阿莫林 (AEE) 2005 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Ameren third quarter earnings conference call.

At this time, all participants in a listen-only mode.

Following today's presentation, instructions will be given for the question-and-answer session. If anyone needs assistance at any time during the conference, please press the star followed by the zero. As a reminder, this conference is being recorded Tuesday, November 1 of 2005.

I would now like to turn the conference over to Bruce Steinke, Manager of Investor Relations.

Please go ahead, sir.

Thank you, [inaudible]. Good morning, everyone. I'm Bruce Steinke, Manger of Investor Relations at Ameren Corporation. Here 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, our Vice President and Treasurer, Jerre Birdsong, and other members of senior management.

Before we begin, let me cover a few administrative details.

This hour-long call is available by telephone for one week to who anyone wishes to hear it by dialing in the playback number. The announcement you received in our news release carries instructions on re-applying the call back telephone.

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

I also need to let you know that comments made on this conference call may contain statements 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 and the forward-looking statements and risk factors sections 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 third quarter and first nine months of 2004, to our earnings per share for the third quarter and nine months of 2005, on a comparable share basis. In addition, this presentation includes a slide that compares our 2005 earnings guidance to full year 2004 earnings. To access the presentation, you may look in the investor section of our website under presentations or follow the link for the webcast.

Gary will begin this call with an overview of our third quarter 2005 results and some operating and regulatory matters. Warner with then follow with a further update on regulatory matters and a more detailed review of third quarter results. We then open it up for questions.

Thanks, Bruce.

Good morning, and thank you for joining us.

This morning we reported earnings of $1.37 per share for the third quarter of 2005. As compared to earnings of $1.20 in the third quarter of last year.

For the first nine months of 2005, Ameren reported earnings of $2.94 per share, compared to earnings of $2.44 per share in the prior year period.

Significantly, warmer summer weather and earnings from Illinois Power, acquired on September 30 last year, drove an increase in Ameren's earnings per share in the third quarter of 2005 compared to 2004. These increases were offset in part by higher fuel and purchased power costs and higher operating expenses at our Callaway nuclear plant due to the start of the 70 to 75 day refueling and maintenance outage on September 17, 2005.

Several factors drove our fuel and purchase power costs during the quarter, including increased electric sales levels, increased usage of gas-fired generation, and increased coal and related transportation cost. In addition, fuel and purchase power costs rose to due to higher expenses associated with our participation in the Midwest Independent Transmission System Operator, or MISO Day 2 Markets. As we discussed in the past, we had expected to incur higher operating expenses due to our participation in MISO, however, the actual charges incurred were higher than we had anticipated.

In part, these higher charges were due to volatile summer weather patterns and related loads. In addition, we attribute some of these higher charges to the relative infancy of the MISO Day 2 markets. We'll continue to fine tune our operations and work closely with MISO, to ensure that the MISO Day 2 markets operate more efficiently and effectively in the future.

Our fuel and purchase power costs were also higher due to some unscheduled outages at our coal-fired power plants during the quarter. The availability of our coal-fired plants in the third quarter decreased from 94% in 2004, to 92% in 2005. However, due to the warm weather and strong market prices for power, the capacity factors of our coal-fired power plants in the third quarter increased from 79% in '04, to 82% in 2005.

Last quarter we updated you on disruptions in coal deliveries from the Powder River Basin for our plants, due to rail maintenance on the joint Burlington-Northern, Union Pacific line. Overall railroad performance during the third quarter was consistent with our expectations with deliveries in the range of 85% to 90% of scheduled levels.

Unfortunately, additional coal delivery issues arose in October. Two bridges on the Union Pacific rail line were washed out and large sections of track were damaged by heavy rains near Topeka on October 1. Since that time, the tracks have been temporarily repaired. However, significant levels of congestion have resulted.

In October, deliveries approximated 80% of scheduled levels. We expect deliveries to steadily improve over the remainder of 2005, and based on information provided to us from the railroads, we expect to begin receiving scheduled levels of deliveries by year end.

