Greetings, and welcome to the Ameren Corporation's Fourth Quarter 2012 Earnings Conference. [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, Senior 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 Executive 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 1 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, and 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 by our speakers. To access this presentation, please look in the Investors Section of our website under Webcast and Presentations and follow the appropriate link. Turning to Page 2 of the presentation, I need to inform you that comments made during this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives, events, conditions and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated. For additional information concerning these factors, please read the Forward-looking Statements section in the news release we issued today and the Forward-looking Statements and Risk Factors section in our filings with the SEC. Tom will begin this call with an overview of 2012 results and 2013 guidance, followed by a discussion of recent regulatory and business developments. Marty will follow with more detailed discussions of 2012 financial results, 2013 guidance and regulatory and other financial matters. We will then open the call for questions. Before I turn the call over to Tom, I would like to mention that we are now using the term "adjusted" to designate our non-GAAP earnings rather than our former term of "core." Let me be clear that we have not modified our approach as to how we calculate and present non-GAAP earnings. Only the designation has changed. With that housekeeping out of the way, 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 2012 adjusted earnings of $2.42 per share, in line with both our narrowed November 2012 and our initial year-ago guidance ranges. This is a decline from 2011 adjusted earnings of $2.56 per share, reflecting lower earnings from our merchant generation business. 2012 adjusted earnings from our rate-regulated utilities were $2.29 per share, equal to the level achieved in 2011, reflecting on the positive side of a full year of the 2011 Missouri electric rate increase and the absence of a Callaway refueling outage in 2012. These positive factors were offset by reduced Illinois electric delivery earnings, reflecting a lower allowed return on equity resulting from low treasury bond yields and required non-recoverable program donations related to 2012 implementation of formula ratemaking. The regulated utility earnings comparison was also impacted by the negative effect of warmer 2012 winter weather on electric and gas sales volumes. Merchant generation adjusted 2012 earnings were $0.17 per share, a decline of $0.13 per share compared to 2011, primarily due to lower power prices and higher fuel costs. On December 20 of last year, we announced that we intend to exit our merchant generation business. As a result of this decision, we stated that Ameren expected to take a fourth quarter 2012 charge against earnings to reduce the carrying value of our merchant generation business's energy centers. The 2012 GAAP loss of $4.01 per share, which we announced today, included both this fourth quarter charge and a first quarter charge related to the merchant generation business. Together, these non-cash impairment charges totaled $6.42 per share. Marty will provide more details on our earnings in a few minutes. Moving to Page 4, I would like to highlight some key 2012 accomplishments. I am pleased…

Thanks, Tom. Turning to Page 10 of the presentation. As Tom discussed, today we reported 2012 GAAP loss of $4.01 per share compared to 2011 GAAP earnings of $2.15 per share. This 2012 GAAP loss reflects the previously discussed impairment charges resulting from the write-downs of the merchant generation business' energy centers. Excluding the items noted on this page, Ameren recorded 2012 adjusted earnings of $2.42 per share compared with 2011 adjusted earnings of $2.56 per share. On Page 11, we list key factors that drove the $0.14 per share decrease in 2012 adjusted earnings compared to 2011 adjusted earnings. The combined 2012 adjusted earnings results from our regulated utilities, Ameren Missouri, Ameren Illinois and ATXI, were $2.29 per share, unchanged from the level achieved in 2011. These flat regulated utility results reflected on the positive side of full year of the July 2011 Missouri electric rate increase and the January 2012 Illinois gas rate increase; the absence of a Callaway refueling in 2012 compared to 2011; and the 2012 favorable FERC order related to a disputed power purchase agreement, which expired in 2009, among other factors. These positive factors were offset by reduced Illinois electric delivery earnings, reflecting a lower allowed return on equity resulting from low treasury bond yields and required non-recoverable program donations related to 2012 implementation of formula ratemaking, among other things. Other factors negatively impacting the comparison of 2012 earnings to 2011 earnings included higher depreciation and tax expenses at Ameren Missouri. This higher depreciation expense reflected increased plant investment, while tax expense increased due to a higher effective income tax rate and increased property taxes. Finally, weather had a negative impact on both electric and gas sales volumes, reducing 2012 earnings by an estimated $0.07 per share compared to 2011. Winter weather was much…

[Operator Instructions] Our first question comes from the line of Stephen Byrd with Morgan Stanley.

