阿莫林 (AEE) 2011 Q1 法說會逐字稿

Greetings and welcome to the Ameren Corporation first-quarter 2011 earnings conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions). As a reminder, this conference is being recorded.

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

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

Before we begin, let me cover a few administrative details. This 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 is also being 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 section in our filings with the SEC.

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

Thanks, Doug. Good morning and thank you for joining us. Today, we announced first quarter 2011 core earnings of $0.25 per share, compared to first quarter 2010 core earnings of $0.40 per share. These results were in line with our expectations, despite being lower than those of the same period last year. The decline in core earnings per share was primarily the result of reduced margins in our merchant generation segment as well as higher operations and maintenance expenses and reduced capitalized financing costs in our regulated utility segments.

Kilowatt hour sales to [native] load utility customers decreased 3% in the first quarter of 2011, compared to the first quarter of 2010, due in part to milder winter temperatures. Kilowatt hour sales to residential and commercial customers, both of which are temperature sensitive, declined 4%. Kilowatt hour sales to industrial customers rose a strong 7%, an encouraging sign of continued economic growth. the decline in merchant generation segment margins reflected lower realized power prices and higher fuel and related transportation costs. The higher O&M expenses at our Ameren Missouri and Ameren Illinois regulated utility segments in the first quarter of 2011 largely reflected increased storm related expenses compared to the first quarter of 2010.

We continued to exercise disciplined cost control in the first quarter of 2011 with operations and maintenance expenses, excluding storm related costs, up just slightly over the year-ago quarter. Factors favorably contributing to first quarter 2011 core earnings, compared to the first quarter 2010 core earnings, included lower interest expenses and 2010 electric rate changes in Missouri and Illinois.

Turning to page 4, today we are reaffirming our GAAP and core earnings guidance of $2.20 to $2.60 per share for this year. Further, we are reiterating our GAAP and core guidance ranges of $2.05 to $2.30 per share for our combined Ameren Missouri and Ameren Illinois segments and $0.15 to $0.30 per share for our Merchant Generation segment.

Moving to page 5, we continue to anticipate positive free cash flow of approximately $100 million in 2011. This amount excludes approximately $45 million of potential cash proceeds from the pending sale of our remaining interest in the Columbia combustion turbine facility to the city of Columbia, Missouri. Regarding storm impacts, this year our region has been hit very hard by a series of winter and spring storms effecting the lives of tens of thousands of our customers. Our employees in Illinois and Missouri have worked tirelessly and effectively to restore power and help meet other community needs.

In Illinois, the February storms were the most widespread severe winter weather to hit our service area in years. Snow, ice, sustained high winds, and freezing rain caused power outages in more than 50 counties and created several days of challenging work. More than 1,600 Ameren Illinois employees and outside partners were part of the restoration effort. Reflecting the effectiveness of our work, the Illinois Commerce Commission commended Ameren Illinois for its efforts preparing for and responding to these historic winter storms.

In Missouri, while significant efforts and expenditures were incurred to prepare for and deal with the February storms and a tornado in early January, the most severe weather in that state hit in April. Not only did the torrential rain and gale force winds with an F-4 tornado uproot and damage more than 500 poles and toss electric wires onto streets and yards, they left hundreds of people homeless, destroyed churches and businesses and shut down our region's international airport. This was the worst tornado to hit the St. Louis region in nearly 40 years with more than 2,500 buildings damaged beyond repair. These April 22 storms followed storms that tore into Illinois earlier that week. Ameren Illinois deployed more than 1,000 people to safely restore our Illinois customers, only to subsequently send hundreds of crews to Missouri.

Ameren Missouri assembled and employed crews of more than 2,000. We managed to safely restore power to nearly all of our Missouri customers within 72 hours and to the St. Louis airport in 24 hours. During extraordinary events like these, our employees' commitment to our customers is clear, and I am proud of their performance. I want to recognize and thank all of our Ameren Missouri and Ameren Illinois co-workers for their dedication over the past few months and the teamwork exhibited as crews traveled back and forth between the two states, assisting one another with service restoration efforts.

Moving to page 6 and regulatory matters. We are currently in the middle of an important electric rate case proceeding before the Missouri Public Service Commission. Last September, we filed for an electric rate increase of approximately $263 million. We recently revised our request to approximately $200 million annually, or an approximate 8% increase in overall electric rates to reflect updates and settlement of various issues. This request is driven by the significant investments we have made in our electric infrastructure to maintain and to improve the reliability of our system and to provide cleaner energy, consistent with customers' expectations.