We continue to employ coal conservation measures similar to those we put in place earlier in the year. Through the third quarter, those measures have in part impacted our interchange margin opportunities. Looking ahead in the fourth quarter, we expect these measures to increase our costs to serve our native load customers, as well as impact future interchange margin opportunities. While we expect these measure to have somewhat of a dampening effect on 2005 earnings, we believe these measures are prudent and will permit us to operate the coal-fired generation fleet effectively and reliably throughout the rest of this year and better position us for future opportunities.

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

Closing my discussion on operations, on September 17 our Callaway nuclear plant began a scheduled 70 to 75 day refueling and maintenance outage, reducing third quarter 2005 earnings by an estimated $0.03 per share. During this outage, which is the most extensive in Callaway's history, we will refuel the plant and replace the steam generators and turbine rotors. We believe these improvements will improve the reliability of the plant and increase plant capacity by approximately 60-megawatts. At this time, the outage is on schedule and is expected to be completed later this month.

Now moving to regulatory matters. As most of you know, there's been a great deal of activity going on in Illinois, in determining how our Illinois distribution utilities will transition for a different framework after the current electric rate freeze expires at the end of 2006. Transitioning to this new framework requires that our Illinois utilities determine how they should procure power from the wholesale market place and so it's utilities no longer own significant amounts of generation. It also requires that we determine how we -- how they should recover power costs from customers. In addition, our Illinois utilities will need to update their electric delivery service charge tariffs.

By the end of 2006, the bundled electric rates for our Illinois utilities will have been flat or declining for 15 to 25 years. In late September , we filed an 10-K with the SEC, in which we estimated that the average bundled of electric rates for our Illinois utilities on a combined basis, may increase by 20% to 25% in 2007, over present bundled rate levels. That estimate was based on a number of assumptions about electricity consumption, market prices for power, and the type of power supply product to be procured. It was also based on future auction results, rate base levels, operating and financing costs, rate making outcomes, and various other factors. Course, actual results could be significantly different from these assumptions.

We also believe that it's time to adjust our electric delivery service rates for Ameren, CIPS, Ameren Celco, and Ameren IP, in order to recover the significant infrastructure investments that we've made as well as recover higher operating costs. As a result, we planned to file delivery service rate cases by the end of this year.

Since our Illinois utilities no longer own any significant generation, we also have proposed to the Illinois Commerce Commission the use of a transparent and highly competitive auction process for the procurement of power for our Illinois customers. Our proposal also includes a mechanism for recovery from customers of the power supply costs our Illinois utilities incur from the auction process. We believe this type of auction will result in the lowest costs for our customers and is consistent with existing laws and regulatory policy. Our auction proposal is also consistent with recommendations made in last year's ICC-sponsored workshops, and has been supported by the ICC staff, the supplier and customer groups, in testimony filed with the ICC.

Hearings on our proposal were held by the Illinois commerce commission in early September. We expect a proposed order from the administrative law judge in the case in late November or early December and a decision by the ICC in January.

As you probably know, there has been opposition to the auction process. Last summer, the Illinois Attorney General, the Citizens Utility Board, and the Environmental Law and Policy Center filed a motion to dismiss the auction proceedings with the Illinois Commerce Commission. We filed responses opposing that auction.

In our opinion, their arguments relied on an incorrect interpretation of the Public Utilities Act. In July, the Illinois Commercial Commission unanimously rejected the motion to dismiss the auction proceedings. In early September, the Illinois Attorney General, Citizens Utility Board, and others filed suit against the Illinois Commerce Commission and the individual commissioners in the Circuit Court of Cook County, Illinois, alleging, again, that the ICC did not have authority to approve the auction. That suit basically raised many of the same legal arguments that were made in the Illinois Commerce Commission proceedings.

We intervened in the Cook County case and have filed similar defenses. We expect a hearing in this case in mid-December.

In early September, the Governor of Illinois also indicated, in a letter addressed to the ICC Commissioners, his opposition to the auction process, as well as any -- to any increases in electric rates after the rate freeze. As many of you know, we replied to the Governor in a letter dated September 15, and filed a related 8-K at that time.

