阿莫林 (AEE) 2005 Q2 法說會逐字稿

Good morning and welcome, ladies and gentlemen, to Ameren Corporation second quarter 2005 earnings conference call. At this time I would like to inform you that this conference is being recorded and all participants are in a listen only mode.

At the request of the Company we will open the conference up for questions and answers after the presentation. I will now turn the call over to Bruce Steinke, Manager of Investor Relations. Please go ahead, sir.

Thank you, Denise, and good morning everyone. I am Bruce Steinke, Manager of Investor Relations here at Ameren Corporation. With me today is our Chairman, Chief Executive Officer, and President, Gary Rainwater; our Executive Vice President and CFO, Warner Baxter; our Vice President and Controller, Marty Lyons; and our Vice President and Treasurer, Jerre Birdsong.

Before we begin, let me cover a few administrative details. This hour-long call is available by phone for one week to anyone who wishes to hear it by dialing a playback number. The announcement you received in our news release, carries instructions on replaying the call by telephone.

This call is also being broadcast live on the Internet and the webcast will be available for 1 year on our web site, www.ameren .com. This call contains time sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited.

I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives and financial performance.

We caution you that various factors could cause actual results to differ materially from those anticipated in the forward-looking statements. For additional information concerning these factors, we ask you to read the forward-looking statements section in the news release we issued today in the forward-looking statements and risk factors section in our filings with the SEC.

To assist in our call this morning we have made a slide presentation available on our website that reconciles our earnings per share for the second quarter in the first six months of 2004, to our earnings per share for the second quarter and first six months of 2005 on a comparative share basis.

In addition this presentation includes a slide that compares updated earnings guidance to full-year 2004 earnings. To access this presentation you may look in the investor section of our website under presentations, or follow the link for the webcast. Gary will begin the call with an overview of our second quarter 2005 results and some operating regulatory matters, and Warner will follow with a further update on regulatory matters and a more detailed review of our second quarter results and revised earnings guidance. We will then open it up for questions. Here is Gary.

Thanks, Bruce. Good morning and thank you for joining us. This morning, we reported earnings of $0.93 per share for the second quarter of 2005 as compared to earnings of $0.65 per share in the second quarter of last year. For the first six months of 2005, Ameren reported earnings of $1.55 per share compared to earnings of $1.20 per share in the prior year period.

Ameren's earnings per share in the second quarter of 2005, benefited from stronger interchange power sales margins, earnings from Illinois Power Company which was acquired in September of 2004, hotter than normal weather, and the lack of a refueling and maintenance outage at our Callaway nuclear plant in the current year. These increases were offset, in part, by higher labor, employee benefits and depreciation expenses in our pre-Illinois Power acquisition business.

In addition, Ameren received an $18 million refund in the second quarter of 2004 from the Midwest Independent Transmission System Operator. For previously paid exit fees that did not recur in 2005. This refund benefited earnings by $0.6 per share last year.

In last year's second quarter, our Callaway nuclear plant was out of service for 64 days for refueling and maintenance outage which reduced earnings by $0.20 per share. I should note that Callaway nuclear plant is scheduled for a 70 to 75 day outage beginning this September. During this outage we'll not only refuel the plant but we will also replace the steam generators and turbine rotors. We believe this will improve the reliability of the planned and increase plant capacity by approximately 60 megawatts.

I should also note that despite some initial concerns about potentially low Missouri River levels, impacting the delivery of key materials for the maintenance outage, all the major equipment is at the plant sites and ready for the project to begin. The lack of an Callaway outage in the current quarter allowed us to increase the availability of our electric generation fleet to 86% from 80% in the second quarter last year as well as increase our capacity factor to 78% from 72% in the second quarter last year.

This improved generating plant availability and the new MISO Day-Two market provided us the opportunity in the second quarter to take advantage of higher power prices in the interchange markets. In the second quarter of 2005, interchange power sales increased over 39% when compared to the second quarter of 2004 and we realized average revenues of almost $38 per megawatt hour on the sales which is $8 per megawatt hour higher than the second quarter of 2004.

At this time we expect power prices to remain higher than 2004 levels for the rest of 2005. We believe this factor, when coupled with the interchange margins, we realized during the first half of the year, will result in interchange margins which will be higher than our original expectations for 2005.

As a result, today we revised our 2005 earnings guidance range to $3 to $3.20 per share, up $0.10 per share from our original guidance of 290 to 310 per share. We believe energy prices will remain above 2004 levels throughout 2005 due to higher natural gas prices as well as higher gold prices due in part to disruptions in deliveries of coal out of the Powder River Basin in Wyoming.

In early May there were two derailments due to the unstable track conditions on the joint Burlington Northern Union Pacific line that serves the Powder River Basin. As a result, the Federal Rail Administration placed speed restrictions in sections of the line into the track could be made safe. These actions reduced deliveries of coal from the PRB coal mines.

In 2004, 86% of Ameren's electric generation was supplied by its coal-fired power plants and 85% of coal used by these plants was delivered by the railroads from the Powder River Basin. In early July of 2005, one of the railroads projected that maintenance of the joint rail-line will be completed by December of 2005 and normal delivery should resume at that time.