Included in our request are costs associated with the newly installed scrubbers on our Sioux Power Plant, which represents approximately $106 million of our total request. The second key driver of the request is higher net fuel costs. In a few minutes, Marty will provide more detail on our updated request as well as the current positions of other parties to the case. The outcome of this case is very important to our Company, our customers, our shareholders, and the state of Missouri. The bottom line is that we are seeking to recover the cost and investments we are actually incurring to provide service to our customers and to earn a fair return on our investments. In addition, we are seeking consistent constructive regulatory policies that support necessary investments for safe, reliable, and cleaner energy for the benefit of our customers and all stakeholders now and in the future.

While we are discussing Missouri rates, I would like to provide an update related to the appeals of certain aspects of our recent Missouri Electric orders. In late December 2010, the Cole County Circuit Court in Missouri allowed 4 industrial customers, appealing the 2010 electric rate increase, to pay the portions of their bills representing increases from previously approved levels into the court's registry, pending resolution of these appeals. This December court order stayed the two most recent electric increases for those 4 customers, subject to certain bonds being posted, which they did in February.

Over the last 2 months, the office of public council and the Missouri industrial energy consumers have sought the to roll-back our 2010 electric rate increase to 2007 or to 2009 levels for all customers. These roll-back attempts have been made at the Missouri Public Service Commission, the Missouri Western District Appellate Court and most recently, the Cole County Circuit Court. We strongly disagreed with all these motions and they were denied in all instances. In the most recent ruling on this matter, the Cole County Circuit Court stated that the December 2010 stay only applied to the 4 industrial customers. It did not apply to all Ameren Missouri Electric customers.

As we have previously stated, we disagree with the circuit court' original December ruling, creating a stay for the 4 industrial customers. Based on the merits of the case, we do not believe it is probable that a loss will result from any of the issues being appealed by the parties, and we will continue to vigorously argue for our positions before the courts.

Turning to Illinois regulatory matters, in that state we have requested a $111 million increase in annual electric and natural gas delivery revenues based on a future test year ending December 31, 2012. In Illinois, Commerce Commission decision is expected in mid-January 2012, with new rates expected to be effective that same month. 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 investment. The ICC recently established a schedule for this case and we have listed several key dates on this page.

On the Illinois legislative front we are proactively engaged in supporting the advancement of House Bill 14, the Energy Infrastructure Modernization Act. This legislation is designed to benefit the state of Illinois and its electric and gas utility customers by providing incentives for substantial new investments that would modernize and upgrade electric and natural gas systems, improve service reliability, enable the delivery of more competitive supply sources of natural gas and create jobs. These goals would be achieved by authorizing formulaic rate-making for qualifying utilities.

This would be done by prescriptively establishing a rate of return on equity and allowing for annual resetting of rates, all while still providing appropriate regulatory oversight by the ICC. Qualifying Ameren Illinois would need to commit to invest an incremental $950 million of capital over a 10 year period. This would be in addition to a baseline level of capital expenditures determined by Ameren Illinois' average capital expenditures calendar years 2008 through 2010. We would also need to commit to creating 750 jobs either internally or externally and to achieving certain performance improvement goals.

Shifting from our regulated utilities to our merchant generation business, we continue to seek and act upon opportunities to market and sell power at premiums to visible market prices, to reduce and eliminate operating and planned capital expenditures. And to take other actions such as the sale of our Columbia combustion turbine asset to fund the cash needs of that segment and limit its needs for additional external financing.

Moving now to environmental matters, as I stated in February, 2011 looks to be a pivotal year for federal environmental regulation. In March, the US EPA issued proposed rules for retrofitting power plants with maximum achievable control technologies to reduce hazardous air pollutants such as mercury and acid gases. Also in March the agency issued proposed cooling water standards. Later this year, the US 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 issue rules for managing coal combustion byproducts and reducing greenhouse gas emissions later this year. These rules are expected to impose additional costs on our Company and our customers and these additional costs could be substantial.

We continue to have a team of experts actively evaluating these proposed and anticipated environmental standards. The team is focused on ensuring that we meet these standards in the most cost effective manner possible, taking into account outlooks for power prices, delivered fuel costs, and alternate compliance approaches in technologies among other factors. We are still evaluating the rules proposed by the EPA in March and their impact on each of our generating units. As a result, we are not updating our environmental compliance or related capital expenditure plans at this time. In addition to evaluating proposed and anticipated rules, we are actively working with other companies in our industry to develop responses to the EPA's proposals and meeting with state and federal officials including members of Congress in an effort to protect and promote the interest of our customers and shareholders.

