阿莫林 (AEE) 2008 Q4 法說會逐字稿

Welcome to the Ameren Corporation 2008, year-end earnings conference call on the 17 of February, 2009. Throughout today's presentation all participants will be in a listen-only mode. After the presentation, there will be an opportunity to ask questions. (Operator instructions) . I will now hand the conference over to Mr. Doug Fischer. Please go ahead,

Thank you, and good morning. I'm Doug Fischer, Director of Investor Relations for Ameren Corporation. On the call with me today is our Chairman, President and Chief Executive Officer, Gary Rainwater; our Executive Vice President and Chief Financial Officer, Warner Baxter; our Senior Vice President and Chief Accounting Officer, Marty Lyons; our Vice President and Treasurer, Jerre Birdsong; our Vice President and Controller, Bruce Steinke; and other members of the Ameren management team.

Before we begin, let me cover a few administrative details. This call will be available by telephone for one week to anyone who wishes to hear it by dialing a call-back number. The announcement you received in our news release carry instructions on replaying the call by telephone. This call is also being broadcast live on the Internet and the Webcast will be available for one year on our Website, www.ameren.com. This call contains time-sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited.

I also need to let you know that comments made on 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 and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated in the forward-looking statements. For additional information concerning these factors, we ask you to read the forward-looking statements section in the news release we issued Friday and the forward-looking statements and risk factors sections in our periodic filings with the SEC.

To assist in our call this morning, we have posted presentation slides on our Website that we will refer to during this call. To access this presentation, you may look in the investors section of our Website under presentations and follow the links for the Webcast. Gary will begin this call with comments on our recently announced common dividend reduction and provide an overview of 2008 earnings results and key regulatory and operating accomplishments. He will then briefly provide some perspectives on 2009. Marty will follow with more detailed comments on recent regulatory developments. Warner will then provide more detailed discussions of our 2008 results and 2009 earnings guidance, liquidity and financing plans and our overall earnings growth objectives. We will then open the call for questions. Here's Gary.

Thanks, Doug. Good morning, and thank you for joining us. Last Friday, Ameren's Board of Directors made the very difficult decision to reduce the quarterly common dividend to $0.385 per share, which is consistent with an annualized rate of $1.54 per share. We recognize the importance of our common dividend to our investors and this dividend reduction, while clearly prudent, was not a decision that our Board took lightly. It was made only after implementing many other less painful steps. We've put in plans to significantly reduce 2008 and projected 2009 capital and operating expenditures by approximately $800 million. We also reduced executive management salaries and incentive compensation opportunities and placed firm controls on headcount and operating expenditures.

You'll look at slide three of our presentation. As you would expect, the decision to reduce the dividend was made after careful evaluation. First and foremost, the decision to reduce the dividend was based on the desire to enhance Ameren's financial strength and flexibility, as we manage our Company through these unprecedented times. In addition, we recognize that Ameren's business mix has shifted over the past several years, with significant earnings and cash flow contributions coming from the non-regulated generation business. The Board also took into account the dramatic changes that have taken place in the economy and the capital, credit and commodity markets.

It's important to note that, while Ameren is a financially strong Company with solid current liquidity, we are not immune to the impacts of the current economic environment. Like other companies in our industry, Ameren is being impacted by a general economic downturn, resulting from the global economic recession, that we expect will lower customer electricity and natural gas usage in the near term and produce some uncertainty around future usage as well. The ongoing requirement to fund significant capital expenditures to meet customer reliability needs and environmental requirements. Challenging and expensive capital and credit market conditions. Volatile commodity prices, while principally impact the stability of earnings and cash flows of our non-regulated generation business.

The need to finance future debt maturities and credit facilities, which expire in January and July, 2010. And while improved, regulatory frameworks that still result in regulatory lag and inhibit us from earning our allowed return on equity in a rising cost environment. While we have challenges, we also believe that we have a long-term strategic plan that will allow us to meet them head on. Our strategy remains one that's focused on investing in the energy infrastructure of our regulated businesses in order to deliver safe, reliable and affordable energy to our customers, in an environmentally responsible manner. This strategy will not only allow us to meet our customers' expectations and grow our regulated businesses for the benefit of our shareholders, it will also be a critical factor in helping maintain and create jobs and provide long-term growth in Missouri and Illinois during this difficult economic period.

Another key aspect of our strategy is to continue to optimize our non-rate-regulated generation assets. In that light, we are taking actions to significantly reduce spending, while actively managing the existing assets in this business to execute on that strategy. The final key component of our strategy is to enhance our financial strength and flexibility for the benefit of all of our stakeholders. The action that our Board took in reducing our common dividend will clearly help us execute on this component. Financial strength and flexibility provide near and long-term benefits to our shareholders and customers.

The lower dividend rate will allow Ameren to retain approximately $215 million of cash annually, which will help us to; invest; to improve reliability to meet our customers' expectations; satisfy federal and state environmental requirements; reduce our reliance on dilutive equity and high-cost debt financings; and enhance our access to the capital and credit markets. The combination of our investment and financing strategies will drive solid long-term earnings per share growth, principally from our strong regulated asset base. It's also important to note that our payout ratio has been among the highest of our utility peers. As you can see on slide four of our presentation, in 2008, we paid out 88% of our GAAP earnings in dividends versus 50% to 60% for peer companies. The new dividend level better aligns our payout ratio with industry peers.

Turning to slide five. Our adjusted dividend level also provides Ameren with a more sustainable dividend payout ratio, based upon anticipated earnings from our regulated business. This new dividend rate, coupled with our targeted long-term annual earnings per share growth rate of at least 5% off a midpoint of our 2009 core earnings guidance, is expected to provide competitive, long-term total return potential for shareholders. Looking ahead, our goal would be to grow the dividend level as the earnings from our rate-regulated operations increase and our overall cash flow profile improves. Of course, as they have done in the past, our Board is expected to also consider several other factors, including our overall payout ratio, payout ratios of our peers, potential future cash flow requirements and other key business considerations.

I'd now like to discuss some of our accomplishments in 2008. We reported 2008 core, or non-GAAP, earnings per share of $2.95. Within the range of both the original guidance we issued in January of 2008 and the revised earnings guidance range we provided to the market in early November 2008. Our 2008 results were achieved despite the challenges of weakening economic conditions, as well as volatile and uncertain capital, credit and commodity markets. Importantly, in 2008 and early 2009, we were able to successfully execute on key aspects of our long-term strategic plan. Our strategic plan calls for generation excellence and improvement of customer service and satisfaction.

Recall that in October 2008, our Callaway nuclear plant completed its first ever breaker-to-breaker run and completed a plant record 28 day refueling and maintenance outage this past fall. At AmerenUE, equivalent availability of our coal-fired generating units was a solid 88%, as compared to 89% in 2007. At our non-rate-regulated generation operations, we set new generation records. Producing approximately 31 million total megawatt hours, as equivalent availability for our coal-fired units was 85%, compared to 81% in 2007.

Amidst the economic challenges facing us and our nation, we've remained focused on our customers and have made significant investments in our energy infrastructure to improve overall reliability and customer satisfaction. In Missouri, through the year-old power-on-reliability program, we buried more than 100 miles of electric line, trimmed trees along more than 6,500 miles of line, tested nearly 100,000 wood utility poles, and inspected over 8,000 miles of line. In Illinois, we targeted the worst performing circuits and aggressively trimmed trees in our 44,000 square mile territory. And continued to automate our transmission system to elevate our reliability. We believe that high quality customer service is essential to earning solid returns in our regulated businesses.

On that note, I am pleased to say that we made meaningful progress on the regulatory front in 2008 on early 2009. On our third quarter 2008 call, we discussed with you the details of the much needed increases of approximately $161 million in electric and natural gas rates authorized for our Illinois regulated operations, which became effective October 1, 2008. In Missouri, AmerenUE received approval of an electric rate increase on January 27 of this year, with new rates expected to be effective March 1. The authorized increase in annual electric revenues is approximately $162 million.

