Good morning ladies and gentlemen, and welcome to the Ameren Corporation Q1 2011 Earnings Conference Call. (Operator Instructions). As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Doug Fischer, Director of IR for Ameren Corporation. Thank you, Mr. Fischer – 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 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 includes 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’s section of our website under webcasts and presentations and follow the appropriate link. Turning to page 2 of the presentation I need to inform you that comments made during this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated and described in the forward-looking statements. For additional information concerning these factors please read the forward-looking statements section in the news release we issued today and the forward-looking statements and risk factors sections in our filings with the SEC. Tom will begin this call with a brief overview of Q1 2011 earnings and 2011 guidance followed by a discussion of recent business developments. Marty will follow with more detailed discussions of our Q1 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 Q1 2011 core earnings of $0.25 per share compared to Q1 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 Generations segment, as well as higher operations and maintenance expenses and reduced capitalized financing costs in our regulated utilities segments. Kilowatt hours sales of electricity to native load utility customers decreased 3% in Q1 of 2011 compared to Q1 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 grew 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 utilities segments in Q1 of 2011 largely reflected increased storm-related expenses compared to Q1 of 2010. We continued to exercise disciplined cost control in Q1 2011 with operations and maintenance expenses, excluding storm-related costs, up just slightly over the year-ago quarter. Factors favorably contributing to Q1 2011 core earnings compared to Q1 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…

Thanks, Tom. Turning to page 7 of the presentation, today we reported Q1 2011 earnings in accordance with generally accepted accounting principles – or GAAP – of $0.29 per share compared to the Q1 2010 GAAP earnings of $0.43 per share. Excluding certain items in each year, Ameren recorded Q1 2011 core earnings of $0.25 per share, compared with Q1 2010 core earnings of $0.40 per share. Q1 2011 core earnings exclude one item that is included in GAAP earnings. This item is a four-set [ph] per share gain from the impact of unrealized marked 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 variants between fore earnings per share for the Q1 of 2011 and for Q1 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 Q1 2011 earnings by $0.05 per share, compared to Q1 of 2010, while lower regulated electric and natural gas margins, excluding the impact of rate changes, reduced earnings by $0.40 per share. Half of this $0.40 was due to milder winter temperatures compared to Q1 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 Tomsock [ph] Hydroelectric plant which returned to service in Q2 2010. Other factors contributing to lower Q1 2011 earnings included reduced equity-related capitalized financing costs, or EFCFC equity, of $0.03…

Thank you. We will now be conducting a question-and-answer session. (Operator Instructions.) Our first question is from Paul Ridzon with KeyBanc Capital Markets. Please proceed with your question. Paul Ridzon – KeyBanc Capital Markets: Good morning, how are you? Can you just give a little bit more detail on the $0.03 cost on the Sioux scrubbers with the equity linked financing and then secondly just clarify what’s in the ongoing earnings? You’re keeping the storms in there I assume, and what are you doing with the charge for the Naranda [ph] excess capacity margin?

Sure, let me, I think there were three questions in there which are all good questions I appreciate. Let me make sure I try to hit them all though. I think the first one was about the EFCFC 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 the EFCFC – 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 the interest financing costs and the equity related financing costs. And 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 appreciation recognition and the interest financing costs associated with that scrubber. However, we are not able to continue to recognize EFCFC equity, so that was a plus last year; this year when you compare year-over-year results we don’t have those same EFCFC 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 EFCFC 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 Q1 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 Naranda [ph] related issue, and as we mentioned in our prepared remarks we expect that based on the Public Service Commission’s order in our fuel adjustment clause proceeding that in Q2 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 we gave today. Paul Ridzon – KeyBanc Capital Markets: Thank you very much for clearing that up.

Our next question is from Erica Piserchia with Wunderlich Securities. Please proceed with your question. Erica Piserchia – Wunderlich Securities: Hi guys, how are you? Just a couple questions. First I realize you don’t normally break out some of the usage statistics ex the weather, but can you talk a little bit maybe 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. 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 was in part due to the weather. However, when we strip out weather we do still see in the Q1 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’ll 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 Naranda [ph]. 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 outsized growth, Missouri excluding Naranda [ph] is frankly still down a little bit year-over-year in the industrial sector. Erica Piserchia – Wunderlich Securities: Okay, so it sounds like what you’ve seen in the Q1 would then seem to be consistent with that full-year expectation, implicit because you’ve maintained your guidance?

Yes, that’s exactly right. I mean we had never come out and- In Q1 we had talked about moderate sales improvement but I don’t think we quantified it, but what we’re seeing in Q1 is 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. Erica Piserchia – Wunderlich Securities: 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 cost improvements in terms of your hedge 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?

Yeah sure, Erica, and I’d be happy to sort of expand on that. When you look at the slide we prepared, slide 12, we tried to break down for you the main components of our overall hedged fuel costs. And if you look back at the changes, if we’re looking 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 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 that was our expectation, that based on current prices and broker quotes that we believed that we would, as we put additional hedges in place we’d be able to bring the average cost down. And you know, 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. Erica Piserchia – Wunderlich Securities: Okay, thank you, that’s helpful.

Our next question comes from Paul Patterson with Glenrock Associates. Please proceed with your question. Paul Patterson – Glenrock Securities: Good morning, guys. I know you’re not updating the environmental CAPEX on the merchant fleet because of those proposed EPA rules, but is there any sort of directional, I mean is there any major change that you think may be happening there as a result of that or is it pretty much youthful for what we know right now?

This is Tom Voss. We’re just now really getting a chance to look at those rules and you know, they’re fairly extensive and fairly detailed and it’s really going to take some time to figure out how we’ll 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’ll actually play out on our particular plants yet. Paul Patterson – Glenrock Securities: Okay, and then 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?

