阿莫林 (AEE) 2011 Q4 法說會逐字稿

Greetings, and welcome to Ameren Corporation's fourth quarter earnings conference call.

At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder this conference is being recorded.

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

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

Before we begin let me cover a few administrative details. This call is being broadcast live on the Internet and the webcast will be available for one year on our website at www.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 webcast and presentations and follow the appropriate link.

Turning to page 2 of the presentation, I need to inform you that comments made during this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, events, conditions and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated and described in the forward-looking statements. For additional information concerning these factors, please read the forward-looking statements section we issued today and forward-looking statements and risk factors -- we are getting a little bit of an echo here. So just a moment. Let me see if this microphone is better. Just bear with us here for a moment, please.

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 filing with the SEC. Tom will begin this call with an overview of 2011 earnings and 2012 guidance followed by a discussion of recent business and regulatory developments. Marty will follow with more detailed discussions of 2011 financial results, our 2012 guidance and regulatory and other financial matters. We will then open the call for questions.

Here's Tom, who will start on page 3 of the presentation.

Thanks, Doug. Good morning, and thank you for joining us. Core earnings for 2011 were $2.56 per share in line with the increased guidance range we provided in November of last year. As expected these 2011 results were below the $2.75 of core earnings per share achieved in 2010. This reflected lower electric sales to native load utility customers due in part to summer temperatures that, while warmer than normal, were below those of a very hot 2010.

In addition, Merchant Generation margins declined as a result of lower realized power and capacity prices as well as higher fuel and transportation related expenses. These factors were offset in part by increased electric utility rates in Missouri and Illinois. Further, core non-fuel operations and maintenance expenses were lower, reflecting continued disciplined cost management and interest costs fell as we used our free cash flow over the last two years to reduce outstanding debt. Beginning on page 4 you will find a list of our key accomplishments in 2011.

These accomplishments are clear evidence of our commitment to providing customers with safe, reliable, environmentally responsible and reasonably priced energy while at the same time enhancing value for our shareholders. To put these accomplishments into context, it is important to summarize some of our key financial objectives. At our regulated utilities, we seek to earn fair returns on our investments which allow us to attract on competitive terms the capital we need to provide the level of service our customers expect. We are working to earn fair returns by maintaining solid operating performance while improving our regulatory frameworks and seeking rate relief as needed.

Further, we are committed to allocating capital to those projects in which we expect to earn fair returns and aligning our spending with regulatory outcomes and economic conditions. At our Merchant Generation business we seek to protect and enhance shareholder value by minimizing operating and capital spending during the current period of low power prices while advocating for regulatory policies and power market improvements that will lead to improved economics. While I will not touch on each of the 2011 accomplishments listed on pages 4 and 5, I would like to summarize and highlight a few of our successes. At Ameren Missouri and Ameren Illinois we posted another year of solid distribution system reliability. And at Ameren Missouri and our Merchant Generation business, availability of our energy centers remained high. Our restoration efforts following severe storms in both Missouri and Illinois won praise from government officials.

In addition, in 2011, we actively pursued legislative and regulatory agendas that we expect will improve the predictability and level of earned returns at our regulated utilities. The most notable development on this front was the enactment by the State of Illinois of legislation establishing performance-based formula rate making for electric delivery service. Further, we sought and obtained electric and gas rate increases in Missouri and a gas rate increase in Illinois. The latter of which was authorized in January of 2012.

Continuing on page 5. At our Merchant Generation business we updated our environmental compliance strategy during 2011, leading to reductions in capital spending plans and expected future operating costs compared to our prior plans. Ameren Transmission Company also notched important successes, allowing us to move forward with our plans to improve the regions electric transmission system and also create jobs. In May, the Federal Energy Regulatory Commission, or FERC, approved requested constructive rate treatment for two transmission projects.

And in December, the Midwest Independent Transmission System Operator, or MISO, approved three major transmission projects. On the financial front we concluded another year of successful cost management with a decline in core non-fuel operations and maintenance expenses. In addition, we generated enough cash flow from operations to fund more than $1 billion of investments and the common dividend while also reducing outstanding borrowings. And more than 85% of these investments were for infrastructure at our regulated utilities. Finally, in October of 2011, Ameren's Board of Directors increased the quarterly common dividend by $0.039 -- 3.9% per share.

Moving now to page 6 and a forward focus. Today we announced 2012 GAAP and core earnings guidance of $2.20 to $2.50 per share. The projected decline in 2012 core earnings per share compared to 2011 is primarily due to expected lower margins at our Merchant Generation business and an assumed return to normal temperatures. These factors are expected to be partly offset by increased utility rates as well as reduced non-fuel operation of maintenance expenses in Missouri.

Turning to page 7 and pending regulatory matters, in January of 2012, Ameren Illinois elected to participate in Illinois' new performance-based formula rate-making process for electric delivery service by making an initial filing with the Illinois Congress Commission. As a result, we expect Ameren Illinois electric delivery earnings in 2012 and beyond to reflect formula rate-making which will enable us to invest in the state, improving infrastructure and creating jobs. The improved infrastructure will enhance reliability and provide customers with the energy usage options made possible by Smart Meters.

