阿莫林 (AEE) 2009 Q4 法說會逐字稿

Greetings, and welcome to the Ameren Corporations's fourth quarter and year end call. At this time all participants are in a a listen only mode. (Operator Instructions). As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Mr. Douglas Fischer, Director of Investor Relations for Ameren Corporation. Thank you Mr. Fischer, you may begin.

Thank you and good morning. I'm Doug Fischer Director of Investor Relations for Ameren Corporation. On the call with me today are our President and Chief Executive Officer, Tom Voss and our Senior Vice President and Chief Financial Officer, Marty Lyons, as well as 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 contained 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 at www.Ameren.com.

This call contains time sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. To assist in our call this morning, we have posted presentations slides on our website that we will refer to during this call. To access this presentation, please look in the investor section of our website under webcast and presentations and follow the appropriate link.

Turning to slide two of our presentation, I need to let you know that comments made in 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 in the forward-looking statements. For additional information concerning these factors we ask you to read the forward-looking statement section in the news release we issued today and the forward-looking statements and risks factors section in our periodic filings with the SEC.

Tom will begin this call with an overview of 2009 and 2010 earnings guidance, followed by a business and regulatory update. Marty will follow with a more detailed discussion of our 2009 financial results, our 2010 earnings guidance and a financial update. We will then open the call for questions.

Here is Tom.

Thanks, Doug. Good morning and thank you for joining us.

Moving to slide three of the presentation posted on our website, I'm pleased to report that 2009 non-GAAP or core earnings were $2.79 per share in line with our expectations. Key drivers fairly affecting 2009 core earnings per share compared to 2008 results included new utility service rates in Illinois and Missouri and lower operations and maintenance expenses. These lower expenses were due in part to the absence in 2009 of a refueling outage at the Callaway nuclear plant and proactive cost cutting effort across all of our businesses.

These positive factors were more than offset by lower electricity and natural gas sales in our regulated utility businesses as a result of weak economic conditions, the Noranda outage, and milder 2009 weather. Merchant generation margins were also hurt by higher fuel costs and less generation being in the money. High depreciation and interest expense at an increased average number of common shares outstanding further affected comparative results.

Turning to slide four, today, we announced 2010 GAAP and core earnings guidance of $2.20 to $2.60 per share. The expected decline in 2010 earnings from 2009 primarily reflects lower projected merchant generation segment margins and earnings. While earnings of our regulated utilities are expected to improve, regulatory lag is anticipated to result in earnings lower than those authorized by state commissions. Marty will provide details on our 2009 and 2010 guidance in his remarks. But, before I turn the call over to him, I would like to provide a business and regulatory update.

Looking now at slide five, in electricity sales that are regulated utilities, it is clear that the economy drove our sales down in 2009. While 2009 was indeed a difficult year, there are signs that the weak economy has hit bottom in our region. In a positive sales development, the Noranda Aluminum smelter plant has continued to add to its load as the plant moves towards returning to full capacity. You may recall that Noranda's New Madrid, Missouri smelter plant, AmerenUEs largest customer sustained damage because of a power interruption on nine Ameren-owned power lines during a severe ice storm in January 2009. As a result, the smelter's load was sharply reduced, but has been rising steadily as repairs have been made to their production lines, with full production expected to be released early in the second quarter of this year. In Illinois, our industrial sales are expected to benefit significantly from the expansion of an oil refinery and the resumption of higher levels of operations at several other facilities. While increased industrial sales in Illinois will not significantly contribute to margins, the health of local businesses is certainly a key to the prosperity of all of our customers.

Moving onto the regulatory front, we have rate cases pending in both of our Illinois and Missouri jurisdictions. We are seeking revenue levels that reflect the significant investments we have made in electric and gas utility infrastructure to improve reliability. We are also seeking recovery of higher financing costs and in Missouri rising net fuel costs. As detailed on slide six, our Ameren Illinois utilities are currently requesting $130 million annual increase in base electric and natural gas delivery rates. This amount is less than our original request of $226 million due in part to the removal of revenues related to reliability audit expenditures. We are now seeking recovery of these costs in a separate rider.

The lower rate also reflects updates to our requested rates of return on equity and other items. The staff for the Illinois Commerce Commission or ICC is currently supporting a $46 million annual revenue increase; the staff's lower revenue amount reflects their lower recommended return on equity of approximately 10.1% compared to our request of approximately 11.5% and use of a lower pension and benefits expense level, among other things. ICC administrative law judges are scheduled to issue their proposed rate order by February 25 with the ICC expected to issue an order in late April. New rates should be effective by early May 2010.

Turning to slide seven at AmerenUE we filed a request with the Missouri Public Service Commission in July of 2009 for an annual electric service rate increase of $402 million. More than half of the request was for anticipated higher net fuel costs. These increased net fuel costs would have been eligible for recovery through the fuel adjustment clause, absent this filing. On December 18th the staff of the Missouri public commission filed a direct testimony in the rate case recommending an annual electric service rate increase of $218 million to $251 million with approximately $214 million of this related to higher net fuel costs. The staff's lower revenue amount reflects their recommended return equity range of 9% to 9.7% which was lower than our initial request of 11.5%.