Because of the railroad delivery problems, we received approximately 85% of expected deliveries in June. We expect to receive 85% to 90% of scheduled deliveries of PRB coal until track repairs are complete and speed restrictions are removed. To insure that we will be able to maintain sufficient coal levels and all our coal-fired power plants during this maintenance period, we are employing several strategies to manage our coal inventory levels.

Those strategies include purchasing economically available coal in the spot market, particularly in Illinois were some of our plants are equipped to blend PRB coal with Illinois coal. In addition, we're raising the price at which we offer some of our coal-fired units which will impact our interchange sales principally during off peak hours. And of course, we continue to work very closely with the railroads to ensure that our deliveries are being made as timely as possible to the appropriate locations.

We believe all these strategies will permit us to continue to operate our coal-fired fleet effectively and reliably throughout the rest of this year. Actual power plant performance, power market conditions, weather induced demand for power, cost of alternative coal supplies, and the actual time required for the railroads to resume deliveries, could have a significant impact on the effectiveness of these strategies. We also continue to actively hedge our coal and transportation needs.

Currently Ameren has coal supply and transportation contracts for nearly 100% of our expected 2005 requirements. In addition, we expect very soon to have hedged 100% of our 2006 coal supply and related transportation needs and approximately 90% of our 2007 requirements.

As we have noted previously, we have seen pressure on coal and related transportation pricing of the past year. In addition, we believe the current coal delivery disruptions will only increase pressure on pricing as many utilities including Ameren attempt to build coal inventory levels for future operating needs.

We continue to expect coal and transportation annual cost increases of 3% to 5% in 2005, in 2006 we now, expect annual coal and transportation costs to rise 5% to 10% and in 2007 we expect increases to be in the range of 10% to 15% above 2006 levels. These cost increases will put pressure on electric margins, it is important to point out that approximately 50% to 60% of our coal needs are procured for Missouri regulated operations.

Our electric rate freeze in Missouri expires on July 1st, 2006. In addition, Senate Bill 179 was signed into law this month. This law enables the Missouri Public Service Commission to authorize fuel and environmental cost recovery mechanisms for Missouri utilities. Regulatory framework in Missouri could mitigate the cost increases for coal and transportation in the future as we will have the opportunity recover these increased costs through base rates or a fuel recovery mechanism.

Our unregulated electric generation operations in Illinois, these cost increases will impact electric margins. However, as I noted earlier, we have seen market prices for power rising meaningfully in 2005. We believe part of this increase is being driven by rising coal and transportation price increases. While it is difficult to predict how future prices for power will be impacted by these cost increases, it is reasonable to believe that they will be.

On the electric transmission front, you may recall that in last quarter's call, we indicated we were seeing what we believed to be sub-optimal dispatching of plants and some price volatility in the MISO Day-Two markets that began on April 1st. I am pleased to report that have been improvements since our last call, and most importantly, we have not experienced any major issues associated with the reliability of our system. We continue to work closely with MISO to optimize the market.

One final operations point on the integration of Illinois Power into Ameren, our integration efforts remain on track, we converted many operating and financial systems on April 1st and the conversion of IP's customer information system will occur in the fall. I continue to be very pleased with the progress of our integration efforts.

Turning to regulatory matters, we completed several longtime pending matters during the last quarter, specifically in May, we completed the transfer of Ameren UEs, Illinois and Electric & Gas utility service territory to Ameren CIPS. And the transfer of 550 megawatts of generating capacity from our unregulated Ameren Energy Generating Company subsidiary to Ameren UE.

In May, we received an order from the Illinois Commerce Commission granting and $11 million annual increase in gas delivery rates for Illinois Power. On June 1st, we expanded our service territory in southern Missouri to serve Noranda Aluminum, the largest user of energy in the state of Missouri.

Finally we continue to prepare for the end of rate freezes in 2006 in Missouri and Illinois. Earlier this year we filed, with the Illinois Commerce Commission, a proposed method for procuring power in Illinois for 2007 and beyond. In June the ICC staff filed testimony responding to our initial filing. The ICC staff continues to support the auction process and the full recovery from customers of costs of purchased power resulting from the auction. However, the ICC staff did propose some modifications to our original proposal.

In July, we responded to the staff and other intervenor testimonies and proposed several modifications to our original filing. Those modifications related to the timing of the auction and the amount of generation our unregulated affiliate could supply to our customers directly through the auction among other things.

We are hopeful that a proposed modification will satisfy the issues raised by the ICC staff and other intervenors. In addition, the Illinois Attorney General and Citizens Utility Board, have raised issues related to the authority of the ICC in this matter and the viability of other options for procuring power. However, we continue to believe the auction process is not just lawful, but it's clearly the most transparent and competitive process to supply power to our customers going forward.

Rulings on this matter by the Administrative Law Judge in June and the ICC in July, supported our position as to the ICC's lawful authority to approve the auction process and as a means of procuring power on behalf of our customers. Later this year we plan to make filings with the Illinois Commerce Commission that will serve as a basis for adjusting our delivery service rates. And by January 1, 2006, we'll provide an updated cost of service study to the Missouri Public Service Commission staff and others. Warner will go through these matters in a bit more detail.

In summary, we're very pleased with our operating results for the first half of 2005. In the second half of this year we will continue to focus on the successful completion of our Callaway nuclear plant outage, the management of our coal inventories, final stages of integration of Illinois Power, and the Missouri and Illinois regulatory processes.

