Doug Fischer – Director of IR Thomas Voss – Chairman, President, CEO Martin Lyons – SVP, CFO

Steven Berg – Morgan Stanley Paul Patterson – Glenrock Associates Julian Dumoulin-Smith – UBS John Hansen – Prestigious Advisors Michael Lapides – Goldman Sachs Andy Bishop – Morningstar Kevin Fallon – SIR Capital David Paz – Bank of America (Brian Tadio – Future and Company)

Thank you and good morning. I am Doug Fischer, Director of Investor Relations for Ameren Corporation.

On the call with me today are Tom Voss, our Chairman, President and Chief Executive Officer, Marty Lyons, our Senior Vice President and Chief Financial Officer and other members of the Ameren management team. Before we begin, let me cover a few administrative details.

This call is being broadcast live on the internet, and the webcast will be available for one year on our website at Ameren.com. Further, this call contains time-sensitive data that is accurate only as of the date of today’s live broadcast.

Redistribution of this broadcast is prohibited. To assist with our call this morning, we have posted a presentation on our website that will be referenced during this call.

To access this presentation, please look in the investor section of our website under webcasts and presentations, and follow the appropriate link. Turning to page 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 statement.

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 factor sections in our filings with the SEC. Tom will begin this call with an overview of second quarter 2012 earnings and 2012 guidance, followed by a discussion of recent regulatory and business developments.

Marty will follow with more detailed discussions of second quarter 2012 financial results, 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.

I’m pleased to report that today we released second quarter 2012 core earnings of $.73 per share, compared to $.59 per share of core earnings in the second quarter of 2011. This improvement reflected increased earnings from our regulated utility operations, partially offset by decreased earnings from our merchant generation operations.

Key drivers of the higher regulated utility earnings were a favorable federal energy regulatory commission order related to a disputed Ameren Missouri power purchase agreement that expired in 2009, the absence in 2012 of a 2011 Ameren Missouri charge to earnings related to the fuel adjustment clause and 2011 Missouri electric and 2012 Illinois gas rate adjustments. Other factors having a favorable effect on second quarter 2012 regulated utility earnings compared to second quarter 2011 regulated utility earnings included reduced storm-related costs and increased electric sales to native load customers resulting from warmer temperatures.

Merchant generation earnings were negatively impacted by lower prices for electricity. Marty will provide more details on our second quarter earnings in a few minutes.

Turning to page four, based on second quarter results, today we are raising our 2012 core earnings guidance range to $2.25 to $2.55 per share, from a prior range of $2.20 to $2.50 per share. Our core earnings guidance range for our merchant generation business segment remains $.05 to $.15 per share.

The favorable earnings impact of warmer-than-normal second quarter temperatures, and the previously mentioned FERC order on the disputed power purchase agreement, have led us to raise core guidance for our regulated utility businesses by $.05 per share, at both the low and high ends of the range, to a new range of $2.20 to $2.40 per share. This guidance assumes normal temperatures for the second half of the year, and so far third quarter temperatures have been much warmer than normal, and I am very pleased to note that during the current extended period of very warm weather, which began with record temperatures in May, our utility systems have performed well, demonstrating the value of the significant reliability investments we have made in recent years.

Extreme weather puts strains not only on our system, but also on our customers we serve and our employees. We continue to provide a range of assistance to help low-income customers cope with the impacts of warm weather.

These include promoting and contributing to programs that assist low-income customers with their bills, and annual donations of residential air conditioning units to local charities for distribution. I also want to commend our employees, especially our generating center, substation mechanics and line workers, for their dedication and focus on safety.

They work hard in the heat, so that our customers can stay cool. Moving to page five, we have significant electric rate cases pending in both Missouri and Illinois, with decisions from utility regulators in these states expected later this year.

While Marty will update you on other details of these proceedings, I want to touch on some policy issues. We continue to believe that modern, constructive regulatory frameworks, which provide timely cash flows and a reasonable opportunity to earn fair return on investments, are clearly in the best long-term interest of our customers and the states in which we operate.

These frameworks support our ability to attract capital on terms which facilitate the timely investment needed to modernize our regulated utilities companies’ aging infrastructure and meet customers’ expectations for safe, reliable and clean energy. Constructive regulatory framework and the investment they facilitate, also help create good-paying jobs.

In our pending electric rate case in Missouri, we are seeking recovery of costs and investments we have already made to serve customers. Further, we are seeking to enhance the existing regulatory framework in the state.

As a result, we have made several new proposals in this case. First, we are requesting approval of a storm cost-tracking mechanism that will 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 requesting 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 a related regulatory matter, early this year, Ameren Missouri filed the request with the Missouri Public Service Commission for approval of new and expanded energy efficiency programs for the three-year period beginning in January, 2013. This was the utility’s first request under the Missouri Energy Efficiency Investment Act, or MEEIA.