Staff's revenue amount also incorporated lower depreciation, lower plant maintenance, and financing cost levels, as well as other adjustments. The staff testimony reflects continuation of the current fuel adjustment clause and the pension and OPAB trackers and a modified environmental cost recovery mechanism. Other parties filed testimony in December, including a group of large industrial customers and the Office of Public Council. The Office of Public Council recommended a return on equity of 10.2%, the large industrial customers recommended a rate increase of $139 million which included $181 million increase related to net fuel costs. Their lower revenue requirement reflects their lower recommended return on equity of 10%, the use of significantly lower depreciation rates and plant maintenance expenses as well as lower financing costs and consumption levels, among other things. It should be noted that the large industrial customers' testimony reflects continuation of the current fuel adjustment clause, as well as the modified approach for the counting and recovery of environmental costs. Last Thursday AmerenUE filed its rebuttal testimony in this case which included, among other things, a modification of its originally requested ROE down to 10.8%. We anticipate that certain major changes to revenues, expenses, rate base and capital structure will be trued up through January 31, 2010 in an early March update. A PSC order is expected by late May with new rates effective in late June 2010.

We are very aware that the prospect of higher utility rates is difficult for our customers in Illinois and Missouri, especially in this economic environment. We have taken many proactive steps across our Company to control our costs in order to moderate the need for higher rates. These steps include reductions in planned operating and capital expenditures, headcount reductions, and the freezing of management's salaries. As always, there are several issues which need to be carefully considered in these rate cases, some of which are rather complicated. We believe we have filed well-supported rate cases in both Illinois and Missouri and expect to be treated fairly by the respective commissions. Parties in both states have filed very aggressive positions in a number of areas, including return on equity, depreciation, and certain operating expenses. These aggressive recommendations are not consistent with sound long-term energy policy and would result in our need to reduce our level of investment in energy infrastructure and operations. For several years, our regulated utility businesses have been earning returns on investments that are well below our authorized levels in part due to regulatory lag. We are committed to improving earnings to levels that represent fair returns on our regulated investments. We strongly believe that consistent constructive regulatory outcomes will allow us to achieve this objective, as well as continue to invest in our energy infrastructure on a timely basis in order to maintain reliability consistent with our customer's expectations.

I would like to shift from a discussion of our regulated utilities to an update on our merchant generation business. Currently power prices are low, a condition very much linked to weak economic conditions. Weak economic conditions have reduced the demand for power and other energy commodities. We believe that when the economy recovers, and we expect it to recover, these prices will rise. In the meantime, we continue to look for every opportunity to prudently reduce our operating and capital spending in this business as well as protect and enhance margins. We have a consistent practice of hedging both our power sales and our fuel costs. As a result, our margins were well-protected in 2009 and we have a solid base of sales hedges for 2010 and out through 2012 at prices that are above current market prices. Such hedging protects credit quality and reduces earnings and cash flow volatility. In addition, we continue to focus on providing value added electricity products to the market.

Leveraging our competitive merchant generation assets, our experienced power marketing group has a track record of enhancing margins through sales to wholesale and retail customers. Strengthening our ability to successfully weather the current price environment,we have reduced planned operating and capital spending, substantially improving the cash flow outlook for our merchant generation business. Turning to slide eight, those action have included updating and refining our strategy for compliance with current environmental standards. Most of you recall that our merchant generation business reached an agreement with the Illinois Environmental Protection Agency in 2006. This agreement was ultimately adopted by the Illinois Pollution Control Board as a compliance alternative to the Illinois mercury regulations. These regulations, which were modified in 2009, require our merchant generating plants to reduce emissions for sulfur dioxide, or SO2, nitrous oxide, or NOx, and mercury over a number of years. The nitrous oxide emission standards phase in through January 1, 2012 and the sulfur dioxide emission standards phase in through January 1, 2017. The mercury removal efficiency requirements are deferred until January 1, 2015.

NOx and SO2 compliance are determined on a system-wide base. As you know, in 2009 we reduced our anticipated non-environmental capital spending in the merchant segment by approximately $1 billion over the period of 2009 to 2013. Because of the excellent performance of recently installed scrubbers at our Duck Creek and Coffeen plants, which are achieving removal rates beyond those contemplated in our initial plans, we have been able to re-evaluate and improve our compliance strategy. As a result of this performance and updated cost experience, our estimate of capital expenditures required for compliance with existing air emissions standards for our merchant generation fleet has been reduced. We now expect these expenditures will cumulatively be between $1.2 billion and $1.5 billion over the period of 2010 through 2017. Our previously disclosed range of comparable capital expenditures was $1.5 billion to $2 billion. These estimates of our capital spending required to comply with regulations as of December 31, 2009, and would allow for each of our merchant coal fired power plants to remain in service beyond January 1, 2017. As you would expect, we have teams in place that continue to evaluate our plans in light of changing technologies, power prices, and delivered fuel costs in order to ensure that we identify the lowest cost options in terms of both capital and on-going operating costs.

