阿莫林 (AEE) 2010 Q1 法說會逐字稿

Greetings and welcome to the Ameren Corporation's first quarter conference call. At this time all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. (Operator Instructions). As a reminder this conference is being recorded.

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

Thank you and good morning. I am Doug Fischer, Director of Investor Relations for Ameren Corporation. On the call with me today are our Chairman, President, and Chief Executive Officer, Tom Voss, our Senior Vice President and Chief Financial Officer, Marty Lyons, and other member of the Ameren management team.

Before we begin, let me cover a few administrative details. This call will be available for telephone for one week to anyone who wishes to hear it by dialing a playback number. The announcements you received in our news release carry instructions playing the call by telephone -- on replaying the call by telephone. This call is also be 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 presentation 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 the presentation posted on our website, I need to inform thaw 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, 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 statements section in the news release we issued today and the forward-looking statements and risk factors section in our periodic filings with the SEC.

Tom will begin this call with an overview of first quarter earnings and 2010 earnings guidance, followed by a discussion of regulatory business and operating matters. Marty will follow with a more detailed discussion of our first quarter financial results, our 2010 earnings guidance and regulatory and financial matters. 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 our presentation, first quarter 2010 non-GAAP or core earnings were $0.40 per share, compared to first quarter 2009 core earnings of $0.54 per share. These results were within expectations with the aid of higher sales due in part to colder than normal weather and cost control efforts. The decline in earnings compared to the year ago period was primarily the result of lower Merchant Generation segment margins. These lower margins were a result of lower realized power prices and higher fuel and related transportation costs. Higher depreciation expense and an increased average number of common shares outstanding among other items also contributed to the decline. These factors were partly offset by several positive items. Colder winter weather and an emerging economic recovery helped drive first quarter 2010 utility electric and natural gas sales higher than those in the year ago quarter. Earnings also benefited from the March 1, 2009, Missouri electric rate increase being in place for the entire first quarter in 2010.

Turning to slide four today, we reaffirmed our consolidated 2010 GAAP and core earnings guidance range of $2.20 to $2.60 per share. However, we have adjusted our segment guidance ranges. We now expect our regulated utilities to earn in the range of $1.85 to $2.10 per share, a decrease of $0.05 per share at both the high and low ends of the range. This reduction in our guidance is being driven by the recent Illinois Commerce Commission order partly offset by anticipated deep cuts in operations and maintenance in capital spending planned for our Illinois regulated utilities. I will discuss this matter in more detail in a moment. Offsetting the decrease in expected earnings from our regulated utilities, we now expect our Merchant Generation business to earn in the range of $0.35 per share to $0.50 per share due to cost reduction efforts. In a few minutes Marty will provide further details on our first quarter earnings and our 2010 guidance.

Turning to slide five, as many of are you aware, we received a rate order from the Illinois Commerce Commission or ICC on April 29. The order authorized our Illinois electric and natural gas delivery utilities to increase rates by $5 million annually compared to our updated request of $130 million. We are clearly very disappointed in the decision, and we are taking action. Our responses will include asking the ICC to immediately correct errors totaling $25 million in the order and re-hear certain additional issues. We will also reduce plain spending levels at our Illinois utilities to more closely synchronize spending levels with the revenue and related cash flow levels provided by the ICC. Given the magnitude of the difference between the level of revenues granted by the ICC and our request, this synchronization will not be easily achieved. While we will always deliver safe and adequate service and meet our minimum regulatory requirements, the operations spending and capital investment reductions that will be necessitated by this order may hinder our ability to provide the quality of service our Illinois delivery customers expect. I feel strongly that the ICC's order is not in the best interests of the more than one million homes and businesses we serve in central and southern Illinois and our employees, contractors, vendors and our investors. We must be provided adequate cash flows to invest in our energy infrastructure, and we must earn adequate returns our regulated utility investments in order to main taken financially strong and stable utilities for the benefit of all stake holders, not of least of which are our customers. In the absence of adequate revenues and related cash flows, we are left with no reasonable choice, but to make these expenditures reductions. Marty will cover the key financial aspects of the order in his comments.

Moving back to a discussion of the first quarter of 2010, a moment ago I mentioned the cold winter weather we experienced during the first quarter. This cold winter weather and an emerging recovery in the economy led to a 7% increase in first quarter 2010 kilowatt hour sales to residential and commercial customers, compared to the first quarter of 2009. The improving economy was also evident in the level of kilowatt hour sales to industrial customers of Ameren's regulated utilities, especially in our Illinois service territory. These sales advanced 2% compared to the first quarter of 2009 excluding sales to AmerenUE's largest customer, the Noranda Aluminum smelter plant in New Madrid, Missouri. As many of you will recall in the Noranda's plant sustained damage because of a power interruption on non-Ameren damage because of a power interruption on non-Ameren owned power lines during a severe ice storm in January of 2009. Electric sales to the plant have gradually increased since that incident and have not reached pre-storm levels. Including the Noranda, electric sales to industrial customers increased 10% in the first quarter of 2010 compared to the first quarter of 2009. Natural gas utility sales also increased 3% in the first quarter of 2010, compared to the year ago period due to colder winter weather.