I wanted to just touch on the disclosure, and thank you for the additional disclosure on the merchant business, as well as the increased spending at the utility. Regarding the merchant business, can you just discuss a little bit further whether you're taking action to actively evaluate strategic alternatives for the business? Or are you still more on the assessment phase? Is this something that is taking time with management? Is this something that you're actively pursuing at this time?

Sure, Stephen. I'll see if I can expand a little bit. Obviously, we put out the 8-K, suggesting that we expected to exit from the business. I think one of the things we tried today was to provide clarity that, that exit could take the form of either sale or restructuring. And as you would expect, management is spending time and attention with respect to those exit strategies and exit possibilities.

Okay. Understood. And just as a follow-up, you laid out shared services, which was helpful. Presuming that you did have a complete exit from merchant generation, should we assume that, that $30 million would not effectively be transferred back to the parent but would effectively -- no longer be an expense to the parent because those services are truly allocated and dedicated to the merchant business?

Yes, Stephen. We would expect that in the event of a merchant exit, that, that cost -- the cost, that $30 million could be substantially eliminated.

Okay. Substantially eliminated? So does that mean when you look at that $30 million, that it is -- that, that truly is allocated and you wouldn't see a substantial portion coming back to the parent?

Yes. I guess what I'm saying is a large part of that is dedicated specifically to support of the merchant business. And so in the event of the exit, much of that cost could be eliminated. And so yes, that is what I'm saying, is that we would work to eliminate -- reduce and eliminate those costs.

Our next question comes from the line of Paul Patterson with Glenrock Associates.

Listen. On the guarantees and credit support for the coal contracts and for the Ameren Energy Marketing energy contracts, you mentioned that there's going to be some disclosure in the 10-K. Could you give us a general sense as to what the level of those obligations might be?

Yes. Sure, Paul. I think that -- and we did list it in the script the way you said it. But I would say that these guarantees are actually primarily on behalf of Ameren Energy Marketing. And the extent of those right now, I'd say, is about $200 million of guarantees. And like I said, it's primarily for power transactions. The actual mark-to-market exposure under those is only about $25 million. But that's the -- I think that gives you a general sense of the scope. And again, there will be more details on the 10-K.

Okay. And then with respect to the CapEx numbers that you're mentioning at the utility and the fact that you're negative free cash flow there, should -- how should we think about the financing going forward? Because it looks like you guys have a lot of CapEx forecasted, if you're having your rate base go that much. How should we think about the financing and specifically, the potential for equity or equity-like financing in the next couple of years?

Sure. Well, when you look at the debt financing, I guess a couple of things. One of the things we've talked about over time is looking to keep the cap structures of our regulated entities in that range of, say, 50% to 53% equity, which is something that we would work to do over time. As you look at this next year and the negative $435 million, a couple of things to look at. One, we did finish the year with no borrowings under our credit facilities, a couple hundred million dollars of cash on hand as we go into next year. We would also look over time -- as we have in the past, we have the earnings and the regulated businesses that produced retained earnings, which are in excess of the dividends that we pay out. So there's -- those retained earnings are there to again build equity in the regulated businesses such that then we can also do some debt financing to cover this -- some of this cash flow shortfall. That said, as we move through time, like I said, we will look to keep those cap structures in that 50% to 53% range in terms of equity. Right now, we're not issuing shares under the drip of 401(k). As we mentioned on the call, we don't have -- we don't anticipate doing that in 2013. But as we move into 2014 and beyond, it's certainly a possibility that we would begin again issuing stock associated with those drip and 401(k) programs in order to keep the equity content within the regulated entities in that 50% to 53% range.

Any sense as to how much those drips would be?

Historically, Paul, they were in the $75 million to $100 million range.

Our next question comes from the line of Ashar Khan with Visium.