Over the next two years our environmental capital expenditure plans are moderate. We will use this time to continue to continue to evaluate our plans, looking for any opportunity to reduce compliance costs. Over the past 18 months we have reduced pay incentives, head count, and investment across the Company to mitigate the negative impact on sales of a weak economy and related lower power prices. We have also enhanced our financial strength and liquidity position. Our regulated utilities are controlling spending and seeking updated rates to recover our costs and earn fair returns on investment. I believe that our actions have established a solid foundation for executing on future strategies and creating long-term shareholder value.

While we expect earnings per share to decline in 2010, we expect earnings from our regulated businesses to improve over time as a result of narrowing the gap and investing in improving reliability and promoting a cleaner environment. Our merchant generation business is poised to benefit from an expected eventual recovery in power prices. Further, I believe the Ameren common shares provide investors with an attractive and sustainable dividend supported by our rate-regulated utility earnings.

I will now turn the call over to Marty to walk you through the details of our 2009 earnings and 2010 earnings guidance.

Thanks, Tom.

Turning to slide nine, I would like to direct you to the year column, which reconciles 2008 earnings to 2009 earnings. 2009 net income in accordance with Generally Accepted Accounted Principles was $612 million or $2.78 per share, compared to 2008 GAAP net income was $605 million or $2.88 per share. Excluding certain items in each year, Ameren reported 2009 core net income of $615 million or $2.79 per share, compared with 2008 core net income of $622 or $2.95 per share. There are three items in 2009 that we have excluded from our core earnings. These are the net costs associated with the Illinois comprehensive electric rate relief and customer assistance settlement agreement reached in 2007, which reduced 2009 GAAP earnings by $0.08 per share. The net affects of unrealized mark-to-market activities which increased 2009 GAAP earnings by $0.14 per share and employee separation and impairment charges related to our head count reduction and facilities closures, which reduced 2009 GAAP earnings by $0.07 per share.

Continuing with the 2008 to 2009 earnings reconciliation on slide nine, the Missouri electric rate increase which took affect March 1st, 2009 raised 2009 earnings by $0.40 per share net of amortizations compared to 2008. The net increase in Illinois electric and natural gas delivery service rate, effective October 1, 2008 lifted 2009 earnings by $0.40 per share compared to the prior year. We estimate milder weather reduced 2009 earnings by $0.15 per share, compared to 2008 and by $0.13 per share compared to normal.

Moving to the next slide in our year-to-year reconciliation, reduced sales to Noranda Aluminum lowered 2009 earnings by $0.11 per share. Other electric and gas margins for our regulated utility operations, excluding the impact of rate adjustments, weather, and the lost Noranda sales, decreased earnings by $0.30 per share. As Tom discussed earlier, this decline in margin was largely due to lower electric and natural gas sales volumes as a result of the weak economy. The next line on the reconciliation is a $0.10 per share decline in our merchant generation segments earnings, reflecting the absence in 2009 of the gain recorded in 2008 for a lump sum settlement payment received from a coal supplier related to a contract termination. Other electric margins for the merchant generation business decreased by $0.05 per share in 2009 compared to 2008. This merchant generation decline was largely due to having less in the money generation and higher fuel and related transportation costs, offset in part by improved realized revenue per megawatt hour.

Proactive forward sales and hedges of 2009 generation executed in prior years at higher than 2009 market prices largely shielded merchant generation segment earnings from the impact of falling market prices for power. The absence of a refueling and maintenance outage at the Callaway nuclear plant boosted 2009 earnings by $0.09 versus the prior year. You will recall, the Callaway is typically re-fueled every 18 months so there is no refueling outage every third year.

The next three lines are reconciliation combined to reduce 2009 earnings by $0.02 per share compared to 2008. This reflected higher distribution system reliability spending and higher depreciation and amortization expense offset by lower plant operations and maintenance expense. Higher financing costs and share due solution reduced 2009 earnings by a combined $0.31 per share versus 2008.

Moving now to the other taxes line on the reconciliation, where higher property taxes contributed to a $0.06 per share increase in costs versus the year ago period. Finally the net impact of other debt items, including the lower bad debt and non-plant operations and maintenance expenses increased 2009 earnings per share by $0.05 per share compared to 2008.

Turning to slide ten, I would like to discuss the key assumptions and drivers behind our 2010 core earnings guidance of $1.90 per share $2.15 per share for our Missouri and Illinois regulated utilities businesses. In 2010, we expect to achieve returns on equity of approximately 7.5% to 8.5% on average expected 2010 utility common equity of about $6 billion. These returns are anticipated to be up from an average 2009 returns on utility common equity of approximately 6.5% to 6.8%. The guidance for our regulated utilities reflects expected new Illinois electric and gas delivery rates effective in late April or early May and expected new Missouri electric rates effective in late June.