Turning to Missouri, we are focused on modernizing the existing regulatory framework. A modern regulatory framework that allows us to recover and earn fair returns in our investments on a timely basis will improve our ability to bring aging infrastructure up to 21st century standards, allowing us to meet customer expectations and create jobs. Earlier this month, Ameren Missouri filed an electric rate case with the Missouri Public Service Commission, seeking to recover its operating and capital costs and to earn a fair return on the investments it has made to serve its customers. Marty will provide details of the filing in a few minutes.

However, I would like to highlight two proposals we have made in this case to enhance the existing regulatory 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 rate cases.

In addition to the pending electric rate case, in January 2012, Ameren Missouri filed its first request with the Missouri Public Service Commission for approval of new and expanded energy efficiency programs under the Missouri Energy Efficiency Investment Act. Our proposed energy efficiency programs are expected to provide significant long-term benefits to our customers. The energy efficiency legislation was designed to enable utilities to pursue cost effective energy efficiency programs by requiring that the regulatory framework properly align the utilities financial incentives with those of customers. Ameren Missouri's ability to move forward with its proposed energy efficiency programs will require a regulatory framework consistent with this legislation. And our energy efficiency proposal is consistent with the legislation and industry best practices.

Before I conclude my comments on pending regulatory matters, I want to mention that we support the MISO's filing at the FERC for an annual capacity construct as a first step, although we continue to advocate for a multi-year capacity construct to ensure properly functioning power markets. Further, we strongly support MISO's effort at FERC to increase the amount of capacity that can be shared across the MISO PJM seam. Constructive action on these matters is the right thing for FERC to do because it would lead to prices that more accurately reflect the value of capacity, improve efficiency and reliability, and benefit customers over the long-term.

Turning to page 8. Our Merchant Generation business has produced positive free cash flows in recent years including over $200 million in 2011. This reflects the benefit of our forward power sales and hedging programs and actions we have taken to control spending. For 2012, we have against sold-forward or hedged nearly all of our expected 2012 Merchant Generation output at prices above current market levels. As a result we expect our Merchant Generation segment to be free cash flow positive in 2012 and for Genco with the benefit of existing money-pool receivables to provide for its own cash needs.

However, as we look beyond 2012 we cannot ignore the potential negative impact of lower prices on our cash flows. As most of you are aware since late 2011, there's been a sharp decline in forward power prices. We attribute this most recent price decline to the US Court of Appeals order staying the Cross-State Air Pollution Rule, or CSAPR, as well as the recent decline in natural gas prices. It is unclear to us exactly when legal and regulatory uncertainties related to CSAPR will be resolved and when natural gas and power prices will recover. This decline has prompted us to again revise capital spending plans for our Merchant Generation business. As a result, we have decided to immediately decelerate construction of the Newton Scrubber project, postponing installation until such time as the incremental investment necessary for completion is justified by the visible market conditions.

In addition, we are removing from our forward five-year expenditure plans the previously planned Edwards III Helper Electrostatic Precipitator. We believe that these actions are the best path to ensuring appropriate returns on incremental environmental investments and achieving continued positive free cash flow at our Merchant Generation business segment during this period of low power prices. We estimate that these actions will reduce 2012 through 2014 capital needs by a total of approximately $270 million compared to prior plans. As we work to ramp down the Newton Scrubber project, we will do so in a manner that preserves the value of work commissioned to date.

We plan to take delivery and place the various completed components and materials into a safe store condition over the remainder of this year. Thereafter, we will perform minimal amounts of ongoing construction activity such that when the economics merit completing the Newton Scrubber project in earnest, we will be able to do so in an orderly and cost effective manner. We have already initiated discussions with our partners and vendors on the tasks, timelines and costs associated with decelerating the project. Based on these discussions we have removed the vast majority of capital spending related to the Newton Scrubber project from our 2013 and 2014 plans. And we have reduced our expected 2012 spending level on the Newton Scrubbers to approximately $150 million reflecting work commissioned to date.

These developments highlight the critical need for a viable multi-year capacity market in the MISO region as well as the need for portability of capacity between MISO and PJM. The current state of uncertainty rising from low power prices and uncertain environmental rules has the potential in my view to negatively impact electric reliability within MISO and elsewhere in the nation. Moving now to page 9, we remain very excited about our plans to significantly grow our investments in FERC regulated electric transmission projects. In fact, Ameren expects to invest a total of approximately $1.7 billion in such projects over the five-year period ending in 2016.

Customers should benefit from improved reliability and a more efficient electric system. Our investors should benefit because we expect to earn fair returns on such investments. At this time we are investing in FERC regulated transmission through two different entities, Ameren Illinois Company and ATX. Ameren Illinois has significant opportunities to invest in projects that are focused on local load growth and reliability needs. This business expects to invest nearly $900 million in such projects over the five-year period.

ATX plans to build Greenfield regional transmission projects, initially within Illinois and Missouri and to invest approximately $750 million in such projects over the next five years. In December of 2011, MISO's Board of Directors approved three of ATX projects as multi-value projects. These projects represent more than $1.2 billion of ATX investments over eight years. And we're moving ahead with development of these projects. In fact for the largest of these, the $800 million plus Illinois Rivers project, we are moving forward with the line routing and the sighting process.