Moving from sales to plant operations, I am pleased to report that AmerenUE pump storage hydro electric plant in southern Missouri returned to service last month. On December 14, 2005, water over topped a dam causing Taum Sauk upper reservoir to fail. After determining what caused the failure, we began rebuilding the plant and established one of the nation's most rigorous dam safety programs. The rebuilt upper reservoir is the largest roller compacted concrete dam in North America. After extensive testing, the 440-megawatt plant was released for operations by the Federal Energy Regulatory Commission in early April. In addition, all in service criteria recommended by the Missouri public service Commission staff were met on April 15. We are proud that this critical asset has returned to our generation portfolio. Continuing our discussion of planned operations, AmerenUE Callaway Nuclear Plant began a scheduled refueling and maintenance outage in mid-April. The total duration of the outage is expected to be about 35 days. Refueling outages at the 1,190 megawatt plant occur every 18 months.

Moving back to regulatory matters, in Missouri we expect an order from the Public Service Commission or PSC in response to our pending electric rate increase request in late May. We recently revised our request to reflect updated cost levels and settlements of various issues throughout the case. The current request is now at $287 million, which would represent an approximate 13% increase for our customers. As we have discussed in the past, this rate increase request is driven by the significant investments we have made in our electric infrastructure to maintain and improve the reliability of our system for our customers consistent with their expectations. These investments are working. In terms of outage frequency, our reliability was among the top 25% in the country in 2009. The request also reflects the higher net fuel operations and financing costs which we are experiencing. The need for consistent, constructive, regulatory policies and decisions that support necessary investments in our energy infrastructure for the benefit of all of our stakeholders is critical and is consistent with sound long-term energy policy. Otherwise, these investments will be deferred or not made in order to fairly balance operating and financial needs. This is not a path we wish to take.

We are also very aware that higher utility rates are difficult for some of our customers to absorb, especially in the current economic environment. At both our Illinois and Missouri utilities we have taken many proactive steps to help our customers manage their energy costs. These steps have included reductions in planned operating and capital spending, including head count reductions and the freezing of management salaries. Our cost control efforts have directly benefited utility customers by contributing to downward revisions to our revenue requests. In addition, we continue to provide several energy efficiency and low income energy assistance programs to our customers.

Just as we are committed to providing safe and adequate service to our customers at affordable rates as well as serving our communities and the respective states in which we operate, we are also committed to providing fair returns to our shareholders. For several years our regulated utility businesses have been earning returns on investment that are well below our authorized levels, in part due to regulatory lag. We remain committed to improving our earnings to levels that represent fair returns on our regulated investments. To achieve fair returns we remain focused not only on pursuing constructive regulatory outcoming including mechanisms that reduce regulatory lag but also on closely aligning our spending and investment with the level of rates, reflected cash related cash flows and returns authorized by the respective commissions.

Turning to another topic, it has long been our desire to combine our three Illinois delivery utilities into a single entity and to combine the Merchant Generation subsidiary currently held under AmerenCILCO with our other merchant assets. On March 15, we filed an application with the Federal Energy Regulatory Commission or FERC requesting authorization to complete a two-step internal corporate reorganization, which we expect to accomplish on or before October 1st of this year. The first step would merge AmerenCILCO and AmerenIP into AmerenCIPs and rename the surviving company, Ameren Illinois Company. The second step would move Ameren Energy Resources Generating Company or AERG from Ameren Illinois Company and place it as a subsidiary under Ameren Energy Resources Company or Resources. As a result, Resources would be the holding company for all of the generating assets of our Merchant Generation business segment. The merger of our Illinois utilities does not require ICC approval. We have been operating these Illinois utility as a single business segment for several years. We have also been operating all of our Merchant Generation assets and activities as a single business segment. This reorganization will bring our legal structure in line with the organization of our business segment. We believe consolidation of our Illinois utilities will, over time, lower costs and increase our efficiency, provide greater convenience to our customers and improve transparency for our investors.

