Douglas Fischer Thomas R. Voss - Chairman, Chief Executive Officer and President Martin J. Lyons - Chief Financial Officer and Executive Vice President

Stephen Byrd - Morgan Stanley, Research Division Paul Patterson - Glenrock Associates LLC Ashar Khan Julien Dumoulin-Smith - UBS Investment Bank, Research Division Michael J. Lapides - Goldman Sachs Group Inc., Research Division Scott Senchak Joseph DeSapri - Morningstar Inc., Research Division Dan Jenkins Terran Miller Phillip Pennell

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. Thomas R. Voss: 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 to report that we posted our best safety performance in company history as measured by work -- lost workday away accidents. Further, our utilities recorded their best electric distribution system reliability performance in our history. In addition, Ameren Missouri's Callaway Nuclear Energy Center performed exceptionally well in 2012, running continuously since its November 2011 refueling. We also had several notable regulatory accomplishments last year. We obtained FERC approval for constructive rate treatment of Ameren Transmission Company of Illinois' Spoon River and Mark Twain projects, greenfield regional projects expected to enter service in 2018 and forward-looking ratemaking for Ameren Illinois' electric transmission business. Ameren Missouri received a needed electric rate increase in December of last year, with new rates that became effective in January of 2013, and our merchant generation business won unanimous approval from the Illinois Pollution Control Board for a variance to the Illinois Multi-Pollutant Standard, allowing all of its currently operating energy centers to continue operating through 2019 without derates or shutdowns due to state sulfur dioxide limitations. Finally, the Edison Electric Institute honored both Ameren Illinois and Ameren Missouri with the association's Emergency Assistance Award, recognizing both utilities for their outstanding response in restoring electric service to New Jersey residents in the aftermath of Hurricane Sandy. Turning now to Page 5. Today, we also announced Ameren's 2013 GAAP and adjusted earnings guidance range of $2 to $2.20 per share. The projected decline in 2013 adjusted earnings per share compared to 2012 reflects an expected loss this year in the merchant generation segment due to lower power prices as opposed to earnings before impairment charges in 2012. The midpoint of adjusted earnings guidance for our regulated utilities is $2.25 per share. Again, Marty will provide details regarding our earnings guidance later on this call. Moving to Page 6, I will now update you on regulatory matters at our utilities. We continue to believe that modern constructive regulatory frameworks, which provide timely cash flows and a reasonable opportunity to earn fair returns on investments, are in the best long-term interest of our customers in the states in which we operate. These frameworks support our ability to obtain cash on a more timely basis to reinvest in our energy infrastructure and also attract capital on terms which facilitate timely investments to modernize our regulated companies' aging infrastructure. And such investments enhance reliability and the overall quality of service we can deliver to our customers, as well as improve the environment and help us meet our customers' and states' energy needs and expectations. All this ultimately helps us deliver on our customers' #1 priority, reliability, and also assists us in creating well-paying jobs. As I previously mentioned, in December of last year, Ameren Missouri received approval from the Missouri Public Service Commission to increase electric rates. The amount of the increase was $260 million annually and was based on an allowed return on equity of 9.8%. These new rates went into effect on January 2. Through this rate order, we did make incremental progress in our efforts to enhance the electric utility regulatory framework in Missouri. The Missouri PSC rate order meaningfully improved the regulatory framework for energy efficiency programs and enabled us to launch the largest energy efficiency program in the state's history. In addition, Missouri PSC authorized implementation of a new storm restoration cost-tracking mechanism that provides the opportunity to recover cost incurred to restore service after major storms in a manner that is both fair to both customers and investors. The Missouri PSC also confirms some key provisions associated with the fuel adjustment clause. We continue to strongly believe that modernizing Missouri's energy policies to support investment in the state's aging energy infrastructure will clearly bring long-term benefits to our customers and the entire state of Missouri. That is why we, along with every other investor-owned electric utility in the state, strongly support the Infrastructure Strengthening and Regulatory Streamlining act filed in the Missouri Senate and House of Representatives a few weeks ago. This legislation is intended to modernizing -- to modernize Missouri electric regulatory framework by providing for a more timely recovery of investments that are actually serving customers between rate cases. This legislation is largely fashioned after the infrastructure recovery legislation that has been utilized by the water and gas utilities in the state. The proposed legislation also contains a cost tracker for certain operations and maintenance expenses. In addition, this legislation streamlines regulation while maintaining all the consumer protections in the current water and gas infrastructure laws, including very strong oversight and approval