We are also pleased to report that the Missouri Rate Order authorized a fuel adjustment clause, as well as a reliability cost tracker mechanism. The fuel adjustment clause and other tracker mechanisms improve our ability to continue to invest in infrastructure. So that we'll be able to meet our customers' expectations for safe and reliable service. We do consider the Illinois and Missouri rate orders to be clear signs of the progress we're making on the regulatory front and a strong foundation for future growth in our regulated businesses. And while rising operating and financing costs are still resulting in regulatory lag in both Missouri and Illinois, we will be filing rate cases more frequently in the future to minimize regulatory lag, as well as to make any bill increases more manageable for customers. Marty will cover the details of our recent rate orders in Missouri and Illinois in a moment.

Despite our recently granted rate increases in Missouri and Illinois and our proactive sales of 2009 non-rate-regulated generation in early 2008, we believe our 2009 core earnings will be relatively flat compared with 2008 core earnings. As I mentioned earlier, we are navigating our Company through a global recession, volatile commodity markets and unprecedented strains in the capital and credit markets. We believe these factors will result in lower customer usage versus 2008, lower power prices for unsold non-rate-regulated generation, and higher financing costs throughout 2009 and longer. Warner will walk you through some of our key drivers for 2009 a bit later.

In closing, we've taken timely, prudent actions over the past few months to build on our financial strength and enhance our financial flexibility in light of the difficult economic, capital and credit market conditions. These actions included reducing our common dividend, accessing the capital markets to increase our available liquidity, as well as making significant reductions in our 2008 and projected 2009 spending plans, while still meeting our reliability, environmental and safety objectives. As a result, our current available liquidity, which represents our cash on hand and amounts available under our credit facilities, stands at a solid $1.3 billion.

The need for utilities to have strong cash flows and good credit ratings, solid overall returns on their investments, and the ability to access the credit and capital markets on a timely basis has never been more apparent. The bottom line is that our management team remains keenly focused on prudently managing our business during this difficult economic period to ensure that we're able to execute on our long-term strategic plan of maintaining solid available liquidity and financial flexibility. So that we're able to invest in our energy infrastructure for the benefit of our customers and to deliver solid long term returns to our shareholders. I'll now turn the call over to Marty to discuss recent regulatory developments.

Thanks, Gary. As Gary mentioned, we made good progress on the regulatory front in 2008 and early 2009. As we have previously discussed, in late September, the Illinois Commerce Commission or ICC, authorized new and electric gas rates for our Illinois distribution utilities; AmerenCIPS, AmerenCILCO and AmerenIP, effective October 1, 2008. As summarized on slide six, these new rates provide approximately $161 million in additional annual revenue and allowed returns on equity of nearly 10.7%. The ICC also approved an increase in the monthly charge for gas residential customers, such that it now recovers 80% of fixed delivery service costs versus the prior 53%. The remainder is recovered through volume-based charges. This will make our gas utility earnings less sensitive to volumetric swings.

As shown on slide seven, we anticipate the redesigned gas distribution rates will result in a redistribution of margins during 2009. While the redesign is expected to have no net impact on full-year 2009 results, we do anticipate margins in the first quarter will be $0.05 per share lower than the same period in 2008. And that this decline will be offset by higher margins in the second and third quarters, as shown on the slide. The increased rates are already improving the earnings and cash flows of our Ameren Illinois utilities from depressed levels. We consider the Illinois rate order a clear sign of the progress we are making towards restoring the financial health of our Ameren Illinois utilities.

However, as we have previously discussed, we expect that the new Illinois rates will not fully recover at the level of costs we are currently experiencing, especially financing costs. As a result, we expect our Illinois distribution utilities earnings to fall short of allowed rates of current returns. Consequently, rate case filings with the ICC are being targeted for late in the second quarter or early in the third quarter of 2009.

Turning now to slide eight and Missouri. In April 2008, AmerenUE requested an electric revenue increase due to higher costs across this business, including fuel and reliability costs, as well as higher infrastructure investments. A critical aspect of this case was AmerenUE's request for implementation of a fuel adjustment clause. As Gary mentioned, on January 27, 2009, the Missouri Public Service Commission authorized AmerenUE to increase annual electric revenues by approximately $162 million. The new rates reflect an allowed return on equity of 10.76%, a 52% common equity ratio, and a rate base of $5.8 billion.

Importantly, the Missouri rate order also authorized AmerenUE to implement a fuel adjustment clause. The fuel adjustment clause applies to net fuel costs, which include delivered fuel and purchased power costs, net of off-system sales revenues, including Midwest Independent Transmission System Operator, or MISO, costs and revenues. The fuel adjustment clause passes through to customers 95% of deviations between actual net fuel costs and net fuel costs of approximately $328 million included in base rates, subject to prudency review, as shown on slide nine.

In addition, to the fuel adjustment clause, the Missouri Commission also approved a vegetation management and infrastructure inspection cost tracker. The Missouri Commission also authorized continued use of the pension and other post-retirement employee benefits cost tracker, first approved in the May 2007 electric rate order. The Missouri Commission also approved amortization and recovery, over five years, of $25 million of previously expensed O&M costs related to the January 27 -- the January 2007 severe ice storm.

In addition, previously expensed MISO day two expenses of $12 million were authorized for amortization and recovery over two years. In total, the portion of the full rate increase granted by the Missouri Commission, which provides for recovery of net additional prior-period costs, will result in approximately $12 million of additional annual amortization expenses. Overall, we believe this order by the Missouri Commission is constructive. However, because of continuing investments in our utility infrastructure, rising operating costs and costs of capital; we do not expect to earn the return on equity allowed in this proceeding during 2009. As a result, we expect to file another electric rate case in Missouri later this year. The exact timing will depend on the timing and magnitude of cost increases and rate base initiatives, among other things.

On January 28, 2009, just one day after the Missouri Commission delivered its order in this case, a severe ice storm hit Southeast Missouri. This severe winter ice storm caused a power outage at AmerenUE's largest retail customer, Noranda Aluminum. According to Noranda 's January 29, 8-K filing with the Securities & Exchange Commission, the outage affected approximately 75% of the smelter plants' capacity. Further, Noranda stated that preliminary information and management's initial assessment, indicated restoring full capacity may take up to 12 months, with partial capacity phased in during the 12-month period. AmerenUE supplies electricity to this facility but the transmission and distribution lines that feed the Noranda facility and that failed are owned by others.

It's too early to assess the exact impact of the outage on AmerenUE's business. While AmerenUE expects it will be able to sell the power that would have gone to Noranda into the off-system wholesale power market, at prices that currently above Ameren's tariff rate, the newly approved Missouri fuel adjustment clause requires that 95% of the incremental off-system sales margins be flowed through to electric customers. In response to this unanticipated event, AmerenUE filed a request with the Missouri Commission for a rehearing of the January 2009 electric rate order in consideration of revisions to the fuel adjustment clause tariff to mitigate the Noranda issue. Unfortunately, the Missouri Commission expressed its intent to deny the rehearing request, at a public agenda session last week. And an official bow to that effect is expected later this week.

If 75% of Noranda's capacity were down for 12 months, the reduction in AmerenUE's pretax annual earnings could be as much as $73 million due to the loss of up to approximately 3.2 million megawatt hours of retail sales. At this time, we are unable to reasonably estimate the impact of the Noranda outage, as well as the impact of other storm-related costs on our earnings. UE is currently considering other possible steps it might take to mitigate the loss of revenues from Noranda , including filing for an accounting authority order. Consistent with our past practice, we will exclude the earnings impact of this severe ice storm from core earnings. I will now turn the call over to

Thanks, Marty. Starting first, with our 2008 earnings results, please turn to page 10 of our slide presentation. We announced 2008 net income, in accordance with generally accepted accountable principals, of $605 million or $2.88 per share, compared to 2007 GAAP net income of $618 million or $2.98 per share. Excluding certain items in each year, Ameren recorded 2008 core or non-GAAP net income of $622 million or $2.95 per share, compared to 2007 core net income of $685 million or $3.30 per share.