I will now turn the call over to Marty.

Thanks, Tom. Turning to page 10 of the presentation. Today we reported 2011 earnings in accordance with generally accepted accounting principles, or GAAP, of $2.15 per share, compared to 2010 GAAP earnings of $0.58 per share. Excluding certain items in each year, Ameren recorded 2011 core earnings of $2.56 per share, compared with 2010 core earnings of $2.75 per share. 2011 core earnings exclude three items that are included in GAAP earnings. The first of these non-core items is employee separation charges related to the 2011 voluntary retirement offer which reduced earnings by $0.07 per share.

The second non-core item is a $0.02 per share loss from the net effect of unrealized mark-to-market activity. The third of these full-year 2011 non-core items is goodwill, impairment and other charges, taken in the third quarter of $0.32 per share. These charges were the result of the Missouri Public Service Commission's disallowance of costs of enhancements related to the rebuilding of the Taum Sauk pumped storage hydroelectric energy center, as well as our decision to cease operations at the Meredosia and Hutsonville Merchant Generation Energy centers.

Turning to page 11, here we highlight key factors driving the variance between core earnings per share for 2011 and 2010. Key factors adversely affecting the comparison include a decline in margins at our regulated utilities of $0.30 per share after excluding rate changes. We estimate that $0.13 of this decline was due to lower weather-normalized loads and $0.10 was primarily the result of temperatures that were below those of a very hot 2010. Another $0.05 of the decline was due to a second quarter 2011 charge related to the Missouri Public Service Commission requirement that certain revenues be flowed through the fuel adjustment clause. A decline in margins at the Merchant Generation business reduced 2011 earnings by $0.21 per share. The reduced margins reflected lower realized power and capacity prices and higher fuel and related transportation costs.

Several severe storms in the first half of 2011 reduced earnings by $0.09 per share, with $0.06 of this related to Ameren Missouri and $0.03 related to Ameren Illinois. Key factors favorably impacting the comparison of 2011 core earnings to 2010 core earnings included electric rate increases in Missouri and Illinois. Changes in electric and gas rates, net of certain related expenses increased earnings by $0.23 per share. These rate changes included higher electric rates in Illinois effective in 2010 and an electric rate increase in Missouri effective in late July 2011.

The other key factor positively impacting earnings was lower core non-fuel operations and maintenance expenses which benefited 2011 earnings by $0.20 per share, excluding the previously discussed storm restoration costs. Turning to page 12, I would now like to discuss the key drivers and assumptions behind our 2012 earnings guidance for our Missouri and Illinois regulated utility businesses of $2.20 to $2.40 per share. In 2012 we expect to achieve an earned return on equity of approximately 9% to 9.6% on average regulated utility common equity of approximately $6 billion. This guidance assumes a return to normal weather, reducing earnings by an estimated $0.16 per share compared to 2011 results.

While 2011 summer temperatures were milder than those experienced in 2010, 2011 summer temperatures were much hotter than normal. Weather normalized margins are expected to increase as a result of the 2011 Missouri Electric rate increase and the 2012 Illinois natural gas delivery rate increase. Our guidance also reflects the implementation of the new formula rate-making process for our Illinois electric delivery business. Our earnings expectations for this business assume a formulaic midpoint allowed return on equity of 9.2%, which incorporates a forecasted 2012 average 30-year treasury yield of 3.3%. This treasury yield forecast is based on the blue chip consensus estimate as of February 1, 2012.

Finally, our Outlook for regulated margins assumes little growth in weather-normalized electricity sales. Regulated utility earnings guidance for 2012 incorporates increased non-fuel O&M spending at our Illinois utility as we begin to implement our electric delivery modernization action plan. At our Missouri utility, we expect 2012 non-fuel O&M spending to be lower than that experienced in 2011. Headcount at Ameren Missouri and Ameren Services declined by approximately 340 at the end of 2011 as a result of the voluntary retirement program.

In addition, the absence of a scheduled refueling and maintenance outage at the Callaway Nuclear Energy Center in 2012 is expected to lower O&M expenses by $0.10 per share. Callaway is refueled approximately every 18 months. Finally, we expect 2012 regulated earnings to be impacted by increased depreciation and amortization expenses. Moving to page 13, let's now shift to a discussion of the key drivers and assumptions behind our 2012 earnings guidance for our Merchant Generation business. We expect this segment to post earnings of $0.00 to $0.10 per share this year. The most significant driver of the expected earnings decline in 2012 compared to 2011 is a decrease in margins of $0.20 to $0.30 per share due to lower realized power and capacity prices and higher fuel and transportation-related costs.

We expect our merchant plants to generate approximately 27 million megawatt hours in 2012, with approximately 25 million megawatt hours of this sold or hedged at an average price of $44 per megawatt hour. Our guidance assumes that unhedged expected generation is sold at current market prices. In 2012, we anticipate having available generation of up to 32.5 million megawatt hours from our coal-fired Merchant Generation Energy Centers in the event power prices rise and support higher generation levels. Our base load fuel and transportation-related costs are about 93% hedged at approximately $24 per megawatt hour.

