Greetings, and welcome to the 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 now 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 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 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 statement 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 three 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 very hot 2010. In addition, merchant generation margins decline 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 maintenances expenses were lower, reflecting continued disciplined cost management, and interest cost fell as we used our free cash flow over the last two years to reduce outstanding debt. Beginning on page four 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 around fair returns by maintaining solid operating performance while improving our regulatory frameworks and seeking rate release as needed. Further we are committed to allocating capital to those projects on which we expect to earn fair returns and aligning our spending with regulatory outcomes and economic conditions. At our merchant generation…

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 $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 into the third quarter of $0.32 per share. These charges were the results of Missouri Public Service Commission’s disallowance of cost 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 – very hot 2010. Another $0.05 of the decline was due to a second quarter 2011 charge, related to Missouri public service commission requirement that certain revenues be flow-through the fuel adjustment clause. A decline in margins at the merchant generation business reduced 2011 earnings by $0.21 per share. The…

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Ladies and gentlemen, thank you. We will now be conducting a question and answer session. Thank you our first question is from Paul Patterson with Glenrock Associates. Please proceed with your question. Paul Patterson – Glenrock Associates: Good morning, can you hear me?

Yeah, Paul. This is Marty Lyons. Yes, we can hear you now. Paul Patterson – Glenrock Associates: Listen I want to ask you...

I apologize. Paul Patterson – Glenrock Associates: That’s fine. I just want to ask about these the delay in these merchant generation CapEx projects one in Newton and the precipitator. Is there a operating earnings impact that’s associated with any of these MEEIAs which do you have to buy emissions or anything, I mean is there any operational issue we should be thinking about in terms of this significant change in CapEx.

Right Paul. I understand. It’s Marty still. No, not in the near-term, these projects really design 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 projects. Paul Patterson – Glenrock Associates: 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’s – it’s teasing to tell I guess whether the ultimate cost of the project will change but just to give you a sense, so 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 built or material that have been commissioned a lot of those to be completed take those to the site, put them in a safe store condition. So we expect to incur about another $150 million this year in doing that. At that point we’ll be taking the capital expenditures down to more of the minimum levels that we described in the call and continued to monitor changes in power market conditions, capacity markets, changes environmental rules and the like. And certainly asses how we might absence 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 that was sort have embedded in the guidance was somewhere around $490 million for the Newton Scrubber project. If we move to reaccelerating it some point in the future, we’ll certainly provide an update on what we think the costs are 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 months to 24 months to complete the project. Paul Patterson – Glenrock Associates: Okay, great. Thanks a lot.

You are welcome.

Our next question comes from the line of Julien Dumoulin-Smith with UBS. Please proceed with your question. Julien Dumoulin-Smith – UBS: Hi, good morning. Can you hear me?

Yes, we can. Julien, this is Marty. Thanks for joining. Julien Dumoulin-Smith – UBS: Yes, of course. I just wanted to clarify a little bit more on the Merchant CapEx front, just what you’re thinking about compliance with MATS and your own Illinois State specific standards, 2015 and beyond, I mean, status quo I would imagine that it would result in some sort of operational impairment of the assets rate without putting in the CapEx, I mean there is some sort of reaction in your ability to dispatch some certain units? Is that the right way to think about that?

Yeah Julien. This is Martin again. That’s a fair assessment. I think without the Newton Scrubbers being reaccelerate out in 2015 timeframe, it’s frankly, it’s really the Illinois multi-polluting standard that becomes the challenging standard for us to comply with. As you know out in that timeframe in 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-polluting standard or other rules. When you get onto 2015, as it relates to MATS compliance, absent the Newton Scrubber we think we have other ways to comply activated carbon and precipitators, low sulfur coal and the like compliance there. And as it turns out with the CSAPR rules obviously they’re uncertain right now because they’ve been stayed. But based on the allowances that came out in the final rules, based on our decision to shutdown Meredosia and Hutsonville, the CSAPR rules really aren’t seen as a significant limitation either. Julien Dumoulin-Smith – UBS: Great. So if I were to kind of hit between lines here, frankly from a compliance perspective, a couple of years, you could decide, let’s say, a couple of years down the road and still they’ll move forward. You said 20 to 24 months there to complete the Newton Scrubber, so there is still a couple of years latitude all in give or take, is that kind of the right way to think about that in order to...