Last month all of the parties to the energy efficiency proceeding filed a stipulation in agreement with the Missouri Public Service Commission, resolving all related issues, and yesterday the PSC unanimously approved this agreement. This agreement aligns the utility’s financial incentives with those of customers, consistent with the MEEIA legislation, that provides timely recovery of the expected costs of the energy efficiency programs we will implement beginning in January of 2013, and the revenue requirement for these program costs will be included in our pending electric rate case, with true-ups to actual costs in future rate cases.

And also for the first time, we will receive timely recovery through rates that is designed to offset revenue losses of fixed costs occurring as a result of implementing our energy efficiency programs. Further, the calculation for such recovery will be based on predetermined values for specific energy efficiency actions, rather than difficult and often contentious after-the-fact measurement.

Here also, the associated revenue requirement will be included in the pending rate case, with true-ups in future rate cases. Finally, the energy efficiency agreement will provide an opportunity for us to earn a performance incentive to reflect the rate base growth foregone as a result of our energy efficiency programs.

Any earned performance incentive will be calculated and collected after 2015, with any earnings benefit expected to be recognized in 2016. Moving now to Illinois, constructive formula ratemaking is in place for our state-regulated electric delivery service, and as Marty will discuss, our initial and first annual uptake formula rate cases are pending before the ICC.

Given the constructive formula ratemaking framework, we are moving forward with plans to invest meaningful incremental capital in this business. Over the next 10 years, our Illinois electric delivery business is required to invest $625 million over and above levels we have been spending in recent years, and create 450 jobs during the peak program year.

The improved infrastructure resulting from these investments will enhance reliability and provide customers with the energy usage options made possible by smart meters. Turning now to page six, I would like to update you on progress on growing our investments in FERC-regulated transmission projects at the Ameren Illinois and Ameren Transmission companies.

Such projects benefit from constructive FERC formula ratemaking. Ameren Illinois is moving forward with its plans to invest approximately $900 million across some 300 projects over the five years ending in 2016, which are focused on reliability and local load growth needs.

As shown in the pie chart, three-quarters of the planned $900 million investment is in projects that do not require regulatory approval because they are improving or rebuilding existing lines. The remaining investments, which are for five Greenfield projects, do require regulatory approval, and as noted on the slide, two of these projects have already been granted such certificates.

On page seven, we provide an update on Ameren Transmission Company, our ATX projects. ATX is moving forward with its plans to invest approximately $750 million in Greenfield regional projects within Illinois and Missouri over the five years ending in 2016.

The bulk of ATX’s investment over this period will be in the $800 million+ Illinois Rivers project, a MISO-approved regional multi-value project to build a transmission line across the state of Illinois. We are currently holding public meetings on route design for this project.

Later this year, we plan to file for a certificate of public convenience and necessity, and an ICC decision will be issued by July of 2013. Once we receive the certificate, we will begin to acquire right of way.

Preliminary construction may start as early as 2013, with a full range of construction activities in 2014. Meanwhile, we recently filed with the FERC requesting the same constructive rate treatment that we’ve already received for the Illinois Rivers Project for ATX’s two other MISO-approved regional multi-value projects.

Turning now to page eight, I would like to comment on our merchant generation business. We continue to act to adjust this business to weak power prices and an uncertain timeline for their recovery.

As we discussed in our first quarter call, our merchant generation business filed a request for a variance within the Illinois Multi-Pollutant Standard, or MPS, with the Illinois Pollution Control Board in May. In our petition, we outlined our need for additional time to comply with SO2 emission levels, currently set to become effective January 1st, 2015.

In exchange for delaying compliance with these levels through 2020, we have proposed a compliance plan that restricts our SO2 emissions through 2014 to levels lower than those required by the existing MPS, thereby offsetting the environmental impact of granting the variance relief. Further, our variance compliance plan will also comply with federal emission rules that are currently stayed, but are under review by the federal courts.

There has been significant public interest in our variance request with various citizens’ groups and the Illinois Attorney General’s office, opposing, and labor and local community interests supporting the variance request. Only the Illinois Environmental Protection Agency and our merchant business are parties to proceedings.

The Illinois EPA has filed a neutral recommendation, but has noted that our compliance plan results in a net environmental benefit. If we are not granted the variance or power prices do not materially increase, there is a significant risk that we’ll have to mothball two of our three unscrubbed merchant generation coal-fired energy centers beginning in 2015.

The Pollution Control Board held a hearing on our variance request just yesterday, and must decide the matter by September 20th of this year. I want to conclude my prepared remarks by noting that the focus of our dedicated employees on maintaining solid operating performance and improving customer service, our active management of our merchant generation business and our disciplined cost management and capital allocation, all reinforce my optimism as to the future prospects of Ameren.

Now I’ll turn the call over to Marty.

Thanks, Tom. Turning to page nine in the presentation.

Today we reported second quarter 2012 GAAP earnings of $.87 per share, compared to second quarter 2011 GAAP earnings of $.57 per share. Excluding certain items in each year, Ameren recorded second quarter 2012 core earnings of $.73 per share, compared to second quarter 2011 core earnings of $.59 per share.