With that I would like to turn the discussion over to Warner.

Thanks, Gary. As Gary noted, the process is well under way to get the Illinois Commerce Commission to decide the process and framework for retail rate designed to determinations and power procurement after the current Illinois rate freeze ends in 2006.

Ameren's and ICC's staff testimony currently reflect a framework that would have all regulated Illinois electric distribution companies adopt their native load requirements for generation, in an ICC monitored, New Jersey-type auction process. It would provide full recovery from customers of the generation costs resulting from that auction.

In 2007, we expect our non rate regulated power generation businesses will be allowed to sell the approximately 14 million-megawatt hours of power that are committed to our Ameren CIPS and Ameren CILCO distribution businesses at market base prices. Prices under our Ameren CIPS and Ameren CILCO power supply contracts that expire at the end of 2006 average approximately $37 per megawatt hour. Market prices today for similar contracts to deliver power in 2005 approximate $52 to $53 per megawatt hour. Of course, these may not be the prevailing market prices at the time of the proposed auctions.

As Gary mentioned previously we expect to make filings later this year to establish the delivery service portion of our electric rates in Illinois after the rate freeze ends. I should note that by 2007, electric rates for all our Illinois utilities will have been frozen or declining for approximately 15 to 25 years. At legislative hearings in early March, we stated that average electric rates for our Illinois utilities on a combined basis could increase in 2007 by 10% to 20% over present bundle rate levels with 50% to 70% of this increase resulting from higher power costs.

This analysis was based on a number of assumptions about auction results which were based on 2005 power prices at that time, rate making outcomes and the like. The final results of the auction process and regulatory proceedings could be significantly different from our original assumptions.

In Missouri, as Gary pointed out earlier, Senate Bill 179 has been signed into law. That law requires that rulemaking proceedings be conducted to spell out more of the details as to how the fuel and environmental cost recovery mechanisms will work. We expect that roundtable discussions will begin in August and that a more detailed procedural schedule will be established in the near future.

As you know, electric rates are frozen in Missouri until June 30th, 2006. We are required to submit an updated cost of electric service study to the Missouri Public Service Commission staff and others by January 1st, 2006.

Based on the results of that study, and the status of the environmental and fuel cost recovery rulemaking proceedings, we will determine what course of action we believe should be taken in resetting electric rates for Ameren UE in Missouri. Missouri Public Service Commission staff and other stakeholders will review our study and based on their analyses, may also make rate recommendations.

Now, I refer you to our website as it provides a more detailed discussion of our second quarter 2005 earnings. As Bruce mentioned earlier, we have posted a slide presentation on our website that reconciles our earnings per share for the second quarter and first six months of 2004, to our earnings per share for the second quarter and first six months of 2005 on a comparable share basis.

In addition, this presentation includes a slide that compares our updated 2005 earnings guidance to full year 2004 earnings. In this presentation, and in our comments this morning, we have isolated the impact of the Illinois Power acquisition on two lines to allow for an easier, year-over-year analysis for our pre acquisition operations.

In the second quarter of 2005, we reported net income of $185 million, $0.93 per share compared to net income in the second quarter of 2004 of $118 million or $0.65 per share. The first six months of 2005, we reported net income of $306 million or $1.55 per share compared to net income in the first six months of 2004 of $215 million or $1.20 per share.

Net earnings from the addition of Illinois Power, added $15 million to net income in the second quarter, and $36 million in the first six months of 2005 over 2004. After taking into account the 30 million shares of Ameren common stock we issued to finance the Illinois Power acquisition, the transaction has been accretive to earnings by about $0.11 per share since the September 2004 acquisition consistent with our expectations.

Earnings per share in the second quarter of 2004 reflected the dilutive effect of partially pre funding the Illinois Power acquisition. The impact of these shares now being covered by Illinois Power's earnings increased earnings per share by $0.8 in the second quarter of 2005 as compared to the second quarter of 2004. Clearly our electric sales volumes and related revenues in the second quarter of 2005 were significantly influenced by the acquisition of Illinois Power, the weather, and higher interchange sales.

Native load electric sales and revenues were up 26%, $299 million respectively. Excluding Illinois Power, native load electric sales and revenues were up 2% and $45 million respectively. Excluding Illinois Power, weather sensitive residential and commercial electric megawatt hour sales were up 9% and 3%, respectively in the second quarter of 2005 compared to the second quarter of 2004. Again, excluding the effect of Illinois Power, industrial electric megawatt hour sales in the second quarter were down 5% in 2005 versus the year-ago period primarily to the reduction of sales and low-margin power sales contract.

The addition of Noranda Aluminum as a customer on June 1st, partially offset these decreases. Hotter weather conditions in our service territory added an estimated $0.5 per share to earnings in the second quarter of 2005 versus the year-ago period. According to the National Weather Service, cooling degree days in the Company's service territory were 22% greater than normal and 6% above 2004 levels. Most importantly, it was hotter during the month of June when Ameren had higher summer rates in effect.

As Gary mentioned earlier we realize to strong interchange margins during the second quarter due to higher power prices and the increased availability of our low cost generating plants. Those margins were $0.16 per share higher in the second quarter of 2005 compared to 2004.

