Patterson – Glenrock Associates

And will that show up in earnings?

Martin Lyons

Well yes, it would show up in GAAP earnings but not core.

Paul Patterson- Glenrock Associates

Okay, but it won’t be showing up in core earnings. And the $0.05, that’s for the three quarters ended—I’m sorry, the last three quarters of this year, and I guess the full-year impact will just be—you know, we just annualized that impact? Is that how we should think about it?

Martin Lyons

Are you talking about the depreciation from—

Paul Patterson – Glenrock Associates

Yes, the deprecation from Duck Creek, yeah.

Martin Lyons

Yeah, it’s about—Paul, it’s about $25 million, so I think that’s probably about $0.06 per share, so the $0.05 per share is really this current year expected impact.

Paul Patterson – Glenrock Associates

And why only Duck Creek? That was the only one that was impaired. Is that because of pollution control equipment, or how should we think of that?

Martin Lyons

Well, you’re right, Paul. That’s exactly right; it’s part of the answer, anyway. When you do an impairment test from an accounting perspective, first you look at the expected gross cash flows undiscounted over the remaining lives of the generating assets and then compare it to the carrying values. The Duck Creek facility did have a high book value or carrying value per megawatt, and that was really a function, as you mention, of the environmental equipment that is on that plant and that we invested in. But also, you might recall, Paul, that generating unit was actually acquired when Ameren acquired CILCORP years ago, and as a result at that time in purchase accounting, that plant was written up to its then fair value. So it had a higher book value as a result of that purchase accounting, and then on top of that the investments were made for environmental controls, so it had a fairly high book value compared to our other plants.

Paul Patterson – Glenrock Associates

Okay, great. Thanks a lot, guys.

Operator

Thank you. Our next question comes from the line of Terran Miller with Cantor Fitzgerald. Please state your question.

Terran Miller – Cantor Fitzgerald

Good morning. Two follow-up questions – first is if the Illinois regulators make a decision on the environmental issues, is that going to be precedent-setting for the state or do you think it’s just limited to your request?

Thomas Voss

Well, I think it’s specific to our request. As I said earlier, I think there is precedent for the Pollution Control Board to grant variances like the one we have requested, so I don’t think it’s precedent-setting in terms of the Pollution Control Board ruling favorably in terms of our specific request. But I don’t think that then would apply to others. It’s really an Ameren Energy Resources specific variance request.

Terran Miller – Cantor Fitzgerald

Okay, and just as a follow-up from Paul Ridzon’s question, if CSAPR rules are not changed, can you get to 2020 without having to scrub?

Thomas Voss

Well, I think we’re positioned pretty well for those rules. I guess I don’t have the data here in front of me to say whether we’ll well positioned all the way out through 2020 or what some of the impacts may be, but we are positioned well for it, again as I mentioned earlier for the reasons I mentioned earlier. When we looked at the emission allowances or the credits that we had as a result of the shut down of the Meredosia and the Hutsonville facilities we did last year, as well as the pollution control equipment we have in place and the use of the Powder River basin coal, so we’re positioned well.

We’ll see what happens with the CSAPR rules, where they come out; but again, I talked about this on the February call, when we looked at the deceleration of the Newton scrubber, when we looked at the rules that were most restrictive for us out in that 2015 time frame, it was the Illinois multi-pollutant standard that was the significant limitation, absent the scrubbers.

Terran Miller – Cantor Fitzgerald

Okay, thank you.

Operator

Thank you. Our next question comes from the line of Ashar Khan with Visium. Please state your question.

Ashar Khan – Visium Asset Management

Hi Marty, how are you doing? Marty, I just wanted to understand—I guess Genco’s doing really well in terms of free cash flow this year, but the hedging slide that you gave us updated kind of nearly shows if one puts in the remaining non-hedged portion that the price could be dropping something like $9 or $10 on a base around ’12 to ’13, which would imply that the business becomes negative cash flow next year. So can you tell me, what is the plan – is the parent going to provide, or how are we going to address this negative cash flow going forward? What is the strategy behind funding the business?