Our second quarter 2012 core earnings excluded two items that are included in GAAP earnings. The largest of these non-core items was the increase in income tax benefit as a result of the first quarter 2012 non-cash asset impairment charge at our merchant generation business, and the GAAP requirement to recognize quarterly income tax expense using the annual estimated effective income tax rate.

This item increased net income by $.18 per share in the second quarter of 2012, partially reversing the $.36 per share first quarter 2012 charge. We expect the remaining $.18 per share of this year-to-date expense to be fully reversed by the end of the year.

The second non-core item is a $.04 per share loss from the net effect of unrealized mark-to-market activity. On page 10, we highlight key factors that drove the $.14 per share improvement in second quarter 2012 core earnings compared to second quarter 2011 core earnings.

These key factors included electric and gas rate adjustments, net of certain related expenses, which increased earnings by $.09 per share. Electric rates changed in Missouri in late July of last year, and gas delivery rates changed in Illinois in January of this year.

A second factor favorably impacting the comparison was the previously discussed favorable FERC order regarding a disputed power purchase agreement. This added $.07 per share to second quarter 2012 earnings.

The earnings comparison also benefited from the absence of the previously discussed second quarter 2011 FAC-related charge of $.05 per share. In addition, lower storm-related costs benefited second quarter 2012 earnings by $.04 per share.

You’ll recall that we experienced severe storms in the second quarter of last year, resulting in high storm restoration expenses. Further, warmer-than-normal temperatures boosted earnings by an estimated $.03 per share, compared to the second quarter of 2011, a period that was also warmer than normal.

We estimate that the warm second quarter 2012 temperatures increased earnings by $.07 per share compared to normal, offsetting a significant part of the estimated $.10 per share negative impact compared to normal experienced in the first quarter of this year due to mild winter temperatures. Second quarter 2012 cooling degree days were 30% greater than normal and 15% greater than those experienced in the second quarter of 2011.

Reflecting this, second quarter 2012 KWh sales of electricity to weather-sensitive residential and commercial utility customers rose 2% compared to the second quarter of 2011. Excluding the impacts of weather, we estimate the second quarter and first half 2012 KWh sales for residential and commercial customers were flat with those of the second quarter and first half of 2011.

A decline in margins at the merchant generation business reduced earnings by $.10 per share, primarily a result of lower power prices. Turning now to page 11.

We have raised our 2012 cash flow projection. We now expect 2012 negative free cash flow of approximately $190 million, an improvement of 40 million from our prior projection.

The improved cash flow outlook reflects higher expected cash flows from operations as a result of the previously-discussed favorable FERC order and our increased earnings expectations. As shown on this page, we calculate free cash flow by starting with our projected cash flows from operating activities, and subtracting from it expected capital expenditures, other cash flows from investing activities, dividends and net advances for construction.

While we anticipate that free cash flow will be negative for Ameren as a whole, we expect our merchant generation business will cover its own cash needs. Moving to page 12 of our presentation, I would like to update you on selected recent regulatory developments impacting our various business segments.

Beginning with Ameren Missouri, as I mentioned earlier, the FERC has issued a favorable order in a longstanding case involving the disputed power purchase agreement that expired in 2009. The FERC’s May 2012 order confirmed its 2010 ruling that Entergy Arkansas should not have included additional charges to Ameren Missouri under the power purchase agreement, and required Entergy to refund the improper charges with interest.

Ameren Missouri received cash reimbursement from Entergy in June. The portion of the reimbursement related to power purchased before implementation of the Missouri Fuel Adjustment clause in February of 2009, an amount that was never included in customers’ rates, was reflected in second quarter 2012 earnings.

Meanwhile, Entergy has appealed the FERC order in the U.S. Court of Appeals.

In a second recent regulatory development involving our Missouri Utility, the state circuit court has reversed the Missouri Public Service Commission’s 2011 order requiring that $18 million related to sales ending in September of 2009 under certain wholesale contracts be flowed to customers through the FAC. As a result of that 2011 PSC order, we took a charge to earnings in the second quarter of 2011, and have completed flowing these funds to customers through the FAC.

In response to the favorable circuit court ruling, the PSC recently appealed the matter to the Missouri Court of Appeals, and a decision is not expected until 2013. As a result, we have not reversed the charge we took in 2011.

The PSC has reviewed the final $26 million relating to these same wholesale contracts for the period ending in May, 2011, and is expected to issue a decision later this year as to whether this additional amount should be flowed to customers through the FAC. A negative PSC decision on this matter would result in a charge to earnings.

At the top of page 13, we list a recent positive development impacting our Ameren Illinois electric delivery business. Last month, the ICC decided to consider Ameren Illinois’ modified Smart Grid Advanced Metering Infrastructure, or AMI, deployment plan.

Installing Smart Grid equipment and advanced two-way electric meters is critical to meeting the infrastructure enhancements required under the Illinois Energy Infrastructure Modernization Act that authorized formula rates, and such expenditures comprise about half of the increase in capital spending required by the act. In March, 2012, Ameren Illinois submitted its original Smart Grid Advanced Metering Infrastructure deployment plan to the ICC, and the ICC subsequently denied that plan in May of 2012.