Yeah, sure Paul, this is Marty again. You know, we’ve talked about it 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. 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 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’ve explored are things like we talked about today. We’re engaged at FERC and 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. Paul Patterson – Glenrock Securities: Okay, and then just finally on the $17 million refund, I know you guys are asking for a rehearing there, but assuming that you don’t get any change on the treatment of 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 this just like a one-timer as it sort of 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 and 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 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 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 Q1 compared to last year. It has to do with the expiration of some of those contracts and the inclusion of margins associated with you know, all of our sales being included in base rates. Paul Patterson – Glenrock Securities: Okay, thanks a lot.

Our next question is from Julien Dumoulin-Smith with UBS. Please proceed with your question. Julien Dumoulin-Smith – UBS: Hi, good morning. Hey, you know, as I was looking at your recent integrated resource plan in Missouri it seemed 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 Hat-Mac [ph] rules, and then also as well tying in discussions- I think you talked about five further units with ACI so perhaps your overall Ameren Missouri environmental CAPEX plan.

Hi Julien, this is Warner Baxter. I can 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 of putting some additional scrubbers on at Rush Island. So where we’re at today is just as Tom said, that we are taking a look at all these rules and carefully looking at our overall and environmental compliance plan. As Marty talked to a little bit earlier we’ve made significant progress in that environmental compliance plan by putting on 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’d be premature to say that we’ve finalized any of those determinations. IRP put that as sort of 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. Julien Dumoulin-Smith – UBS: Great. And then secondly, I know you kind of addressed it just now but with respect to the Missouri sale, the Missouri asset sale to the co-op, at this current point in time do you project needing to inject equity into GenCo in ‘12? Or is that more of a ‘13, ‘14 kind of 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 realized this, that we transitioned a little bit from a Missouri discussion over to a merchant discussion in GenCo. There is a GenCo asset that’s being sold and that’s $45 million of potential additional cash for GenCo to finance its operations. But Julien, we’re at a point where I’d say we’re giving out any guidance with respect to ‘12 or ‘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 we talked about here – $45 million sale of the CT – to plug any cash flow needs that that business segment may need. So those are our objectives and that’s what we’re working to achieve. Julien Dumoulin-Smith – UBS: Great, and then just a quick last question here with regards to the electric rate changes in Missouri, the year-on-year plus 3. Do you mind talking about or elaborating a bit with respect to the net of certain related expenses, just how to think about those related expenses? 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, Julien, 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 to what 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 a different timing pattern of fuel costs you’ll get to a little bit different margin month by month. So I’m not sure you can get to a real run rate on the net other items. Julien Dumoulin-Smith – UBS: Great, well than you very much.

Our next question comes from Andy Levi with Caris & Company. Please proceed with your question. Andy Levi – Caris & Company: Hi, guys, I’m all set. Thank you very much.

Our next question comes from Gregg Orrill with Barclays Capital. Please proceed with your question. Gregg Orrill – Barclays Capital: Thanks. I was wondering if you could touch on HB 14 in Illinois and sort of 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. Gregg Orrill – Barclays Capital: Okay. And also on the Coal 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 Gregg, this is Warner and with regard to the Coal County case, I think you have to keep in mind we have appeals which are pending for both our 2007 and 2009 rate orders, both 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 sort of the rate rollback and those type of issues, if that’s what you’re referring to, as Marty and Tom said those issues have been denied in three venues. Whether there’s anything more that will happen associated with rate rollback remains to be seen but we vigorously defended those positions already and have been successful. But there are still appeals pending and we continue to fight those issues with the courts. Gregg Orrill – Barclays Capital: Okay, thanks. Operator Our next question comes from Toran Miller with Knight Capital Group. Please proceed with your question. Toran Miller – Knight Capital Group: Good morning. I was wondering if you’re willing to comment on what role, what changes might occur as Entergy enters the Miso [ph] and how that might influence the development of a capacity market for Miso [ph].

This is Tom Voss. I’ll take one stab at that and then 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 coming in it should help out with some of the administrative costs we’ve got at 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. Andy Serry [ph]: Agree, Tom. This is Andy Serry [ph]. We are as everyone else is looking at the impact of Entergy joining Miso. Let’s not 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 at Entergy 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. Toran Miller – Knight Capital Group: And can you just give us a broader update on what you think is going on with reference to the potential development in the capacity market? Andy Serry [ph]: 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, sort of a target number for capacity and locational pricing mechanisms to handle not only the export but import constraints of the different zones and across seams as well. But the final implementation with that filing here in June will be for planning year 2013-14. Toran Miller – Knight Capital Group: Thank you very much.

Our next question is from Michael Lapides with Goldman Sachs. Please proceed with your question. Michael Lapides – Goldman Sachs: Hey guys, just got a question for you – at what stage at both the non-regulated side but even the regulated side, when you look at both the various rules kind of making your way through the EPA right now, when do you have to make decisions by to potentially scrub units or start setting retirement dates for units?

This is Tom Voss. 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’d 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 said, 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 Fischer. We have time for just one more question.

Our last question comes from the line of Neil Calton [ph] with Wells Fargo. Please proceed with your question. Neil Calton – Wells Fargo: Hi good morning, everyone. Just a quick question on capacity sort of 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 timeframe out there right now? Andy Serry [ph]: Sure, several questions 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 and 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 work actively with Miso to form that. We were hoping to push the construct needs from a one-year to a multiple-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? Neil Calton – Wells Fargo: Correct.

Yeah, I’ve got that, Andy, if I could be a help. What we’re seeing out there right now for dollars per megawatt years, in 2012 around $360 and in 2013 around $5300. Neil Calton – Wells Fargo: 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 12th on playback and for one year on our website. Today’s press release includes instructions on listening to the playback. You may also call or email 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.