I would now like to update you on recent developments at our Merchant Generation business. As part of our ongoing cost control efforts, today we announced the further $435 million reduction to previously planned 2010 to 2014 Merchant Generation capital expenditures. This reduction primarily reflects a change in our estimated environmental compliance expenditures for our Joppa power plant and lower cost estimates for other environmental projects. We're now planning to use dry injection at Joppa rather than installing scrubbers at two of the four coal fired units. We expect to fully comply with the Illinois multi-pollutant standard through the use of dry sorbent in Joppa and the installation of scrubbers at the Newton plant by the beginning of 2015. Our Merchant Generation business also recently announced it was reducing staffing by approximately 75 positions. The elimination of these positions coupled with other planned spending reductions is expected to reduce 2010 non-fuel operations and maintenance expenses or O&M to approximately $300 million in 2010. This is approximately 10% lower than non-fuel O&M spending in 2009. Marty will provide more complete details on our revised overall Merchant Generation capital and operating expense outlook.

While recognizing the current lower power price environment we continue to believe that our Merchant Generation fleet is highly competitive in its region. The Merchant Generation segment's five largest coal fired power plants are favorably positioned in the regional dispatch order due to their low operating costs. Further, we have a solid base of forward power sales in place for 2010, 2011, and 2012 at attractive prices. In addition, our experience, power marketing group continues to focus on providing value-added electricity products to the market. Leveraging our competitive merchant generating assets this group has a track record of enhancing margins through sales to wholesale and retail customers. As our most recent cost cutting actions again demonstrate, we remain focused on minimizing costs, both operating and capital, at our Merchant Generation business. We continue to expect this segment to produce positive free cash flow in 2010.

Summing this up, we're working to improve the earnings from our regulated businesses over time by narrowing the gap between our earned and authorized returns and making disciplined investments to improve reliability and promote a cleaner environment consistent with our customer's expectations and sound energy policy. Further, we continue to take actions to ensure that our Merchant Generation business remains well-positioned to weather currently low power prices and benefit from an expected power price recovery. Finally, I believe 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 first quarter earnings and our 2010 earnings guidance and to provide further insight on recent regulatory and Merchant Generation developments and other financial matters.

Thanks, Tom. Good morning, everybody.

First quarter 2010 net income in accordance with Generally Accepted Accounting Principles was $102 million or $0.43 per share, compared to first quarter 2009 GAAP net income of $141 million or $0.66 per share. Turning to slide six, excluding certain items in each year, Ameren recorded first quarter 2010 core net income of $95 million or $0.40 per share compared with first quarter 2009 core net income of $114 million or $0.54 per share. There are two items in the first quarter of 2010 that we have excluded from our core earnings. These are the net effects of unrealized mark-to-market activities, which increased earnings by $0.09 per share, and a charge for the deferred tax impact of new federal healthcare laws, which decreased earnings by $0.06 per share.

I would like to comment on the key factors behind the change in core earnings per share between the quarters. Merchant Generation segment margins fell by $0.24, reflecting lower realized power prices and higher fuel and related transportation costs. Other key factors contributing to the first quarter 2010 earnings decline compared to the year ago period included higher dilution and financing costs, which together reduced earnings by $0.07 per share; higher depreciation and amortization, which reduced earnings by $0.04 per share; and, higher income and property taxes and other items which reduced earnings by $0.04 per share. Non-fuel O&M expenses were essentially flat with those in the prior year first quarter on an Ameren-wide basis as higher O&M at our regulated utilities due to scheduled plant maintenance outages was offset by lower O&M in our Merchant Generation business, primarily because of cost reduction action taken last year. As Tom mentioned, these factors were partially offset by higher electric and natural gas margins at our regulated utilities. These margins positively impacted earnings by $0.25 per share compared to the first quarter of 2009, largely as a result of the Missouri electric rate increase which took effect March 1, 2009 and the previously discussed increase in electric and natural gas sales, including increased electric sales to Noranda. We estimate the colder winter weather increased earnings by $0.03 per share compared to the first quarter of 2009 and by $0.02 compared to normal.

Moving now to slide seven, we now expect 2010 GAAP core earnings of $1.85 to $2.10 per share from our Missouri and Illinois regulated utility businesses. Key drivers and assumptions are listed on the slide. As Tom indicated we're deeply disappointed with the order issued by the Illinois commerce Commission in our Illinois rate cases. The new rates, which will go into effect in May, are far below those that we believe to be fair and justified. However, our management team is committed to improving the return on investment at our regulated utilities to levels that are fair by first immediately seeking correction of $25 million of errors in the order and filing for a re-hearing; and, second by immediately beginning to reduce our levels of spending and investment in Illinois to synchronize with the rate case outcome. While we're forced to reduce our expected 2010 earnings contribution from our regulated utilities, we remain focused on delivering returns on utility equity of 7.5% to 8.5% in 2010, returns, which is as I have said before, we do not consider to be adequate and sustainable for the long-term.