We recorded several significant items in 2008 that we have excluded from our core earnings. The net costs associated with the Illinois comprehensive electric rate relief and customer assistance settlement agreement, reached in 2007, reduced GAAP earnings by $0.13 per share in 2008 versus a $0.21 per share reduction in 2007. Net unrealized mark-to-market losses reduced 2008 GAAP earnings by $0.07 per share, as compared to net unrealized mark-to-market gains of $0.04 per snare 2007. A lump sum settlement payment, in 2008, from a coal supplier for expected higher fuel costs in 2009, as a result of the premature closure of a mine and termination of a contract, benefited 2008 GAAP earnings by $0.08 per share. However, the contract termination will result in higher fuel costs for non-rate-regulated generation in 2009.

Missouri accounting and electric rate orders, directing our Missouri utility to record a regulatory asset for the January 2007 severe ice storm costs and authorizing amortization and recovery of these costs, increased 2008 GAAP earnings by $0.07 per share. The Missouri rate order directing amortization and recovery, over two years, of previously incurred costs, pursuant to a 2007 Federal Energy Regulatory Commission or FERC order; increased 2008 GAAP earnings by $0.04 per share. The 2007 FERC order retroactively reallocated certain MISO costs among MISO market participates. This resulted in a 2007 charge to GAAP earnings of $0.06 per share. Finishing up the non-core items, asset impairment charges, related primarily to the Indian Trails cogeneration plant, resulting from the suspension of operation of the plant's only customer, reduced 2008 GAAP earnings per share by $0.06.

On slide 10 of the presentation and focusing only on some of the more significant items. The full-year impact of the 2007 Missouri electric and natural rate increases raised earnings by $0.08 per share. A net increase in Illinois electric and natural gas delivery rates, effective October 1, 2008, boosted earnings by $0.09 per share. Other electric and gas margins increased $0.64 per share in 2008, compared to the prior year. Primarily, as a result of improved generating plant output and higher realized electric margins at non-rate-regulated generation operations. More normal summer weather in 2008, compared to the extremely hot summer weather in 2007, was the primary reason that weather reduced 2008 earnings by an estimated $0.16 per share compared to the prior year. For 2008, our weather sensitive residential and commercial electric sales were down approximately 2% and 1 % respectively compared to 2007.

After adjusting for weather, we estimate our combined residential and commercial electric sales increased approximately 2% in 2008 versus 2007. However, our industrial sales showed the impact of the weakening economy, declining approximately 3% in 2008 compared to 2007. Our cost for fuel and related transportation reduced 2008 earnings by $0.37 per share compared to 2007. In addition, higher plant operations and maintenance expenses reduced 2008 earnings by $0.16 per share versus 2007.

Distribution system reliability expenditures reduced earnings by $0.16 per share in 2008, compared to the year-ago period, as we continued to make significant incremental investments to improve reliability and customer satisfaction. Financing costs also rose in 2008, as we refinanced auction rate debt earlier in the year due to the volatility in the capital markets, as well as issued higher cost debt later in 2008, under significantly strained capital market conditions. Bad debts, labor, depreciation and amortization and other expenses also increased year-over-year.

Moving on to our 2009 guidance on slide 11. As we stated in our news release from Friday afternoon, we expect our core earnings to be in the range of $2.75 to $3.15 per share. Before I discuss a detailed reconciliation between our 2008 earnings results and our 2009 guidance, I believe it is important to look at 2008 core results and 2009 core guidance by segment. In total, our two regulated segments posted core earnings of $1.36 per share in 2008. We expect results from these regulated units to improve in 2009 to a range of $1.65 to $1.85 per share, on a core basis. Up approximately 20% to 35% over 2008 results, reflecting the benefits of the net rate increases in Illinois and the recently granted Missouri electric rate increase.

However, the expected 2009 regulated results, while higher, will still fall below the allowed returns on equity authorized by our regulators. The new rates are based on historical test year data. And 2009 costs are expected to be higher than the levels recovered in rates. This is especially true of financing costs in Illinois, where sharply higher debt financing costs, which were incurred after our rate cases were filed, are not being recovered in rates.

Turning now to slide 12. The midpoint of our core guidance range for Missouri regulated operations, translates into an estimated return on equity of approximately 8%. And the midpoint of our core guidance range for our Illinois regulated operations translates into a estimated return on equity of approximately 6%. As Marty mentioned earlier, our allowed returns on equity are approximately 10.7% for both jurisdictions. So in summary, we expect earnings from our Missouri and Illinois regulated operations to show marked improvement but to still fall short of our allowed return levels. While discouraging, the primary factors resulting in regulatory lag can be addressed in a very straightforward manner by freshening up our rates in Illinois and Missouri to reflect our energy infrastructure investment and higher financing costs, as well as other higher operating costs.

As Marty discussed earlier, this is exactly what we intend to do. It is this straightforward strategy that gives us confidence in our ability to grow our regulated earnings from their current levels. Note, that for every 1% that we narrow the gap between our allowed return on equity and our earned return on equity in our regulated operations; we generate an incremental $50 million and $25 million in pretax revenues in Missouri and Illinois respectively. I should reemphasize that the 2009 Missouri regulated operations, core segment guidance and the related return on equity estimate, exclude the impact of the Noranda outage and the January 2009 ice storm.

For the Illinois regulated operations segment, the 2009 core segment guidance and related return on equity estimate, exclude the estimated $0.03 per share negative impact in the 2007 settlement agreement among parties in Illinois to provide comprehensive electric rate relief. While core earnings from our regulated segments are expected to grow materially, 2009 core earnings in our non-rate-regulated generation segment are expected to decline. We project this segment's core earnings will be $1.10 to $1.30 per share this year. Down from the $1.59 earnings per share posted in 2008. The 2009 non-rate-regulated generation segment core earnings guidance excludes an estimated $0.04 per share negative impact in the 2007 Illinois settlement agreement.

A decline is expected, despite our proactive sales of 2009 non-rate-regulated generation, in early 2008, at power prices well above current market prices. However, the combination of lower power prices for our unsold generation, higher fuel costs, a decline in our estimated generation level to approximately 30 million megawatt hours, and higher environment related costs; are the reasons we expect lower core earnings from this segment in 2009 versus 2008. It is important to note -- excuse me -- it is important to point out that the lower estimated generation level is largely a function of the decline in power prices.

We told you in early November 2008, that for 2009, we had hedged approximately 85% of our estimated non-rate-regulated generation of 32 million megawatt hours at approximately $53 per megawatt hour. Approximately two million megawatt house of generation output that we'd expected, as of our November forecast, is no longer economic due to the significant decline in power prices since that time. Consequently, should power prices rebound during 2009, we clearly have the capacity and availability to sell more generation, which could result in higher than currently expected margins.

Finishing up my discussion of our non-rate-regulated generation business on slide 13. We continue to believe there is meaningful value associated with having iron in the ground, at a time when generation capacity expansion is limited due to the state of the capital markets. You can also see that we have been actively hedging our open generation and fuel positions. For 2010, we have significantly hedged our fuel requirements. In addition, in terms of power, we have significantly hedged our current economic generation, as well as had a meaningful portion of our 2010 economic generation hedged.