of these expenditures by the Missouri Public Service Commission before they are reflected in customer rates. Simply put, modernizing the regulatory framework in Missouri will allow us to modernize our energy infrastructure in a more timely fashion, enabling us to meet our customers' and the states' energy needs and expectations now and in the future while providing strong consumer protections and creating jobs. It's a win-win for everyone. Turning now to Page 7 and an Illinois regulatory update. In 2011, the Illinois General Assembly enacted the Illinois Energy Infrastructure Modernization Act. This act was designed to promote investment in electric utility grid modernization and promote well-paying jobs through establishment of formula ratemaking for electric delivery service. However, in our view, the Illinois Commerce Commission, or ICC, misapplied the act in our electric delivery formula rate orders last year. Nevertheless, we continue to believe that this formula ratemaking framework is constructive if properly applied. We have appealed the ICC's formula rate orders in state court, and we are also actively seeking a legislative solution in a 2-pronged effort to address the ICC's misapplication of the act. We have taken these actions to ensure that the goals of the act are realized. Further, we support legislation recently introduced in the Illinois General Assembly, which would provide formula ratemaking for our Illinois gas delivery service. As with electric delivery, this legislation would provide a framework for accelerated gas infrastructure investment and job creation. Last month, we filed a request for an annual increase in gas delivery rates of $50 million. The case is based on a future test year ending in December 2014. The increase we are requesting reflects in part costs we are incurring in 2013. Moving to Page 8, I will conclude my prepared remarks on our regulated utility businesses by updating you on a key driver of our expected future growth, our exciting plans to invest in FERC-regulated electric transmission projects. Customers should benefit from improved reliability in a more efficient electric system, and constructive formula ratemaking in place for these projects provides a reasonable opportunity to earn fair returns on investments in these businesses. Rates for both Ameren Illinois Company and Ameren Transmission Company of Illinois, or ATXI, are updated each year based on a forward-looking calculation with an annual reconciliation based on actual incurred cost, a provision that reduces regulatory lag. Also, ATXI has received FERC approval to include construction work in progress and rate base for investments in the Illinois River's Spoon River and Mark Twain projects, providing timely cash returns on investments. Given the customer benefits our transmission projects should provide, and FERC's constructive regulatory framework, we continue to move forward with plans to invest meaningful incremental capital in these businesses. In fact, Ameren expects to invest a total of approximately $2.2 billion in FERC-regulated transmission projects over a 5-year period ending in 2017. Ameren Illinois' projects are focused on local load growth, and reliability needs and investments is expected to approximate $1 billion over the same 5-year period. ATXI is focused on greenfield regional transmission projects initially within Illinois and Missouri and plans to invest approximately $1.2 billion over the next 5 years. Our single largest planned transmission investment is ATXI's Illinois Rivers project. This important MISO-approved regional multi-value project involves a construction of a new high-voltage transmission line across the state of Illinois. It will enhance reliability and create new construction jobs in the state. In November 2012, we filed a request with the ICC for a Certificate of Public Convenience and Necessity for the approximately 400-mile transmission line route, with a decision on our request expected to be issued in August of this year. Once we receive the certificate from the ICC, we will begin to acquire rights-of-way for the transmission line, with a full range of construction activities expected to begin in 2014. Turning to Page 9, I would like to close my prepared remarks with a discussion of our merchant generation business. In December of last year, we announced that we intend to exit this business. Ameren no longer considers merchant generation to be a core component of its future business strategy. The volatility of earnings and cash flows of the merchant generation business, as well as the high degree of uncertainty regarding future returns on incremental capital invested in this business, are not in alignment with Ameren's current strategy. The announcement of our intent to exit the business follows a trend of decreasing earnings and cash flows from this segment since 2008. The timing and method of our exit from the merchant generation business is uncertain, with a sale or [ph] restructuring possible. In considering our path forward, senior management and the Board of Directors are focused on maximizing the overall benefit to Ameren, consistent with our legal obligations. While we are working to exit the merchant generation business in a prudent manner, let me reassure you that our management team remains highly focused on our regulated utilities, including growing our investments in jurisdictions with constructive regulatory frameworks so that we may better serve customers. I will now turn the call over to Marty. Martin J. Lyons: 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 warmer in 2012 than the near-normal temperatures experienced in 2011, more