Further, our guidance assumes some moderate electric sales growth. The sales outlook incorporating our expectation that the Noranda smelter plant will return to full operation early in the second quarter of 2010, adding an estimated $0.10 per share to earnings compared to 2009. Note that 2010 earnings per share guidance variances versus 2009 are calculated using 2009 average common shares outstanding. As usual, guidance is based on normal weather which would add an estimated $0.13 to earnings per share versus the milder than normal 2009. In addition, the Taum Sauk pump storage hydroelectric facility is expected to return to service in the second quarter of 2010 improving margins by approximately $1.8 million per month. The scheduled spring refueling maintenance outage at the Callaway nuclear plant is expected to reduce 2010 earnings by $0.09 per share compared to 2009. 2010 earnings guidance incorporates higher expected plant operations and maintenance expenses, primarily for scheduled work at AmerenUE's coal fire plant. Pension and benefit, depreciation and other tax expenses are also expected to increase in 2010 versus 2009.

As I wrap up my discussion of 2010 guidance for our regulated utilities, let me be clear that the return on equity of 7.5% to 8.5% assumed in our guidance is well below the level we consider to be reasonable. As Tom stated earlier, our management is committed to lifting the return on investment at a regulated utilities to levels that are fair. For every 100 basis points by which our regulated utilities under-earn their allowed returns on equity, our shareholders are deprived of earnings of approximately $0.25 per share. We believe that given the current regulatory frameworks in place in Illinois and Missouri, achieving these higher returns will not be accomplished in one rate case proceeding. We are focused on achieving fair returns by pursuing consistent, constructive regulatory outcomes, including mechanisms that reduce regulatory lag as well as synchronizing our spending consistent with the level of rates authorized by the respective commission.

Turning to slide 11, lets now move to a discussion of the key drivers and assumptions behind our 2010 merchant generation business earnings guidance. We expect this business segment to post core earnings of $0.30 to $0.45 per share in 2010. The largest driver of the decline in merchant generation business earnings from 2009 to 2010 is a decrease in expected margins of $0.70 to $0.80 per share. We expect our base load merchant plants to generate approximately 30.5 million megawatt hours in 2010, approximately 26 million megawatt hours is hedged at an average price of $47 per megawatt hour.

Our expected margins assume that all non-hedged expected generation is sold at current market prices. In 2010, we anticipate having base load capacity available to generate 35 million megawatt hours in the event that power prices rise and support a higher generation levels. A $5 per megawatt hour improvement in 2010 market power prices as compared to current prices would increase our expected 2010 generation output by approximately 1.5 million megawatt hours and our expected 2010 merchant generation margin by approximately $30 million. Our all-in base load fuel costs are 100% hedged at approximately $23.25 per megawatt hour. Lastly, the merchant generation business is expected to post higher depreciation and interest expense in 2010 compared to 2009.

Moving now to key Company-wide assumptions our earnings guidance reflects an expected effective consolidated income tax rate of approximately 34% and average number of common shares outstanding of approximately 239 million for 2010. As I close our discussion of 2010 earnings guidance, I remind you that any net unrealized mark to market gains or losses will affect our GAAP earnings but are excluded from our GAAP and core earnings guidance because the Company is unable to reasonably estimate the impact of any such gains or losses. Further, our earnings guidance for 2010 assumes normal weather for the year and is subject to, among other things, regulatory decisions and legislative action, plant operation, 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 statement section of today's press release.

Turning now to slide 12, I would like to report on our 2009 and projected 2010 cash flow. A year ago we shared with you that we expected 2009 negative cash free flow, defined as cash flow from operations less capital expenditures and common dividend of approximately $450 million. I am pleased to report that we were able to achieve markedly better results. This significant improvement was the result of curtailed spending and cash tax savings, including deferral of tax payments as a result of bonus depreciation. As we look to 2010, despite expected reduced earnings we anticipate that free cash flow from our merchant generation segment will be positive, allowing us to reduce outstanding borrowing. We anticipate that our regulated utilities will continue to generate negative free cash flow, although at reduced levels, while providing funding for our current dividend. In summary we anticipate that Ameren on a consolidated basis will require minimal net additional capital from external sources during 2010. We ended 2009 with approximately $1.9 billion of total available liquidity. That was comprised of cash on hand as well as available borrowing capacity under our revolving credit facility. Our debt maturities in 2010 are a very manageable $220 million.

Before we conclude our formal remarks, I would like to share with you some additional numbers to assist you in assessing Ameren's longer term outlook. On slide 13, we detail Ameren's updated five-year capital expenditure outlook. Over the 2010 through 2014 period, cumulative capital spending is projected to range between $6.3 billion and $8.1 billion and between $1.1 billion and $1.7 billion per year. These spending levels reflect reductions made to planned spending in both the regulated utility and merchant generation segment of our business.

On slide 14, we present our expected capital expenditures for our merchant generation business segment for each of the next five years. The amounts shown reflect lower than planned actual expenditures in 2009 and a reduction of $45 million in the years 2010 through 2013 versus estimates we shared with you at the Edison Electric Institute Financial Conference last November. These numbers are included in the total Ameren-wide capital expenditures I just mentioned. Our merchant generation business spending plan are particularly moderate this year and next year. Of course, we will continue to review and adjust as needed our merchant generation business spending plan in light of evolving outlooks for power prices, delivered fuel costs, environmental standards and compliance technologies, among other things.