In closing, I want to reaffirm our dedication to positioning our Company for long-term success. We are doing so by maintaining a sharp focus on customer satisfaction and by managing our expenditures in a disciplined manner. We remain committed to seeking utility rates and constructive regulatory frameworks that allow us to recover our costs and that provide an opportunity to earn a fair return on our investments. Further, we are committed to aligning our overall spending, consistent with regulatory outcomes and the related cash flows, provided by those decisions, and at both our regulated and merchant businesses, we remain dedicated to operating in a safe, reliable, and environmentally responsible manner.

Now, I will turn the call over to Marty.

Thanks, Tom.

Turning to page 7 of the presentation, today we reported first-quarter 2011 earnings in accordance with generally accepted accounting principles or GAAP of $0.29 per share, compared to the first quarter 2010 GAAP earnings of $0.43 per share. Excluding certain items in each year, Ameren recorded first-quarter 2011 core earnings of $0.25 per share, compared with first-quarter 2010 core earnings of $0.40 per share. First-quarter 2011 core earnings exclude one item that is included in GAAP earnings. This item is a $0.04 per share gain from the net effect of unrealized mark-to-market activity, primarily related to non-qualified power and fuel related hedges.

Moving now to page 8, here we highlight the key drivers of the variance between core earnings per share for the first quarter of 2011 and for the first quarter of 2010. Factors adversely affecting the comparison included a decline in margins at the merchant generation business segment, resulting in reduced earnings of $0.07 per share. The reduced margins reflected lower realized power prices and higher fuel and related transportation costs. Winter weather was also a key factor behind the decline in earnings.

Storm related expenses reduced first-quarter 2011 earnings by $0.05 per share, compared to the first quarter of 2010 while lower regulated electric and natural gas margins, excluding the impact of rate changes, reduced earnings by $0.04 per share. Half of these $0.04 was due to milder winter temperatures, compared to the first quarter of 2010. The other $0.02 of this margin related earnings decline reflects lower Ameren Missouri wholesale electric sales and a change in the mix of Ameren Illinois electric sales, mitigated in part by the benefits of the Taum Sauk Hydroelectric Plant which returned to service in the second quarter of 2010.

Other factors contributing to lower first-quarter 2011 earnings included reduced equity related capitalized financing costs, or AFUDC equity, of $0.03 per share, compared to the first quarter of 2010. The lower AFUDC equity reflected the 2010 completion of the scrubbers at Ameren Missouri's Sioux Power Plant. We expect the Sioux scrubber project to be reflected in rates beginning in early August 2011, eliminating this temporary drag on earnings. The final adverse factor of note was a higher effective income tax rate on core earnings. This reduced earnings by $0.02 per share, due in part to the higher income tax rate in Illinois, effective at the beginning of this year.

You will note that the first-quarter 2011 effective tax rate on core earnings was 38.5%. However, over the course of this year, we expect this rate to moderate to within the range of 36.5% to 37%, the expected 2011 range that we shared with you in February. Key factors favorably affecting the variance between core earnings per share for the first quarter of 2011 and for the first quarter of 2010 included lower interest expense which boosted earnings by $0.04 per share. This reflects both reduced borrowings as well as greater capitalized interest cost.

Finally, 2010 electric rate changes in Missouri and Illinois increased first quarter 2011 earnings by $0.03 per share, net of certain related expenses, compared to the first quarter of 2010. As Tom mentioned, we are reaffirming our GAAP and core earnings guidance of $2.20 to $2.60 per share for this year. Further, we are reaffirming our guidance ranges for our combined Ameren Missouri and Ameren Illinois segments and for our merchant generation segment. Of course, extraordinary storms and related restoration efforts are very costly. First-quarter 2011 storm-related operations and maintenance expenses totaled $20 million, which is $18 million more than costs incurred in the prior year's first quarter. In addition, first-quarter 2011 storm-related capital expenditures were approximately $9 million.

At this point, figures are not yet available for the April storms. However, unlike the first-quarter storms, we expect these April costs to be more heavily weighted toward capital expenditures rather than O&M as the vast majority of our effort was focused on infrastructure removal and replacement. On another note, I would like to remind you that from an O&M timing perspective, this year's Callaway Nuclear Plant refueling and maintenance outage is scheduled for the fall, as compared to the spring refueling in 2010.