than offsetting the slightly positive earnings impact of 2012 summer temperatures. They were close to those experienced in 2011. While weather had a negative impact on the year-over-year earnings comparison, we estimate that weather benefited 2012 earnings by $0.09 per share compared to normal temperatures. Absent from this list of key 2012 earnings variance drivers is a change in weather-normalized retail electric sales volumes. Such sales to residential and commercial customers increased 0.3% in the fourth quarter of 2012 compared to the fourth quarter of 2011. This was a definite improvement from the 1.5% decline experienced in the third quarter of 2012 compared to 2011. Full year 2012 weather-normalized sales to residential and commercial customers declined about 0.6%. However, this was partially offset by a 2.1% increase in sales to industrial customers, with higher industrial sales in Illinois more than offsetting lower industrial sales in Missouri. Overall, we estimate that the weather-normalized retail electric sales volume decline reduced 2012 earnings by approximately $0.02 per share compared to 2011. While adjusted 2012 regulated earnings were unchanged compared to 2011, adjusted earnings from our merchant generation business declined $0.13 per share compared again to 2011. This was primarily the result of lower power prices and higher per-megawatt hour fuel costs, partially offset by lower depreciation and Operations & Maintenance expenses. These expense reductions primarily reflected the closure of the Meredosia and Hutsonville energy centers at year end 2011 and the first quarter 2012 impairment charge related to the Duck Creek energy center. Tuning to Page 12. I would now like to discuss the key drivers and assumptions behind our 2013 earnings guidance for our Missouri and Illinois regulated utility businesses. The midpoint of our guidance is $2.25 per share. In 2013, we expect to achieve an earned return of equity of approximately 9.1% on regulated utility common equity of approximately $6 billion. This guidance assumes a return to normal weather, reducing earnings by an estimated $0.09 per share compared to 2012 results. On a weather-normalized basis, we project little electric sales growth in 2013 compared to last year. Also, Ameren Missouri earnings will reflect the absence of the favorable 2012 FERC order relating to the disputed power agreement, reducing 2013 earnings by $0.07 per share compared to 2012. In addition, 2013 earnings will be impacted by the Missouri electric rate increase that went into effect last month, including the impacts of the MEEIA settlement regarding enhanced energy efficiency programs. Ameren Missouri's Callaway Nuclear Energy Center has a scheduled spring 2013 refueling and maintenance outage. This is expected to reduce 2013 earnings by approximately $0.10 per share compared to 2012 since there was no refueling outage last year. In addition, Illinois gas delivery and Missouri Operations & Maintenance cost beyond those resulting from the Callaway refueling are also expected to increase in 2013. This O&M increase includes a $7 million budgeted increase in Missouri storm costs, an amount which was incorporated into the December 2012 rate order and is subject to the new storm restoration cost tracker. Turning then to Page 13, we continue our discussion of the key drivers and assumptions behind our 2013 regulated utility earnings guidance. Our guidance incorporates our formula ratemaking expectations for our Illinois electric delivery business. Our earnings expectations for this business are based on an estimated 2013 year end rate base of $2.06 billion; an equity ratio of 51%; and an estimated formula midpoint allowed return on equity of 8.9%, which incorporates a forecasted 2013 average 30-year treasury yield of 3.1%. This treasury yield forecast is based on the Blue Chip consensus estimate as of January 1, 2013. Further, our guidance reflects the fact that several types of costs are non-recoverable in rates. These non-recoverable cost include approximately $8 million of ICC ratemaking adjustments. In addition, we expect to spend about $7 million this year on certain electric system rework that is not recoverable in rates. And finally, approximately $1 million of non-recoverable donations are required under the Energy Infrastructure Modernization Act, a reduction of $7.5 million -- or improvement of $7.5 million compared to 2012. We also expect higher transmission earnings from Ameren Illinois and ATXI in 2013 compared to 2012, reflecting rate base growth and reduced regulatory lag, reflecting implementation of forward-looking FERC ratemaking with annual reconciliations for Ameren Illinois in 2013. Moving to Page 14. I will conclude the discussion of 2013 earnings guidance by briefly touching on the merchant generation business and other category. Here, we expect a midpoint loss of $0.15 per share. The most significant driver of the expected earnings decline in 2013 compared to 2012 is a decrease in merchant generation margins of $0.45 to $0.50 per share, primarily due to lower realized power prices. We project 2013 merchant generation non-fuel Operations & Maintenance expenses will be approximately $270 million. Depreciation expense is expected to be approximately $0.17 per share lower in 2013 compared to 2012 as a result of the 2012 impairment charges. Regarding key Ameren-wide assumptions, our earnings guidance reflects in an effective consolidated income tax rate of approximately 38%, and the average number of common shares outstanding in 2013 is forecasted to be unchanged at 242.6 million since our dividend reinvestment and 401(k) plans are expected to