Turning to slide eight, we now expect the Merchant Generation business segment to post GAAP and core earnings of $0.35 to $0.50 per share in 2010. The slide lists the key drivers and assumptions behind our 2010 Merchant Generation business earnings guidance. I will touch on several of these items. Merchant Generation margin is expected to decrease $0.75 to $0.85 per share versus 2009, as a result of lower realized power prices and higher fuel and related transportation costs. This is approximately a $0.05 per share larger decline than our prior guidance and primarily reflects the drop in 2010 forward market prices for power, which has reduced expected 2000 generation levels partially offset by expected reductions in associated fuel and in fuel handling costs. Our expected margins assume that all of our unhedged expected generation is sold at current market prices. We expect our base load merchant plants to generate approximately 29 million megawatt hours in 2010. This is a decrease from our prior estimate of approximately 30.5 million megawatt hours, reflecting lower power prices.

We have approximately 26 million of our megawatt hours hedged at an average price of $47 per megawatt hour, 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 1.4 million megawatt hours and our expected 2010 Merchant Generation margin by approximately $23 million. Our all-in base load fuel costs for 2010 are now expected to be approximately $22.50 per megawatt hour. 100% of our anticipated coal, coal transportation, and rail surcharge needs are price-hedged. Importantly, our 2010 Merchant Generation segment earnings guidance has improved because we expect to more than offset the impact of lower margins with non-fuel operations in the maintenance expense reduction.

We now project non-fuel operations and maintenance expenses to approximate $300 million in 2010, a decrease of approximately 10% versus 2009. This reduction reflects our continuous efforts to reduce operating costs in light of weak power price conditions and includes the net impact of head count reductions announced earlier this week. We continue to anticipate that free cash flow from our Merchant Generation segment will be positive in 2010 allowing us to reduce outstanding borrowings. As I close our discussion of 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. Our earnings guidance for 2010 assumes normal weather for the balance of the year and is subject to the assumptions, risks, and uncertainties outlined or referred to in today's press release.

As Tom mentioned and as detailed on slide nine, on Thursday of last week the ICC approved an aggregate $5 million annual increase in utility delivery rates for our Illinois utilities. The order authorized a $32 million increase in electric delivery rates and a $27 million decrease in natural gas delivery rates. The decision is based on authorized returns on equity ranging from approximately 9.9% to 10.3% for our electric utilities and from approximately 9.2% to 9.4% for our gas utility. The order incorporates equity ratios ranging from about 43.6% to about 48.7% of the capital structure. The total rate base amount used in the order was $2.8 billion compared to $3.2 billion proposed by the ICC administrative law judges or ALJs and our requested $3.3 billion. In addition to the ALJs' proposed rate base adjustment, the Commission's order included further reductions for accumulated depreciation and cash working capital. These additional rate base reductions lowered the annual revenue requirement by approximately $52 million compared to the ALJs''s proposal.

The adjustment to accumulated depreciation is a departure from past ICC precedent and we believe it is a violation of the Commission's rules. The Commission did approve the fixed customer charges we proposed, resulting in an increase in the percentage of residential and commercial electric delivery revenues recovered through non-value metric monthly charges to 40% from 27%. This change will reduce the weather sensitivity of our electric delivery revenues. In addition, certain electric and natural gas supply related costs, some of which were previously in base rates will be recovered by riders. This will have an estimated $13 million positive revenue and margin impact in addition to the base rate increase. New rates are expected to go into effect on May 6.

Turning to slide ten, many of you will recall that AmerenUE's pending rate case was initially filed with the Missouri Public Service Commission or PSC in July of 2009. The updated request is for an annual increase in electric service rate of $287 million annually with $118 million of this related to increases in net base fuel costs. This request incorporates various settlements that have been approved by the Missouri PSC, as well as true-ups, including those relating to capital structure, rate base, net base fuel costs, and certain expenses through January 31, 2010. AmerenUE updated revenue request is based on a 10.8% return on equity of 51.3% common equity ratio and rate base of approximately $6 billion. The Missouri PSC staff updated recommended annual rate increase is $165 million incorporating a 9.35% return on equity with approximately $107 million of this amount related to higher net base fuel costs. The staff's revenue amount also incorporates the settlements and true-ups including in AmerenUE's updated revenue request. Other parties have also filed testimony in the case including a group of large industrial customers, Missouri Industrial Energy Consumers or MIEC and the Office of Public Council. The MIEC recommends a 10% return on equity, among other things. The Office of Public Council recommends a return on equity of 10.1%.

Turning to slide 11, as I mentioned, major parties to the case reached agreement on a number of the issues in the case in a series of settlements which were recently approved by the PSC. These settlements resolved many of the issues in the case. Post construction accounting deferrals are to be allowed for the Sioux scrubbers. For the stipulation, AmerenUE will continue to accrue allowance for funds used during construction or AFUBC and will defer depreciation expense on the Sioux plant scrubbers after the in-service date of such equipment. The post construction accounting will end on the earlier of the effective date of AmerenUE's next generate case or January 1, 2012.