Moving on from the segment perspective to an overall Ameren perspective. We have on slide 14, our earnings per share guidance, reconciled between 2008 and 2009. Beginning our discussion with our 2008 core earnings per share number of $2.95, which we discussed earlier, I will comment on some of the more meaningful items. First, you see the impact of the recent Missouri electric rate order, which increases retail rates by approximately $162 million annually. We expect the new rates, net of increased amortization expenses, to benefit our earnings per share by approximately $0.39 from 2009. The Illinois net rate increases are expected to boost earnings per share by approximately $0.38 per share.

For non-rate-regulated generation operations, other electric margins are expected to be lower and reduce earnings by $0.05 per share, reflecting lower expected generation levels and the significant decline in power prices that I just discussed. Regarding our Callaway nuclear plant, we do expect a $0.09 per share earnings pick up, because of lower operations and maintenance expenses resulting from no refueling outage being scheduled for this year, something that occurs every third year. We also continue substantial spending on distribution system reliability in our regulated businesses. Increased depreciation and amortization expenses, primarily reflect rate-based growth and are expected to reduce 2009 core earnings by $0.15 per share.

Net dilution of financing costs are expected to reduce year-over-year earnings by $0.23 per share. In addition to the higher cost of financings recently completed, we expect meaningfully higher interest rates on prospective debt refinancings, due to the disruption in the capital markets. Further, we plan to issue additional debt to fund a portion of our capital expenditures. It is important to note that, approximately $0.12 of the $0.23 projected increase in financing costs is being driven by our regulated operations. Other taxes are expected to reduce earnings by $0.10 per share principally due to higher [ABOR] taxes. In addition, other expenses are expected to rise year-over-year.

An estimated $0.07 per share negative impact in 2009, in the 2007 settlement agreement among parties in Illinois to provide comprehensive electric rate relief and customer assistance, is excluded from core earnings guidance. Any net unrealized mark-to-market gains or losses will impact GAAP earnings, are excluded from GAAP and core earnings guidance, as the Company is unable to reasonably estimate the impact of any such gains or losses at this time. In addition, any effects of a severe winter ice storm, including the impact of the related outage at the Noranda plant, are also excluded from GAAP and core earnings guidance. The Company is unable to reasonably estimate, at this time, the impact of the storm and outage on earnings.

The bottom lines, is that our core earnings per share for 2009 ranges from $2.75 to $3.15 per share. We expect our 2009 GAAP earnings to be in the range of $2.68 to $3.08 per share. Ameren's earnings guidance for 2009 assumes normal weather and is subject to, among other things; regulatory decisions and legislative actions; plant operations; energy and capital and credit market conditions; economic conditions; severe storms; unusual or otherwise unexpected gains or losses; and other risks and uncertainties outlined or referred to in the forward-looking statements section of the press release we issued last Friday and the forward-looking statements and risk factors sections in our periodic filings with the SEC.

Next, and turning to slide 15 of our presentation, I would like to discuss our current available liquidity position. As Gary noted, we currently have a solid $1.3 billion of available liquidity. That is comprised of cash on hand, as well as available borrowing capacity under our $2.15 billion of revolving credit facilities. As you know, we have taken aggressive and prudent actions to manage our available liquidity position since late last year. Including making plans to significantly reduce our capital and operating expenditures in 2008 and 2009, as well as reducing our dividend. These actions are designed to reduce our need to access costly and uncertain capital markets.

During our third quarter 2008 call, we stated that we plan to significantly reduce our originally estimated negative free cash flow for 2008 of approximately $1.5 billion. We delivered on that commitment. Our negative free cash flow at December 31, 2008, approximated $1.1 billion, as shown on slide 16. In 2009, we expect that our operating and capital expenditure reductions and coupled with our dividend reduction, will drive our negative free cash flow down to approximately $500 million.

Moving on to slide 17, you will note that we have modest debt maturities over the next three years. As we look ahead in 2009, we will focus on $250 million of long-term debt to be refinanced at our regulated utilities, as well as $124 million at our non-rate-regulated generation segments and $300 million at Ameren Corporation. We will also take steps to replace our $2.15 billion of credit facilities that expire in 2010. We recognize that the credit markets are very challenging these days. While we will be seeking full renewal of our bank facilities on reasonable terms, we anticipate the possibility that the capacity under our revolvers could be reduced and be more costly. Given this uncertainty, we plan to more aggressively term out our short-term borrowings under such facilities, which will provide further financial flexibility.

In all, we currently expect to issue approximately $650 million of debt at our regulated utilities. $250 million in Ameren Corporation. And approximately $500 million at the non-rate-regulated generation subsidiaries in 2009. Of course, we expect these debt issuances, as well as our borrowings under our credit facilities, will be more costly compared to what we have experienced in the past. In terms of equity financings, as a result of the dividend reduction, other than equity proceeds received under our dividend reinvestment and employee benefit plans, we do not currently anticipate the need for additional equity issuances during 2009. Having said that, our actions to date clearly point to the value we place on having financial strength and flexibility. As we continue to make meaningful investments in our businesses, most notably our regulated businesses, we intend to finance those investments with a blend of equity and debt in the future. So that we maintain a solid capital structure in our regulated businesses, which would approximate 50% to 55% equity.

Having such a capital structure, not only strengthens the financial position of those capital-intensive businesses, it also gives us the ability to earn solid returns on those equity investments. Consequently, we do expect to make appropriate equity issuances in the future, consistent with this framework. As well as to address any unanticipated events, should the need arise. The bottom line is that we plan to be proactive and opportunistic as we implement our long-term financing plans for debt, equity or equity linked securities; in order to appropriately finance our operations, meet scheduled maturities and maintain financial strength and flexibility for the long-term benefit of all of our stakeholders.

To wrap up. We remain very committed to our straightforward long-term business strategy of investing in our Missouri and Illinois regulated businesses, in order to deliver, safe, reliable and affordable energy to our customers. As you can see on slide 18, we plan to continue to make significant investments in our regulated businesses to improve reliability to meet our customers' expectations, as well as satisfy environmental requirements. From 2009 through 2011, we expect our regulated rate base to grow approximately 9% per year. And we will seek to recover those investments and earn solid returns through frequent rate case filings and potential future cost recovery mechanisms. These increased investments, when coupled with the fact that our current rates are not reflective of higher operating and the significant financing costs that we are experiencing, as shown on slide 12 earlier; gives us the confidence in our ability to achieve our long-term annual earnings per share growth target of at least 5% off of the midpoint of our 2009 core earnings guidance. This targeted earnings growth rate, when combined with our new dividend rate, will provide competitive long-term total return potential for shareholders.

Before we open the line up for questions, I want to let you know that we do plan to hold an analysts day in New York City in the spring. We will inform of you of the details, when they are finalized. We will now be happy to take your questions.

Thank you, sir. (Operator instructions) Thank you. The first question is from Mr. Paul Patterson from Glenrock Associates. Please go ahead.

Good morning, guys. I wanted to touch base with you on the earnings going forward in 2010 and 2012, you guys gave us a presentation earlier in 2008, and you mentioned wholesale prices going down. How should we think about the impact of lower power prices and what your outlook is now?

Paul, this is Warner. I think, as you've recognized, power prices have obviously fallen significantly. And so, the guidance that we provided to you back in January of 2008 is no longer valid at this point in time. And what we've provided to you is our earnings per share guidance through 2009. And at this point, nothing more beyond that.

Okay.

So, to address your question with regard to the guidance that we provided in early 2008. Yes, Paul, just to give you a little benchmark on that. We sell a little over 20 million megawatt hours per year from that business, and a $10 movement in price then means a $300 million movement in margin in that business. So relatively small movements in price generate substantial movements in margin. And the price decline that we've seen since about last summer is on the order of $30 per megawatt hour, which is on the order of $1 billion or could be a decline of $1 billion from where we were last year. However, because of our hedging policy, prices were locked in at substantially above where the market is. And while we will see some decline in earnings this year and we expect to see some weakness in the market in the future years, the hedging, really, has helped sustain earnings in that business.