Finally, we project 2012 Merchant Generation non-fuel operations and maintenance expenses will be essentially flat with those of 2011, or approximately $290 million. Regarding key Ameren-wide assumptions our earnings guidance reflects an effective consolidated income tax rate of approximately 36%. And the number of common shares outstanding in 2012 is expected to average 242.6 million. In 2012 we plan to purchase shares on the open market for our dividend reinvestment in 401(k) plans. During the past several years we have issued new shares to fund these plans.

As I close our discussion of 2012 earnings guidance, I 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. Core non-GAAP earnings and guidance also exclude any net unrealized mark-to-market gains or losses. Further, earnings guidance is subject to the risks and uncertainties outlined in or refereed to in the forward-looking statements section of today's press release.

Turning then to page 14, we provide both our actual 2011 and projected 2012 cash flow information. As shown on this page, we calculate free cash flow by starting with our cash flows from operating activities and subtracting from it our capital expenditures, other cash flows from investing activities, dividends and net advances for construction. In 2011, free cash flow reached $381 million. $56 million more than our November guidance. For 2012, we anticipate free cash flow will be negative by approximately $230 million. The decline in free cash flow primarily reflects lower cash flow from operations and higher capital spending plans. Cash flow from operations is expected to decline in 2012 compared to 2011 as a result of lower projected core earnings at our Merchant Generation segment, reduced tax refunds and greater utility spending subject to deferred rate recovery, amongst other matters.

The higher 2012 capital expenditures reflect increased expected spending, primarily at our regulated utilities. We anticipate that our Merchant Generation business will be free cash flow positive in 2012, despite expected lower earnings and higher capital expenditures. Our only material long-term debt maturity in 2012 is a $173 million senior secured note at Ameren Missouri. Moving now to page 15 and pending rate cases. As Tom mentioned, in January, Ameren Illinois made its initial filing under the new performance-based formula rate-making framework for its electric delivery business. This initial filing is for a $19 million annual rate decrease because it is based on 2010 costs. This rate change is to be effective in late October 2012.

However, 2012 electric delivery service earnings will reflect a true-up for 2012 year end rate base and 2012 actual cost of service and include historical ICC rate making adjustments. The allowed return on equity will be based on the prescribed formula I discussed earlier. Moving to page 16 and Missouri, in February we filed for a $376 million increase in annual electric rates with the Missouri PSC. The filing incorporates a 10.75% return on equity, a 52% equity ratio and rate base of $6.8 billion. $103 million of this request is related to higher net fuel costs. Note the 95% of these higher net fuel costs would be reflected in fuel adjustment clause, our FAC, rate adjustments absent this filing.

The request also includes $81 million to recover the annual cost including revenues to offset through-put disincentives of the three-year energy efficiency programs Ameren Missouri proposed in its MEEIA filing, which Tom mentioned earlier. As he stated our ability to move forward with our proposed energy efficiency programs will require a regulatory framework consistent with the energy efficiency legislation. In addition, to recovery of higher fuel costs and costs associated with our proposed energy efficiency programs, the rate request includes recovery of investments made to improve the reliability of our aging infrastructure and to comply with renewable energy regulations, as well as other cost increases.

A PSC order is expected in December of 2012 with new rates expected to be effective in January 2013. On page 17, we detail our new five-year regulated utility capital expenditure outlook. In 2012 we plan to invest approximately $1.2 billion. And over the four-year period from 2013 through 2016, the midpoint of aggregate capital spending is projected to be approximately $5.7 billion with an annual target range of $1.3 billion to $1.5 billion. The environmental expenditures embedded in this outlook are those required to meet current environment rules and regulations including the stayed CSAPR and the recently issued MATS as well as our assessment of the likely impact of the coal combustion byproduct rules. The pie chart on the right side of this page breaks down our five-year regulated capital spending plan by business segment and activity.

A little less than half is from Missouri with almost 30% targeted for our Illinois Electric and Gas delivery businesses and almost a quarter slated for FERC-related transmission projects. The Illinois regulated capital spending numbers reflect additional investments to modernize its electric distribution system as required by our participation in Illinois' performance-based formula rate program. Moving now to page 18, here we provide an update on our 2012 and 2013 forward power sales and hedges and introduce our 2014 hedge data for our Merchant Generation business. As you can see, we have significant hedges in place at power prices greater than current market levels. We already discussed our 2012 power hedges.

For 2013, we have hedged approximately 14 million megawatt hours at an average price of $40 per megawatt hour. Further for 2014, we have hedged approximately 7 million megawatt hours at an average price of $44 per megawatt hour. To assist you in understanding our Merchant Generation business segments margin drivers, we have provided a pie chart that breaks down our 2012 expected revenue by type. Turning to page 19, here we update our Merchant Generation segment's fuel and related transportation hedges. We previously discussed our 2012 fuel hedges, for 2013 we have hedged approximately 12 million megawatt hours at about $25.50 per megawatt hour. For 2014, we have hedged approximately 5 million megawatt hours, also at about $25.50 per megawatt hour. 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 a perspective on how each component contributes to our overall cost.