Subsequent to the governor's letter, Illinois Commerce Commission Chairman, Edward Hurley resigned. Governor [Blagowavich] immediately nominated [Martin Cohen] to replace Mr. Hurley. Mr. Cohen was previously the Executive Director of the Citizen's Utilities Board, which is a leading consumer advocacy group in the state. In a September letter to Mr. Cohen and later with the complaint filed with the Illinois Circuit Court in Sengamen County, we have sought Mr. Cohen's re-accusal from our ICC auction case and the Illinois attorney general's lawsuit due to Mr. Cohen's participation in in case as head of the Citizen's Utilities Board.

Recently, Mr. Cohen agreed not to participate or conifer with any ICC commissioners or staff, regarding these cases without notifying us 30 days in advance or until this matter is resolved in the courts.

Finally, in late September, Moody's placed our Illinois utilities on review for possible downgrade, and in early October, Standard & Poors lowered Ameren's credit rate from one notch, from triple B-plus to from A-minus, and placed the rating on negative watch. Both credit rating agencies attributed their actions to, among other things, the heightened political nature of the regulatory environment in Illinois, and related uncertainty about whether our Illinois utilities will fully recover their costs of provided generation and distribution services to their customers on a timely basis.

As I said earlier, there's been a great deal of activity in Illinois recently, all of which makes it rather complicated for investors to follow. So let me summarize Ameren's views the post-2006 Illinois situation.

By 2007, it will be 15 to 25 years that the bundled electric rates for our Illinois utilities have been flat or declining. This is simply no longer sustainable. Ameren's CIPS and Ameren's Celco own virtually no generation, and we purchased Ameren IP without generation.

At the end of 2006, all contracts procuring power supply for our customers will come to an end. As a result, Ameren's Illinois utilities will have no choice but to go to the wholesale marketplace to purchase power to meet their load requirements. In fact, the ICC mandated Ameren's CIPS and Ameren's Celco to bid out their power supply needs.

We believe our current power procurement auction proposal is legal and will result in the lowest possible costs to our customers. With that said, based on current market prices for power, coupled with increased operating costs and infrastructure investments for our Illinois utilities, we believe our customers could experience meaningful bundled electric rate increases over current bundled rate levels.

Based on federal and state laws and regulatory policies, we strongly believe that we're legally entitled to full recovery of all of our costs of providing generation and distribution services on a timely basis and have made the legal right to sell our unregulated generation at market rates in the wholesale market place. Any regulatory legislative or judicial action that denies our ability to sell our unregulated generation at market rates or impairs the ability of our Illinois utilities to fully recover their costs in a timely fashion will result in legal challenges.

As we've said in the past, we will take all necessarily steps to protect our legal interests in this matter. We certainly would not make these actions lightly, but such regulatory, legislative, or judicial actions could result in a host of adverse consequences, including lower credit ratings, loss of access to the capital markets, higher borrowing and power supply costs, and, in the extreme, bankruptcy of our Illinois utilities. While we believe bankruptcy could occur in only the most extreme circumstances, we're carefully evaluating actions, which may need to be taken to protect our financial and legal interests.

These statements were not made to threaten any key stakeholders. They were made to simply inform key decision-makers of the importance of these issues. The recent actions and statements made by the independent credit rating agencies lend further credence to our beliefs.

Having said all this, we stand ready to work with key stakeholders to develop a constructive solution to these issue,. including the development of a rate increase phase-in plan that incorporates full and timely recovery of our costs and allows our Illinois utilities to maintain their existing credit ratings. We strongly believe that this path will result in the best solution for our customers, investors, employees and the State of Illinois.

As a result, we're harnessing as much internal effort on coming to a constructive solution, as we are on other legal and financial fronts that I mentioned earlier. While proceeding down this path could take several months, in the end, we believe a thoughtful, more constructive solution is much better than an ill-conceived expedient solution. Rest assured that we'll work hard to protect our legal and financial interests to best serve all stakeholders. With that, I'll turn this discussion over to Warner.

Thanks, Gary.

Before I begin my discussion about third quarter earnings, I would like to update you on a few key regulatory issues in Missouri. As we stated last quarter, earlier this year, Senate Bill 179 was signed into law. That law enables the Missouri Public Service Commission to provide utilities with fuel and environmental cost recovery mechanisms. That law also includes that rule-making procedures be conducted to spell out more of the details as to how these cost recovery mechanisms will work. Round table discussions began in August, and we expect private rules to be filed for public notice by year end. Consequently, these rules could be effective in first half of 2006.