The ICC ruled that Ameren Illinois’ original plan did not provide enough support to prove that it was cost-beneficial for electric customers. Ameren Illinois asked for a rehearing and filed the modified deployment plan designed to address the ICC’s concerns about cost justification.

Our rehearing filling demonstrated a positive net present value for a plan which provides for the installation of advanced electric meters for 62% of electric customers within 10 years. The ICC is scheduled to rule on our modified plan in November of 2012, and we are optimistic about a positive outcome.

Assuming ICC approval, we would begin our construction of infrastructure in the third quarter of 2013, with the first meters to be installed in the second quarter of 2014. And finally, I would like to update you on a recent FERC regulatory development.

In June, the FERC issued an order in the electric capacity construct filing of the Midwest Independent Transmission System Operator, or MISO. The FERC approved MISO’s request to change the capacity construct to an annual, from a monthly capacity construct, beginning with the 2013-2014 planning year.

We are disappointed with the FERC’s order and continue to maintain that a multi-year or forward capacity construct is necessary to provide the transparent price signals needed to ensure electric reliability over the long term. However, in an encouraging aspect of the order, the FERC directed staff to solicit comments in a separate proceeding on the issue of capacity portability between MISO and PJM.

This includes an examination of administrative rules that may act as barriers to capacity transfers across the MISO-PJM scene, and potential solutions. We continue to support the removal of unnecessary barriers to capacity portability across the scene, as a means of improving market efficiency.

Moving to page 14, I would like to update you on the first of our two pending Illinois electric delivery formula rate case. While the outcome of the initial case filed in January of this year will establish the level of rates charged to customers from October through the end of this year, it is important to emphasized that full-year 2012 electric delivery earnings will reflect a true-up for 2012 rate base, actual cost of service and the formula-based return on equity, as well as historical ICC ratemaking adjustments.

To assist you in thinking about the expected 2012 earnings power of our Illinois electric delivery business, we have provided estimates of several of the key inputs into the rate formula. Moving to a discussion of the pending initial formula rate case, this filing, as we updated it in July, called for a $20 million annual rate decrease compared to current rates.

In July, the ICC staff filed their most recent testimony in this case. The ICC staff recommended that rates be decreased by 29 million annually, more than the Ameren Illinois’ updated proposal.

The ICC staff’s recommended revenue requirement reflects $20 million of lower rate base, with $14 million of this $20 million the result of downward rate base adjustments for estimated, accumulated, deferred income taxes. We have listed several of the other staff-recommended adjustments to the revenue requirement on this page.

On page 15, we have summarized the positions of the other major interveners in this case. The revenue requirement recommended by these parties range from $33 to 37 million lower than our updated request, and many of their positions on the issues are similar to those of the staff.

We, and the other parties to this case, have different views on another issue related to the rate base and capitalization amounts to be used for both ratemaking and the eventual earnings true-up calculation. We argue that the legislation specifies that rate base and capitalization for a given year should be based on year-end values.

The ICC staff and other interveners recommended that the ICC use average values for a given year. In fact, the ICC adopted average values in a recent Commonwealth Edison order.

However, in late June, the ICC voted unanimously to rehear certain parts of its May Commonwealth Edison order, including the use of average as compared to year-end rate base and the method for calculating interest on the revenue requirement reconciliation. In addition to these issues, the Attorney General has recommended an additional $7 million revenue reduction by crediting Ameren Illinois’ electric delivery cost of service with the benefit of the full amount of electric late payment revenue, including the over half related to power supply, rather than just the portion related to delivery service.

Finally, the Illinois Industrial Energy Consumers recommended limiting the common equity ratio of 50%, rather than the higher amount in our filling. We strongly believe that this proposed adjustment is unjustified.

The ICC administrative law judges are expected to issue their proposed order in this case in August, with an ICC decision expected in late September and new rates to be effective in October, 2012. Turning now to page 16, in April, Ameren Illinois made its first annual electric delivery formula rate update filling.

Again, while the outcome of this update case will establish the level of rates charged to customers beginning in January, 2013, full-year 2013 electric delivery earnings will reflect a true-up for 2013 rate base, actual cost of service and formula return on equity, as well as historical ICC ratemaking adjustment. As updated in July, this filing calls for an incremental $16 million annual rate decrease in addition to our updated request in the initial formula rate case that I just discussed.

The reduction in rates beyond those filed in the initial case primarily reflects lower rate base and return on equity. The lower rate base in this filing, compared to the amount we supported in the initial case, primarily reflects the incorporation of 2011 accumulated deferred income taxes including bonus depreciation.

The ICC staff and other interveners have filed their initial recommendations in the update case. Details of their positions are outlined at the bottom of page 16 and on page 17.

The advocated incremental rate decreases that range from $12 to 23 million more than our proposed $16 million rate reduction. Their arguments were along the same lines they put forward in the initial formula rate case.

Further, the ICC staff argued that the equity ratio should be limited to 51%, which reduced the revenue requirement by 4 million. In addition, the Attorney General of the Citizens Utility Board argued that the revenue requirements should be reduced by 5 million and 3 million respectively, to reflect the impact on deferred taxes of the 2011 change to the Illinois corporate income tax rate.