Okay. You mentioned $53 that you were hedged at, I believe, for this year, correct?

That's about right.

Okay. And then, what is it in 2010 and how much less are you hedged then? Could you just give us a little more flavor on that?

Sure. If you look at slide 13, Paul, on our presentation, you'll see for 2009, we're hedged at 95% and that's right about at $52 per megawatt hour. In 2010, we're not disclosing the specific hedge number that we have out there in terms of price, but you can see that we've hedged 60% of that already for 2010. And as Gary pointed out, we were very proactive while those markets were more liquid, especially earlier in 2008 to try and take some of that hedging off. As well as that incorporates the swap agreement that we entered into as part of the electric rate relief settlement in Illinois a couple of years ago. That pricing is out there and very visible.

Okay. So we'll get a better idea, when you guys have your meeting in spring about what those prices might be. Because just looking at the hedge number of 60%, it's a little bit hard for us to know what that actually translates into?

Sure. In terms of that, when we come back out in the spring, we'll be able to provide you, as we did last year, some more color around not just the hedges but also -- on the power side, but also give you some more color on the fuel side as well.

Okay. And then, with respect to the regulated ROE and what you guys -- the challenge there in terms of earning it, when do you think -- do you think there will be an opportunity to catch up? I know you guys have lowered CapEx, et cetera, but that might probably start up again. I'm just trying to get a an idea as to when that regulatory lag -- will we be in a perceptual situation of sort of under earning or could you elaborate a little bit on that? And just with respect to the dilution of $0.23 a share, how should we think about -- how much equity is a component of that?

A couple of points, Paul, to try to and address here. First, in terms of the regulatory lag. Is there an opportunity for us to narrow the gap? Is the answer is simply, yes. And we are taking actions to narrow that gap, number one, through the filing of more frequent rate cases. But two, looking for the ability to implement cost recovery mechanisms that will give us more timely recovery. One example of that, would be the environmental cost recovery mechanism rules that are currently being -- under study in the state of Missouri. That's certainly an opportunity, as we continue to make meaningful environmental capital expenditures in that business, for us to mitigate the regulatory lag that we see prospectively. And certainly, we will -- in terms of how we time the filing our rate cases, we're going to be mindful of our ability to try and put the most current level of costs, as well as update those filings in our rate cases to try to mitigate, ultimately, that regulatory lag. In terms of the dilution that you asked with regard to 2009, what's reflected in there is the dilution associated with the DRIP program, which is about $0.03 to $0.04 per share. Beyond that, the rest of that is really bladed to the debt financings that we have reflected in there.

Thanks a lot.

Thank you. The next question is from Greg Gordon from Citigroup. Please go ahead with your question.

Good morning, gentlemen. I know the dividend cut was a very difficult decision for you guys. And --.

Greg, I'm sorry, we can't hear you very well. If you can maybe speak into the speakerphone. I apologize.

Sorry. Can you hear me now?

Yes, I can hear you much better now. Thank you.

I was just going to say, I know the change in dividend policy was a very difficult decision for you guys but I know you made the right decision in the long run for your shareholders.

Thank you.

The lower -- a couple of questions. What is your specific expectation for lower volumes in -- or what is your specific volume output expectation at the generation business for 2009? You said that you were expecting, all things equal, lower volumes because of market conditions.

Yes, Greg, this Warner, the output for our unregulated generation segment in currently expected to be 30 million megawatt hours for 2009. And as we've said, we frankly have the availability and the capacity to increase that should power prices increase. Back in November, we had estimated, based on market prices at that time, that we would generate economic generation of approximately 32 million megawatt hours. But because of that fall in market prices, we are now down at 30 million megawatt hours.

So, if prices were to recover, not only would you see higher margins on the 30 kilowatt hours of production but you might be able to increase volumes as well?

That's correct.

You said $0.03 to $0.04 dilution from the DRIP's. How -- what is that in terms of hundreds of millions of dollars of issuance through the DRIP?

In terms of cash flows, the drip is probably going to generate about $80 million of cash, under that program, assuming you had the same level of participation.

Thank you. And then the final question, when we met with you in November, you indicated that you were contemplating a pretty severe cut in capital expenditures. Down to as low as $1 billion for 2009 from the prior budget, which looking at your March '08 10-K, which was $1.8 billion, it now looks like you're now budgeting $1.685 billion. I'm assuming that some of that's a function of the fact that you've now moderated the dividend payment. But can you talk about what is in and what is not in the 2009 guidance, as it compares to what you said at EEI?

Sure. It's a bit complicated but let me try my best. When we came out of EEI, we said we had targeted meaningful reductions in both the unregulated generation business, as well as our regulated business. And at that time, we had actually identified specific reductions that we were going to take actions on in our unregulated generation business. And in fact, those range from approximately $300 to $400 million over -- or under 2008 levels. And in fact, when you look at both 2009, you can't look at just 2009 but have to also look at the reductions that we made in 2008. Because we moved out very quickly to reduce our capital expenditures. And so, when you look at both the reductions in 2008 versus our original plan, versus where they ended up in 2009, we actually achieved approximately $400 million of both capital and O&M reductions in our unregulated generation business.

On the flip side, we had said that we were going -- we had identified about $400 to $500 million of potential reductions in our regulated businesses. And that we were going to continue to assess them. And in fact, we did. And ultimately, when you look again between 2008 and 2009, you'll see a combination of capital and O&M reductions, which approximate $300 million or so, compared to our original estimates. However, we did not go all the way up and get all of those reductions in our regulated businesses, simply due to the fact that the Sioux scrubber project that we had identified. We thought it was more prudent to continue to move forward with that project, among a few others. And so, all of those factors, coupled with the other things that we've done with our financial plans, as you described, ultimately got us to the decisions that we've made to get to our earned capital expenditure and operating expenditure levels.

Okay. I see that now. the CapEx for '08 actually came in almost $340 million lower than the beginning of the year budget.

Yes.

And then, you are just over $100 million later in '09 than the prior budget.

Yes, so it's a combination. When we were looking in November, obviously, we weren't sure how quickly we could get those capital expenditures out of '08 but we were able to make meaningful progress in '08. And then, obviously, again in '09.

But this up Sioux scrubber will continue as planned and the majority of the regulated capital expenditures continue to be in the budget?

Yes, by and large, the Sioux scrubber was -- it's a little bit delayed from what our original plans were. But we are going to continue to move forward with that Sioux scrubber on a more expedited basis that we had discussed in the fall.

Okay. Thank you, gentlemen.

Thank you. And the next question is from Yiktat Fung from Zimmer Lucas Partners. Please go ahead with your question.

Good morning. With regards to the CapEx cuts again. Are you assuming that -- I think that during EEI, you mentioned that you could move potentially, I think, $500 million of environmental CapEx from the 2009 to 2012 time frame, back to beyond 2012. Is that move assumed in your CapEx guidance that you're currently giving out?

This is Warner. No, as is reflected right now, that -- you're relating that to the variance request that we made with the Illinois Pollution Control Board.

Yes.

At this stage, our initial variance request was initially turned down, what we would consider on some of the sort of the technical considerations, in terms of how we made the filing. And so, we are going to continue to seat that variance request with the Illinois Pollution Control Board. But our existing capital expenditure budgets include those dollars in our current plans, until we get a final ruling from the Illinois Pollution Control Board.

So if you prevail, there's an opportunity to potential cut the CapEx even more?

There would be an opportunity for us to defer some of that CapEx, from the '09 to '11 time period, out beyond '12 through '13 and beyond.

And when would you expect a final decision in that issue?

It's uncertain. The Pollution Control Board has not set a specific date but we would expect that to be some time in the second or third quarter before we get a final determination on that. At least, at this time.