First of all, I just want to congratulate -- I would just want to congratulate the senior management and Tom. Known the company for quite a long period of time, and Ameren used to be a premium regulated utility with one of the highest P/E multiples in the sector 20 years back. And I really appreciate you going through the strategy and returning it to its roots. And I would just hope the process is quick and fast because you deserve to be back to a premium regulated utility. And I just wanted to thank you.

Thank you. Thank you for your comments.

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

First, kind of following up on some of the GENCO discussion here, given the potential to sell the assets here, how do you think about some of the eventual tax benefits kind of akin to some of your other neighboring peers, they've discussed? Is there some kind of NOL benefit here we could be looking at?

Well, Julian, I can't comment on -- akin to our neighbors. But yes, I think that there has been -- some have written about. I think some have tried to take a look at, say, the deferred taxes overall at Ameren and then subtract out the regulated utility balances. And I would just caution that, I think, when you do that, you end up with, I'd say, too large of a number. There are certain deferred tax balances up at the Ameren corp level related to Ameren-specific things like employee benefit plans, whether they'd be deferred comp or share plans, as well as deferred taxes on NOLs and tax credit carryforwards and things like that. There are also -- in terms of -- if you start thinking about an exit of the business, there are also certain deferred intercompany gains that would be triggered as a result of the historical transfer of these assets out of the utilities. So there are a number of things that I would say make it difficult to get one's arms around what a potential tax loss would be associated with an exit of the business. The other thing, Julien, is I think the -- as you go through time, that tax basis and the assets change. So depending upon the timing of an exit, the form of an exit, whether it be sale of the assets, sale of the equity or restructuring, all of those things could result in different tax answers in terms of the potential tax loss. So we're certainly hesitant to try to put a precise value on that.

Great. Another quick GENCO follow-up here. Noticed recently, PJM's website seems to suggest that you've been successful in transacting on power and capacity. I'd be curious, just to get a holistic sense, how much are you able to transact into PJM off of your portfolio?

Yes. So, Julien, with respect to the merchant segment, they have about 117 megawatts of approved transmission from MISO into PJM for the planning years, 2012, 2013 and beyond. They've also been able to get an additional 530 megawatts of approved transmission from MISO into PJM starting in 2015. And so that's been approved, and there are also some other requests in the queue. But that's what's been approved at this point.

So when we're thinking about modeling GENCO for the 2015, '16 auction year, we should expect you to be able to clear at least in some of these incrementals? Is that the way to think about it?

Yes. That would be -- think about it, although you used the term GENCO. And I don't have the breakdown, but I think this -- I'm pretty sure that this transmission is unit-specific. And so some of it relates to AERG, and some of it relates to GENCO.

Great. Fantastic. And just a quick, quick follow-up on the put option. Under what scenarios -- if you can refresh our memories, when would you execute it? How do you think about executing it, just given the developments?

Yes. So the execution of -- or the put option is really a GENCO decision, a GENCO board management decision. The put option expires March 31 of 2014. As we said on the call, we do not expect that Ameren and AERG would extend that put option beyond its current date, but it does go through the end of March of 2014.

Our next question comes from the line of Michael Lapides with Goldman Sachs.

Just wanted to ask on the regulated side of the house. Just -- can you talk a little bit about transmission investment, both at Ameren Illinois and at ATXI, just in terms of which one might be more front-end loaded, which one might be more back-end loaded? If I look just at Slide 20, your transmission CapEx roughly -- I think it's $340 million for 2013. It almost implies that both are pretty back-end loaded, but would love your comments.

Yes. No, Michael. I appreciate the question. On Slide 20, though, and as you look to Slide 21 in terms of the rate base growth, I think, overall, the CapEx investment at the Ameren Illinois utilities I wouldn't say is really front-end loaded but, as we've talked before, is more ratable over that 5-year period. And -- whereas the ATXI transmission investment does become more back-end loaded. So it starts a little bit slower, particularly in 2013. But by the time you get to 2014, 2015, it starts to ramp up but gets to more peak levels out in the 2016, 2017 time frame. But again, the Ameren Illinois transmission spending is expected to be more ratable over that period of time.