The ICC administrative law judges are expected to issue their proposed order in this case by early November, with an ICC decision expected in December and new rates to be effective in January, 2013. Moving now to page 18, in an update on our pending Missouri electric rate case.

We have requested a $376 million increase, with 273 million of this related to non-fuel costs. In addition, we are seeking approval of a new two-way storm cost tracking mechanism, and a new plant-in-service accounting proposal, as Tom has already discussed.

Finally, the pending rate request includes the revenue requirement of Ameren Missouri’s new and expanded energy efficiency programs under the Missouri Energy Efficiency Investment Act, or MEEIA. On page 19, we summarize the Missouri PSC staff’s recent recommendations in the pending electric rate case based on our calculation.

The staff recommended a $210 million increase, which included $121 million for higher net base fuel costs. The staff’s net base fuel costs were $18 million more than Ameren Missouri’s request, reflecting updated costs since our initial filing in February.

The staff’s recommended a non-fuel revenue increase of 89 million, which was $184 million less than our request. The primary driver of this $184 million difference was the staff’s recommendation of a 9% return on equity, versus our 10.75% request, which accounted for $98 million.

On this page, we list other key drivers of this difference, such as the exclusion of property tax increases for 2012 over the actual amount paid in 2011, the staff’s recommendation that all of the Entergy purchase power refund be credited back to customers over three years, the rejection of a weather normalization adjustment, a lower rate base number primarily due to lower working capital and a recommendation that we not recover 2011 voluntary separation costs, as well as a number of other adjustments. Turning now to page 20, in other rate case issues, the staff’s revenue recommendation incorporated $80 million related to the energy efficiency settlement that was ruled on by the MPSC yesterday.

Also, the staff supported continuation of the pension/OPEB vegetation management and infrastructure inspection cost tracking mechanism. However, the staff called for changing the FAC sharing mechanism to an 85/15 split rather than the 95/5 split currently in effect.

This change in the sharing percentages is similar to what the staff has recommended in past rate cases. Finally, the staff recommended that the Missouri PSC reject our storm cost tracking mechanism and plant in-service accounting proposal.

On page 21, we outline the Missouri Industrial Energy Consumer group’s recommended reductions to our rate request. As you can see, their positions are similar to those of the Missouri PSC staff, though they recommend adoption of a slightly higher return on equity than the staff, at 9.3%.

Page 22 completes our discussion of the pending electric rate case in Missouri. The Office of Public Counsel made several recommendations in the case, and we note them on this page.

Missouri PSC is scheduled to hold a hearing in the case beginning in late September, and continuing through mid-October, with a decision expected in December, 2012, and new rates to be effective in January, 2013. Moving now to page 23, here we provide an update on our 2012 through 2014 [inaudible] power sales and hedges for our merchant generation business.

Before we move to the updated hedge numbers, at the top of the page we indicate that expected 2012 merchant generation is now expected to be approximately 26.5 million MWh as of mid-2012. This is up approximately 1 million MWh from the estimate we shared with you on our May call, and it reflects increased generation due to the warmer-than-normal summer weather, driving higher spot power prices and increased utilization of gas-fired generation assets.

You will also note that for 2012, we have hedged an amount greater than our expected generation, approximately 28 million MWh, and this amount is hedged at an average price of $43 per MWh. The approximately 1.5 million MWh of hedging in excess of expected generation, we expect it to be settled on a profitable basis using purchase power or additional generation to the extent power prices improve.

Moving to 2013, we have now hedged approximately 22.5 million MWh at an average price of $37 per MWh. Further, for 2014, we have now hedged approximately 12.5 MWh at an average price of $38 per MWh.

Finally, turning to page 24, here we update our merchant generation segment’s fuel and related transportation hedges. For 2012, we have hedged approximately 25 million MWh at $24 per MWh, unchanged from what we communicated to you on the May call.

For 2013, we have now hedged approximately 22 million MWh at about $23.50 per MWh, approximately $1 per MWh less than the number we provided in May. For 2014, we have now hedged approximately 14 million MWh at about $23.50 per MWh, also approximately $1 per MWh less than the number we shared with you in May.

This completes our prepared remarks.

Good Morning. Just wanted to touch on the FERC quarter, regarding the distributed power purchase agreement.

Are there any ongoing impacts to earnings that we should be thinking about, or this more of a onetime item for this quarter?

Yes Steven, no there aren’t any ongoing impacts associated with that. You know the $0.07 gain we had, is their reversal of some negative impacts that we had in prior years as a result of the (inaudible) charges.

Those negative impacts had been included in quarter earnings in the past, which is why we reflected this gain in quarter earnings. That said, we now have a fuel adjustment clause in place in Missouri, and there’re not ongoing impacts from this settlement.

Understood. And then switching gears to MISO capacity.

What are the next steps that we should be thinking about, or further steps to come post the third quarter?