As many of you know, our electric rates are frozen Missouri until June 30, 2006. We're required to submit a cost-of-service study to a Missouri Public Service Commission staff and others by January 1, 2006. Based on the results of that study, and the status of the fuel and environmental cost recovery rule-making 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 others will review our study and, based upon their analysis, may also make rate recommendations.

Separately, we expect to file an amendment to the joint dispatch agreement, or JDA, between Ameren UE and Ameren Energy Generating Company with the Federal Energy Regulatory Commission. This filing will request that the JDA be amended to allocate interchange sales margins based on generation as opposed to load. This will result in greater interchange sales margins being allocated to Ameren UE. This filing is consistent with the Missouri Public Service Commission order issued earlier this year approving the Illinois service territory transfer from Ameren UE to Ameren CIPS.

I would now like to refer you to our website, as I provide a more detailed discussion of our third quarter 2005 earnings.

As Bruce mentioned earlier, we have posted a slide presentation on our website, that reconciles our earnings per share for the third quarter and first nine months of 2004, to our earnings per share for the third quarter and first nine months of 2005, on a comparable share basis. In addition, this will presentation includes a slide that compares our 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, in order to allow for an easier, year-over-year analysis of our pre-acquisition operations.

In the third quarter of 2005, we reported net income of $280 million, or $1.37 per share, compared to net income in the third quarter of 2004 of $232 million or $1.20 per share. For the first nine months of 2005, we reported net income of $586 million or $2.94 per share, compared to net income in the first nine months of 2004 of $447 million or $2.44 per share.

Strong electric sales from warmer summer weather and earnings from Illinois Power drove net income for the quarter higher. These increases were offset in part by higher fuel and purchase power expenses and higher operation and maintenance expenses.

According to the national weather service, cooling degree days in the Company's service territory were 53% above 2004 levels, and 16% greater than normal in the third quarter of 2005. Excluding the effect of the Illinois Power acquisition, residential and commercial electric sales increased 22% and 8% respectively in the third quarter of 2005 compared to 2004. As a result, earnings per share on the third quarter of 2005 benefited from warmer weather, by an estimated $0.20 per share as compared to the year ago period.

The contribution from interchange power sales margins decreased $0.06 per share in the third quarter of 2005, as compared to the prior year, due largely to a 42% decrease in these sales year-over-year. The decrease in interchange sales was largely due to less excess power available to sale, as a result of the addition of Noranda Aluminum as a customer, warmer weather driving increased native load demand from residential and commercial customers, coal conservation efforts, and the scheduled refueling and maintenance outage at the Callaway nuclear plant that began in mid-September.

However, interchange revenues benefited from higher power prices. Interchange revenues averaged $46 per megawatt hour in the third quarter of 2005, versus $28 per megawatt hour in last year's third quarter as higher coal and natural gas prices, coupled with strong demand, drove power prices higher during the quarter. -- sales growth margins were generally flat during the quarter, as organic growth in sales, including the addition of Noranda Aluminum as a customer, were offset by higher fuel and purchase power costs.

Several factors drove the increase in fuel and purchase power expenses during the quarter. Of course, higher sales levels caused these expenses to rise. In addition, due to hot summer peaks experienced throughout the quarter, we were required to run our gas-fired generating peakers more often to meet native load requirements.

We also experienced incremental unscheduled outages in July and August at some of our coal-fired power plants. This caused an increase in purchase power cost.

However, one of the more significant contributors to our increases in fuel and purchase power expenses were higher incremental costs of operating in the Day 2 energy markets of MISO, as Gary discussed previously. We estimate that MISA Day 2 operations negatively impacted our quarterly earnings by $0.10 per share. Higher fuel and purchase power costs were offset, in part, by gains from admission credit transactions of approximately $12 million, or $0.05 per share. As Gary mentioned earlier, our Callaway nuclear plant began a scheduled 70 to 75 day refueling and maintenance outage on September 17, reducing third quarter 2005 earnings by an estimated $0.03 per share.