Reduced emission credits sales lowered second quarter 2005 earnings by $0.2 per share. We continue to evaluate our options for complying with the Clean Air Interstate Rule which includes the possibility of using our emission credits for compliance purposes. At this time, we are targeting emission allowances sales of $3 million to $10 million in 2005 versus $25 million in 2004. To date in 2005, we have sold approximately $3 million of emission credit allowances.

Acquisition related dilution and financing, reduced earnings by $0.4 per share in the second quarter of 2005 over 2004 principally due to the issuance of 7.4 million common shares of stock on May 15th related to our adjustable conversion rate equity security units and addition shares of common stock there were issued under our dividend reinvestment and stock purchase plan in our employee benefit plans.

Higher depreciation and amortization expenses due to increased capital additions reduced earnings by $0.2 per share in the second quarter of 2005 as compared to the year-ago period. In addition, higher employee benefit costs reduced earnings by $0.2 per share in the second quarter of 2005 versus the year-ago period.

In 2004, upon re-entering MISO, Ameren received a refund of fees paid when we originally exited MISO that benefited second quarter 2004 earnings by $0.6 per share. This benefit did not repeat in 2005, causing a negative year-over-year variance. Operations and maintenance and other expenses, decreased earnings by $0.6 per share in the second quarter of 2005 over 2004 principally due to higher labor costs and coal-fired plant maintenance expenses.

This concludes my comments on second quarter earnings. As Gary mentioned, this morning we increased our 2005 earnings guidance range by $0.10 per share to $3 to $3.20 per share. Our original earnings guidance for 2005 was $2.90 to $3.10 per share.

Our guidance assumes normal weather for the rest of the year and is subject to, among other things, plant operations, completion of the scheduled Callaway nuclear plant refueling and maintenance outage later this year as planned, energy market and economic conditions, unusual or otherwise unexpected gains or losses, and other risks and uncertainties outlined in Ameren's forward-looking statements.

I should also point out that this guidance range does factor in the impact of the current disruptions of coal deliveries that are expected to extend through the end of November, as well as our related strategies to manage our coal inventories as Gary discussed previously.

Of course, actual power plant performance, market conditions, weather induced demand for power, availability, cost of alternative coal supplies and the actual time required for the railroads to resume normal deliveries of PRB coal, could have a significant impact on the effectiveness of these strategies.

The principal reason behind increasing our 2005 earnings guidance is the increase in our estimate for interchange sales margins compared to our original expectations due largely to our generating plants's operating performance and higher than expected power prices in the energy markets. Today, we expect interchange sales to contribute $0.60 to $0.75 per share to earnings up from our original estimate of $0.40 to $0.55 per share.

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

[ OPERATOR INSTRUCTIONS ]

The first question is coming from Greg Gordon of Smith Barney.

One near-term question, one long-term question. You have raised your guidance for the year for how much you will earn on interchange sales and I scrubbed the numbers a bunch of different ways, are you basically saying that you are ahead of your guidance for the first six months of the year and you think that even though you have to curtail potentially the amount that you sell to the market because prices are up so much that you will this able to sort of make a consistent margin relative to your plan for the balance of the year? And if that is not the right way to think about it could you talk about that a little?

Good morning. With regard to our guidance for the year there are several factors to consider. Number one, certainly our guidance does incorporate the strong operating results that we have for the first six months of the year but we also factor in our guidance, our belief that interchange power prices will continue to be stronger, certainly, than 2004 for the remainder of the year.

Secondly, we factored into our interchange sales margins and in our belief that the fact that we have the Callaway nuclear refueling in the second half of the year and some of those interchange margins that we expand in the first half of the year will be taken away, at least in part, by the fact that we have our new customer, Noranda, which came on board on June 1st which will take away some of our link that we have had through the first six months. Frankly, those were all factored into our original guidance.

Secondly, as I said before, we have factored in some of the coal management strategies into our guidance. Indicative of the fact that we have had strong results for the first quarter and raised our guidance by $0.10, we will have an affect on our operations based upon our studies right now, we don't think it will have a material effect in the second half.

Two other factors that you have to keep in mind as we look through the rest of the year, we do have emission credits sales the we started off at the beginning of the year that we thought would go up as high as $10 million, our guidance now, reflects may be as low as $3 and go up to $10 so that is factored into our thinking.

I would say finally, the other issue we have seen is obviously we have been part of MISO for the first half of the we have seen some of the MISO related costs as being part of that system, a little bit north of what our original expectations were. Those factors, all of those things are really baked into our guidance to get us to really the upward movement of $0.10 per share.

Thanks. The long-term question is, I understand that in Missouri we're hopefully moving to a paradigm where you're adequately compensated for increases in fuel costs. When we move out to 2007, obviously you're going to have to go to the market to get recovery of what you think a fair value is for your generation output in Illinois.

Do you think that the current forward curves accurately reflect what you guys are seeing in terms of that 10% to 15% increase in fuel costs, fuel and transportation costs in '07, or do you think that there should be upward pressure on that '07 market as we approach the auction?

With regard to the -- it is difficult to predict weather the forward curve is really accurately reflecting those types of activities. One notable point to think about, at least in terms of prices, at least this year, the curve since '07 have reacted, it is too premature to say, but certainly we have seen as an indicator that prices here, I quoted a price for the CILCORP and CIPS contracts were about $52 to $53 based on 2005 prices. Literally, last quarter, that same price was around $48 to $49.