Moving now to slide 15, we provide an update on our 2010 through 2012 forward power sales and hedges. As you can see, we have significant hedges in place for 2010 through 2012 at power prices above the current market. We already discussed our 2010 hedges. For 2011, we have hedged approximately 18 million megawatt hours at an average price of $49 per megawatt hour. Further, for 2012, we have hedged approximately 12 million megawatt hours at an average price of $53 per megawatt hour. Our capacity sales are approximately 75% hedged in 2010, approximately 40% hedged in 2011, and approximately 20% hedged in 2012. To assist you in understanding our merchant generation business segment's margin drivers, we have provided a pie chart that breaks down our 2010 expected revenue by type.

Turning to slide 16, we update our merchant generation segment's fuel and related transportation hedges. We previously discussed our 2010 hedges; for 2011, we have hedged approximately 20 million-megawatt hour at about $25.50 per megawatt hour. For 2012, we have hedged approximately 11 million megawatt hours at about $26.50. Similar to our previous slide dealing with merchant generation revenues, we included a pie chart that breaks down forecasted 2010 all-in fuel costs to provide a perspective on how each component contributes to our overall costs.

As Tom stated, our management team is extremely focused on meaningfully improving the returns at our regulated utilities and continuing to position our merchant generation business to weather current power market conditions and benefit from an expected eventual recovery in power prices. This completes our prepared remarks. We will now be happy to take your questions.

(Operator Instructions). Our first question from Paul Patterson with Glenrock Associates.

Good morning. Just to get a sense for what we are looking at in power prices in your region for 2011 and beyond when you look at the forward curve, what kind of neighborhood are we in with respect to that? Could you give us a little bit of a flavor for that?

Sure, Paul. When we look at the power market, typically, as you probably know, we look at some of the Cin Hub prices and right now Cin Hub around the clock prices for 2011 are in the neighborhood of around $35 per megawatt hour.

Would it be on a basis differential on that? Is it close to that number?

There a couple of things that you want to remember about it. First of all, that is just the Cin Hub price as we talked about on the call. Typically, as we are out on the market we are looking for opportunities to enhance margins beyond the prices you see just at that Cin Hub through sales, through retail customers around the states that we operate in.

In terms of basis differentials, some of the things we have seen recently this past year, we certainly saw basis differentials widen out versus what we've seen in other periods when loads were higher. Essentially as the economy slipped and we saw demand drop off we saw some of the basis differential increase, it was on peak around our service territory in Illinois around 7% decrement on peak, the synergy, and 14% off peak this past calendar year. It it varies from region to region, if you go down to where our EEI Joppa facility is, it's actually better. The basis differential is positive there on peak and a little bit negative off-peak, about 6%.

As we have gone into 2010 planning, we have assumed similar kinds of basis differentials to 2009 as we look out to 2010. We would expect as you look out beyond st '11 and '12 we expect to see the basis differentials tighten up as the economy recovers.

Okay. The finally, on the discussion of getting to a better ROE. You mentioned you don't see this as a one time rate case catch up situation. You mentioned some efforts, obviously you guys are lowering CapEx there and getting a more timely recovery. If you could elaborate on that? What it is in the non-regulated compliance generation CapEx reduction, what you did there and why you are coming in with a lower number now?

Sure. Maybe we will take those out of order. We will talk about what we did in terms of capital expenditures on the merchant side of our business and I will let Chuck Naslund discuss that a little bit.

On the CapEx for our merchant business, if you look at slide eight that we covered, outlines basically in the State of Illinois what plants have to be scrubbed, which once are complete and which ones are yet to go. What you'll see there is we have remaining in order to meet all the compliance requirements in Illinois to scrub the two Newton units and to scrub three out of six of the Joppa units units.

And what the change was, because of the -- as Marty mentioned earlier -- the great performance of the first phase of scrubbers and removal rates has actually allowed us to remove scrubbers on Edwards units 2 to 3 which effectively removed $400 million to $500 million out of the 2010 through 2017 budget.

So emissions should be basically the same achievement with less CapEx, right?

That's correct.

The other thing I would add, as Marty mentioned, we're contending to look at other technologies and looking at ones that are perhaps higher O&M and much lower CapEx. We do have a breathing period year, 2010 and 2011. We finished our phase one scrubbers, we have a couple years before heavy investment needs to start on our phase two.

It gives us plenty of time as the technologies evolve to come up with alternative solutions, and I'm very optimistic that some of our smaller units, like our Joppa unit, that we will be able to come up with technologies and continue to work on reducing those CapEx expenditures.

Great. Thanks, Chuck, I appreciate that.

Paul on your other question in terms of reducing the amount of under-earning that we are seeing in our regulated businesses, obviously some of the things we have talked about over time, filing rate cases on a regular basis to make sure we are recovering our costs on a timely basis and earning fair returns, certainly seeking cost recovery mechanisms in the cases that we have pending. Those cost recovery mechanisms would allow us to recover our costs on a more timely basis, reducing the amount of lag that we have.