On our final page, number 20, we outline capital expenditures for our Merchant Generation business for each of the next five years, showing the breakdown between expenditures for maintenance and for environmental compliance. As Tom mentioned, in light of current forward power and capacity prices, as well as uncertain environmental regulations, we are decelerating construction of our Newton Scrubber project and removing the Edwards Helper Electrostatic Precipitator from our five-year spending forecast. The estimated environmental expenditures in 2012 include approximately $150 million of spending on the Newton Scrubber project. And capital expenditures in 2013 through 2016 assume approximately $20 million per year of ongoing external construction costs for this project.

Newton Scrubber project-related capitalized interest and overheads are not included in the 2013 through 2016 numbers. As you can see on this page, projected environmental expenditures are quite limited over the 2013 through 2016 period. Of course we will continue to review and adjust our Merchant Generation spending plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, environmental standards and compliance technologies, among other factors. This completes our prepared remarks.

Thank you. (Operator Instructions)

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Ladies and gentlemen, thank you. We will now be conducting a question-and-answer session. (Operator Instructions) Our first question is from Paul Patterson with Glenrock Associates. Please proceed with your question.

Good morning. Can you hear me?

Yes, Paul, this is Marty Lyons. Yes, we can hear you now.

I just wanted to ask about the delay in these Merchant Generation CapEx projects, the one at Newton and the Precipitator. Is there an operating earnings impact that is associated with any of this? I mean in other words, do you have to buy emissions or anything different? I mean is there any operational issue we should be thinking about in terms of this significant change in CapEx?

Right, Paul, I think I understand. This is Marty still. No, not in the near term. These projects really designed to help with compliance, really when you get out into the 2015 timeframe. So in the near term, really no impact on operating, earnings, or cash flows as a result of decelerating the project.

Okay. And then with respect to just the capital expense itself, delaying this and what have you, is there any change in terms of the total capital expense that you would be expecting?

Well, I guess that is -- it is too soon to tell, I guess, whether the ultimate cost of the project will change. But just to give you a sense, with respect to the Newton Scrubber project, through the end of 2011, we had invested about $100 million roughly in that project. As we said on the call, this coming year as we decelerate the project, we do plan to take materials that have been billed or materials that have been commissioned, allow those to be completed and take those to the site, put them in safe-store condition. So, we expect to incur about another $150 million this year in doing that.

At that point, we will be taking the capital expenditures down to more the minimal levels that we described in the call. And continue to monitor changes in power market conditions, capacity markets, changes in environmental rules and the like. And certainly assess how we might, absent reacceleration of that project, go about complying with environmental rules out in that 2015 timeframe.

But I think Paul, when you look back to the guidance we gave last fall, I think the total project cost, it was sort of embedded in the guidance, was somewhere around $490 million for the Newton Scrubber project. If we move to reaccelerate in some point in the future, we will certainly provide an update on what we think the costs are at that time to complete the project. We are estimating as we sit here today, if we were to reaccelerate the project at some point in the future, it would probably take in the range of say 20 to 24 months to complete the project.

Okay, great. Thanks a lot.

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

Hi, good morning. Can you hear me? I just wanted to clarify a little bit more on the Merchant CapEx front. Just when you are thinking about compliance with MATS and your own Illinois State-specific standards, 2015 and beyond. Status quo I would imagine that it would result in some sort of operational impairment of the assets without putting in the CapEx? I mean would be some sort of reduction in your ability to dispatch from certain units? Is that the right way to think about that?

Yes, Julien, this is Marty again. That is a fair assessment. I think without the Newton Scrubbers being reaccelerated out in the 2015 timeframe. It's, frankly, it's really the Illinois multi-pollutant standard that becomes the challenging standard for us to comply with. As you know out in that timeframe, our fleet wide SO2 emissions need to be reduced down in the 2015 timeframe. Between now and then we really don't expect that we would have any forced reductions in generation levels as a result of CSAPR or multi-pollutant standard or other rules.

When you get out into 2015, as it relates to MATS compliance, absent the Newton Scrubber, we think we have other ways to comply, activated carbon, precipitators, low sulfur coal and the like, all help with compliance there. And as it turns out with the CSAPR rules, obviously they're uncertain right now because they have been stayed. But based on the allowances that came in the final rules, based on our decision to shut down Meredosia and Hutsonville, the CSAPR rules really aren't seen as a significant limitation either.

Great. So, if I were kind of to read between the lines here, frankly, from a compliance perspective, you could decide let's say a couple of years down the road and still move forward? You said 20 to 24 months there to complete the Newton Scrubber? So, there's still a couple years latitude, all in? Give or take? Is that kind of the right way to think about that?

Yes, that's fair. We feel like as we decelerate today, that we have got some optionality for a while before [it] would actually impact future generation levels. And in the meantime, we can also look at how we might go about alternatively complying with some of those rules. And, again, assess whether a reacceleration is appropriate.

Excellent. And then just a final question here on the Genco guidance for breakeven cash flow for this year. Are there any exceptional items to bear in mind as we're looking at your EPS guidance translating that into the free cash flow guidance? Anything notable to take note of?

I don't know that there is anything notable to take note of in that regard, as you reconcile.

Okay. So, EPS guidance should equate to positive free cash flow?

Yes, I think so. I mean nothing is coming to mind offhand. We certainly as we mentioned in the call, we are expecting positive free cash flow overall at the Merchant Business.