Net earnings from the addition of Illinois Power added $53 million to the net income in the third quarter and $89 million in the first nine months of 2005 over 2004. Earnings per share in the third quarter of 2004 reflected the dilutive effect of partially prefunding the Illinois Power acquisition. The impact of these shares now being covered by Illinois Power's earnings increased earnings per share by $0.14 in third quarter of 2005 as compared to the third quarter of 2004.

Net dilution and financing costs, excluding Illinois Power- related financing, reduced earnings by $0.01 per share in the third quarter of 2005 over 2004.

Depreciation and amortization expenses higher due to capital additions and reduced earnings by $0.02 per share in the third quarter of 2005 as compared to the year ago period. Reduced employee benefit costs benefited earnings by $0.02 per share in the third quarter of 2005 versus the year ago period, principally due to lower post-employment benefit and medical costs.

Operations and maintenance and other expenses were favorable to earnings by approximately $0.03 per share in the third quarter of 2005 over 2004.

Finally, in the third quarter of 2005, we also took a one-time write-off of $0.04 per share for a leveraged lease investment associated with Delta airlines. Our leverage lease investments now approximate $124 million. Consistent with an SCC order in connection with the acquisition of Silcorp, we have been evaluating the potential divestiture of some or all of these investments.

This morning, we also re-affirmed that we expect our 2005 earnings to range between $3.00 and $3.20 per share, consistent with previous expectations. Since our second quarter conference call, we have modified several line items on our earnings guidance slide based on our third quarter results and expectations for the remainder of the year. This morning, I will address a few of the more notable changes that we made from last quarter.

We do expect ongoing coal conservation efforts to negatively impact native low margins, as well as interchange margin opportunities for the remainder of the year. For the year, we now estimate that native low margins will be $0.03 to $0.07 per share greater than 2004. In addition, we estimate that margins from interchange sales will be $0.16 to $0.24 greater than 2004, as we expect market prices for power to remain robust for the remainder of the year.

In addition, based on our experience to-date on the MISO Day 2 energy markets, we expect MISO Day 2 operations to negatively impact earnings by $0.21 to $0.28 per share over 2004. And finally, we expect gains from the admission allowance transactions to more closely approximate gains recognized in 2004. Of course, our guidance assumes normal weather for the rest of the year and subject to, among other things, plant operations, completion of the scheduled Callaway nuclear plant refueling and maintenance outage in November 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.

This completes our prepared remarks.

We will now be happy to take your questions.

Thank you, sir. Ladies and gentlemen, at this time we will begin the question-and-answer session. [OPERATOR INSTRUCTIONS]

And our first question is from [David Frank] with [Peak-One Capital].

Please go ahead.

Hi. Good morning.

Good morning, David.

Warner, you mentioned the structuring of the joint [inaudible]. Could you give us a little more detail on how that actually works? How it works now, and how it will function under the restructuring proposals?

Sure. Basically, the joint dispatch agreement, the way it works today, is that it's between Ameren UE and Genco, Ameren UE generating Company. Basically, under that agreement, UE and Genco can basically dispatch jointly their operating units to serve their native load needs. Basically, under the joint dispatch agreement, however, UE, for their own generation as first call on their generation and Genco for their native -- for their native load needs as first call on their own generation, and to the extent that there's any excess generation available on either side, due to power supply needs, then those energy transfers are transferred between those two entities at incremental costs. What we will be doing at the end of the year, consistent with the order from Missouri Public Service Commission earlier, is allocating some of those interchange margins, which are now based on load factors, in the future will based on generation. And that's -- that's an agreement that we made as part of that transfer order.

I guess the part I'm confused on -- at the end there, you said what margins were -- as a percent of load factor or [inaudible]. I'm sorry.

Historically, they were based on loads, going forward, they will be based on generation.

So what the -- what we believe, then, that the result will be is that greater levels of interchange margins will be allocated to AmerenUE versus the way they are now. In our filings back in probably a year or two ago, we estimated that incremental margin transfer would range anywhere from 7 to $24 million, but of course, that was based on power prices at that time. So just to tell you what we've put in testimony around this particular issue.

Do you -- do you allocate maybe in terms of percent what that meant -- $24 million of that [inaudible] 10% of the margins or 50% of the margins? Do you have it broken out that way?