Before I leave the subject of guidance, I would like to discuss a recent Missouri Public Service Commission action and its expected impact on 2011 earnings. On April 27, the Missouri Public Service Commission issued an order in its first prudence review since implementation of Ameren Missouri's fuel adjustment clause. The review covered the period from March 1 through September 30, 2009. In this order, the PSC ruled that Ameren Missouri should have included in the fact calculation all revenues and costs associated with certain long-term partial requirement sales that were made by Ameren Missouri due to the loss of load from Miranda Aluminum's Missouri smelter plant. The loss of load was caused by a severe ice storm in January of 2009.

We are very disappointed in and disagree with the PSC order's classification of these sales. We believe that the terms of the fuel adjustment clause tariff did not provide for the inclusion of these sales in the fuel adjustment clause calculation. Therefore, we intend to seek rehearing of the order and if necessary, to appeal it through the judicial process. In addition, we are also considering other regulatory approaches to recover this extraordinary loss resulting from the January 2009 ice storm. However, as a result of the order, we will record a second quarter pre tax charge to earnings of $17 million. These sales were recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009. Ameren Missouri also recognized an additional $25 million of pre tax earnings associated with the same long-term partial requirement sales contracts subsequent to September 30, 2009. The Missouri Public Service Commission has not completed a prudency review of the fact calculation for this subsequent period. If we determine that these sales are probable of inclusion in the fact, a charge to earnings would be recorded in the period in which that determination is made.

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

Turning now to page 9 and our pending Missouri Electric rate case, here we provide a summary of our request, updated for certain true-ups through February 28, 2011, and settlement of certain issues. As Tom mentioned, we are now requesting an annual electric rate increase of approximately $200 million, based on a 10.7% return on equity, a 52.2% equity ratio, and rate base of approximately $6.7 billion. Approximately $40 million of the request reflects increased net base fuel costs. Other parties have also updated their recommendations in this case. The Missouri Public Service Commission staff now recommends an approximate $86 million annual revenue increase.

The drivers of the difference between our updated request and the staff's updated recommendation are provided on this page. As you can see, the largest driver is return on equity, accounting for about $108 million of the difference, based on the staff's midpoint return on equity. Also, the staff continues to recommend 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. On page 10, key aspects of the updated positions of several other parties to the case are outlined.

The Missouri industrial energy consumers are recommending $58 million of downward adjustments to our requested revenue requirement. Primarily reflecting a 9.9% midpoint return on equity and the exclusion of approximately $11 million of property taxes related to the Sioux scrubbers and Taum Sauk. The office of public council has recommended disallowance of the approximately $90 million of Taum Sauk Power Plant investment, which we have included in our filed rate base. The revenue requirement associated with this proposed disallowance is approximately $10 million annually. 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, net of insurance proceeds. This request is consistent with our 2007 settlement agreement with the state of Missouri.

Finally, the Missouri Energy Group, which represents certain other business customers, filed testimony supporting an approximate 9.9% mid-point return on equity. Hearings for this case are currently under way before the Missouri Public Service Commission and are scheduled to continue through mid-May. A Public Service Commission order is expected in July with new rates expected to be effective in early August. As Tom stated a moment ago, this electric rate case is very important for our Company. The results will impact the cash flows we have available to make important investments in our energy infrastructure in the future. We are committed to aligning our operations and maintenance spending and capital investments within our rate regulated businesses with the revenue and related cash flow levels provided by regulatory decisions.

Moving now to our merchant generation business segment on page 11, we provide an update of our forward power sales and hedge data. As you can see, we have significant hedges in place which are at power prices above current market levels. We expect our merchant plants to generate approximately 29 million megawatt hours in 2011. These 29 million megawatt hours include 100% of the expected generation of the Edison Electric Energy Inc. Plant, a plant in which Ameren owns an 80% interest. For 2011, approximately 27 million megawatt hours of our generation is sold or hedged at an average price of $45 per megawatt hour. For 2012, we have hedged approximately 17.5 million megawatt hours at an average price of $48 per megawatt hour. Further, for 2013, we have hedged approximately 9 million megawatt hours at an average price of $42 per megawatt hour. Our capacity sales are approximately 80% hedged for 2011, approximately 52% hedged for 2012, and approximately 26% hedged for 2013.