And I guess one thing of note, early in this first quarter, we did sell one of our assets at the Medina Valley Cogen facility, fairly small facility. I think about $17 million in cash flow coming from that. So, that may factor into our net CapEx for this year. But other than that, earnings should translate into cash flow.

Great. And then just a tiny clarification here in terms of your guidance for coal. It seems like that came down $1.00 per megawatt hour in 2013. Just wanted to clarify. Is that basically a lower PRB price, or a lower transport price?

Well, it's really a little of each, Julian. So, the price dropped I guess from a $26.50 to $25.50. We did increase the amount of transportation that we have hedged. We also increased the amount of coal we have hedged. And, as you saw, a little bit of fuel surcharge. So, frankly, all three of those things would have gone into the mix.

Thanks for the clarification.

Our next question comes from the line of [Tom Bradinoff], with Fore Research & Management. Please proceed with your question.

Hello, guys. Good morning. Can you hear me? I had a question on your cash flow, going forward. Basically, it sounds like that you indicated basically in 2012 your Merchant Business would be cash flow positive. And I think you mentioned that you are going to get the benefit of the money pool receivables there to kind of help you with that.

So I'm kind of curious as to what that number is that is going to be coming from the money pool receivables? But really I'm more interested in 2013, when obviously, kind of given where the current strip is and where prices are today, that Merchant Business will be burning call it the $100 million plus of cash. So, are you going to explicitly support that Business going forward, and kind of bridge that short fall? Or like what is the thinking in terms of actually helping with the cash flow situation post-2012?

Sure. So, let me start with the 2012. So, when we talked about the Merchant business overall being cash flow positive in 2012. I'm talking about Ameren Energy resources overall, which has got both the Genco subsidiary as well as the AERG subsidiary assets in it. Overall that would be cash flow positive. And then as you point out, we said Genco, which is a subsidiary of the Merchant Segment, would utilize some of its money pool receivables.

As of year end, it had about $74 million of money pool receivables. And we project somewhere in the neighborhood of around half of that might be utilized this year by Genco. As you look out in 2014 and beyond, we certainly haven't given any cash flow guidance. We have said before and we have repeated that our goal is for the Merchant segment, as well as for Genco to be able to support their own cash flow needs. And we feel like the decisions we've made here with respect to decelerating the Newton Scrubber project and deferring the precipitator at Edwards, are certainly very helpful to us in achieving that goal.

Got it. So, maybe then the question really is -- and you know at the end of the day, I am kind of running my own math and I'm sure you guys have your own projections. But -- maybe the right question then to ask is, assuming that the Business is cash flow negative in 2013, then how would you think about the Merchant Business at that point in time? Just help us kind of think through the various options.

Well, I think the various options first of all, have to do with the segment and with the way the segment operates its Business. So, we are certainly going to be looking for further opportunities to reduce operating expenses, to carefully and continually examine even the capital expenditures that we still have in the forecast.

And we are continuously seeking opportunities to market the power that we have at above market prices. So first and foremost, we are going to be looking to that segment to provide for its own needs. And like I said, I do think that these capital expenditure reductions that we have made go a long way to helping that business cover its own cash needs over at least the next couple of years.

Got it. And then what about my other question is, in terms of coal to gas switching? Calpine last week obviously said that they were definitely seeing that in PJM. Are you guys seeing something similar in MISO at this point?

No, -- I think within MISO at least within certainly our part of MISO, gas prices being as low as they are, we are seeing maybe a little bit of gas-fired generation coming into the mix. Certainly as we look ahead ourselves to this coming year, we have talked about having about [26] million megawatt hours that we are going to generate.

I think our coal-fired plants are going to produce about 26.5 million and maybe 0.5 million coming from our gas assets? So, we're expecting a little bit more contribution this year from our gas assets.

Overall though, within MISO, our part of MISO, the low cost delivered PRB coal is still pretty competitive with the gas assets that exist in our part of the country. So, certainly with these low gas prices, there will be more gas generation. But I think to a lesser extent than you may be seeing in other parts of the country.

Okay. Thank you, guys. Appreciate the color.

Our next question comes from the line of David Paz with BofA Merrill Lynch. Please proceed with your question.

Good morning. Just had a question on the parent level note, the $425 million note. Are there any covenants in there that prevent you from divesting any of your segments, particularly your Merchant Segment?

David, it is Marty. I am certainly not aware of any covenants in that indenture.

Great. And then on the merchant power hedges, and forgive me if you went through this earlier, I might have missed this. But I just was trying to get a feel for the 3 to 4 kilowatt hours that you added in your hedges in 2012 and 2013, as well as your 2014 hedges. Particularly in 2014, was the 7 terawatt hours at the average price of $44 entered into last year? Or are these part of like a multi-year contracts that predate post-September 30, 2011?

Yes, David, I think it's -- we have been entering into those over all those periods of time. So, some of the contracts date back to probably pre-2012. I don't have the exact dates. But other hedges that are embedded in that mix have been entered into 2012 or excuse me, in 2010, 2011. So, we have been building that hedge block and that hedge piece up over time.

Okay. So, you can't give me a percentage?

No. I don't. I don't have a percentage breakdown.

Okay and on the capacity only hedges that you disclosed -- I'm sorry did you say why that is not in the current presentation?