While AmerenUE is no longer seeking an environmental cost recovery mechanism in this pending case, it remains able to request use of such a mechanism in the future. The settlements also include a provision that mitigates the impact of an unexpected significant decline in AmerenUE sales to the Noranda smelter plant. If a significant loss of service occurs at Noranda, AmerenUE will be allowed to sell the power not taken by Noranda and use the proceeds to offset revenues lost up to the amount necessary to be held harmless. Any excess revenues will be refunded to customers through the FAC. In addition, the settlements provide for continuation of trackers for pension and other post retirement benefit expenses. Additionally, prospective capacity and energy revenues from certain bilateral contracts will flow through the FAC. This provision was balanced by allocating the related fixed and variable costs to supply these contracts to the retail jurisdiction.

Open issues in the Missouri rate case that remain to be decided by the PSC include the return on equity level and the amounts of plant maintenance and depreciation expenses to be included in rates. Also, unresolved are the levels of vegetation management and infrastructure inspection and storm cost expenses to be included in rates, and weather trackers will be authorized for these items. In addition, parties have argued against AmerenUE's proposal to include in net base fuel costs, the nuclear fuel that is on site at Callaway for the current refueling. Finally, continuation of the fuel adjustment clause, which no party opposes, and the level of sharing of prospective changes in net fuel costs remain open issues. The Missouri PSC is expected to issue an order by late May with new rates effective in late June 2010.

Before concluding our formal remarks, I would like to provide information that should assist you in your ongoing assessment of Ameren's Merchant Generation business. Moving now to slide 12. We provide an update on our 2010 through 2012 forward power sale and hedges as of March 31. As you can see, we have significant hedges in place for 2010 through 2012 at power prices above current market prices. We already discussed our 2010 hedges. For 2011, we have hedged approximately 19 million megawatt hours at an average price of $48 per megawatt hour. For 2012, we have hedged approximately 13 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 23% hedged in 2012. To assist you in understanding margin drivers, we have provided a pie chart that breaks down Merchant Generation 2010 expected revenue by type.

Turning now to slide 13, several analysts and investors have asked to us provide further insight on the prices at which we expect to sell the unhedged portion of our Merchant Generation output relative to visible market prices. First, I think it is important to note that our generation levels have historically been more weighted to on peak hours than off peak. In 2010, we expect that 53% of our anticipated 29 million-megawatt hours generated to be on-peak hours. The on-peak waiting and synergy hub around the clock price is approximately 47%. As we look ahead beyond 2010, we expect these historical trends to continue with more of our generation being on-peak than the synergy hub around the clock average. Further, given that the base of our hedges in 2011 and 2012 are around the clock swap contracts, remaining unhedged volumes are even more concentrated to on peak hours than the expected generation mix.

Another thing to consider about our unhedged volumes beyond 2010 is that we did not hedge simply through at market, forward or spot sales. This slide illustrates key factors that go into the pricing and profit opportunities of selling a load shape product, a product we are well suited to provide and actively market. Our ownership of iron in the ground, low cost coal fired base load and coal and gas fired intermediate and peaking generation gives us a solid position from which to work to achieve premiums above visible forward power prices through negotiated customized contracts. As we move forward to hedge open positions in 2011 and beyond we will be targeting wholesale and retail opportunities that allow us to enhance margins by leveraging our capability. Customized and value-added load shape sales, which are made to wholesale and large retail customers, have historically produced premiums above relevant market based energy costs as illustrated on the right-hand side of the slide 13.

Turning now to slide 14, here we update our Merchant Generation segment's fuel and related transportation hedges. We previously discussed our 2010 hedging, and no other changes to our fuel hedging positions have occurred since our last quarterly update. Before leaving the slide, however, I would like to make a couple of additional points. Spot prices for PRB coal today are lower than our embedded 2010 coal prices for our Merchant Generation segment by about 10%, and as we look out to 2011 and 2012, broker quotes for PRB coal would suggest prices are around 15% to 20% lower than embedded prices in our current hedges, so actual term contract prices can vary from these quotes. Further, the embedded transportation rates for our Merchant Generation business in 2011 and 2012 approximate current market prices, as all of our rail contracts have been renegotiated over the past two to four years.