I think the thing we’re really focused on is this capacity portability issue. And I think the next steps are for, you know, in accordance with the FERC ruling for MISO and PJM double discussion about some of the barriers to portability, as well as other issues that they have.

And then we and other parties will be filing comments with FERC regarding the portability issues. So those are the ongoing things to watch for.

Good Morning, how are you?

Good, thank you, how are you?

All right. The Illinois pollution deferral, you know, regulatory deferral that you’re asking for in terms of implementation, how should we think about the impact of that on your plans, where they stand now I guess due to this issue.

There was a press report, I think yesterday, that there was a potential plant closures, et cetera if this wasn’t deferred, and I wanted to get some census to where things stand?

Sure Paul. I think what you’d be seeing in the press reports would be consistent with things we’ve talked about on our past couple of calls.

Obviously earlier this year as a result of the drop in power prices amongst other things, we decelerated construction of the (Newton Scrubber) Project. We talked about the fact that, you know, one of the obstacles we had was the Illinois Multi Pollutant Standard and the racket down in terms of So2 emissions.

I understand, I don’t mean to make you go over that, I apologies. What I was trying to figure out was, if you were to get this, would this make things – I mean, in other words we should be under - the guidance in your forecast and everything are under the expectation that we don’t have a change, is that correct?

And if I guess you did get the change, how might that change things? Do you follow what I’m saying?

Am I understanding it correctly?

I guess so, but you know there’s not, I’d say an immediate near term impact. As we look out, you know, we’re concerned about that ratchet down out in 2015.

And to the extent that release isn’t granted by the pollution control board, you know, and the Newton Scrubber, is not reaccelerated, then we do face the prospect of plant closures as discussed in our prepared remarks. So, you know, this is really an impact when we look out to that 2015 timeframe.

And then, with respect to guidance, I gather, if I understand this correctly, it’s because of the FERC order and because of normal weather in the second quarter, that you guys are raising the guidance? Is that correct?

Yes, those were some of the things that we had. You may recall Paul that after the first quarter, we actually lowered our guidance from our regulated entities by about $0.05 on either end of the range, and that’s because in the first quarter we had about $0.10 of negative impact from weather, and so we lowered the guidance $0.05.

We’ve seen an improvement in the weather situation, we’re still down year-to-date by about $0.03 on a net basis versus normal. But we did see some positive impact in the second quarter from weather.

And we also had the, as you noted, the positive FERC ruling. Those things allowed us to move the guidance back up $0.05 to where we started the year for the regulated entities.

Thank you.

Hi, Good Morning.

Good Morning, Julian.

First on the treasuries and the Illinois (formulate grates). I noticed that you mentioned 3% here.

Is that still using the blue chip average? And then secondly, did that have sort of market-to-market impact in the second quarter, and what was that?

I apologize if I missed that in your prepared remarks.

That’s fine. Julian the 3% it reflect the actual experience in terms of (inaudible) for the first half of the year, as well as, you know, blue chip forecasting as of July.

So, it’s really the average for the year, which is what’s included in the ROE. So, that 3% is what’s baked into the guidance.

In terms of a way to think about that, about every 10 basis points or so, is about a half cent per share. So about a 30 basis point move is probably a penny and a half to two cents when you’re thinking about the impact of something like that overall.

I wouldn’t say there was a mark-to market the regulatory asset that we recorded at the end of the first quarter, was unchanged at the end of the second quarter as it related to that business.

Thank you.

Morning.

Good Morning.

My questions have been answered. Thank you very much.

Okay, thank you.

Hey, guys congrats on a good quarter, good first half of the year. On Illinois, Marty, just want to make sure I followed the rate base level declined from 2012 in your filing the 2013 little bit over right around $100 to $120 somewhat million dollars.

Can you just walk us through the (Pumaton Takes) meaning net capital additions minus normal course depreciation and then minus bonus depreciation, just so we can kind of think through the give and take, and then think about how this impacts post 2013?

Yes, I don’t – Michael, I don’t have a full reconciliation to walk you through, maybe something you can follow up with Doug after the call. But you highlighted one of the drivers for that decrease.

The biggest is really that bonus depreciation, which has been included. And of course that’s been reflected in the guidance.

I think what you’ve seen in some of these cases that we have pending, is folks arguing that the accumulated depreciation should be included in the rate base. And certainly for this year in terms of the way we’ve been broadcasting out earnings and forecasting our rate base, we’ve included the deferred tax update from bonus depreciation in there, so that’s the big driver.

Thank you.

Hi, Good Morning. Actually I have a clarification question on the FAC ordered.

If I understand correctly you took $18 million charge in 2011, no charge (inaudible), and then you reversed the charge in 2013 paying (inaudible)? Is that correct?

That could be, and I don’t want to speculate on the outcome in ’13, but yes, we took a charge last year of about $0.05, as noted on the call there’s still about $25 or $26 million pending before the Reserved Public Service Commission that we expect them to rule on later this year. And then we’ll see how these court appeals play out.