Got it. And on Ameren Illinois, the distribution side, I want to make sure I understand. In your guidance, are you assuming you earn on a year end rate base and not the weighted average rate base? And I know that's been a little bit of a disputed point between companies there and the commission and the legislature. Just trying to make sure I understand what's in guidance versus what you think the regulation and the legislation supposes currently?

Yes. No, Michael, it's a good observation. You're right. We have baked in the year end rate base, so we are operating with the expectation that the legislation, as we understand it, should work -- will work that way in 2013. So we have reflected in there the year end rate base.

Got it. Last item on the non-regulated side. I noticed you didn't provide hedging detail.

I didn't provide hedging details. I mean, given our intent to exit that business, I thought that providing those disclosures with long -- basically get to longer-term earnings and cash flow drivers were less relevant and wanted to focus more on the exit. That said, Michael, all of the data that traditionally we've provided in those slides will be provided in the 10-K. So you'll certainly have access to that information.

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

Just a couple of questions. Do you expect the level of the parent long-term debt to grow over the next couple of years? In other words, will you be issuing any parent long-term debt?

We would expect, Scott, that over -- if you look at where our investments are being made over time, really being made at the regulated utilities and therefore would expect, consistent with past practice, that those investments would be financed at those regulated utility subsidiaries.

And the parent currently does have some debt, I think. In your '13 guidance, where is that interest expense allocated?

In the 2013 guidance, consistent with past practice, the interest expense is allocated to the merchant and other.

Okay. Got you. And is there an overall equity ratio that we should think about going forward to keep the overall business? And I noticed you mentioned the utilities are going to be 50% to 53%. But just wondering, as we model this to find out, what should we do for the overall company?

Yes. Overall as well, we talked about over time at about that 50-50 kind of level. I think, as you probably saw in the stats that were attached to the press release, I think after the impairment charge, we stand right around 49% and we'd expect to be right around that 50-50 over time.

Our next question comes from the line of Joe DeSapri with MorningStar.

Can you talk a little bit about the thought process or considerations around pursuing the Illinois variance at GENCO? And then soon thereafter, deciding that the business still isn't economic despite receiving a desired variance outcome, kind of what sort of changed there?

Well, I'm not sure that anything really changed there. When you look back at the reason for pursuing the variance, certainly, the power prices are very low. The financial situation and condition with respect to GENCO and the merchant business suggested that a variance was really needed, that financially, we're just really unable to put money forward to complete the scrubber in the near term. And of course, we've provided, I think, a proposal that was overall environmentally beneficial in putting that forward. I think what transpired is -- or what's happened is that -- is simply a continuation of the same situation, that financial -- excuse me, the power markets continued to be very difficult. We saw over the course of 2012 not only a decline in near-term power prices but also a flattening of the forward curve and -- which make the outlook for the business even more challenging. So I wouldn't really say any difference. I would say it's just both a reflection of the same difficult conditions.

And a follow-up. Will those -- will that benefit of that variance allowance, could that potentially transfer to a new potential owner if the assets were sold?

Yes. That's a variance that is -- variance was granted to Ameren Energy Resources.

Our next question comes from the line of Dan Jenkins with the State of Wisconsin Investment Board.

First of all, I was wondering if you could give a little more clarity regarding 2013 debt financing plans. You mentioned you don't expect any equity issuance and that you're going to have negative free cash flow. So if you could just give us a sense of -- besides the debt issuance, I know you have $350 million that matures late in the year -- but just overall?