Turning to page 12, here we update our merchant generation segment's fuel and related transportation hedges. For 2011, we have hedged approximately 28 million megawatt hours at about $23.50 per megawatt hour. For 2012, we have hedged approximately 20 million megawatt hours at about $24.50 per megawatt hour. That cost is approximately $0.50 per megawatt hour lower than the figure we disclosed in February 2011, and for 2013 we have now hedged approximately 8 million megawatt hours at about $27 per megawatt hour. This cost is also an improvement by approximately $1.50 per megawatt hour compared the to our February disclosure. These 2013 coal hedges continue to include a large proportion of our expected burn at the 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. This hedging information completes our prepared remarks.

We will now be happy to take questions.

Thank you. We will now be conducting a question-and-answer session. (Operator Instructions). One moment, please, while we poll for questions. Thank you.

Our first question is from Paul Ridzon with KeyBank Capital Markets. Please proceed with your question.

Good morning, how are you?

Good morning, Paul.

Good morning.

Can you just give a little more detail on the $0.03 cost on the Sioux scrubbers with the equity linked financing?

And then, secondly just clarify what's in ongoing earnings. You're keeping the storms in there, I assume. And what are you doing with the charge for the Miranda excess capacity margin?

Sure. Let me -- I think there were three questions in there, which all good questions, I appreciate. Let me make sure I try to hit them all, though.

I think the first one was about the AFUDC equity. Last year, when we were constructing the Sioux scrubber, we were certainly capitalizing all of the financing costs associated with that as part of AFUDC. Those are both interest costs as well as equity financing costs. Once the scrubbers went into service in accordance with a regulatory agreement, we were able to defer them for regulatory purposes, the depreciation associated with that scrubber after it went into service, as well as all financing costs, both interest financing costs and the equity related financing cost. Once we get to the point of our new rates going into effect in Missouri, we would expect that all of those costs would then be getting recovered.

For accounting purposes, for financial reporting purposes, we are able to defer the depreciation recognition and the interest financing costs associated with that scrubber. However, we are not able to continue to recognize AFUDC equity, so that was a plus last year. This year, when you compare year-over-year results, we don't have those same AFUDC equity earnings. However, for regulatory purposes, those are being deferred and we certainly will get those returns once the new rates go into effect. And we did -- if you look back at our guidance we gave in February, my recollection is we expected a $0.07 to $0.08 negative impact year-over-year related to that AFUDC equity issue, but I think that was your first question.

The second question, I think, related to storm costs. We mentioned in our prepared remarks that we did have this year in the first quarter about $20 million of incremental operations and maintenance expenses associated with storm restoration costs. That equates to about $0.05 per share and they have been included in the ongoing earnings. We have not stripped those out, so that was I think your second question.

And then I believe your third question had to do with the Miranda-related issue. As we mentioned, again in our prepared remarks, we expect that based on the Public Service Commission's order in our fuel adjustment clause proceeding, that in the second quarter we would take a charge of about $17 million, and so that is also reflected in the ongoing earnings and is also reflected in the guidance that we gave today.

Thank you much for clearing that up.

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

Hi, guys. How are you?

Just a couple questions. First on -- I realize you don't normally break out some of the usage statistics, ex the weather. Can you talk a little bit more broadly about what you're seeing, excluding weather, on residential and commercial usage, just kind of going more to the economy? And then I have a follow-up question as well.

Sure, Erica. Thanks for the question. Yes, when we -- this is Marty again.

When we look at the sales for the quarter, as we talked about in our talking points, a couple things that I'd say impacted overall the native load margins. Some of that was reduced residential and commercial sales, which in part is due the weather. However, when we strip out weather, we do still see in the first quarter year over year some slight reduction in the residential and commercial sales. We talked at the beginning of the year about our expectation of moderate sales growth and what we're looking for over the course of the year today is probably in the range across the Company of around 1% growth in residential and commercial sales, probably a little less on the residential side and a little more on the commercial side, and that will vary a little bit from state to state as well, but that is what we're looking for over the course of the year.

In terms of industrial sales, if you're getting to economic recovery, we did see, again, year-over-year pretty good sales growth in industrial, even excluding the impact of Miranda. Overall, we saw, as we talked about in our talking points, a 7% year-over-year improvement in industrial sales. Over the course of the year, we don't necessarily expect industrial sales to be that robust, but we do expect that we may be able to still see mid single digit improvement year-over-year in industrial sales. And again, I'd say this year seeming to be led by Illinois, where we saw more out-sized growth. Missouri, excluding Miranda, frankly, is still down a little bit year over year in the industrial sector.