Those kinds of recovery mechanisms such as trackers or riders are helpful in terms of being able -- given an opportunity to earn your allowed return in your jurisdiction. We will be looking and making sure that we manage our spend appropriately and try to manage our spending to help close those gaps over time.

Before I leave the whole Q&A with you, Paul, you know I appreciate the questions. As it relates to basis differential, one thing I did want to mention, as we look at some of these basis differentials, it is really only a percentage of our volumes that are exposed when you look at something like 2010. Some of our hedges really do protect us from some of that basis differential. Of our total megawatt hours we have expected to generate next year of about 30.5, only about 35% of those are actually exposed to some of those basis differentials as I discussed before, so that helps to mitigate the impact of those basis differences.

Thanks.

Our next question is coming from Reza Hatefi with Decade Capital Management.

Thank you.

I guess one of the drivers on slide ten is an earned ROE of 7.5% to 8.5%. Is it fair to say because of the timing of the rate cases and when they go effective that in the first half of 2010, you will earn close to the ROE you earned in ' 09, which was 6.7% or something and then in the back half of 2010, you are expecting to earn roughly a 9%, which averages to about 8% of the year?

Is that the best way to think about that?

I won't comment on the specific earned ROE percentages in the first half and the second half, but your overall thought process is good. Until those rate cases come to a conclusion and we have rate adjustment, we expect in the first half of the year to continue to experience some of the regulatory lag that we did see last year. Again, I wouldn't comment on the percentages; there's certainly seasonal volatility and depending upon power plant outages, things like that, it could certainly swing those earned ROE percentages, but overall your thoughts are generally correct.

And then looking at slide 15, a follow-up on the hedge question from earlier. If I look at 2012 hedges, 12 terawatt hours at $53, if I remember correctly, about 8.7 terawatt hours of that is from the Illinois swap contract which I think was at $53. And then one terawatt hour is, at Legacy hedges, at $33, does that sound right?

That sounds right. The contracts we have in place and the swaps provide the base and I think you are right there about 8.8 million megawatt hours and some of the Legacy contracts do provide the remainder, which typically those contracts are with wholesale concerns or large industrial concerns are with wholesale concerns or large industrial concerns around the State of Illinois.

I guess I would also mention when you look out to 2011 and 2012 and you look at those hedges, the shaping of the hedges approximates the kind of profile you would see in around the clock kind of product. However, given the shape of the generation that we actually have available the unhedged megawatt hour are bound to a little more on peak than off; probably 55 on peak and 45 off peak which is also true for the unhedged megawatt hours for 2010.

Just on the hedged numbers, if 8.8 terawatt hours is $53 and one terawatt hour is $33, that implies the other 2.3 or so terawatt hours is about $61 or $62 backing into it. Are those with hedges that were layered on back in 2007 or 2008? It seems like a really nice price. When were those hedges put on?

Those contracts were put in place in prior years. I can't expect to the exact pricing on all the Legacy contracts, but your assumption is correct. They were put in place a couple years ago.

Have you started hedging 2013 yet?

Wouldn't comment on 2013, at this point.

Thank you.

Our next question with Carl Seligson with Utility Financial Experts.

I'm, as usual and unfortunately it has been going on for several years, terribly disappointed at the actions of the Missouri Commission, in particular, and your assumptions that you will be earning 2 to 3 percentage points on equity less than what you asked for. I noticed last week the commission granted an increase to Michigan gas -- Missouri gas energy which of course they are a small company, but nonetheless, was down a 10% ROE down from 10.5%. The Chairman made the statement about the unanimity of the decision. I don't think of talking to individual commissioners as unanimity with bargaining. The bargain seems to go towards the low end rather than the high end.

I wonder what steps you might take either be they with legislature or in specific filings and things you have asked for, trackers, etc., to try to cut the spread between earned returns and lag returns? You don't have a forward year though they tried to supposedly update your year during the course of the proceedings, but what else besides the forward year can you look to put in and/or to get the legislature to say this makes sense? Otherwise, you will have to continue to cut CapEx and continue to try to avoid the financial markets.

This is Marty. Thanks for dialing in. As we look to this ongoing rate case, we remain optimistic that we will get a fair outcome in this case, and I think Karl, with respect to the things that will help close the ROE gap over time which we have mentioned are talking points we are focused on and cognizant we have to achieve for our investor base. As part of this case we are looking for continuation of some of the constructive riders we have received in the past, the trackers, such as the fuel adjustment clause and the pension and OPEB trackers that we have.

We are also looking for other things that will help us in making sure we can earn something closer to our allowed ROEs, something like the environmental cost recovery mechanism that we are seeking in our current case in Missouri as well as some of the other adjustments that we laid out in slide seven of our presentation. We are looking to work over time to improve our ability to earn fair rates of return in our jurisdiction.