purchase shares on the open market this year, as was the case last year. As I close our discussion of 2013 earnings guidance, I'll remind you that any net unrealized mark-to-market gains or losses will affect our GAAP earnings but are excluded from our GAAP earning guidance because the company is unable to reasonably estimate the impact of any such gains or losses. Adjusted non-GAAP earnings and guidance also exclude any net unrealized mark-to-market gains or losses. Further, earnings guidance is subject to the risks and uncertainties outlined or referred to in the Forward-looking Statements section of today's press release. Turning then to Page 15. We provide both our actual 2012 and projected 2013 cash flow information. As shown on this page, we calculate free cash flow by starting with our cash flows from operating activities and subtracting from it our capital expenditures, other cash flows from investing activities, dividends and net advances for construction. In 2012, we experienced negative free cash flow of $12 million. For 2013, we anticipate negative free cash flow of $435 million. The projected decline in free cash flow compared to last year reflects lower expected cash flows from operating activities and higher expected capital spending. Cash flow from operating activities is expected to decline compared to 2012, primarily due to lower adjusted earnings in our merchant generation segment. The higher 2013 capital expenditures reflect increased expected spending at our regulated utilities, partially offset by lower expected spending at the merchant generation business. We expect 2013 free cash flow to be negative for Ameren's regulated utilities, reflecting the significant investments we are making in these businesses. However, we expect both the merchant generation business segment and Ameren Energy Generating Company, or GENCO, to be roughly cash flow neutral in 2013, presuming continued Ameren ownership of the merchant generation business and/or GENCO. These expectations incorporate approximately $100 million for the merchant generation segment and approximately $60 million for GENCO of expected cash benefits from the Ameren tax allocation agreement. These actual -- the actual level of cash tax sharing benefits realized is subject to the realization of forecasted levels of taxable income or loss at Ameren and its subsidiaries. Further, these free cash flow estimates assume 2013 merchant generation segment and GENCO cash capital expenditures of approximately $50 million and approximately $45 million, respectively. Moving from a discussion of earnings and cash flow, I would like to comment on the recently received Missouri electric rate order and the recently filed Illinois gas delivery rating -- rate request. Turning to Page 16 of our presentation. As Tom already mentioned, in December of last year, the Missouri PSC approved an approximately $260 million annual increase in Ameren Missouri's retail electric rates. Of this amount, approximately $84 million is for recovery of higher net fuel costs, and approximately $80 million is related to the enhanced energy efficiency programs approved by the Missouri Public Service Commission in an August 2012 settlement. Among other things, the order incorporated a 9.8% allowed return on equity and continued the fuel adjustment clause with its 95-5 sharing split. Tom previously discussed several important aspects of this rate order, and I refer you to the information on pages 16 and 17 of our presentation for more details on this rate order. Moving now to Page 18. Last month, Ameren Illinois filed a request with the ICC for a $50 million annual increase in natural gas delivery service rates based on a future test year ended December 31, 2014. The ICC is required to issue an order in December of 2013, with new rates expected to be effective late that month. The key drivers of this request are rate base growth reflecting additional investment in plant, higher operating expenses, a requested increase in the allowed return on equity and lower usage by residential and small non-residential customers. Turning to Page 19, other aspects of the request include a proposal to increase to 85% from the current 80% proportion of the gas delivery revenue requirement as collected through the fixed monthly charge. This change would provide greater stability to customers' delivery rates and greater stability to Ameren Illinois' gas margins. We have also requested approval of an approximately $80 million plan to install advanced gas metering infrastructure over the 2014 through 2019 period, similar to the period over which we will be installing advanced electric metering infrastructure in Illinois. The concurrent installation of these systems for customers to whom Ameren Illinois provides both services will be cost beneficial. Moving to Page 20, I will summarize our projections for growing Ameren's investment in the regulated utility businesses over the 5-year period ending 2017. As you can see, we plan to allocate a growing and substantial portion of our investment dollars to utility businesses operating under constructive, formula-based regulatory frameworks. Nearly 30% of our planned 5-year $8.1 billion of regulated utility investment is slated for FERC-regulated transmission projects at Ameren Illinois and ATXI. Another 30% of planned investments for the 5-year period is for our Illinois electric and gas delivery services. We are also making meaningful ongoing investments in our Missouri utility operations, but these investments are expected to grow at a much slower rate than those in the FERC-regulated transmission and Illinois electric delivery businesses. However, as