We do believe that, in part, that is being driven not only by natural gas prices, but the rising coal and transportation costs. As the markets shake out a little bit more, as -- it is because of this disruption as other utilities seek to hedge their supplies going forward and build up inventories that they will continue to see some coal and transportation cost pressures and we to believe the forward curve could indeed reflect more of those things looking ahead.

Thank you.

Next question comes from David Frank (ph) of Peak-One (ph) Capitol.

Good morning. Warner, I was wondering, is there a fixed place power contract between UE and Ameren Energy where UE sells Ameren Energy?

I'm sorry, David, say that again? Is there a --

fixed price contract?

Ameren Energy for UE acts as an agent to sell the excess power. That UE has available and to the available markets.

Is that done under a -- is there a contract in place? How is the price determined between what UE sells at and what Ameren Energy buys at?

Ameren Energy simply acts as an agent so there really isn't a sale to Ameren Energy, they're simply a marketer of that excess generation for UE and they take that into the power markets. Ameren Energy, there is no separate contract where there is a sales directly to them and they going to the market. They simply act as a marketer.

So it is basically market sale through Ameren Energy?

Through Ameren Energy and then reflected on UE's financial statements. Ameren Energy is a marketer too for our unregulated generation operation. They work off both of those entities.

I know we have talked a lot about Illinois. I came in a little late on the call. When do you expect or do you anticipate making a filing in Missouri?

With regard to Missouri, the only requirement that we have in terms of a rate study is that by the end of the year we have to file a cost of service study with Missouri Public Service Commission staff and other stakeholders. That is all we are required to do. Whether we do anything that would be in the form of a formal rate case filing remains to be seen.

But many factors will go into play there, one being the results of our cost of service study, but two, as I stated earlier, we are in the process of beginning the rulemaking proceedings for the fuel adjustment recovery mechanisms and environmental cost recovery mechanisms in Missouri and they will proceed as my belief through the end of the year and perhaps early into next, although a formal docket hasn't been established yet.

How those proceedings are playing out will obviously weigh into our decision as to what actions we take. We can't predict what actions other stakeholders including Missouri Public Service Commission staff may take as a result of our filing, but that's a whole other issue.

Congratulations on a great quarter.

Thanks, David.

Next question is coming from Ashar Khan, of SAC Capitol.

Good afternoon. Good morning, sorry. Warner, I had a note to myself that you were going to come close to a decision regarding your CapEx program going forward by the summer. I thought I would check in whether that decision has been made and if you can give us a better guidance as to -- because the range was pretty vast if I remember as to what the future CapEx would be. Is there any update to that?

I don't think we have said we're going to have something by this summer. We proceeded along this year, we continue to refine our guidance. We would expect to have further information to provide by the end of this year.

As we move, as we continue to move forward and work among ourselves that Ameren in terms of what we believe the appropriate environmental compliance strategy would be, as well as work with other key stakeholders along the way, we will then be in a position to share more fully what we expect that environmental compliance plan. We would expect that to be later in the year.

I apologize if you mentioned -- did you mention how much you were hedged in coal in '06, and '07?

Yes, we did. We stated that we expect to at least very soon to be virtually 100% hedged for 2006 coal and transportation supply requirements, and then approximately 90% hedged for 2007 for coal and related transportation.

Can we view, Warner, looking at the forward spreads that you see that this better performance in the interchange sales is as you stand right now, something which is sustainable like next year and going forward?

As you look ahead to next year, there are several factors you have to keep in mind in terms of the interchange margins. One certainly would be how you look at the power prices and what the forward curve may be and certainly a lot of indicators show that the power that the forward curve will continue to be solid given where gas prices are, and we talked about related transportation costs issues which will have an effect on that.

As you look specifically to Ameren there are a lot of things you have to think about. The rising fuel costs will be a factor but we have a Callaway outage, we will not have a Callaway refueling outage next year. That will give us some extra link that we normally would not have had.

That will be also affected by the fact that we have a full year of sales to Noranda, which is the largest energy user in the state of Missouri. They will become more of a native load customer and that will affect some of our excess power that we will have available for the interchange markets. As we get further along this year, as typically we do, later this year or early next, we will provide more detailed guidance in terms of how we view 2006 and specifically interchange margins.

One thing, the weather helped, but overall for the first six months it is not a big thing. I am just thinking that this new guidance is a new benchmark from which to grow earnings assuming that the power prices remain at the current level. Is that a fair statement?

That would probably be -- he would have to run through the analysis I just gave you. It would be premature to say this would be the benchmark to move forward. We are pleased with the results we have had this year. And of course, one of the things that is factored in this year is not just power prices but a solid generation we have had and obviously we look forward to continuing to have that as well as the fact that next year, when we have a significant refueling outage at Callaway, we do hope to add around 60 megawatts of capacity to Callaway, that is all positive. It is premature to say this is the benchmark for us to move off. We will give you more guidance as the year moves on and certainly as we give guidance for next year on that matter.

Could you share with us what your capacity factors were on the generation fleet?

Sure we can. With regard to the generation fleet for the quarter, in total, our net capacity factor was 78%.

Versus the previous year?

Approximately 72%.

The differences that Callaway, if you take the nuclear out the know what the remaining would be?