On slide 15, we present our updated capital expenditures outlook for our Merchant Generation business segment for each of the five years through 2014. As Tom mentioned today we announced an additional $435 million reduction to previously planned Merchant Generation capital expenditures for this period primarily as a result of lower estimated environmental compliance expenditures. This is a result of our ongoing efforts to ensure that we identify the lowest cost options for environmental compliance in terms of both capital and ongoing operating costs. As you can see over the next two years, our environmental capital expenditures plans are moderate. We will use this time to continue to evaluate our plans looking for any opportunity to reduce compliance costs. In closing, I want to assure you our management team is focused on improving the returns at our regulated utility and continuing to position our Merchant Generation business to weather current power market conditions and benefit from an expected recovery in power prices.

This completes our prepared remarks. We will now be happy to take your questions.

Thank you. We will now be conducting our question and answer session. (Operator Instructions).

Our first question this morning is from the line of Paul Patterson, Glenrock Associates. Please proceed with your question.

Good morning, guys. Can you hear me?

Yes, Paul, we can hear you.

I wanted to ask you guys about the CapEx and O&M reductions at the Generation business and how we should think about the O&M and other operational costs going forward? In other words, are the operational costs sustainable and does the capital cost reductions have an impact on operating costs in future year that is we should think about?

In conjunction with that I am wondering about the capacity auction that came out from the Illinois power agency, if you guys could just address that? The prices seemed a lot lower. What do you think is going on there and how that may or may not impact you guys?

Sure, Paul. Thanks for the questions.

This morning, like I did on the last call, I have other members of management here, and one of those is Chuck Naslund, our President of Merchant Generation business. I will let him talk and speak to the capital expenditures and other operating expense reductions.

Sure. Thanks, Marty. Good morning, Paul.

Paul, to start with the operations and maintenance expense is, as you may recall, last year we announced staffing reductions in the order of about 135 positions and then earlier this week an additional 75 positions. All of those reductions carry forward as far as permanent O&M reductions in our cost to run our business, and so those do carry on out through all of those future periods.

As we mentioned in our news release, we have made for 2010 O&M reductions of about 10% over this past year, and those carry forward on into the 2011 time period, so certainly I believe they're sustainable on into those future years. On the CapEx side, we are currently implementing requirements in the state of Illinois for the multi-pollutant standard, which in essence is very similar to CAIR and CAMR requirements that have been stayed by the courts, but nonetheless they're pretty a aggressive standards.

Through optimizing the set of compliance measures we have over time and with the first phase of scrubbers being finished, we have been able to rearrange our future CapEx expenditures in a fashion to take advantage of good performance of our Phase I scrubbers. Now we're in a position where we will only be scrubbing Newton 1 and 2, and we have been working on the design there and actually have been able to bring our cost estimates down.

Then on our Joppa plant, as I mentioned in the last quarter phone call, we have been evaluating dry sorbent injection at that plant and that now official in our budget of how we're going to address that. For that particular plant, because the Illinois NPS would only require about a 50% reduction in SO2, that has to be completed by 2015, and beyond this, then, we would envision some incremental O&M costs for Trona, or sodium bicarbonate, that is used when you do dry sorbent injection, but it would be out in that 2015 and beyond period.

You don't see any operational expense that is are going to be increasing as a result of this until perhaps 2015. Is that the way we should think about it?

That's correct.

And then if you could address the capacity option and what happened there?

The result, this is Andy Serri. The results of the capacity auction were in line with what we were expecting throughout the Midwest. Normally, we target in that 70% to 75% range as far as capacity sales, just due to the length of capacity that's in the market. Obviously we're on track here for 2010 and we see the same results in that 70%, 75% range going forward in 2011.

So we should expect a significant drop off in terms of 2011, in terms of revenues and stuff? Looks like you are much less hedged in 2011 and 2012.

It will reflect current prices, and the prices that we're cleared in the Illinois RFP were probably reflective of current market prices for capacity.

Okay. Thanks a lot, guys, I will let someone else ask.

Thank you.

Our next question is from the line of Phyllis Gray of Dwight Asset Management. Please proceed with your question.

Good morning.

Good morning, Phyllis.

I was wondering if there was any update to the cash flow forecast that you provided at the end of the fourth quarter?

Good question. No, we don't have an update included in here although I think our guidance that we provided in our guidance for the year is still good.

You recall that we projected that our cash flows, which is cash flows from operations less CapEx and dividends, would be about cash flow neutral for the year, for the Company overall, and that we're expecting positive cash flows, free cash flows at the Merchant Generation segment, which are being offset by the expectation of negative free cash flows at our regulated businesses, but no other update beyond that. I think the guidance we gave at year end is still good.

Okay.

And I see that ComEd has made an interesting proposal in Illinois, and wondered if that is anything that will impact you should it go forward?

I think that certainly saw media releases yesterday like you probably saw. Haven't seen the exact details of that, and I guess as we learn more, we would have to (inaudible).

Thanks very much.

Thank you.

Thank you.

Our next question is from the line of Tom Scotia with Alliance Financial Corporation. Please proceed with your question.