Martin Lyons

Sure, Ashar. I think, Ashar, we’re still focused on the merchant business and Genco maintaining an ability to meet its own cash needs and to stay cash flow positive, so we haven’t given any guidance yet so I’m—I know you’ve got your own model, I’m not going to comment on the figures you threw out. But that is our goal, that is our focus, and as you saw earlier this quarter, we did put in place a put option that to the extent Genco found itself needing financial resources, could put its gas-fired assets over to its affiliate for an immediate $100 million of cash, and then that would be trued up to fair value so that it would actually receive fair value for the assets.

That’s consistent with one of the things that we’ve been talking about for a number of quarters, that Genco does have certain assets that it could sell. We have, as you’ve seen over the past couple of years, we’ve sold some of our smaller gas-fired units and that’s an option for Genco to the extent that it did need to raise cash as a fall-back. But it’s certainly focused on trying to reduce its capital expenditures, reduce operating costs, continuing to work to market its power to higher margin customers and meet its own cash needs.

Ashar Khan – Visium Asset Management

Okay, but does the parent in terms of the write-down—or I guess what you’re saying is you’re going to sell the assets to fund it, or does the parent need equity to fund it as well going forward? Is it going to be a combination of both, or it’s just the Genco selling assets and plugging the hole?

Martin Lyons

Well Ashar, I guess the answer I’m trying to convey is first and foremost, they’re going to try to manage operating costs and capital expenditures to work towards a cash flow positive situation. With respect to Genco, it could then pursue sales of assets, if needed, to generate cash, and those are the primary focus areas.

In terms of the impairment, the impairment was not a Genco asset; it was an energy resources asset but over in the AERG subsidiary, so the impairment really didn’t affect Genco, the legal entity. It basically rolls up and impacts only Ameren’s financial statements, and as you see today, nearly 52% equity in our total capital structure after the write-off and we have plenty of liquidity – over $2 billion of liquidity. So really, no impact on cash. Our equity content and our cap structure remain strong, and so overall don’t see a need for additional equity at this point.

Ashar Khan – Visium Asset Management

Okay, thank you so much.

Operator

Thank you. Our next question is from the line of David Paz from Bank of America. Please state your question.

David Paz – Bank of America

Good morning. I have a question, just a follow-up on Ashar’s question. If the Genco put option is exercised, would AERG issue its own debt or would it borrow from the parent?

Martin Lyons

Yeah, David – no, AERG would borrow from the parent. AERG doesn’t have any borrowing capacity of its own, so it could borrow from the parent but then the idea, David, is that AERG would be buying those assets from Genco at fair value and could turn around and sell those assets at that price, generate the cash, and pay down that borrowing. So that’s the idea of it – that if some amount of money goes into Genco for those assets, an equivalent amount of value comes out in the form of power plants which could then be resold to pay down the debt.

David Paz – Bank of America

Got it, okay. My original question was on dividend policy – I’m curious if you have an update how should we think about dividend policy going forward. I know you have 6%, or roughly 6%, rate base growth. Should we expect continued dividend growth?

Thomas Voss

This is Tom Voss. You know, we really haven’t articulated a dividend growth policy, but it’s management’s objective to continue to grow our utility earnings by making disciplined investments in the utility infrastructure, and as we grow the earnings and cash flows of the regulated business, we’ll continue then hopefully to grow the dividend. But any future increase will be a Board decision and it will be based on our recent financial performance and current financial position, as well as our outlook for earnings, cash flows, and financial position.

David Paz – Bank of America

Now is that outlook to earnings exclusive to regulated, or is it overall?

Thomas Voss

Regulated earnings.

David Paz – Bank of America

Great. Okay, thank you.

Operator

Our next question is from the line of Reza Hatefi with Decade Capital Management. Please state your question.

Reza Hatefi – Decade Capital Management

Hi, thank you. I guess you have a great utility rate base kegger, but I assume that’s probably running a little negative cash flow and then we’ll see what happens with the merchant segment. How should we think about financing over the next two, three years to achieve this rate base kegger? Do you need to reinstitute the DRIP-dribble or will there be equity in 2013, ’14? How is that going to get financed, I guess?

Martin Lyons

Good morning, Reza, this is Marty. I think when you look out and you do your modeling, I think you should assume that over time we’re going to look to keep the equity content in our cap structure in alignment with generally where it is. I’ve talked about this before – generally in that 50 to 53% kind of equity content in the total capital structure. So as we move through time, we’ll want to keep a strong balance sheet and a strong equity content in our cap structure.