With regards to your segment guidance, I was wondering if you could allocate some of those items that you listed on slide 14? That gives 2009 earnings guidance to each segment. For example, the depreciation and the pension and benefit costs. Those items that aren't exactly clear where they reside in the three segments?

Sure. Some of those, I think we have identified as part of the conversation. For instance, the dilution and financing, we've identified in our call. $0.13 of the $0.23 related to the regulated operations. Where the rest, really related to the unregulated generation. The pension and OPEB costs, Marty do you have more of a breakdown on that one?

Yes, I have more of a breakdown in terms of components being, active medical and pension. But not so clear of a breakdown, frankly, on the segment guidance.

Okay.

What we can do, to break that down a little bit for you, we can probably give you a little bit more of that information by segment. Certainly, when you look at the pension and OPEB costs, primarily that, in large part, will be driven by the unregulated generation segment. Remember, we have this pension and OPEB cost tracker in Missouri. And so, that's helpful there, in part. As well, as in the distribution system reliability, a good chunk of that still relates to the Missouri operations in Illinois, probably a little bit more in the Missouri versus the Illinois at this point in time. But we can come back to you with a little more detail and we can provide some of that, certainly, at analysts day to kind of help you through some of those specific line items. If you would like us to.

Okay. That would be great. Just a couple of more questions. Can you kind of explain the outperformance at the non-rate-regulated segment in 2008? I think that beat the top end of your guidance by about $0.09. And also the slight underperformance at Union Electric?

Yes, I think there are a couple of things to think about there. With regard to the unregulated generation segment, that was principally driven by solid operating performance by our generating units. They delivered record generation levels. And so, we were pleased to see not just the record generation levels but the improvement in overall, the plant operations. So that was certainly one of the key drivers there.

So, they're seeing higher output?

Yes. But -- and I think the other thing too, power prices were a little bit better, in terms of what we had done. And also, we were active, at the beginning of '08, to really hedge before prices fell later; our open generation position. So it's a combination of all of those things that really drove the performance there. In terms of UE being slightly down, certainly we had some incremental financing costs. We had to replace our auction rate debt earlier in the year at costs which were certainly higher. And then beyond that, I think they had a few related Callaway outages. So, they had a Callaway outage later in December, which effected a little bit of their operations. And then, really, there's just a bunch cats and dogs, including some tax-related items, that drove it down. But nothing significant.

And just one final question. With regards to the hedging disclosure that you gave, is that $53 that you mentioned during EEI for 2009 still valid?

Well, what we had just said, I just spoke, I believe it was to Paul, a little bit earlier, that number for 2009 that you see on slide 13, that 95% hedged. That's at $52 per megawatt hour, that number is there.

And the $52, is that just around the around the clock price or does that also include the margins from capacity payments and ancillary services?

I'm sorry I didn't hear the question.

Is the $52, just the around the clock component or does that also include capacity prices? Do you also mix in the capacity revenues and the ancillary service revenues?

Yes, I'm sorry. That's an all-in price.

All-in price. Okay. Thank you.

Thank you. The next question is from David Frank from Catapult Capital. Please go ahead with your question.

Hi, good morning, Warner. Given all of the talk of uncertainties like future carbon regulations, commodity price volatility, has any of this caused management to consider divesting the coal plants, the merchant coal plants? Or are you married to those plants for now?

David, this is Gary. Actually, we have considered divesting some of the units. And that work, we -- it hasn't gone public yet, but we are putting in place a plan to potentially sell some of the smaller units.

Like the smaller coal units in Illinois?

The smaller coal units like Meredosia.

Is there a market out there now for those plants, do you think?

There is potentially some market for them. And we don't know the full answer to that question but there's potentially a market, it depends on the buyer. And what the buyer -- buyers like co-ops and munis may be interested in those kind of units.

Okay. And just on that note, have you actually refiled yet with the State of Illinois on the delay of the pollution spending or can we expect you to make that filing soon?

David this is Warner, we have refiled that. A few weeks ago, we did make that filing. And so, the process has started. And so, we anxiously await the Illinois Pollution Control Board's decision here later this year.

Did we ever find out why it took them so long just to come back and say, "You didn't file it appropriately." or you made some technical -- there were some technical problems?

David, I think the Illinois Pollution Control Board addressed that in the normal course of their procedures. And so, I wouldn't suggest that it was sort of a delay. They considered it. They made a decision. And so, we've been working with the Illinois EPA to -- in terms of making our amended filing. And so, I wouldn't suggest that they sat on their hands in any way. I think they just went through the normal course of business.

Okay. All right. Well, thanks, guys.

Thank you. The next question is from Jeff Coviello from Duquesne Capital. Please go ahead.

Hello?

I'm sorry. That has disconnected. We'll come back to Mr. Coviello. The next question is from Reza Hatefi. Please go ahead.

Thank you. Would you also happen to have a forecasted unregulated generation number for 2010? I think 2009, you said 30 terawatt hours.

At this time, we're not providing any guidance beyond 2009 in terms of generation levels. We'll be able to give some more color when we come back to you in the spring at analysts day. But at this point, we're sticking with just our 2009.

Okay. And how about percentage hedged for 2011 for power? Is that available now or --?

At this point we're not providing the specifics. But certainly, when you look at -- we already had the swap out there, which we entered in to sometime ago, and that was probably approximately 25% of the overall generation, under historical generation levels. But beyond that, no, we're not providing any other guidance for 2011, at this point in time.

Okay. And back at EEI you had -- I think you also had spoke about this today a little bit. You had forecasted $50 to $100 million of operating expense reductions, I think, at the unregulated operations for 2009. Is that still the range? Is that still good for O&M cuts, $50 to $100 million? And it is better to -- is that a cut versus 2008 levels, or is that an elimination of expected higher O&M that's no longer there in '09.

Sure. Well, with regard to the guidance we gave you, we -- those reductions were achieved in the unregulated generation business. In terms of eliminated versus deferred, I think frankly, it's a combination of some of those. Depending on certain of the capital expenditures, which obviously drive some of the O&M as well. But I don't have a specific break down as to which of that would be entirely eliminated prospectively versus what may show up in the later years.

Okay. And do you happen to have a -- formulated a new estimate of sorts regarding environmental CapEx going forward? Some of that is still up in the air with the Illinois issues but is there any update on that at all?

in terms of the overall environmental, what we will do, certainly at the end of this month, we'll provide the information in our 10-K that will outline our five-year capital expenditure plan. And we'll have some insight in there in terms of environmental. And reflected in there, will be some color around the various issues that we've talked about. Including, not just the Illinois Pollution Control Board, but obviously, Care has been reinstated. So we'll have to reflect those provisions in our guidance, as well as other rules associated with the Illinois EPS rules and regulations. We'll be able to give you some more color here very soon on that. And certainly, when we come back to you at our analysts meeting, we'll be able to give you even more in-depth discussion around that.

Thank you very much.

You're welcome.

Thank you. The next question is from Mr. Jeff Coviello. Please go ahead with your question.

Jeff, are you there? Jeff, we're obviously having phone connection problems with you because if you're speaking, we obviously can't hear you. So operator, if you can go to the next question, please.

Thank you. Mr. Coviello's line has now disconnected. I do apologize. The next question from Michael Lapides from Goldman Sachs. Please go ahead, sir.

Just a couple of just CapEx related questions. Can you just refresh our memories, which coal plants on the non-reg side you're scrubbing in 2009 and adding SCR's to?

In 2009, we're scrubbing Coffeen plant and Duck Creek plant. And SCR's, we've already added at Coffeen. Any others? I don't recall any other SCR's. I think that's it.

And how long are are the outages at each plant, as you're finishing up installing the scrubbers, just on average?

I can't give you a precise number but it's in the range of 12 weeks to tie in the scrubber for the final operation.