Good morning. How are you guys doing?

Good morning.

I was wonder if any of the capital expenditures cuts contemplate some closures of some plants that you otherwise would have spent CapEx on?

They do not contemplate closure of any plants.

Okay. And the decision to use the dry sorbent technology, if a relatively constricting mapped standard were to come out next year, because of CAMR, do you believe that your dry sorbent technology would be able to comply with the more stringent standard?

Again, I would have to take you back. We're currently under the Illinois multi-pollutant standard, which basically is comparable to the CAIR and CAMR regulations previously drafted, and our current compliance plan would have us in compliance with that, so the answer to your question would be whether EPA issues a different CAIR or CAMR law than what was previously contemplated. I can't speculate on that not knowing what that would be.

Okay. Thank you.

Thank you.

Our next question is from the line of Michael Lapides with Goldman Sachs. Please proceed with your question.

Congrats on a good quarter. A couple of high level questions.

One, when you use Trona, does it impact, meaning doe it de-rate a plant, and meaning name plate is 500 megawatts are you really generating something slightly less than that? Also as you finish scrubbing projects, are you looking at converting more of your facilities to use Illinois basin coal versus powder river basin coal? Can you talk about whether that's economic and how much of that fuel switching you can do once a plant is scrubbed?

Michael, this is Chuck again. The first question on Trona de-rating the plant, our answer would be no, we do not anticipate any de-rates due to use of injecting Trona in the back end of the plants.

As far as Illinois basin coal, that is an economic issue. We do have the ability to burn Illinois coal with the scrubbers that have been installed, so we do have fuel flexibility. However, currently the economics are it is much better to use powder river basin coal, so it would take a significant shift in the Illinois coal market prices before we would shift back, and it would be an economic decision at that point in time.

Can those facilities, could you burn 100% Illinois basin if the economics warranted it?

Yes.

Okay. Thank you, guys. Much appreciated.

Thanks, Michael.

Thank you.

Our next question is from the line of Reza Hatefi with Decade Capital. Please proceed with your question.

Thank you.

If I just heard correctly, the O&M, your previous guidance was $315 million and now it is $300 for the Illinois utility?

Yeah, that's right. In our last call we talked about $315 million. Now, we're targeting approximately -- we're not targeting, we're expecting approximately $300 million.

And I guess in maintaining your guidance, are you embedding any relief from the appeal in Illinois, I think you said $25 million or so?

Yes. I think as we look at our guidance, we have assumed that either we're successful in the appeal and getting the $25 million of errors corrected or we will be able to achieve savings through cost cutting measures to make up for any shortfall there.

And then just lastly on slide 12 where you have the hedging, 2012 looks like 14.5 terawatt hours at $53 and in your fourth quarter slides, it was 13.5 terawatt hours at the same price, so how did that -- can you talk about that 1 terawatt hour? I am just surprised the average price stayed the same; power markets were pretty weak in the first quarter, the forwards were pretty weak.

You're right, it was about 1 million more megawatt hours that we hedged and frankly it was a rounding between where we were a little above 53 to just a little below 53.

Okay. This is a quick last question.

The reorganization of the Company, where you're combining the Illinois utilities and then the merchant segment. Would the merchant segment, at this point, if continued weakness in the commodity markets continued, would the rest of the Company or the merchant bond holders or anyone have any recourse to the rest of the Company if some unforeseen things happen the next few years?

I think that as we go through the reorganization, obviously, we're, as Tom said, seeking to really achieve efficiencies and better alignment of our legal entities with our overall segment operations, and we think that will provide us cost savings opportunity as well as, hopefully, better transparencies of earnings and cash flows for investors.

As you look at the Merchant Generation segment, specific answer to your question on the debt is that the Genco bond holders do not have recourse to the parent, but of course certainly when we look at those overall Merchant Generation operations, we certainly believe as we talked about in the talking points, we believe our assets are plants are well-positioned, our core five plants are well-positioned in the markets that we operate in; and we do believe, as we look out this year, we have positive free cash flows. We believe that by cost cutting actions that Chuck and his team have taken, capital spending reductions we have taken, the liquidity that we have today, we certainly believe we're very well-positioned to ride through this trough in the energy markets until we do see recovery of power prices in the future.

Thanks again.

Thank you.

Our next question is from the line of Dan Jenkins, State of Wisconsin Investment Board. Please proceed with your question.

Good morning.

Good morning.

I was curious on the Illinois appeal of the Illinois -- is the whole $25 million then related to the new procedure that they used for the cumulative depreciation? Is that what that is and are there any other issues that you're asking for re-hearing or appeal on?

Well, there are really I would say two pieces to that. One is the errors that we believe exist within the order itself and corrections that we believe should be made just in terms of how the calculations have been done to carry out what we believe the Commission ordered, and we are seeking correction of those errors immediately.