Okay.

So it sounds like -- and then what you've seen in the first quarter obviously would then seem to be consistent with that full year expectation implicit because you maintain your guidance is that -- ?

Yes. That's exactly right. We had never come out -- in the first quarter we talked about moderate sales improvement, but I don't think we quantified. What we're seeing is, in the first quarter, perhaps a little weaker than expectation, but overall we expect the growth this year to come in reasonably in line with our original expectations and we're able to maintain the guidance.

Okay.

And then just a second question on -- I may have missed just at the end of your comments there, Marty, on some of the fuel costs, improvements in terms of your hedged profile for this quarter versus your comments on the February call. Just what exactly is going on there? Is that more on the base load, the coal input costs, or anything going on with transportation there? What's sort of driving that? Is that the mix that you mentioned at the end or -- ?

Yes, sure, Erica. I'd be happy to sort of expand on that.

When you look at the slide we've prepared, slide 12, we try to break down for you the components of -- the main components of our overall hedged fuel costs. And if you look back at the changes in -- looking out at '12 and '13 for example, we really haven't changed at all the amount of hedges we have in place for transportation or fuel surcharges, so those amounts really haven't changed.

The coal hedges, however, have increased, and those hedges have increased I'd say in a line with the power hedges that we have in place, so we added some coal hedges to get the percentages up in line with our power hedges and as we did that we were able to bring the blended average of our hedges down. And we tried to communicate that back in February, that was our expectation, that based on current prices and broker quotes that we believed that we wouldn't -- as we put additional hedges in place, we would be able to bring the average cost down. And, at least as far as broker quotes go, between February and now, we've actually seen some improvement in pricing, and as we put these hedges on, we did in fact lock in prices that allowed us to bring the blended average down.

Okay. Thank you. That's helpful.

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

Good morning, guys.

Good morning, Paul.

On the -- I know you're not updating the environmental CapEx at the merchant fleet because of the proposed EPA rules, but is there any directional -- is there any major change that you think may be happening there as a result of that or is it pretty much -- is it pretty much useful for what we know right now?

This is Tom Voss.

We're just now really getting a chance to look at those rules. They're fairly extensive and fairly detailed and it's really going to take some time to figure out how it will comply. We do think there's maybe a little bit more flexibility than expected in the rules but at this point in time we really can't tell how that will actually play out on our particular plants yet.

And then just -- in terms of financing the merchant environmental CapEx, is that something that's solely something that's going to happen at the merchant sub or do you foresee some cash coming from the parent on that?

Yes, sure, Paul, this is Marty again.

As we talked about repeatedly and we said on this call, our objective would be for that business segment to be able to provide for its own cash needs and so with that being the objective, we're certainly still looking at every opportunity to, again, sell power at prices, premium prices to visible market prices. We're looking -- continuing to look at opportunities to further reduce operating expenses. We'll look at opportunities to defer or reduce capital expenditures to the extent it's prudent to do so and basically take actions to limit the financing needs for that business.

Other things that we would explore are things like we talked about today, we're engaged at FERC in the process of getting approval to sell our Columbia CTGs to the city of Columbia, again, about $45 million of additional cash proceeds, so we're going to look at opportunities like that to close the gap if there is one in cash flows needed for financing at that business.

Okay.

And then just finally, on the $17 million refund, I know you guys are asking for rehearing there, but assuming that you don't get any change in treatment on that, should we think of there being any ongoing issue in terms of this ruling other than the $17 million that you currently have to refund or is there -- or is this just like a one-timer or is it as it would seem? In other words, your ultimate exposure is $17 million as opposed to some ongoing potential impact from that?

Right, I understand, Paul. The exposure is limited because after our last rate case there was a change in the way these sales are incorporated into the overall rate making, into the base rates, so the exposure was the $17 million, but as we talked about on the call, there was about $25 million of additional margins that have been recognized on these contracts for periods subsequent to this particular -- to the period affected by this ruling but prior to the new rates going into effect, so there is a little bit of additional exposure.

However, after our last rate case the -- those sales and the margins on those were included in the overall base rate, and I think that's one of the reasons, too, why we're seeing a little bit of a reduced margin in this first quarter, compared to last year -- has to do with the expiration of some of those contracts and the inclusion of margins associated with all of our sales being included in base rates.

Okay. Thanks a lot.

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

Hi. Good morning.

Good morning.