No, I didn't. But you did notice a change. I mean, frankly, we took it out. Capacity revenues as you can see from the revenue breakdown at this point are unfortunately only about 1% of our overall revenue. So, breaking that out didn't seem all that necessary at this point in time.

Certainly as those capacity revenues improve over time, we certainly maybe break it out again. I think it is safe, David, to be thinking about $15 million to $30 million of capacity-only kind of revenues, over the next couple of years, given current prices. As you can see from the pie chart, the majority of the capacity that we sell is embedded in some of our full requirements contracts. So, the capacity only sales, like I said about 15 to 30, is probably a safe number to put in your model.

Great. Thank you. Thank you so much.

Our next question comes from the line of Scott Senchak with Decade Capital. Please proceed with your question.

Hello, it is actually [Resin Hitoughy]. I guess just given your pretty solid CapEx program over the next few years, could you talk about need for drip or dribble or equity? How should we think about that over the next few years?

Good question. As you may have picked up in our talking points, we are stopping this year issuing shares for those programs. So you should not expect to see any dilution from those programs this year. However, moving forward in time, we will assess that on a year-to-year basis as we look at our cash flow needs to, in particular, finance the regulated CapEx plans that we have.

I think that to the extent that we can support these capital expenditures through reinvestment of earnings that we make in our regulated Business, we will certainly seek to do that. But also, at all times, thinking about maintaining sort of the financial strength that we have today. Certainly like to have the equity content in our cap structure somewhere between, I'd say, 50% of 53% equity range.

So, our goals as we move through time are to keep that equity content solid in our balance sheet, keep our credit profile strong and stable, and fund these capital expenditures in a prudent way. Hopefully, you can see through time, we are trying to be very careful and thoughtful about our allocation to capital, and the returns we are earning on those capital investments.

And just a follow-up on an earlier question. I guess the cash flow question on the Merchant Segment -- a lot of things could change going forward, but is it in your toolbox to use any cash from the Corporate segment to fund any shortfalls at the Merchant segment? Is that part of the potential equation?

Well, yes. It is in the toolbox. It is something that we could choose to do. But as we have said repeatedly, our goal is for the Merchant segment and for Genco to work to provide for their own cash needs. So, that remains our focus.

Great, thank you.

Ladies and gentlemen, due to time constraints we ask that you limit yourself to one question and one follow-up question.

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

Hi, guys. Actually a couple questions on the regulated side of the house. First, in the transmission spending guidance that you give five-year look, how back end- or front end-loaded is that? And if you could touch on that on both at AIC and at ATX. And a follow-up to that, in Missouri you talked about trying to get a clause in this rate case that reduces lag on kind of plant being put in service. Do you need legislative relief to actually get that done? I thought that there was a used and useful clause in state regulation in Missouri?

Yes, Michael, this is Marty again. I will try to take both of those questions. With respect to the transmission spend, what you really ought to see with respect to the Ameren Illinois utility spend, with respect to transmission is, it would be more ratable over the five-year period. So, you see in the pie chart that we have got $900 million of spend over the 2012 through 2016 period. And as we said in the call, I think it is somewhere in the neighborhood of $180 million or so that we are spending this year.

So in 2012, you should see kind of a stable run rate over that period of time. With respect to the transmission company spend, however, that $750 million, that is more back-end loaded. We are going to be in working through the routing process, the deciding, we are going to be working on getting in ICC certificate in place. And then moving forward. So, that capital spending really starts to ramp up and 2014, and more so in 2015 and then 2016.

Got it. And the Missouri regulation legislative question?

Yes, now you're Missouri question. What we're proposing I would say in this current rate case is, Michael, somewhat similar to the accounting treatment that we got relative to the Scrubber investment, that we had between the time that asset went into service and the time we got that into rates. You may recall that in that particular case, we were allowed after it went into service to defer depreciation, as well as carrying costs on that asset from the time it went in service to the time rates became effective. And what we are seeking here is something similar, but allowing us to have that kind of construction accounting on a broader basis with respect to plant put in service.

Got it. Okay. Thanks, guys, and congrats on both a good quarter.

Thank you, Michael.

Our next question comes from the line of Greg Reese with Catapult. Please proceed with your question.

Hello, guys. My questions have actually been answered already. Thanks.

Okay, Greg, thank you.

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

Hello, good morning. Wondering about just that latest decline in prices. Has that kind of changed your hedging strategy at all for the Merchant Business?

Yes, Robert, this is Marty. No, I wouldn't say it really is affecting our hedging practices. What we have really tried to focus on over the past few years, several years, is working to market our power to higher margin customers, and when we hedge, also looking at how we get the best location if you will to minimize basis risk.

So, we are still looking at putting on hedges. As sales opportunities come along, we're still pursuing those. And we're certainly focusing on the more higher margin opportunities that we get. But we are continuing to put hedges on. I would say for the past year or so, we have been putting hedges on and operating to sort of the lower-end of our hedge policy parameters. But sitting here today certainly feel happy that we did that, that we have locked in some power prices in our hedge portfolio that are above current market prices.