However, there is also a longer term process for seeking re-hearing on various other issues in the case where the Commission ruled against the positions that we believe justifiably we had taken. That process, we will ask for a rehearing. In our slides, we layout that the Commission has a period of about 20 days to decide whether to take action or take up that re-hearing, and then if they do there would be up to another five-month process after that where they give consideration of those issues that we seek re-hearing on; and at the end of that five months, if we were successful in that effort we would see an adjustment in rates at that point in time.

How much of it is related to just the calculation errors and how much to other issues then?

Well, the calculation errors, I would say, is about $25 million. The breadth of the things we seek re-hearing on hasn't been determined, but it would be the issues in the case that separated our request for about $130 million in the amount granted by the Commission.

Okay. Have you gotten any response back from the Commission just on the what they think of your calculation error issue?

No.

Okay. Thank you.

Thank you.

Our next question is from Neil Carlson with Wells Fargo. Please proceed with your question.

Good morning, everyone.

Hi, Neil.

A apologize in advance if this was answered during the call. I may have missed it.

I believe the Genco has a $200 million debt issuance maturing recently or coming up soon. Any plans around that as of yet from a financing perspective?

Thanks, Neil.

No, we didn't talk about that earlier on the call. There is a maturity related to Genco debt later this fall. We're still evaluating how we might address that maturity.

What we did talk about earlier on the call, Neil, though is that we do have positive cash flows at the Merchant Generation segment overall and at Genco in particular as well, and we have got options as to whether we will use those cash flows to reduce long-term debt or short-term debt, as the case may be, so we'll continue to evaluate how we deal with that as we go into the second half.

Okay. Thanks.

Thank you.

Our next question is from David Frank of Catapult Capital Management. Please go ahead with your question, sir.

Good morning, guys.

Good morning, David.

Just wondering, we were all kind of curious what kind of Commission would evolve in Illinois, but it appears now to be the most unfriendly business Commission in the country, practically. This is a populous marxist commission that has -- why are they doing what they're doing? Is this a statewide effort? Is this an edict from the Governor? Is this just -- they surprised everybody, I think.

Well, David, we were, as we said in our talking points, very disappointed with the order. We certainly believe that the case we put together and the revenue requests that we had before them was fully justified, and I certainly can't speak to why the order came out exactly the way it did. As I said earlier, we will certainly seek to get errors that we identified corrected, and we will vigorously seek rehearing of the issue that is we lost in the case.

Rob, this is Doug Fisher. We have time for one more question.

Thank you, sir.

That question is from the line of John Hanson with Praesidis Advisors. Please go ahead with your question, sir.

Good morning.

Good morning.

Just a follow-up on a couple areas in the Merchant Generation, as we look out here. In the O&M cuts we're talking about, are we -- you talked about the number of people, but when I do the math there is probably more money than that than just the people, but are we deferring some maintenance projects? I know we had to do that a year or two ago when we were doing cuts.

I apologize. You broke up and faded off at the end.

Are we deferring maintenance projects in the Generation to get to those numbers?

We can answer that question.

We currently in our five year forecast have the appropriate levels of operations and maintenance expense budgeted to adequately maintain our facilities, so the numbers we have given you, again a lot it is staffing reductions and that's where we're at.

Okay. Good.

As we looked at those capacity options, it almost appears to us that the numbers were so low that some people have to be considering next couple of years whether they keep plants open. You said you were going to keep yours open. Do you think we're going to have plant closures as a result of some of these weak energy and capacity prices?

There is a potential for that. When we sell capacity, we sell capacity outright, and we also bundle it with energy sales as well, and so you have to look at the entire picture, not just the capacity side of the equation. We position ourselves fairly well with our hedges going forward, so can't speak to other folks, but we'll have to see what happens going forward.

So we're getting pretty good results in the bundling market as we're selling into this market?

As we illustrated on our one slide, I think it was slide 13, we look at several components when we bundle a sale together, but, yes, we look at the big picture when we make a bundled load following sale.

And that's said to your question does cause to you step back and especially take a look at I would say the least efficient units in your overall fleet, and make assessments as to whether those facilities should be considered for temporary closure, moth balling, if you will, given some of the overall weak power price conditions and that is a step we'll certainly take, and I would imagine others are doing the same.

This is Doug Fisher. Thank you for participating in this call.

Let me remind you, again, that this call is available through May 12 on playback and for one year on our website. Today's press release includes instructions on listening to the playback. You may also call the contacts listed on the release. Financial analysts should be directed to me, Doug Fisher; media should call Susan Gallagher. Susan's and my contact numbers are on the news release.

Again, thank you for your interest in Ameren.

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