Obviously we took a charge because of the – last year, because of the commissions decision, and of course we flowed those monies back through the FAC. If at some point that commission decision is reversed one way or another, and ultimately we’re able to collect those monies, at that point, it would become a gain.

Thanks so much.

Good Morning. A question for you, within your 2012 earnings guidance of $225 to $255, what is the amount of parent company drag when you’re not allocating, non-recourse debt, interest expense related to that?

You know, I don’t know what the parent company drag is. Typically what we’ve done with our debt for the most part is allocated those costs out.

So, you know the parent company debt that exist, you know, the $425 million of debt, you know, for the most part those interest charges actually get allocated out to the merchant segment, and (inaudible) supporting that merchant segment. So, while the $425 is an obligation of Ameren Corporation, the debt is being seen as supporting capital expenditures made at the merchant segment over time.

Primarily, I shouldn’t say primarily, really a AERG, which is a non-registrant, so we allocate those interests costs out to that segment.

But there’s a much larger component of non-recourse that you also book within the Merchant Generation section, that would go away if you walked away from those businesses. I’m just trying to understand, if you separated from the Merchant Generation Businesses, one of the ongoing expense that you would have at the holding company level to offset against the regulated utilities?

In terms of the debt, there’s $825 million dollars or so of debt, at Ameren Energy Generating that is non-recourse debt. That interest expense is allocated to Ameren energy Generating and AER, and then there’s the other $425 up at Ameren Corp.

and again that’s an Ameren Corp. obligation and the interest expense is allocated down to that segment, Ameren Energy Resources.

Thank you.

Good morning.

Good morning, David.

I was just wondering, following the agreement on MEEIA, what are the prospects of settlement in your ending Missouri rate case?

Yes, David, I think I will maybe Warner Bax to take that one.

David, how are you doing?

Good morning, how are you doing?

I’m terrific, thanks. With regards to the settlement – I mean, as you know, we’ve in the last several rate cases, we have not really come together in a comprehensive basis to settle the entire rate case, and that’s due to several reasons – largely due to the fact that we have several parts of those cases, and certainly several issues to resolve.

But historically, we have been able to take several issues and resolve those in a partial settlement, and then take ultimately fewer issues to the commission. Having said all of those things, certainly, if the prospects or settlements are always there so that the discussions be fruitful, and if they are fruitful, we would be happy to engage in those discussions there, if you can find something that makes sense.

So, I can’t predict the outcome, but certainly if the opportunity is right, if it make sense for us, then we will move forward with that.

Great, and just one question regarding your merger statement, what price level, Marty, are you looking for that you would need to avoid mob falling, the two of the three un-scrubbed core plant?

You know, David, there’s not, I would say, a specific price level of the words that I point to that, you know, would cause us to avoid them – and I think what you’re really asking is there a certain price level in which the, you know, Newton Scrubber would be, you know, we accelerated, and you know, consistent, and then what we said on prior calls, you know, I think that we – you know, we’ve estimated that if we reaccelerated that we would probably need something like 20 or 24 months of construction time to have that scrubber in service. So, we continue to have some time to watch how things develop, but it’s not just power prices – certainly watch power prices – I think of power, I guess you could say I think of energy, and I think of capacity because we are watching energy prices, capacity prices, development in terms of, you know, federal and environmental regulations, in the likes of – you know, there will be host of factors, but I can’t point to a specific price that would be toward the threshold.

Thank you.

I just wanted to follow up so I understood the guidance. It look like there’s about seven cents of extra weather in the second quarter, and seven cents associated with the – seven cents of the weather, and seven tenths of [inaudible] fourteen then, and you mentioned on how you readjusted your number previously.

Is there anything that we should be thinking about that would lower the number so that we only have the five cents increasing guidance, or is there something – or are you guys just being conservative?

So, yes, you are right and the numbers that you gave out are right, the Q2 weather versus normal was about a plus seven cents, and then the FERC agreement was another, you know, seven cents, but you are absolutely right. I think in terms of, again, why five cents, I think that again, we are still bond weather wise because we had about a ten cent drag in the first quarter.

We only reduce the regulated guidance by about five cents – you know, we picked up seven cents of that, yes, in the second quarter, but we are still down net three cents a-year-to-date due to weather. If that’s on a prior call, we – we’ve had about three basis point drop in the ROEs in Illinois, which again, as I said earlier, there’s probably a penny-and-a-half to what two cents of earnings, and then I think one other thing, Paul, that we mentioned on the call is that, you know, we strip out weather – you know, we’re seeing pretty flat, low growth in terms of residential, commercial year-to-date.

We did, at the beginning of the year, and frankly, continue to expect as we look to the second half of the year to see, to see some growth in those categories, year-to-date we haven’t seen any. Now, weather normalization is obviously, say not an exact science, with that pretty good extremes in both in terms of the winter months and the spring summer months year-to-date, and so, sometimes those can cause variations, but we are seeing things pretty flat year-to-date.

So, those are some of the factors – the other thing that I would say though, Paul, what we mentioned is that, you know, the July weather has been extremely warm, and continues to be extremely warm, even this week, and none of the impacts of that favorable weather in July have been reflected in the guidance that we have provided.