As you know, we don’t have the DRIP-dribble program currently issuing any new shares, but as we said I think on our first quarter call, that that’s something that we’ll evaluate on a year-to-year basis; and to the extent that equity is needed to keep the balance sheets of our utilities in that strong and that kind of category that I mentioned, we’ll certainly act to do that.

But it’s important when you look out over time to remember that these businesses do generate significant earnings each year over and above that which is paid out in dividends, so there’s the ability to reinvest retained earnings over time. And I’d also point out that you see the 6% kegger in the overall rate base but you’ve also got an allocation going to those jurisdictions that have formulaic ratemaking, which over time should allow us to continue to bring up our blended earned ROE on that rate base. So in addition to the 6% rate base, you’ll hopefully also see a little bit of growth in the blended average earned returns, which helps as well.

Reza Hatefi – Decade Capital Management

And then just finally kind of thinking about your regulated earnings power, should I just basically take this new rate base slide and use that, or is there anything else that I’m missing in terms of getting your regulated earnings power?

Martin Lyons

No, I think you’re on the right track. I think we just talked about a few things that you would have to consider, and that’s the rate base growth, the allocation of the capital to the various jurisdictions and how that affects the blended earned ROE, and then over time as you model it out, how we would go about financing that, which again I said largely would be through reinvestment of retained earnings, some debt financing, and then depending on your model some consideration of additional equity, but the objective getting to that 50 to 53% equity ratio.

Reza Hatefi – Decade Capital Management

Okay, thank you very much.

Operator

Thank you. As a reminder, ladies and gentlemen, we ask that you please limit your time to one question and one follow-up as necessary. Our next question is from Michael Lapides of Goldman Sachs. Please state your question.

Michael Lapides – Goldman Sachs

Hey guys. Congrats on a good quarter and obviously in terms of some of the regulatory improvements you’ve made in your jurisdictions over the last couple of years. O&M – can you talk—I just want to make sure I understand – year-over-year from 2011 to 2012, both at the regulated side and at the merchant side, what’s embedded in guidance for year-over-year changes in O&M.

Martin Lyons

Thanks, Michael. I think we would refer you back to the first quarter call transcript, but I think when you look at overall, it’s in Missouri you’re seeing actually a trend down in O&M. You’ll recall that late last year, we actually had a voluntary retirement or severance plan that ended up having about a 340 headcount reduction overall between Ameren Missouri as well as our business in corporate services area. So that’s rolling through in terms of cost savings this year.

For the merchant business, we actually kind of gave out a specific number that was down a little bit from the prior year, which was about—an expectation of O&M expense of about $290 million. Again, like I said, it’s a little bit down from last year. And then in Illinois, I think the important thing to remember there is whatever the O&M costs are, those will actually be included in the formula ratemaking adjustment that we book this year. So whether they were to go up or down, it would result in more or less revenue being recognized under the formulaic rate adjustment. We do expect those O&M expenses, however, to go up as we are ramping up to meet the requirements of the law in terms of investments and job creation. So those O&M expenses are going up in Illinois this year.

Michael Lapides – Goldman Sachs

Okay. And thinking about Illinois, in your guidance, what rate base is assumed in guidance for 2012, and what earned ROE level is assumed in your guidance level for this year?

Martin Lyons

I’ll see whether somebody has the rate base number – I don’t have that off the top. But we did—you know, Michael, overall in terms of the ROE, the midpoint of our ROE reflects about a 9.2% earned ROE, or assumed earned ROE in Illinois. That assumes average treasury yields of about 3.3% for the year, so that’s the ROE that we had embedded as a midpoint. You’ll recall that there is a—you know, where the ROE actually ends at the end of the year will be a function of where the 30-year treasury yields actually go over the course of the year, and then there’s a plus or minus 50 basis point collar on that ROE.

One thing I might mention is that that plus or minus 50 basis point collar equates to about a plus or minus $0.025 per share, so there’s a band or a collar on the ROE based again on the formula.

One of the things I’d point you to just in terms of rate base was that in our January 3 filing – and this was on Slide 14 – the rate base in that January 3 filing was about 2.16 billion, actually shown on that slide. What that represented was the rate base from the 2010 FERC Form 1 plus 2011 and 2012 net plant additions. And then what that wouldn’t reflect is simply adjustments to the deferred tax balances.