Sure, Dan. I think -- yes, you're on the right track there, obviously. We have a $200 million maturity in Missouri in July and a $150 million maturity in Illinois later in the year in December. As we think about it -- so I think those would be likely potential candidates for refinancing. As I mentioned earlier on the call, at year end, we also -- Ameren-wide had about $200 million of cash on hand and no credit facility borrowings. As we go into next year, we do expect that we are going to have these negative free cash flows at the utility businesses. So we'll we thinking about, Dan, the $200 million maturity in July at Missouri. But we'll be taking a look at what cash they have on hand, as well as what happens between now and July in terms of capital expenditures and free cash flows and then making the determination about the timing and the size of a debt offering with respect to Missouri. And similar, in Illinois, we are investing in Illinois, both in the distribution business, as well as in the transmission infrastructure, expecting to have negative free cash flows there. And again, we'll be taking a look at that, as well as in conjunction with that $150 million maturity, and assessing again the timing and size of a debt offering there. But you're on the right track in thinking about those maturities coupled with the negative free cash flows associated with those businesses.

Our next question comes from the line of Terran Miller with Cantor Fitzgerald.

Just in terms of the generation business, I know you said that the timing is uncertain. But would you be disappointed if we got to year end 2013 and this had not been resolved?

Terran, this is Marty. No, I wouldn't say disappointed if we got to the end of 2013 and it wasn't resolved. I think -- as I said before, we're going to do what we believe is in the greatest overall benefit for Ameren, and we're certainly looking to approach this exit in whatever form it takes in an orderly fashion.

Okay. And just a follow-up on the variance question. The variance was granted to, I believe, Ameren Energy Resources. If that portfolio is split, what happens to the benefits and the variances, i.e., if Gen files or is -- if it has to go to one buyer and the other assets go to another.

Yes, Terran. I know it's a legal question that I guess I'm not really prepared to speak to at the moment. I'm not sure whether each entity would individually need to comply with the emissions limitations of the variance, or whether there'd be a requirement to go back to the Pollution Control Board. So I wouldn't want to speculate at this point on how that might have to be handled.

Our next question comes from the line of Phillip Pennell with Mariner Investment Group.

Just a quick one, going back to the interconnect question with regard to PJM and MISO. I know that there is some going back and forth right now between the 2 ISOs, and I was wondering -- you have any comments in terms of how you expect that to work out? And obviously, with -- I believe it's Elgin as the only plant that's got any capacity payments that it's receiving now through PJM, and you mentioned that it was going up to like 500 megawatts or whatever in 2015. Are the other gas plants that are currently in the area going to receive any of that as potential capacity payments?

Yes. Let me see if I can expand a little bit. First of all, Elgin is actually in PJM and so it is receiving capacity payments. But that would be in addition to what I noted earlier on the call, the 117 megawatts of approved transmission from MISO into PJM for 2012, 2013 is incremental to Elgin, as is the $530 million of approved transmission starting in 2015. And again, I believe that, that transmission that's been approved from MISO into PJM is power plant unit specific. And I don't recall whether the other gas-fired units actually would benefit from that transmission, those transmission paths. The megawatt of -- the megawatts I just talked about in terms of approved transmission is really obtained through sort of normal processes of working with PJM to get that transmission into -- from MISO into PJM. So it's sort of just part of normal processes that we've been working through. In terms of the broader discussions between PJM and MISO, we're certainly hopeful that we can get to a point where we have more complete capacity portability between MISO and PJM and -- but when and how those discussions may come to that end is difficult to predict. We're certainly hopeful that the conversations will be fruitful and substantial progress can be made in 2013.

Okay. I mean, obviously, what PJM came back with last was not constructive. But I guess we'll just have to wait and see. Finally, you mentioned that moving forward with the unregulated business spin off or restructuring or whatever happens would be done within the context of your legal responsibilities. What are you referring to with regard to your legal responsibilities?

Certainly, as we think about the exit from the merchant business, we're certainly mindful of not only our fiduciary duties to the Ameren shareholders but also obligations that we have to the noteholders at GENCO. And that's what we meant by that.

All right. With that, I think we're going to end since our time has expired. This is Doug Fischer. Thank you for participating in this call. Let me remind you again that this call is available for 1 year on our website. You may also call the contacts listed on our press release. The financial analyst inquiry should be directed to me, Doug Fischer, or to Matt Thayer, my associate. Media should call Brian Bretsch. Our contact numbers are on the news release. Again, thank you for your interest in Ameren, and have a good day.

This concludes today's teleconference. You may disconnect your lines at this time, and thank you for your participation.