Got it. And when we think about the Illinois requirements that exist today, regardless of, assuming current rules, no variance, which of the plants that have to be scrubbed or have SCR's on them by 2013 or '14?

The Newton plant and the Edwards plant and those are the two that we asked for a variance from the Illinois Pollution Control Board, in order to move those out into the later years. And I still am fairly confident that we'll get that. But in the meantime, we've moved that capital requirement back into the earlier years. And so, it is reflected in our current capital estimates for '09 -- beginning in '09.

Meaning that you've got, in your '09 CapEx guidance, some CapEx related to putting scrubbers on either or both Newton and E.D. Edwards that may actually get pushed out if you get the variance?

That's correct it's in '09, '10 and '11 currently and it would get pushed out beyond that time period if we get the variance.

Got it. Okay. Thank you, guys.

Thank you. The next question is from Steve Gambuzza from Longbow Capital. Please go ahead.

Good morning. Following up on Michael's question, what exactly is the non-regulated CapEx guidance for 2009?

Sure. Why don't I try and actually just give the specifics for all of the segments because my guess is that that's of interest to the entire group. In general, the Missouri regulated segments will have capital expenditures of about $835 million. The Illinois regulated segment is right around $440 million. The unregulated or non-rate-regulated generation segment is around $400 million. And then, we have other capital expenditures of approximately $10 million, which should bring you very close to the numbers that we have identified for our capital expenditures of approximately $1.7 billion.

Okay. And Coffeen and Duck Creek, will those scrubber installations be completed in 2009?

Duck Creek is being completed now. And Coffeen is in early 2010.

Okay. Will -- what percentage of Coffeen's capital cost will be completed by the end of 2009? Will it be substantially complete in terms of the capital spending?

I would say, most of it will be done by then.

So the remaining -- could you give a sense for how much of the $400 million is related to the E.D. Edwards, Newton, potentially starting that project? That CapEx seems like it has the potential to go away, should you be successful in your filing.

I think with regard to -- is your question -- the Coffeen and Duck Creek are moving forward.

Yes.

So your question relates to Newton and Edwards. I think, with regard to 2009, that number probably ranges between $30 to $50 million, that can be moved out as a result of that. The bigger impact for those, frankly are in the '10 and '11 time period.

Okay.

Okay?

And is the non-environmental maintenance-related CapEx at the non-reg, is that in the kind of $50 to $100 million range?

I'll tell you, in terms of when you look at unregulated generation, you look at the discretionary CapEx or the non-environmental CapEx, that has been taken down very meaningfully in terms of where they're at. So, I'm not sure -- it's something less than $100 million in terms of --.

$100 million would be a more normal number. I think it's in the $20 to $40 million range.

Okay. So, it looks like there's roughly $300 million in 2009 for finishing Coffeen and Duck Creek?

Yes, I think in terms of the specifics, I think we can come back to you in terms of what those specific projects are in terms of '09. I think to say, that that's exactly that number, I think I'd like to hold off on that and then we can provide some more guidance to you on that specifically, later.

Okay. And your point about the non-regulated O&M expense reductions of $50 to $100 million, that is embedded in your 2009 outlook and that's not necessarily a $50 to $100 million sequential decline, right? It is versus what your old plan was? Is that the right way to think about it?

Well, I think when you look at the $50 to $100 million, that is in our plan, number one. And then two, when we talked about that before, is when you looked at the overall OEM expenditures compared to '08 levels, those were the kind of numbers we were trying to achieve, and we did.

Can you give a sense for sequentially, what that means of what '09 non-reg O&M would be sequentially versus where '08 came out?

Boy, in terms of the top, I do not have that off of the top of my head in terms of what that would be. I'm sorry.

Okay. And then finally, at your 2008 analysts day, you provided an outlook on estimated fuel costs for the non-reg business, as well as your hedge position, which has been substantially filled out, particularly -- essentially all in 2009. And the 2010 piece with the signing of the transpor. contract has been substantially filled out. And at that time, you forecast non-regulated fuel costs to rise by $2 a megawatt hour in '09 versus '08. And then, a further $2 a megawatt hour in 2010. This seems -- this is obviously very important information. I was wondering if you could provide any additional color on that now? Or if not, should we, at least think of those increases as still being in the ballpark of what you've locked in?

Sure. I think what we can provide you is '09 versus anything beyond that. Because consistent with what we've said, we're going to stick to our '09 numbers and then provide the other information in an appropriate fashion either at analysts day or even later. But when you look at '09 for the unregulated generation, we expect those fuel costs to come in around $23 per megawatt hour, roughly, for 2009, which is up a little bit from what I think we were at analysts day.

And what was the driver of that? Was it just the potential -- was it -- can you comment on what diverged in terms of driving those costs higher?

Well, I think number one, we had some more environment requirements in terms of what we had to do to increase those costs. So, that was part of that increases. I think, in terms of where we ultimately landed, remember, we still had some of the transportation costs. But then the other piece, remember we had, and we talked about this during the year, was the Exxon contract termination. Remember, we said that we picked up the entire gain.

Okay.

And we said that was going to be about $0.08 per share in 2009 that would drive those costs up. And so when you look at that --.

So, you booked a gain in '08, reflecting that cost increase in '09, essentially?

That's correct. So, it isn't an apples to apples comparison. So, that's one of the bigger drivers. And that's probably $25 to $30 million.

Pre-tax.

Yes.

Okay. That's very helpful. And then you're --?

Just to be clear, Steve, do remember, we did get paid for that.

Yes, understood.

We did get paid for that.

So that's -- you received the cash in '08 related to that.

That's correct.

And then, your financing plans, $500 million at the gen-co. Clearly credit markets have improved and there's kind of a window now that exists, are you -- but it seems like this -- how knows how long this window will last. Could you comment on what part of the year you might consider doing that gen-co financing?

As I said in my talking points, in terms of our overall financing plan, whether it be debt, equity or indirectly; we're going to be opportunistic and proactive in accessing the markets to finance our plans, including looking at this unregulated generation financings. Certainly, we strongly believe that the actions that we've taken in terms of, not just capital expenditure reductions, but also the action that we took with regard to the dividend, obviously, is credit enhancing. And will give us greater ability to execute all of those financings, not just in 2009 and beyond. So in terms of timing, I think that, as you point out, we will watch carefully the markets, we'll access it when we believe it's appropriate to get reasonable terms to get that across the finish line.

Well, it is fair to say, you'd like to get the Illinois Pollution Control Board situation resolved before proceeding with that financing?

That's a factor. Certainly, it's a factor. To say that is the factor and the only factor, that would not be appropriate to say that.

Okay. Thank you for your time.

Thank you. The next question from is Zach Schreiber from Duquesne Capital. Please go ahead with your question.

I'm going to try this again, can you guys hear me?

Yes, Zack.

It is actually Jeff. How are you?

Jeff, I'm sorry.

Good morning. Sorry about that. I don't know what happened. I wanted to ask two questions. The first is on the strategic review of the coal plants you mentioned earlier in the call. I just wondered if that encompassed all of the units or if you're only really looking at the small ones? Or if it could, in fact, be the whole segment? And the second question just has to do with 2010 hedging. And I realize you're not going to give out an exact number. But is it -- should we think of it as being above the 2009 number, as far as the price you hedged at or below it?

I'll address the second question and I'll let Gary tackle the strategy one here in a moment. In terms of the other, I really don't want to give sort of a leaning one way or another. It just wouldn't be appropriate at this point in time. I will say, as we've said in the past, that we were aggressively trying to hedge out some of those positions in those outer years. Obviously, as you know, the liquidity in those markets began to dry up. more so as the year went on in 2008. But we had put some of those positions on earlier, as you, even saw in some of our earlier presentations, in terms of where our hedge percentages. So we'll be able to give you some more of that insight. As well as the thing that will be helpful when we talk more will be, obviously, the RFP process, which is going to be taking place in Illinois. Here, first half of this year, probably here sometime in the second or third quarter. And so, that will be instructive too in terms of not just '10 but also some of the years beyond.