I know you are looking for it and you have been looking for it for several years, but it doesn't seem to do you much good. I'm wondering if there isn't anything more specific and more action that you can take. The current case is a pretty good example as far as most of the recommended increase by staff has to with fuel costs which you would have gotten through operation of the fuel clause in any case. They are not giving you any breaks as far as --

Karl, this is Warner Baxter.

Hi, Warner. Good.

I think at the end of the day, as Tom said earlier, we put together a well-supported case and we feel confident in our ability to have a fair hearing of this case in front of the Commission and a fair outcome ultimately from that commission. Marty outlined the various riders and tracking mechanisms that we will seek; in this case and potentially in future cases, we can see other mechanisms to continue to mitigate that lag.

Lastly, there are other alternatives out of the regulatory mechanism, as you know, that we could consider from a legislative prospective, but that's not in the short-term. It is something down the road. We are mindful of it and we will continue to do the best we can to narrow that gap.

Our next question is coming from Yiktat Fung with Zimmer Lucas. Please state your question.

Congratulations on solid numbers and especially on the improvement on the environmental CapEx outlook.

My first question pertains to the revenue breakdown on slide 15. In terms of the 79% portion that is energy and capacity for requirements contracts, are those contracts exposed to customers switching?

I apologize; you broke up a little bit. I think you are asking about the capacity hedges on slide 15.

I'm asking about the four requirement contracts that makeup 79% of your revenue.

You are speaking about the power hedge sales themselves and whether there is some exposure to customers switching.

Correct.

It has really diminished, because we -- previously some of these contracts were for auction related sales. Those auction related sales have been dropping off over the past couple of years and the swap contracts come into place. As the auction contracts roll off, which actually roll off middle of this year, we are less exposed to that kind of customer switching.

Going back to your earnings drivers for emerging segment, one of the drivers that seems to be missing or does not seem to be mentioned on slide 11 is basically O&M costs. Does that mean O&M is flat year-on-year at this segment?

No, I think if you go back and look at some of the guidance we've provided in previous quarters. We have barely been working to reduce the O&M, and I believe it's actually down a little bit, 2010 versus 2009.

That previous guidance I was bringing it back down to around 2008 levels still holds?

Yes, We provided some guidance back at the end of the third quarter relative to 2008 levels and that guidance is about right.

Going onto the regulated segment. Can you give a bit more color as to what you assume for your load, for load growth in 2010 versus 2009?

I think you expect, obviously, the Noranda plant to come back and industrial sales in Illinois will have a bit of up tick. Can you comment a bit on what you assume for residential and commercial?

We are fairly bearish in terms of residential and commercial sales; in industrial we talked about we are expecting growth as Tom mentioned in our sales to Noranda -- they seem to be coming back strong which is terrific news.

In Illinois we see some industrial growth in particular that we expect to take place. While we have low margins in that business, we do believe that's good for the economy in general, for our customers as well as for our power prices as well. Those are all good.

In terms of the residential and commercial sales, more modest expectations there. Really, we think that we won't see strong improvement in those areas until you look out into the future and you see some stronger economic recovery that would support some job growth.

Basically, the assumption is somewhere around flat year-on-year for residential and commercial?

Yes, I think close to that off of the low 2009 levels that you saw.

Thank you very much.

Our next question is coming from Dan Jenkins with State of Wisconsin Investment Board.

Hi, good morning. Had a couple questions on the Missouri case on your slide seven. When you mentioned the $402 million annual request, does that reflect the 11.5 ROE that you initially requested or the 10.8 that you are asking for now? And, if it is the 11.5, then what is the difference in that?

I was also curious -- you mentioned that you were going to true up through January 31. You obviously already have results through December 31 and you probably have a good idea on January. How is that going to impact the request?

The $402 -- if I understood your questions, the $402 million request was based on -- it is based on the initial ROE that was filed. We did, as you mentioned, drop the ROE request there and I guess as a frame of reference I think it is about every 100 basis points is about $45 million or so. You can do the math to figure out the impact there in terms of the ROE drought.

However, as you mentioned and we mentioned that there are going to be updates through the end of January and we don't have all of those numbers, today. We will be making a filing in March or the parties will be in the case any way in the March time frame that would provide the overall pluses and minuses.

Of course, one of the things that you see on that list that will go the other way in terms of moving the ROE going down would move the overall request down, but certainly pushing the other way would be anticipation that we would be able to update the capital structure to reflect the equity that we did put into Union Electric when we issued equity in the fall.

I just want to make sure I have this clear, is the staff not contesting the fuel clause or the pension OPEB trackers in this case?

That's right. We are saying the staff testimony didn't object to continuation of those -- the FAC and those tracker for pension and OPEB.

And so the only tracker they are really contesting is this vegetation and infrastructure inspection costs or are there other things that are being contested?

That is Warner Baxter. The other thing they are contesting -- we asked for a storm tracking mechanism in our rate case and it gets a little bit to an earlier question about other things that we are seeking to try to mitigate regulatory lag. One of the new things we did ask for in this case is a storm tracking mechanism and the staff is opposing that recommendation at least to date in their filing.