Basically I would say that our capacity factors were generally flat for the quarter when you exclude Callaway. Our coal-fired plants were probably in that 76, 77% range. That's actually very encouraging to us because we did have some additional outages as you might expect when Callaway is up and running, we often do more of our coal-fired outages, and a tribute to our generation that we had not only were able to overcome those outages but we were able to run during a time when power prices were high.

Warner, you still remain on track, one of your objectives was to improve the capacity and availability factor of the non nuclear fleet going forward. That process is still on track?

Ashar, this is Gary. I would say that it is. The point that Warner just made about the first half of this year performance is encouraging because expected the capacity factor was expected to be down somewhat for the coal fleet, but it actually held where it was last year. And going forward, we still expect to improve capacity factor and availability by about 1% per year for the next several years.

Thank you very much.

Next question is coming from Daniele Seitz of Maxcor Financial.

I was wondering if you could remind us of the load that is dedicated to Noranda, or approximately.

The Noranda contract is approximately 470 megawatts.

Related to that $0.60 to $0.75 of interchange sales margin, was that somehow this load will be dedicated more to Noranda? I am assuming this represents roughly one-third of what the availability capacity is normally? Or is it hard to tell?

It is a little hard to pinpoint. Noranda was only in operation for one month during the quarter number one. Noranda is going to show up as an industrial electric sale. They will not show up in the interchange.

It is a difference in margin?

Earnings are regulated return, margins on Noranda, which is an around-the-clock customer versus the interchange sales. It is hard to pinpoint the specifics on the margins there.

If you have no Callaway refueling next year, roughly refueling is roughly $0.20 or so, is this to look at its or could it be less or more? For next year?

When you look at our guidance slide that we had last year, Callaway refueling outage which was a 64 day outage cost as $0.20 per share. This year, we put a nickel plus and a nickel - around that due to the nature of the outage and the extension going from 70 days to 75 days. It is anywhere from $0.15 to $0.25 in terms of what we expect the impact of the Callaway outage to be on our operations this year.

For that line item alone, that will not repeat next year. Assuming that Callaway operates as planned. Again, with Callaway being up and running all next year, as I said before, we likely will have some incremental coal-fired unit outages when Callaway is up and running. That will be a mitigating factor in part, but we don't have the details around that at this that in time.

One more question, in Missouri you are anticipating two separate increases in fuel costs. Environmental costs from the rest of the issues in your cost study or everything is going to be reviewed together in January?

The way we will prepare the cost of service study since it won't be a rate case filing, it will be a study that will be basically all in. It will reflect both our costs for fuel and environmental, at least that's what we expect to do at this time.

When an actual rate case would be filed and depending upon how the rules and regulations play out for fuel and environmental cost recovery mechanisms, that will dictate how a formal rate case will be played out for those two items whether there are separated out or embodied in a recovery mechanism or some combination thereof.

Aside from normal accretions, what would make a normal rate case in Missouri would be the added capacity and are there any other major elements as well? That you should think about?

In terms of a rate case, any time you have that there are a lot of elements to consider. Returns on equity, operating expenses that you have, we have talked about fuel and coal and transportation costs, employee benefits, certainly rate based additions, these are all things that you have to factor into.

Other issues we have dealt with in the past in Missouri relate to things like depreciation expense, joint dispatch agreement, these are all issues that we have dealt with in the past that I am certain as we move forward into another rate case we will address in some form or fashion in the future.

From looking at roughly, do you feel that currently your [INAUDIBLE] would justify going in especially since you added some capacity or it is hard to tell at this point?

It would be premature to say at this point. When we file the cost of service study, that will be a milestone in the process. But other milestones will include the fuel and environmental cost recovery mechanisms among other things, it would be premature but as we have said in the past we will have made meaningful capital additions and certainly costs in many aspects of our business will be going up and other things will be factored into the overall equation in terms of revenues and things we're seeing in the power markets as well. All of those things will be put in there and we will give you more insight on that a little bit later this year if not early next.

Thank you.

Next question comes from Steve Fleischman of Merrill Lynch.

Hi, Steve.

Is there any way to break out of this $0.70 or so of interchange between Missouri UE and Illinois?

You're speaking specifically of the guidance we are providing? How much of that is Missouri and how much is Illinois?

Yes.

Generally speaking to that breakout has been anywhere from 60% to 70%, generally speaking dependent upon the year. That is a pretty good rule of thumb.

To Missouri.

Yes.

When you think about the fuel clause and the Environmental, some kind of rate review, etc. How should we think about these interchange sales from Missouri? Is that going to be netted out in the fuel clause? How should we think about that component of it?

The simple answer is it is too early to say. That is one of the things that will be addressed in part to during these rulemaking proceedings, whether the fuel adjustment writer will reflect off-markets or off-system sales directly in the fuel rider whether there will part of base rates or a combination thereof.

Was there any guidance in the law or anything the commission said on that yet?

There's no specificity around that. That is what the rulemaking proceedings would consider as well as potentially incentive related types of mechanisms around those things. Those are things that will probably be addressed over the next several months.

And in the rulemaking process of?

It could be. It will clearly be addressed. Whether the rule making process will say this is how it will be done remains to be seen. One of the things in Missouri, which is a little bit unique, is the fact that among all utilities in Missouri, off-system sales are distinctly different between many electric utilities. Whether a formal rulemaking will be definitive around that is probably too premature to say. I am certain it will be discussed.