Michael Lapides – Goldman Sachs

Got it, because I noticed that in the Com Madison (ph) filing process, there was about a $500 million difference in the rate base between the ALHA order and a lot of the company and even the intervenors, which has a significant impact. Are you guys facing a similar issue?

Martin Lyons

I would say, Michael, that it’s probably in the $200 million range for us, I would believe. The other thing to remember about Illinois, and that’s just we’re talking about the electric delivery rate base. You’ve also, of course, got the gas rate base that we’re earning on as well as the transmission rate base in Illinois, so that’s not total Illinois rate base.

Michael Lapides – Goldman Sachs

Understood. Thanks, guys. Much appreciated.

Operator

Thank you. As a reminder, we ask that you limit your time to one question and one follow-up as necessary. Our next question is from Tom Rebinoff of Fore Research & Management. Please state your question.

Tom Rebinoff – Fore Research & Management

Hey guys, good morning. Just a quick question – I wanted to go back to CSAPR one more time. I just wanted to make sure that I understand what you were trying to convey. So basically you guys said you are well positioned for CSAPR. So what does that mean exactly, then? I guess if Illinois does not approve—sorry, if Illinois does approve your request, would you have to spend any more money on CAPEX beyond what you’ve told us already, or is that going to be it? And then I guess how do we think about what you mentioned on the last call in terms of having to start thinking about the scrubbers for Newton by the end of this year, maybe early next year?

Martin Lyons

Yeah, sure. You know, I think in terms of CSAPR, again, when we looked out to 2015 absent the Newton scrubber and if the multi-pollutant standard wasn’t in place, we believe we were positioned well for compliance with CSAPR and don’t believe the Newton scrubber would be needed to meet the CSAPR requirements. That’s why we’re very focused on the multi-pollutant standard variance and relief. Your question about the considerations around the Newton scrubber – obviously we’re pursuing this relief from the Pollution Control Board relative to the MPS. Absent that relief, we would be sort of back to where we were, I would say, when we last talked on our year-end earnings call, which would be that we believe that if we reaccelerate the scrubber project, it would take about 20 to 24 months to complete that; and again, the way the multi-pollutant standard currently works, there’s a ratchet down in terms of SO2 emissions out in the 2015 time frame. So sometime in the first half of next year is sort of the point that is critical, and if we decided to reaccelerate sometime in the first half of next year, we’d be in a position to have the scrubbers in place the first half of 2015.

But again, there are a lot of factors we’ll consider in making that evaluation and making that decision. Today, as we’ve said, market prices and capacity prices just don’t seem to justify completion of that scrubber, and we’ll continue to evaluate things as we move through time.

Tom Rebinoff – Fore Research & Management

Okay, got it. And so then a quick follow-up question – I guess it’s the Illinois Pollution Control Board that will have to opine on your request. Now, is the MISO—or I guess, does the MISO have a say in this at all, or no?

Martin Lyons

No, I don’t believe so.

Tom Rebinoff – Fore Research & Management

Okay, got it. Thank you, guys. Appreciate it.

Operator

Thank you. Our next question is from the line of Alex Tai of Standard General. Please state your question.

Alex Tai – Standard General

Hi guys, good morning. I actually just wanted to follow up on Tom’s question there. Specifically, you said that you probably will not need a scrubber if you comply, you believe, with the EPA regs. So what about other forms of capital expenditure? Would you need anything else, or do you think you’re all set, period?

Thomas Voss

You were breaking up a little bit, but I think your question was would the capital expenditures that we’ve got, or the pollution control equipment that’s in place, we’d be sort of all set. I think the answer is yes. We’ve made significant investments in pollution control equipment. We’re incurring significant O&M costs today for compliance with the multi-pollutant standard, and those things position us well in terms of the federal air emissions rules that we’re aware of today.

Alex Tai – Standard General

Got it, okay. So it really is only the state pollution rules that are imposing the need for new environmental capital expenditures?

Thomas Voss

Well, yes, for this Newton scrubber project, that’s right; and again, I’d refer you to our five-year CAPEX plans that we put out in our 10-K, and you’ll see them updated in the 10-Q, but really no change. Based on the equipment we’ve got in place, the capital expenditure plans we’ve laid out, we believe we’ll be positioned well.