That’s great, just one other – that leads me to my second question, which is, are you guys having any new peaks? Have you found any change in peak demand?

You mentioned the [inaudible] kind of flattish, and I think that is – well, a lot of people’s, actually, are even down where they are normalized. But just in terms of – you had measly hot weather I think in the mid-west, at least it looked like it was, for me [inaudible] – what do you guys think of in terms of peak demand?

Yes, you know, I should have brought some exact datas, but I don’t. I can tell you that while we have, you know – you know, had some very strong demands, I think we’re still down for some of the peaks that we saw a couple of years ago, but I won’t – and maybe then I will ask somebody else to do it, to comment on that quickly.

This is Maurine Barkoski. Transmission system basis, we did set a new all-time peak on July the 25th, of a – I forget the exact number, but I think it was 18,588 megawatts, and based on the two individual companies, Ameren Illinois, did set a new all-time peak on that same day, Ameren Missouri has not yet exceeded it’s all-time peak which was in 2007.

Thank you.

Good morning,

Good morning.

First question is with regards to your – the request of environmental variance in Illinois. With the sharing that had taken place yesterday, can you – what’s the next step here?

Is there another hearing date, or is the next thing we will hear is the ruling coming out of court?

Yes, no, there – you know, there won’t be another hearing set, and we, basically, will expect to see a decision by the pollution control board deadline September the 20th.

Have they given you any – or have you gotten any guidance, or input on what their major focus is? You’ve mentioned all the major parties and their different views, but have they given you any idea what they are focused on in terms of making their decision?

No, the – you know, yesterday, I think the public hearing was well attended, all five of the members of the pollution control board were in attendance. I think they were – they were very attentive, and I think they heard, you know, from folks that spoke, I would say, on behalf of our competition, you know, folks that are located in our service territories that, you know, would – that spoke of the potential economic and personal impact of the variance, and of course there were a citizen’s group there who spoke in opposition.

So, you know, what they – with the police and the control board there to do again is to balance both environmental concerns with economic concerns, and you know, they heard testimonies on both sides. You know, ultimately, really the only parties to this to proceeding are ourselves and the IEPA that noted on our call, the IEPA has taken a neutral stance on this, and sees our petition as being environmentally beneficial, and that is our view as well, and so, we look to pollution control board again to balance the, you know, the economics with the environmental mandate.

Thank you.

Hi, just a few follow ups on the [inaudible] side of the equation. First, as you just eluded to for the net positive benefits – I know it’s IEPA here, but kind of just wanted to get a sense of how is it actually a net positive, is it just because you’re accelerating some of the reductions from 2015 forward, and that sort of off net would have happened in the back half of the [inaudible] – [inaudible] what you think about it?

Yes, that is a good way of think about it, Julian.

All right, and then secondly, on capacity affordability, what could this eventually mean, just trying to think about an ideal scenario, is this all of your capacity, partial – you know, is this just about getting some transfer right that is recognized – there are a number of different iterations that could be coming out of this, but I just wanted to get your state.

I think that is probably true, there probably are a number of different iterations that could come out of it, but certainly, I think that to the extent that, you know, we have capacity, and we’ve got, you know, there’s available transmission to get, you know, out of MISO, and into PJM – you know, we think we should be able to sell that capacity into PJM, whether that’s the percentage of our fleet, ultimately it would be available to do that – you know, I don’t know off hand. I think it could be a number of, as you said, a number of outcomes there.

Operator, this Doug Fischer, we have time for one more question.

Hey, Marty, an easy one here, can you just walk us through in the first half of 2012, what are items that are still included in ongoing [inaudible], but may not actually happen until next year, meaning, kind of like the FERC item, the seven cent benefit from the FERC item that is ongoing EPS? I’m just trying to think about whether it’s storm related, or anything else that is left for accounting lease and ongoing EPS, but may not actually be reoccurring 12 months from now.

Yes, sure, Michael. I think that we tried to list the major ones on, you know, slide three, and I guess those are mostly related to Q2, and maybe I should focus you back on our Q1 slide as well – we had a similar slide for Q1, but you do see, you know, the third quarter there, we had the absence of the fact charge from last year, and the storm costs from last year.

As I recall from the first quarter too though, we picked up a couple of cents of impact in Ameren Illinois because of contributions that we made at the start of the Illinois rate file. So, again, I just want to point you back to those first quarter slides, I think we have negative in the first quarter that would not be repeating again next year.

And then, I think as you, as you look to next year, you know, I think some of the things to think about as just the – you’ll have the resolution in the Missouri rate case later this year, next year we will have a calloway outage, where there was not calloway outage this year. Those will be some of the drivers as well as what happens with 30 year treasuries, and it affects Illinois, and in our continuing to deploy capitals that we’ve laid out.

So, those are some of the impacts to be thinking about.

Got it, okay. Thank you, Marty, thank you, much appreciate it.

Thanks, Mike.

Thank you, this is Doug Fischer – thank you for participating in this call. Let me remind you again, that this call is available for one year on our website.