Yeah. That’s fare. We feel like, as we decelerate today that we’ve got some optionality for a while before what actually impact future general 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. Julien Dumoulin-Smith – UBS: Excellent and then just a final question here on the Genco, a guidance the breakeven cash flow for this year. Are there any exceptional items there to bear in mind as we’re looking at your EPS guidance translating then to free cash flow guidance anything notable to take note of?

I don’t know that there is anything notable to take note of in the – in that regard as you reconcile. Julien Dumoulin-Smith – UBS: Okay. So EPS guidance should equate to positive free cash flow?

Yeah. I think so. I mean nothing has come into mind off hand. We’re certainly, as we mentioned in the call, we’re expecting positive free cash flow overall at the Merchant business. And I guess one think of note early in this first quarter we did sell one of our assets with Medina Valley co-gen facility, a fairly small facility. I think about $17 million and 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. Julien Dumoulin-Smith – UBS: Great and then just tiny clarification here in terms of your guidance that for coal. It seems like that came down a buck a megawatt hour in 2013, just wanted to clarify is that basically a lower PRB price or lower transport price.

Well, it’s really a little off each Julien, so the price dropped I guess from about $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. Julien Dumoulin-Smith – UBS: Okay. Thanks.

Our next question comes from the line of Tom Rebinoff with Fore Research and Management. Please proceed with your question. Tom Rebinoff – Fore Research and Management: Hey, guys. Good morning. Can you hear me.

Yeah, we are little bit flank, but we think we can hear you okay. This is Marty. Tom Rebinoff – Fore Research and Management: Great. Hey, Marty. So I had a question on your cash flow going forward basically it sounds like that you have indicated that basically in 2012, you Merchant business would cash flow positive, and I think you have mentioned that you’re 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 that’s going to become from the Manipur receivables. But really more interested in 2013, when obviously you’ve kind of given where the current strip is and where prices are today, that Merchant business will burning, I’ll call it a $100 million plus of cash. So are you going to explicitly support that business going forward and you’ll kind of bridge that shortfall or like what’s the thinking in terms of actually helping with the casual 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 Genco subsidiary as well as the eight AERG subsidy area assets and 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 Manipur receivables. As of yearend, it had about $74 million of Manipur receivables. And we project some more 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’ve repeated that and our goal is for the Merchant segment as well as for Genco to be able to support their cash flow needs. And we feel like the decisions we have 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. Tom Rebinoff – Fore Research and Management: Got it. So maybe then the question really is – I mean at the end of the day I am kind of running my own math and I am 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, like you know just help us kind of think through the various options.

Well, I think in 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’re continuously seeking opportunities to market the power that we have at above market prices. So, first and foremost, we’re going to be look into that segment to provide for its own needs And like I said I do think that these capital expenditure reductions that we’ve made go a long way to helping that business cover its own cash needs over at least the next couple of years. Tom Rebinoff – Fore Research and Management: Got it. Got it. And then what about my another question as 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’re seeing maybe a little bit of gas fire generation coming into the mix. Certainly as we look ahead ourselves to this coming year, we’ve talked about having about 25 million megawatt hours that we’re going to generate. I think our coal-fired plants are going to produce about 26.5 million megawatt hours and maybe 0.5 million megawatt hours coming from our gas assets, so we’re expecting a little bit more contribution this year from our gas assets. Overall though within MISO, in 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 will – 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. Tom Rebinoff – Fore Research and Management: Okay. Thank you, guys. I appreciate the color.

Our next question comes from the line of David Paz with Bank of America Merrill Lynch. Please proceed with your question. David Paz – BofA/Merrill Lynch: Hi. Good morning. I 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 in your Merchant segment.

David, it’s Marty. I am certainly not aware of any covenants in that indenture. David Paz – BofA/Merrill Lynch: Great. And then on the Merchant power hedges and forgive me if you went through this earlier, I might have missed this, but just was trying to get a feel for the three to four terawatt hours that you added in your hedges in 2012 and 2013 as well as your 2014 hedges, particularly 2014, was the 7 terawatt hours at the average price of $44 entered into last year or are these part of like a multiyear contracts that predate post September 30, 2011.