As I was looking at your recent integrated resource plan in Missouri, it seems as if you're planning to move forward or could potentially move forward with new scrubbers at Rush Island. I was just wondering if you could give us a sense as to CapEx and timing, and perhaps as you alluded to before, how that meshes with perhaps your initial read on EPA's Hazmat rules? And, perhaps, also as well, tying in discussions, I think you talked about 5 further units with ACI, so perhaps your overall Ameren Missouri environmental CapEx plan?

Hi, Julian. This is Warner Baxter.

Can I comment a little bit on what we put in the IRP and really where we're at on the environmental compliance plan? As you know, we filed that IRP, integrated resource plan, in February, and prior to that we had not seen at least the proposed new rules on the MAC standards and of course the transport rules are still pending, and, so that was based on a host of assumptions at that point in time.

And, you're right, we looked out in the next several years at putting some additional scrubbers on at Rush Island, so where we're at today is just as Tom said. We are taking a look at all these rules and carefully looking at our overall environmental compliance plan. As Marty talked a little bit earlier, we've made significant progress in that environmental compliance plan by putting in the Sioux scrubbers, but we are still going to be continuing to look at all those proposed rules and look very carefully at all of our potential compliance options to do what we can to mitigate the increasing costs associated with those new rules to our customers, so right now it would be premature to say that we finalized any of those determinations.

IRP put that as our best view at that time, but we will sharpen our pencil here over the next several months and get to a more refined view in the future.

Great.

And then secondly, I know you addressed it just now, but with respect to the Missouri sale, the asset sale to the Missouri co-op, at this current point in time do you project needing to inject -- do you project needing to inject equity into Genco in '12? Or is that more of a '13, '14 decision at this point as far as you guys see out?

No, I'd go back to my prior comments. Julien, this is Marty.

That CT that we talked about, just for clarity, because I know you just transitioned and I know you realize this, we transitioned a little bit from a Missouri discussion over to a merchant discussion in Genco. It's a Genco asset that's being sold and that's $45 million of potential additional cash for Genco to finance its operations.

We're not at a point where I'd say we're giving out any guidance with respect to '12 or for '13. I'd go back to my prior comments that we are looking at every opportunity to improve margins associated with that business and reduce operating and capital costs to avoid the need for additional financing, and we'll look at opportunities like the sale that we talked about here, $45 million sale of the CT, to plug any cash flow needs that business segment may need, so those are our objectives and that's what we're working to achieve.

Great.

And then just a quick last question here with regards to the electric rate change in Missouri, the year on year plus 3. Do you mind talking about or elaborating with respect to the net of certain related expenses, just how to think about those related expense? Is that a full year impact here and what those expenses are?

Right. No, I wouldn't necessarily annualize those. I think that when you have a rate increase, sometimes there are things that are annualized like increases in depreciation or amortizations.

However, that would also include things like changes in the timing of when fuel costs, for example, are recognized under fuel adjustment clause in Missouri. To the extent that the timing of the inclusion of a base fuel cost changes from period to period, that would affect the margins that we have for that segment, so I go back a little bit. We mentioned in the comments about we did see some lower margins. We said part of that had to do with some of our weather sensitive loads. Also, some of it had to do with these long-term requirement sales, which again were included in the overall net based fuel cost calculation in the last rate case.

So again, incorporating those and incorporating different timing pattern and fuel cost, you'll get to a little bit of a different margin month by month. I'm not sure you can get to a real run rate on those net other items.

Great. Well, thank you very much.

Okay.

Our next question comes from Andy Levy with Caris & Company. Please proceed with your question.

I'm all set, but thank you very much.

Thank you.

Our next question comes from Gregg Orrill with Barclays Capital. Please proceed with your question.

Thanks.

I was wondering if you could touch on HB14 in Illinois and what are the prospects for that and the key issues that are the swing factors right now for whether it gets done or not?

Good morning, this is Scott Cisel, and I'll respond to your question.

We continue to proactively meet with the leaders and the member of the general assembly, and they remain curious and wanting to understand the merits. And we are working hard to get a vote cast in both chambers before the end of this session. Certainly, it's too early to predict the outcome, but we believe there's a fair chance that the bill will be heard, and we'll have an opportunity to have a vote cast again in both chambers yet this spring session.

Okay.

And also on the Cole County case in Missouri, are you still expecting a ruling on the merits of that case or not, given that you have a rate decision coming up?

Hi, Greg, this is Warner.