Got it.

We'll be able to get you some of that. And now, I'll let Gary comment a little bit more on the final strategies and thinking around the unregulated generations plants.

Yes, Jeff, as far as the strategic review, we still believe that our merchant generation business is a good complement to the regulated business. It just is not a business, though, that we can count on to pay the dividend year after year because of the volatility of the commodity cycle. But a good point to note, though, is that even with this downside market that we're seeing now, which is probably the worst recession that the US has experienced in 40 or 50 years and the severe down commodity market, we're weathering this reasonably well. We do expect to see an earnings decline this year and soft earnings for a couple of years. But we expect this business to remain positive and be a good earnings contributor to our Company long term. The strategy, though, that we're kind of moving to and with the reduced dividend, is the ability to pay the dividend from the regulated businesses. And as the earnings in the regulated businesses grow, we would hope to grow the dividend in the future. And we have materials, in fact, included in our materials -- you can see that with the increase in earnings this year of $1.75, we're able to fully cover the dividend from our regulated businesses.

Got it. And so, on the non-reg strategic review then, is just looking at individual assets, maybe some smaller assets?

It's a more an asset tempt to focus the business and our major assets, workhorse assets are going to continue to be money makers for us. The smaller units, really, could be more effectively owned and operated by smaller companies.

Got it. Okay. Thank you very much.

Thank you. The next question is from Mr. Scott Engstrom from Blenheim Capital. Please go ahead.

Thank you. Good morning. A question on slide 11 and 14. On 11, you have the segment guidance and on the non-rate-regulated '08 was $1.59. And the midpoint of '09 would be $1.20. So call that, in round numbers, $0.40 delta year-over-year. And then on slide -- and these questions have kind of been asked in different ways but maybe it will be more direct. Slide 14, you show specifically $0.05 from margin. I'm just trying to pick up the other $0.35. I think what you've said is dilution is -- of that dilution of $0.23, $0.12, is that regulated? So I assume $0.11 is non-regulated, is that right?

Yes. I think that the answer was $0.23 was the dilution of which -- yes. I won't repeat you. I think you've got that accurate.

And you said, substantially, a large portion of the pension would be non-reg. So if I said that was $0.06 that gets me -- those three items would get me to $0.22. Can you help fill the gap on where the other $0.18 is?

If I can try and answer your question. I think that on the pension on the OPEB, I wouldn't say substantial, obviously a piece of that is part of the Illinois regulated operations, as well. And then in trying to fill the rest of the gap, I think you've got the depreciation and amortization is a meaningful number in there too. And a piece of that is not just the regulated operations but a part of that will also be the unregulated.

Okay. All right. That's $0.15 in total. I assume only -- maybe a 1/3 of that is unregulated. Is that going to be ballparkish?

I think that -- again, Marty, do you have any more specifics on that break down?

I don't have the specific but I actually think the depreciation and amortization may be closer to 50% non-rate-regulated.

Okay.

Some of the projects we discussed earlier, like the scrubber project at Duck Creek, when those types of assets go into service, we'll be using sort of a higher depreciation rate, I'd say, on those, than some of our historical plants.

And I think, Scott, you look at, for instance, the other taxes. You start picking up cats and dogs. And you probably have $0.03 to $0.04 of those other taxes relate to some incremental property taxes we expect to incur at the unregulated generation segment. So, I think that you start picking up those pieces here and there, you start getting closer to that reconciliation. We can -- again, in terms of the analysts day, we can provide more substantive reconciliations, if that would be helpful for you to identify or to try to reconcile the numbers on a segment-by-segment basis.

Okay. And then will be -- I'll look forward to that. And if I focus just on the dilution line, the say $0.11, just back of the envelope, that's about $30 million pre-tax. Does that come from, essentially, financing negative free cash flows? Or is that related to higher financing costs? How do you break that down between new financing and higher rates?

I think it's really a combination of both of those. We're going to refinance some existing debt, which is out there, as we've laid out in the slide. Coupled with the fact that, yes, we are experiencing negative free cash flow. We talked about the negative $500 million of cash flow on an Ameren basis. And so, as we've said, we're going to be out there issuing approximately $500 million of unregulated debt financings. And our plan is for 2009 and that is the combination to replace lower costs debt, which is existing -- which is outstanding already, but also to access the markets to finance our existing operations.

Last question. Just trying to think about the impact of implementing the fuel clause at Missouri. If I look at on slide 14, the $0.39 impact of the rate case, does that -- that picks up, I assume the uplift from getting the fuel clause? And is the $0.06 of other electric and gas margin negative, the $0.06 negative, does that capture losing some of the off-system sales then? Is that how I should think about it.

This is Marty. Let me try to help you with that. I think in terms of, any Missouri rate case that -- what that $0.39 is, is really the rate increase that we got, which is about $162 million, less the amortizations we talked about on the call, of about $12 million. And then it's about 10 months of that. That gives you the $0.39. So it doesn't incorporate the switchover to the FAC. That amount is buried down there, if you will, in the $0.06 of negative regulated electric and gas margins. And what you see down there, is both the change and the January and February margins year-over-year from '08 to '09, prior to the rate increase going in to effect, and the FAC going in to effect. It also incorporated the impact of moving from no FAC to an FAC.

And as we've provided you, I believe it was on slide 15, where we give you the breakdown of the -- what was in our 2008 actual income statement in terms of fuel costs and off-systems sales, which was $277 million, versus what was included in the rates that the Commission granted, which was $328 million. That's a delta of about $51 million. And that's actually on slide 9. I apologize. I think I directed you to the wrong slide. But that $51 million increase is included in the rate increase granted by the Commission. So you would actually, to figure out the impact, again, take 10/12 of that for the 2009 impact, which is about a $42 million 2009 increase in fuel expense, that's embedded in the $162 million increase that the Commission granted. So, what you're seeing down there is those two items, the 2009 fuel cost increases, the change in the January and February margins. And then that's being partially offset by load mix changes and other elements of margin that aren't included in the FAC.

Vivian, we have time for one more question.

Okay. Thank you very much. The next question from Phyllis Gray from Dwight Assess Management. Please go ahead.

Good morning. Could you tell me if the cash flow forecast on slide 16 reflects the Noranda outage impacts?

I'm sorry -- could you -- we didn't hear that, could you say again, please?

Can you hear me better?

Yes, that's much better. Thank you.

Does the cash flow forecast on slide 16 reflect the outage at the Noranda plant?

The cash flow forecast? No it does not. It does not reflect that.

Okay. Thank you. And I'm sorry if I missed it. Did you talk about any need for a cash contribution to your pension plan this year?

No, we haven't addressed that. But our practice is to make a cash contribution equal to the expense. So even though we would not have a required contribution this year, we would plan to make a contribution equal to the expense for the pension plan.

Okay. And is that included in your cash flow forecast on slide 16?

Yes, it is.

Very good. Thanks very much.

You're welcome. We would like to thank you all for participating in this call. Let me remind you again that this call is available through February 24 on playback and for one year on our Website. The announcement carries instructions on listening to the playback. You can also call the contacts listed on our news release. Financial analysts inquiries should be directed to Doug Fischer. Media should call Susan Gallagher. Doug and Susan's contact numbers are on the news release. Again, thanks for dialing in.

Thank you, ladies and gentlemen. And as said, this conference will be available for replay after 9:00 a.m. Mountain Standard Time today until February 24, 2009 at 23:59 Mountain Standard Time. Thank you, that does conclude our conference for today. Thank you for your participation. You may now disconnect.