Yeah. David, I think look we’ve 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 date, but other hedges that are embedded in that mix have been entered in 2010, 2011. We have been building that hedge block and that hedge piece up over time. David Paz – BofA/Merrill Lynch: Okay. So, can you give me a percentage [indiscernible].

No. I don’t have it, I don’t have a percentage breakdown. David Paz – BofA/Merrill Lynch: Okay. And on the capacity-only hedges that just closed, I’m sorry, did you say why that is not in the current presentation.

No, I didn’t, but, yeah, you did notice change. Frankly, we took it out. I mean 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 mean I think it’s 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 it from the pie chart, the majority of the capacity that we fell is embedded in some of our four requirements contact. So the capacity only sales like, I said about, $15 million to $30 million, is probably a safe number to put in your model. David Paz – BofA/Merrill Lynch: Great. Thank you. Thank you so much.

Our next question comes from the line of Scott Senshak with Decade Capital. Please proceed with your question. Reza Hitucki – Decade Capital: Thank you. It’s actually Reza Hatefi. Just I guess given your pretty solid CapEx program over the next few years, could you talk about need for trip or dribble or equity, how should we think about that over the next few years?

Good question. As you may you have picked up in our talking points, we – our stop in this year issuing shares for those programs, so you shouldn’t expect to see any dilution from those program 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’ll certainly seek to do that, but also at all times thinking about maintaining sort of the financial strength that we have today. Certainly, we’d like to have the equity content and our cap structure somewhere between, I’d say 50% to 53% equity range. And so our goals as we move through time are to keep that equity content solid in their 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’re earnings on those capital investments. Reza Hitucki – Decade Capital: And just a follow-up on an earlier question, I guess the cash flow question on the Merchant segment, a lot of things can change going forward but is it in your tool box to use any cash from the corporate segment to fund any shortfalls at the Merchant segment, is that part of the potential equation?

Yeah, I mean it’s in the toolbox. It’s something that we could use to do. But as we’ve said repeatedly our goal is for the Merchant segment and for Genco to work to provide for their own cash need. So that remains our focus. Reza Hitucki – Decade Capital: 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. Michael Lapides – Goldman Sachs: Hey, guys. Actually a couple of questions of the regulated side of the house. First, in the transmission spending guidance that you give five year look, how backend or frontend loaded is that, and if you could touch on both AIC and at ATX. And 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 there was an used and useful clause in state regulation in Missouri.

Michael, this is Marty again. I’ll 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 it’s being more ratable over the five year period. So you see in the pie chart that we’ve got $900 million of spend over the 2012 through 2016 period. And as we’ve said in the call I think it’s somewhere in the neighborhood of $180 million or so that we’re spending this year so in 2012. So 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 backend loaded. We’re going to be working through the routing process, the siding, we’re working on getting an ICC certificate in place and then moving forward and so that capital spending really starts to ramp up in 2014 and more so in 2015 and then 2016. Michael Lapides – Goldman Sachs: Got it. The Missouri regulation legislated question.

Yeah. Your Missouri question. What we’re proposing and I would say in this current rate case is, Michael somewhat similar to the accounting treatment that we got relative to scrubber investment that we had between the time that asset went to into service and the time we got into rates. You may recall that in that particular case we were allowed after it went into service to differ depreciation as well as caring cost 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. Michael Lapides – Goldman Sachs: Got it. Okay, thanks guys and congrats on both a good quarter.

Thank you Michael.

Our next question comes from the line of Greg Reiss with Catapult. Please proceed with your question. Greg Reiss – Catapult: Hi 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. Robert Howard – Prospector Partners: Hi, good morning. Wondering about just the latest decline in prices, is that kind of changed your hedging strategy at all for the Merchant business?

Yeah, Robert this is Marty. No, I wouldn’t say it really is affecting our hedging practices. What we’ve 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 risks. So we are still looking at putting on hedges as sales opportunities come along. We’re still pursuing those and certainly focusing on the more higher margin opportunities that we get, but we are continuing to put hedges on. I’d say for the past year or so we’ve been putting the hedges on and operating to sort of the lower end of our hedge policy parameters, but sitting here today certainly feel happy that that we did that that we’ve locked in some power prices in our hedge portfolio that are above current market prices. Robert Howard – Prospector Partners: Yeah. Okay. And then I think it was kind of related to Julien’s question earlier, slightly different though. Is there kind of a time limit that just delayed construction must be completed, I mean, if you don’t have it done by 16 or 17, some rule kick in that okay the plant can’t run or is there anything like that at all or can you just kind of delay indefinitely?