With regard to the Cole county case, I think you have to keep in mind, we have appeals which are pending for both our 2007 and 2009 rate orders on specific issues. And those are still pending and those will go through the normal process here over the next several months and maybe beyond, just several, but maybe close to a year when you look at our most recent rate case. Those will go in the normal course.

If you refer to the rate roll back and those types of issues, if that's what you're referring to, as Marty and Tom said, those issues have been denied in 3 venues. Whether there's anything more that will happen associated with rate roll back remains to be seen, but we've vigorously defended those positions already and have been successful, but they are appeals pending and we continue to fight those issues with the courts.

Okay. Thanks.

Our next question comes from Taran Miller with Knight Capital Group. Please proceed with your question.

Good morning.

I was wondering if you're willing to comment on what role or changes might occur as Entergy enters the MISO and how that might influence development of a capacity market for MISO.

I'll take -- this is Tom. I'll take one stab at that and maybe somebody else will want to jump in.

It's kind of early right now to really state a lot about how the markets will be affected. We certainly think that them coming in, it should help out with some of the administrative costs of operating MISO and that would be a good thing. Actually, how the market's going to flow, I think it's just too early to speculate on that at this time.

Agreed, Tom. This is Andy Serri.

We are, as everyone else is looking at the impact of Entergy joining MISO. Let's not lose fact -- or lose sight that it has to receive all the necessary approvals for that to happen, but there is some transport capacity between MISO and Entergy as it currently exists and we're looking at that. As far as not only the ability to get capacity and energy into the Entergy markets, but also just the state of the Entergy markets, not only Entergy's position, but the different players in that market as well.

And, could you just give us a broader update on what you think is going on with reference to the potential development of the capacity market?

Sure.

As it stands right now, MISO has plans to file a new capacity construct next month, June of this year, and that construct would basically go from a monthly requirement to an annual requirement. It would be a single round with a vertical reliability target, a target number for capacity and locational pricing mechanisms to handle not only the export, but import constraints of the different zones and across the seams as well, but the final implementation with that filing here in June would be for planning year 2013-14.

I thank you very much.

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

Hey, guys.

Just had a question for you. At what stage on both the nonregulated side, but even the regulated side, when you look at the various rules making their way through the EPA right now, when do you have to make decisions by on whether to scrub units or potentially start setting retirement dates for units?

Well -- this is Tom Voss.

We're certainly -- we've been planning for a long time. We weren't just waiting for these rules. We had our own point of view, you might say, on where we thought they would be and when implementation schedules and we were working towards compliance. I don't think anything that came out so far would change anything we've been working on as far as compliance.

We still have time, we think, in order to figure out exactly the best way to comply with these new rules. As I say, they have some flexibility involved with them that we're pleased with and we have to study it a little further to ensure, but we have time to change or adjust our implementation schedule.

This is Doug Fisher. We have time for just one more question.

Our last question comes from the line of Neil Kalton with Wells Fargo. Please proceed with your question.

Good morning, everyone.

Good morning, Neil.

Just a quick question on capacity, following on a previous question about the MISO looking at a capacity market, is that shaping your hedging philosophy in terms of capacity as you look out to '13, '14?

And then very quickly, separately, what kind of prices are you seeing out there in the market for capacity in the 2012-13 time frame right now?

Sure. Several questions there. I'll see if I can address them. If I don't, let me know.

We look at capacity, not only capacity sales individually, but also as we add full requirement customers bundling energy with capacity sales on that. Into that capacity construct, we're actively selling into that market, both on the retail and the wholesale sector, but as far as the construct, we worked actively with MISO to form that. We were hoping to push that -- the construct moves from a 1 year to a multi-year, similar to what we're seeing in PJM, but yes, I think your other question was as far as what we're seeing for capacity prices in 2012 and '13?

Correct.

I've got those Andy, if I can be of help.

Yes, go ahead.

What we're seeing out there right now for dollars per megawatt years, in 2012, around 360, in 2013, around 5,300.

Thank you.

I would now like to turn the floor back over to management for closing comments.

This is Doug Fischer.

Thank you for participating in this call. We look forward to meeting with many of you at the AGA Financial Forum in May, in mid-May.

Let me remind you again that this call is available through May 12 on playback and for 1 year on our website. Today's press release includes instructions on listening to the playback. You may also call or e-mail the contacts listed on the release. Financial analyst inquiries should be directed to me, Doug Fischer, media should call Susan Gallagher. Our contact information is on the news release.

Again, thank you for your interest in Ameren.

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