Tom mentioned earlier, we do believe it is in our customers' best long-term interest to grow our investments in our Missouri operations at a greater rate if the regulatory framework is modernized so that regulatory lag can be minimized. Turning to Page 21, we show that these aggregate regulated capital investment plans translate into expected rate base growth of approximately 7% annually from 2013 through 2017. With this growth most rapid in regulatory jurisdictions with constructive formula ratemaking, we believe we are on a path that will enhance our ability to earn fair returns on a growing level of utility investment. Moving to Page 22, I will conclude my prepared remarks by discussing our intention to exit the merchant generation business. As we stated back in December, we have begun planning to reduce and ultimately eliminate over time merchant generation's reliance on Ameren's shared services and financial support as a result of our decision to exit the business. We are focused on making this transition in an orderly manner. Ameren currently provides at cost approximately $30 million annually of shared services such as IT systems, finance, accounting and human resources to the merchant generation business. In addition, Ameren provides various forms of financial support to the merchant generation business segment. This support includes a non-rate regulated money pool under which merchant generation units may have access, at Ameren's discretion, to short-term intercompany borrowings. At year end 2012, GENCO had no borrowings from this money pool. In fact, it had $25 million of cash or equivalents on hand and was a lender to the money pool. Other financial support to the merchant generation business includes guarantees and credit support for coal supply contracts and guarantees for Ameren Energy Marketing energy contracts. Details of these guarantees and credit support will be provided in our 10-K. Further, Ameren guarantees AERG's obligations under the put option arrangements between GENCO and AERG. I would note that Ameren and AERG do not expect to extend the put option beyond its March 28, 2014 expiration. Of course, we will update you on our plans to exit the merchant generation business as appropriate over time. That concludes my prepared remarks. We will now invite your questions.

[Operator Instructions] Our first question comes from the line of Stephen Byrd with Morgan Stanley. Stephen Byrd - Morgan Stanley, Research Division: 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? Martin J. Lyons: 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. Stephen Byrd - Morgan Stanley, Research Division: 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? Martin J. Lyons: 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. Stephen Byrd - Morgan Stanley, Research Division: 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? Martin J. Lyons: 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. Paul Patterson - Glenrock Associates LLC: 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? Martin J. Lyons: 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. Paul Patterson - Glenrock Associates LLC: 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? Martin J. Lyons: 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. Paul Patterson - Glenrock Associates LLC: Any sense as to how much those drips would be? Martin J. Lyons: 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. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: 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? Martin J. Lyons: 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. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: 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? Martin J. Lyons: 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. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: 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? Martin J. Lyons: 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. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: 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? Martin J. Lyons: 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. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: 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. Martin J. Lyons: 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. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: 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? Martin J. Lyons: 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. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: Got it. Last item on the non-regulated side. I noticed you didn't provide hedging detail. Martin J. Lyons: 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? Martin J. Lyons: 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? Martin J. Lyons: 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? Martin J. Lyons: 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. Joseph DeSapri - Morningstar Inc., Research Division: 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? Martin J. Lyons: 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. Joseph DeSapri - Morningstar Inc., Research Division: 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? Martin J. Lyons: 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? Martin J. Lyons: 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? Martin J. Lyons: 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. Martin J. Lyons: 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? Martin J. Lyons: 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? Martin J. Lyons: 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.