You can’t. This is Martin again. You can delay in definitely, but the Julien’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 emission rates for the fleet. So out in that period, we absent other ways to comply might need to or would need to ratchet down to generation from our uncontrolled generating plants. Which plants would do that, how that might take place, that’s all something that we have to asses and examined here over the coming months in terms of again absent the Newton scrubbers, how we would best go about complying. Robert Howard – Prospector Partners: Okay. And that delay that – 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 where you sort of on the track to come up to this decision anyways even with power prices being a little bit higher from like last fall’s levels.

Well, I would say that the power prices that we’ve seen here in the first quarter to us don’t look supportive of continuing with the investment at the space we were making at. So the prices did have a significant impact on the decision. But also the continued low capacity prices certainly about a capacity program within MISO. The other things though that also effected the decision where the stay of the CSAPR rules and the final match rule that came out as well as our decision last year to shut down Meredosia and Hutsonville. Those things – shut down of Meredosia and Hutsonville changed our emissions profile for a fleet, so that impacted our outlook. The stay of CSAPR affected our outlook, but again getting to your question, certainly the power prices were a very factor in the decision. Robert Howard – Prospector Partners: There hasn’t been, there’s been enough other things going on that is power prices were to certainly jump to where they were in October. So is it necessarily enough for you to say hey we’re going to put this back on schedule?

Right. So that’s a good point. I think that look we’re going to take the time that we’ve bought through this deceleration to really access the power markets, capacity markets, change in environmental rules and like I said, but very closely at how we might alternatively comply with the rules that exist and make a reassessment at some point in the future. Robert Howard – Prospector Partners: Okay, great. Thank you very much.

You are welcome.

Our next question comes from the line of John Murphy with Green Arrow. Please proceed with the question. John Murphy – Green Arrow: Hi guys, can you just give an update on what you’re seeing in the Illinois’ government aggregation market and what kind of opportunity that could be for you?

Yes, so that’s – good you broke up a little bit for folks that maybe 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 is an opportunity to some more generation to these aggregated municipal buyers through there are fee processes. So when you see there is an 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 about relative to say in the hub spot price. John Murphy – Green Arrow: Great. Excellent.

This is Doug Fischer, 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. Alex Tai – Standard General: Hi, guys. How are you doing?

Good. Thank you. Alex Tai – Standard General: I just want to clarify a little bit on the timing of any decisions that’s going to be made on the CapEx spend. You had previously said that 2015 is sort of the timeframe that you sort of have to – you have that something in place and you also said that it would take about 20 month to 24 months to complete that project, if you were to reaccelerate the new scrubbers. Just rough math, at least maybe 12 months with which to decide whether or not to resume the project, is that correct, am I sort of thinking about this the right way?

Yeah. That’s right. I think, so as we will continue to asses I’d say that the timeframe to if we were to reaccelerate, reaccelerate the project, what the exact timeframe would be. But like I said sitting here today we’re thinking it’s 20 month to 24 months, so I’d say certainly sometime next year we’ll be at a point in time where we’ll be making some decision as it relates to compliance with those 2015 targets. Alex Tai – Standard General: Got it. And in terms of the some of the other options you had mentioned activated carbon or – I don’t specifically remember if you’ve mentioned this, but dry sorbent injections, what’s the lead time for converting to an alternative system for environmental combines.

I think one thing about Illinois as it relates to Mercury is we’re already are using a lot of activated carbon for compliance there already, so you know that 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 in place. I think that is probably a shorter timeframe than the one we’re talking about in terms of the scrubber project. Alex Tai – Standard General: Got it and so I guess to get a little bit more clarification, if you decide to not resume the scrubber, what, I mean, can you sort of just layout I guess a roadmap of what the other options look like?

Not at this time. I think it’s really too soon and premature to say. I think that we’ll asses all alternatives we have with respect to compliance and look we’re talking about 2015 and certainly a lot can change in terms of forward power prices and capacity prices. And so we’ll be assessing all of those compliance options at the same time as we’re really watching how the power markets and environmental standards unfold. Alex Tai – Standard General: 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.