I guess my other question is on the hedging of the coal and looking out to 2007 where you are 90% hedged, I know we haven't had this auction in Illinois yet, but are you hedging out more of your power at the same time in just the wholesale markets to match your coal or are you waiting for the auctions?

With regard to our overall hedging strategy obviously it is premature to to get into specifics of how we're doing it. But we have the opportunity to not only hedge some of the 3,000 megawatts which will come off over these CIPS and CILCORP contracts and forward sales whether it be the auction or not.

But we also have some other contracts which are coming off during this period of time over the next several years that are longer term contracts which typically three to five-year contract which are rolling off. That will be put together in our whole portfolio and a strategy will be developed and worked on as we speak in terms of how we will hedge those open positions.

Today, you may be haven't done a lot of hedging of that?

It is too early for us to give specifics on that guidance.

It would be helpful to get a sense of how much you are open or not. I do appreciate you giving the detail on the fuel.

We appreciate that and understand you're coming from. We just want to make sure we're careful in not giving out information which would be premature of how we want to hedge our portfolio.

One last quick question, when you gave the Illinois data when you testified 10% to 20% rate increase, do you recall what the generation price assumption was when you gave that?

To be honest with you, Steve, I don't. When we talked about that we were using generation prices around that time which was in the March hearings so if you look in February, March timetable that was the types of prices we're using, I don't know the specific number but it was pretty much a standard price for a similar contract.

Thank you.

Next question comes from Douglas Fischer of A.G. Edwards.

Congratulations on a solid quarter. A lot of ground has been covered in the Q&A but just one small question. In your guidance, are you assuming normal weather for the entire year now? I was looking back at some of your prior guidance and I don't think the weather impact has changed versus the current guidance. We've had a hotter than normal second quarter, we had a fairly hot July. Comment on that if you would.

Generally speaking we look at our guidance, we assume normal weather and that is basically what we have assumed. It is interesting, there is an article in The Wall Street Journal talking about the sweltering heat and we've certainly experienced some that in the second half of July.

It is a mixed bag in terms of the first half and the last couple days have been drop-dead gorgeous in the area, not great for the utility business relatively speaking but gorgeous to the outside. It is early to say how much weather is going to affect our July results, but our assumption to answer your question explicitly assumes normal weather for the rest of the year.

Thank you.

Next question comes from Ben Sung (ph) of Luminous Management.

My questions have been asked and answered. Thank you.

Next question from Douglas Lee of UBS.

Good morning. In your prepared remarks you had discussed the idea that rising fuel costs have impacted the unregulated margins but that our prices have also been rising. Can you please quantify for us what the net effect has been year-to-date and what you expect it to be for the year?

With regard to that matter, what we have said was that we are seeing certainly with regard to 2005 our original guidance was that coal and transportation costs going into this year would rise 3% to 5% and that has not changed. It continues to rise 3% to 5%, we are employing some strategies around our coal management inventories but as I said before they have not been material.

To say how prices have risen, or one-to-one offset it is impossible to say, the bottom line is you look at our guidance and we have taken it up by $0.10 per share, factor in a lot of the other things I mentioned earlier in the call. Is impossible to do a one-for-one comparison.

Doug, this is Gary. While we can't give you the numbers that you're looking for, I can give you a little better perspective on it. If you look at the rise in the market price of $4 to $5 per megawatt hour, that would equate to a $0.40 to $0.50 per million BTU increase in fuel prices which is something like 30% to 40% increase. I don't know that the market is being driven to that extent by the rise in fuel prices, but the fuel price increase that we have seen so far is substantially greater than the movement in coal prices.

Thank you, that helps.

Next question is from Scott Ingstrum (ph) of [INAUDIBLE] Management.

Wondering if you had that net income numbers at the operating subs -- the reporting subs.

We are happy to give those to you. We should have anticipated that. We have it right here. For the three months ending June 2005 for the quarter Union Electric was at $130 million, CIPS was $7 million, Genco was $31 million, CILCORP was $2 million, and Illinois Power was $15 million.

Thanks a lot.

Next question is from Zach Schreiber of Duquesne Capital.

Hey, Warner, it's Zach.

Hey, Zach, how are you doing?

Good. How are you, sir?

I'm well, thanks.

Congratulations on a good quarter. A question in terms of coal price issue, the PRD issue, buying economically available Illinois basis coal, can you talk to us about the coal price of per ton was of the PRB stuff that you contracted, the contracted price on that, some of the market prices where the prevailing market is versus the Illinois. And what the heat rate, heat and the sulfur are so we can actually -- we always take your word but to realistically do some of the math ourselves to understand some of that. And do you guys need to procure two credits, or do you withhold your bank and use it for your own accounts against now burning through some of your Illinois Basin coal, and is that why your holding back on the S02 sales?

Hi, Zach. Your -- there were pieces that were kind of breaking up. I will do the best I can in terms of answering your questions.

With regard to the Illinois purchases of coal, one piece I should give you is the strategy we have employed but I wouldn't suggest in terms of our total coal buy, is significant. We have done a little bit of that it, but I wouldn't suggest that the amount of Illinois coal we purchased in the bigger picture is significant.