Our next question is coming from Billy Hagstrom with Catapult Capital. Please state your question.

You talk about an improved regulated earnings outlook as you narrow the gap. If I look at slide 10, your 2010 regulated guidance of 205 midpoint roughly is an 8% ROE. I think about the bullet at the bottom of the page that highlights $0.25 of earnings per every 100 basis points of ROE and these pending rate cases allow you to earn closer to your currently allowed ROE's. Are you expecting to get roughly 250 of earnings just for the regulated business by next year?

That was not the comment. I think the comment here overall was that we plan to reduce the regulatory lag we have through the businesses we have through the pending rate cases where we expect to improve the returns that last year were in the 6.5% range; we expect those to improve to the 7.5% to 8.5% range in the current year.

As we look out over time, we'd see the opportunity as we close the gap, between that mid-point, let's say 8%, and our allowed returns, which is our last series of rate cases in Missouri and Illinois, the ROEs that were allowed were around 10.7%. What we are saying there is for every 1%, we can close from that 8% mid-point up through 10 or 10.7% is going to provide us the opportunity to get the $0.50 or more of earnings. It is illustrating some of the earnings power of the businesses we have.

Okay, that's helpful. Good luck, guys.

Our next question is coming from Michael Lapides with Goldman Sachs. Please state your question.

On the environmental slide in terms of meeting the NPS requirements, you talk a good bit about -- can you talk about SCRs at all? Do yo not need SCRs at these facilities because you are meeting your NOx requirement through the scrubber? If you wouldn't mind giving an update on that? Can you talk about alternative technologies you have looked at, meaning Trona injections as a substitute for scrubbing?

Yes, Michael. It's Chuck Naslund again. As far as your question on SCRs, we currently have adequate SCRs and low-NOx burners on all of our units to be able to meet all the NOx requirements and all the NPS out through 2017. We have no additional CapEx expenditures in that particular area.

As far as alternative technologies, you are right on, we are looking very hard on Trona injections or some kind of sodium bicarbonate type injection where it is very low CapEx expenditure, but more of an O&M component. We believe some of our older, smaller units that may be the best economical approach and we have plenty of time as that technology shakes out to adjust CapEx for those Joppa units out in the future.

Can you talk about the returns on capital you expect to make if -- if you can't use Trona and you have to use the scrubbers, what kind of returns on capital you expect to make on that investment?

Can you repeat that question? I apologize.

Lots of companies in the industry face this in terms of whether to scrub plants or shut plants down. Can you talk about the returns on capital you expect to make on the scrubbing of some of our larger units on the non-regulated side?

I don't have the returns off the top of my head. I think what we will be doing over the next couple of years as we re-evaluate these plans, is certainly look, as I've said before, at the power price conditions, the fuel costs, look at the developments in the regulated areas and look at whether these incremental investments that we have that today we plan to make will provide us returns in excess of our cost to capital; and that's what we'll be taking a look at as we make the final decisions as to how to proceed with the capital expenditures that we have planned.

Last question, balance sheet one, was looking at the earnings release and noticed that long-term debt had come down about $800 million. But, I think that the draw on the credit facility or the borrowing on the credit facility is now about $830 million.Can you talk about plans for that? Are you going to leave that outstanding or are you going to term that out at one of the utility subs?

We expect as we said before, overall as we look at this year, that we expect to be around cash flow future neutral overall at the Ameren Corp level. As you look at some of the borrowings that you see there, some of those borrowings are for the merchant business, support the merchant business. Some of the cash that we have on hand is at the regulated business.

Regulated businesses, we are expecting them, as I said before, to be cash flow negative and eat into some of the cash balances this year. Whereas on the merchant side of our business, where we expect to be cash-flow positive, to have the ability to pay down some of those borrowing this year. You should see the borrowings and the cash balances coming down over the course of the year. While we don't have to access the capital markets this year, we still have the possibility, especially late in the year, of doing some additional debt at the merchant generation segment of say a couple $100 million, which that long-term debt might also be utilized to keep the borrowings under the credit facility level.

Got it. Thank you. Much appreciated.

We have time for one more question.

Our last question is coming from Steve Gambuzza from Longbow Capital. Please state your question.

Just on the non-regular O&M, I want to make sure I understood the answer, that was the prior guidance the 2010 non-reg merchant generation O&M would be roughly flat with the 2008 level? Is that correct?

That's correct.

Can you tell me what the number was in 2009?

I apologize. I don't have that handy. We can try to --

I will follow-up off line.

Maybe we have it, but following up off-line would be best.

Thank you.

Yes, Steve, this is Doug Fisher. If you would give me a call about that, we will catch up on that.

Unfortunately our hour has expired. Thank you for all your interest and participating in this call. Let me remind you again that this call is available through February 24 on play back and for one year on our website. Today's press releases includes instructions on listening to the play back. You may also call the contacts listed on the release. Financial analysts inquiries should be directed to me Doug Fisher. Media should call Susan Gallagher. Susan's and my contact numbers are on the news release. Thank you for your interest in Ameren and have a good day.

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