Yes, okay. And then I think this is kind of related to Julien's question earlier, just slightly different. Is there kind of a time limit that this delayed construction must be completed? And if you don't have it done by an 2016 or 2017, does some rule kick in that, okay the plant can't run? Is there anything like that at all? Or can you just kind of delay indefinitely?

Well, you can. This is Marty again. You can delay indefinitely. But to Julian's question, and hopefully I was responsive. But where you would start to see some reduction in terms of generation capability is out in the 2015 timeframe, when the Illinois multi-pollutant standard has another ratchet down in terms of SO2 emissions rates for the fleet.

So, out in that period, absent other ways to comply, we might need to or would need to ratchet down the generation from our uncontrolled generating plants. Now, which plants would do that, how that might take place, that is all something that we have to assess and examine here over the coming months in terms of again, absent the Newton Scrubbers, how we would best go about complying.

Okay. And that delay, when you made the decision to delay, was that really driven by this latest decline in prices? -- since your last call? Or was it kind of sort of on the track to come up to this decision anyways, even with power prices being a little bit higher like last fall to levels?

Well, I would say that the power prices that we have seen here in the first quarter to us don't look supportive of continuing with the investment at the pace we were making it. So, the prices did have significant impact on the decision, but also, the continued low capacity prices and uncertainty about a capacity program within MISO.

The other things though that also affected the decision were the stay of the CSAPR rules and the final match rules that came out, as well as our decision last year to shut down Meredosia and Hutsonville. Those things, the shutdown of Meredosia and Hutsonville changed our emissions profile for our fleet, so that impacted our Outlook. The stay of CSAPR affected our Outlook. But again, getting back to your question, certainly the power prices were a very big factor in the decision.

Yes, okay. So, there has been enough other things going on that if power prices were to suddenly jump up to where they were in October or so, it isn't necessarily enough for you to say, we're going to put this back of schedule?

Right. That's a good point. I think that look, we are going to take the time that we have bought through this deceleration to really assess the power markets, capacity markets, change in environmental rules. And like I said, look very closely at how we might alternatively comply with the rules that exist, and make a reassessment at some point in the future.

Okay, great. Thank you very much.

Our next question comes from the line of John Murphy with Green Arrow. Please proceed with the question.

Hello, guys. Can you just give an update on what you're seeing in Illinois government aggregation market and what kind of an opportunity that could be for you?

Yes, you broke up a little bit for folks that couldn't hear. I think the question was about municipal aggregation in Illinois. And we do see that as an opportunity, frankly, for the Merchant Business. We certainly as part for that Business, we certainly have been very active as I said a little while ago offering our product to industrial customers, large commercial and municipal customers.

And we certainly see this as an opportunity to sell more generation to these aggregated municipal buyers through their RFP process. So, we do see this opportunity on the Merchant side of our Business. And again, we are very much focused on seeking opportunities to market and sell our power at prices that offer attractive margins relative to say an Indy Hub spot price.

This is Doug Fisher. Operator, we have time for just one more question.

Thank you. Our last question comes from the line of Alex Tai with Standard General. Please proceed with your question.

Hi, guys. How are you doing? I just wanted to clarify little bit on the timing of any decision that is going to be made on the CapEx spend. You had previously said that 2015 is sort of the timeframe that you'd sort of have to have something in place. And you also said that there was going to take about 20 to 24 months to complete the project if you were to reaccelerate the Newton Scrubbers. Just kind of rough math, at least, 12 months in which to decide whether or not to resume the project? Is that correct? Am I sort of thinking about this the right way?

Yes. That's right. I think that as we will continue to assess, I would say that the timeframe to, if we were to reaccelerate the project, what the exact timeframe would be. But like I said, sitting here today, we're thinking it is 20 to 24 months. So, I would say, certainly sometime next year we will be at a point in time where we'll be making some decision as it relates to compliance with those 2015 targets.

Got it. And in terms of some of the other options you had mentioned, activated carbon, or I don't specifically remember if you mentioned this, but dry sorbent injection? What is the lead time for converting to an alternative system for environmental compliance?

Yes, I think one thing about Illinois as it relates to mercury is, we already are using a lot of activated carbon for compliance there already, so that is sort of underway. In terms of DSI, I can't really, sitting here today, give you a timeline on what it would take to put that into place. I think that is probably a shorter timeframe than the one we are talking about, in terms of the Scrubber project.

Got it. And so, I guess just to get a little bit more clarification. If you decide to not resume with the Scrubber, can you just sort of lay out a road map of what the other options look like?

Not at this time. I think it is really too soon and premature to say. I think that we will assess all alternatives we have with respect to compliance. And look, we are talking about 2015. And certainly a lot can change in terms of forward power prices and capacity prices. So, we will be assessing all of those compliance options at the same time as we are really watching how the power markets and environmental standards unfold.

Okay. All right. Well, thank you very much.

Thank you.

Thank you for participating in our call. And thank you especially for your patience with our technical difficulties today. This is Doug Fischer. Let me remind you again that this call is available on our website for one year. Today's press release includes instructions on listening to the playback telephonically or accessing it on our website.

You may also call the contacts listed on the release. Financial analyst inquiries should be directed to me, Doug Fischer. Media should call Brian Bretsch. Our contact numbers are on the news release. Again, thank you for your interest in Ameren Corporation.

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