We're always hesitant to give out specifics and we don't give out specifics in terms of our specific buys under specific contracts. But I think that purchase that we have done, the purchases we have done there, as well as the rest of our strategies, are reflected in an overall guidance for the rest of this year. That's what we have to say on the Illinois piece.

Now, you asked a question, I think, on the emission allowances which I really couldn't understand. Could you ask that again?

It seems like the emission allowances this year and that you're planning on selling are actually lower than what they have been historically and I was wondering if that was partly because of these PRB issues, selling in excess of the market's to keep it for your own accounts as you burn dirtier coal.

I understand. The view on that, backing off of the emission allowance sales is principally driven more by a broader environmental compliance strategy as opposed to the things which are going on in the coal markets and the purchase of the Illinois coal and the need to use an existing emission allowances. You shouldn't conclude that there is a direct relationship. To say that there is a factor you need to think about, yes, I wouldn't say it is significant at all.

Thank you. Great quarter.

Thank you.

Last question is from Dan Jenkins of State of Wisconsin Investment Board.

Good morning. On the Noranda sale, you said that started in the beginning of June. For your 2005 guidance, how much of the sales growth is Noranda addition as a customer?

As we went into 2005, I think the final details of the regulatory approval is where we are not consummated at that point we factored in the Noranda contract beginning on June 1st into our 2005 guidance. When you look at our sales growth line of $0.10 to $0.20 per share, that reflects the Noranda contract from June 1st, onward.

Which is a meaningful piece of that sales growth on a year-over-year basis because we didn't have Noranda last year. As we went into the year, we talked how that Noranda sale was going to impact our interchange sales margins. Originally we expected that interchange sales margins might have gone down. Things have changed since then but clearly, we expect a little bit of a flit between interchange sales and sales growth going into the beginning of this year and we still believe that.

If you include the bulk of those pieces, what is the addition from both of those pieces working together?

When you look at it depends on what you view as power prices, we went into the Noranda contract hoping to be relatively neutral in terms of what the interchange margins we were losing versus the sales growth that we would have for this around-the-clock type of customer. With interchange margins, power prices moving up there may have been some opportunity losses there, but no more than that. In terms of original guidance it has little effect if not any.

What I am trying to get at is -- you can't break out how much of the sales growth is from Noranda and how much was everything else?

$0.10 to $0.20 we're talking about now, Noranda for the year will be about a dime roughly.

Okay.

Of that $0.10 to $0.20, about a dime of that might be Noranda.

Obviously that would affect the 2006 guidance as well because you don't have 12 months instead of seven.

That is fair. That is correct.

Beyond Noranda you mentioned industrial sales were down because I think you said some contracts is down 5%.

Yes.

In the quarter. Could you expand on that? Just this weak industrial sales. Could you give me more color on what is behind that?

The issue with the low-margin sales, the same phenomenon that we talked a little bit about in the first quarter. We have some sales of the Illinois service territory that we really back up purchase power, isn't backed up with our generation. It is essentially low-margin sales contract that we purchased power and we enter into the northern part of the service territory, not our service territory but the Commonwealth Edison service territory, and make some sales there and we have historically done it in the margins probably a year or two ago were more favorable.

Some of those contracts are rolling off, not renewing those but they are generally low-margin sales. It is a similar type of phenomena and we saw in the first quarter that we are experiencing here. There's a meaningful pact relatively speaking in terms of sales but little on the bottom line.

So you are not pursuing those sales?

That is correct.

What would industrial sales in your base territories? Do you have a feel for how much those were minus the Noranda impact? Was it decent?

Yes, Dan. They are relatively flat. We normally expect to see very low industrial sales growth over a year as we've seen 0% to 1%. We have seen a shift in our economy from industrial to commercial with strong commercial growth but very low industrial.

Given your purchase of Illinois Power, your power costs have gone up 20%, your generation sources, I was wondering what impact the coal situation might have on those costs in your margins?

When you think about Illinois Power we are locked in for the vast majority of our Illinois Power needs through 2006. As we announced the deal for Illinois Power we entered into a supply agreements with Dynegy for approximately 70% to 75% of those needs and we have hedged a good portion of the remaining piece of that for 2005 and continue to do so for 2006 for Illinois Power. Post 2006, Illinois Power will be just like CIPS and CILCORP. They will participate in the auction process and they will receive their generation through the auction process and what will happen based upon at least everything that has been filed today is that the result of that auction process will be recovered directly from customers.

So you don't think the higher coal prices won't be a problem for your purchase power than the recovery of that?

And to the current contract in Illinois we have proposed with the ICC staff has proposed, other parties to the case proposed including Commonwealth Edison, those costs would be recovered directly from customers as resulting from the auction process. There are some that disagree with that but at least at this point in time that is the direction it appears to be heading.

The last thing I was wondering about, it looks like from your guidance, CapEx and dividends are about $160 million higher than cash flow and you also have $250 million maturities in the second half. I was curious if you could talk about what you're financing plans are in the second half. Would that come mostly from your and aces? What are your plans?

I'll have our Treasurer Jerre Birdsong address some of those issues?

Yes. We have got the cash to cover the maturing debt that you're referring to later in the year. Any other financing plans if you notice there is a short-term debt balance at Union Electric and that very well could be termed out but that should be about the extent of the financing for the remainder of the year.

Thank you.

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