Alex Tai – Standard General

Okay. And this is a slightly different but same line of questioning, I guess – you’ve disclosed that you’ve increased the hedges on the merchant generating segment. Is there any breakdown of where those new hedges are? Are they within the Genco or within AERG?

Thomas Voss

Yeah, no breakdown there. You know, they’re AER overall hedges.

Alex Tai – Standard General

Got it. Okay, great. Thank you, guys.

Doug Fischer

This is Doug Fischer. Operator, we’ve exceeded our scheduled hour but I think we’ll take just two more questions. So Operator, if you’d please put those through.

Operator

Thank you, Mr. Fischer. Our next question is from Julian Dumoulin-Smith with UBS.

Julian Dumoulin-Smith – UBS

Hey, good morning. So first, you’ve talked a lot about the peaker asset sales. Just kind of curious – any outlook in terms of getting that done and the follow-up there? The Grand Towers unit, I imagine that one has got a better heat rate. How much did it run in the quarter?

Thomas Voss

Julian, I don’t have any specific data on Grand Tower or the other couple of peakers to share with you. We do expect the Grand Tower will be running more this year than it has in the past, given the low power prices. Overall on your other question, really no update on the overall process. Again, the put option was put in place really as more of a—if an emergency situation need arose, Genco could put those assets. You know, one of the things we pointed out on our year-end call was that Genco had money pool loans that were made to affiliates at year-end. Those balances have actually grown a little bit here in the first quarter. I think when you see their balance sheet, I think they’ve got about $95 million loan to affiliates, so really no immediate need for cash. There is—you know, the loans that have been made to affiliates, so there’s really no process underway right now to sell those assets.

Julian Dumoulin-Smith – UBS

Great. And just to make sure I heard you loud and clear here, in terms of actually achieving that 0.38 standard under the new 2020 extension, there really is nothing incrementally for you to do – it’s probably just running a little bit more of the, call it running perhaps your scrubber just a little bit harder, or something like that. Is it something akin to that?

Thomas Voss

Julian, that’s right. We have the ability, given the controls we’ve put in place, to meet that more stringent standard, and with no additional cost. So we, again, believe that’s something that, as you say, if we push the scrubber equipment that we’ve got in place, we’ll be able to achieve that.

Julian Dumoulin-Smith – UBS

All right, great. Thanks for being explicit there.

Operator

Thank you. Our final question today is coming from Raymond Leung of Goldman Sachs. Please state your question.

Raymond Leung – Goldman Sachs

Hey, guys. Thanks for the call. A couple of my big questions were answered with respect to where you were getting the cash on the put and the intercompany loan; but can you talk about how you guys are thinking about—I think in your K, you indicated that you may trip to your covenant. Should we just assume that bank line, you can’t access that going forward? And just to clarify, you indicated if you were to comply with the Illinois rule here that you probably wouldn’t see much of an incremental increase in the operating costs if you got the variance?

Thomas Voss

Right. So that is what I just said – is that we wouldn’t expect to see incremental operating costs as a result of the variance being granted. And I think your other question was—I’m sorry, could you repeat the other question?

Raymond Leung – Goldman Sachs

Well, you guys indicated in your K that you may sort of trip an interest covenant test. Can you talk about how you’re thinking about that and how you may try to deal with that, or if you think you can deal with it at all?

Thomas Voss

Yeah, yeah. I’m sorry – I was focused on the second question and had forgotten the first. But yeah, when you end up seeing our disclosures for the first quarter, they’ll mirror those from year-end, that essentially based on the covenant that borrowings at Genco we forecast to be restricted by the end of the first quarter of next year. So there won’t be any change in the disclosures in the Q relative to the K, which is why we put the put option in place. We wanted to make sure there was clarity in terms of if Genco needed access to cash, access to liquidity, how would it arrange that, because as you say, looking ahead one might assume really no borrowing access under the revolver, based on that disclosure that we’ve made.

Raymond Leung – Goldman Sachs

Okay, thanks.

Doug Fischer

Okay, this is Doug Fischer. I want to thank everybody for participating in today’s 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 to Matt Thayer. Media should call Brian Bretsch. Our contact numbers are on the news release.

Again, thank you for your interest in Ameren Corporation and have a good day.

Operator

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

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