I think -- we have not broken that out, David. I would generally think it's not a very big percentage. It's certainly not in the level of 50% of the margins, but again, keep in mind, even though we allocate these margins, we're under a rate freeze in AmerenUE through June 30, 2006. So should the FBRC even agree to do that say by January 1 of next year, which I'm not suggesting they would, nothing really changes until rates are ultimately reset at UE. This would then just be be part of the regulatory framework in the resetting of rates for AmerenUE as I discussed a little earlier.

Okay. Alright.

Thank you.

You're welcome.

Thank you.

Ladies and gentlemen, if you're having difficulty viewing the slides and media players, you will need to close the player and open it, or go to the presentation area of Ameren's website.

And our next question is from [Ed Hine] from Citigroup.

Please go ahead.

Good morning.

Good morning.

I was wondering if you guys could comment in regards to the Illinois situation. Should we expect to see you guys take some noticeable steps to insulate your credit quality at the Illinois utilities versus the parent? And if so, what would be the time frame on that, and what sort of steps would you take?

Well, I think when you look at our Illinois utilities, I don't know if you'll see any immediate steps to try to improve the overall credit quality. As Gary mentioned a little bit earlier, we are taking a look at issues to make sure that we protect ourselves from both the legal and financial interests, in terms of what potential actions may be in the future. If that's what you're talking about, we continue to make that study. When we look at our overall -- currently at our Ameren Illinois utilities, certainly with CIPS and Silcorp, while we've had a downgrade at the Ameren level, those credit ratings still remain strong. As you know, we took Illinois Power from sub-investment grade to above-investment grade, and our desire as we look forward through any future regulatory construct in Illinois, is to maintain those existing credit ratings with any potential regulatory frimwork that would put in place post-2006.

I guess the question I was trying to get at was what sort of steps would you take ring sense those utilities so if a worst case situation were to happen, you would -- the parent -- the parents credit quality would not be as effective?

Well, you know, of course, there are a host of things that we would take a look at. Obviously, we have to take a look at, certainly, as we stand now, what costs of faults we would have do do. We'd have to look at how the dividend policy would be at some of those particular entities as well as look at how we would just manage the overall construction cash flows, among other things, make sure that we have maintained credit qualities. But if at the end of the day, there would be significant changes in -- or regulatory framework come about that would meaningfully result in our Illinois utilities not recovering their costs on a full and timely basis, then we've outlined what potentially some of those adverse consequences would be, and absent that, it would still be very challenging for our Illinois utilities to overcome those regulatory frameworks, should they be put in place.

Okay.

Just a quick question on your pension -- I believe it was last third quarter, you guys made a pretty significant contribution and said that you thought you were not going to have to make another one probably til 2008. It looks like you still are making some contributions in 2005. Can you kind of comment on where you see those contributions going in the next couple of years?

I think , with regard to the -- in 2005, the contribution that we made this quarter was around 80 to $85 million.

Yes.

And, as we look forward then, I think we do not have any required [inaudible] contributions until the 2009 time period, and at this point in time, the contribution would be around $300 million.

Okay. All right.

Thank you very much.

You're welcome.

Thank you.

Our next question from Doug Fischer with A.G. Edwards.

Please go ahead.

Just a follow-up, Warner. I missed what year, again, is the $300 million or so pension contribution, and then I have a couple others.

That's 2009, Doug.

Okay. That's what I thought.

Okay. Is there -- two questions -- first, what forum or how might a forum emerge for discussing a reasonable resolution to the Illinois Power procurement issue? Maybe you can tell us how you might engage the Commission since their involved in a proceeding?

Well, I think, Doug, the forums could be multiple forms, but, certainly, you're right. The Commission involved the auction proceeding, because of ex parte rules, we -- we cannot really discuss those particular issues with them. Yet, at the same time, there are a host of other potential forums, which could develop, including the legislature, where these discussions could take place, and as you know, the legislature is in the middle of a veto session this week that we expect to conclude by the end of this week.

And in terms of this particular issue, we don't expect to see substantive events take place with regards to developing a constructive rate increase phase-in place as an example. Certainly, as the legislature comes back into session at the beginning of next year, during the regular general session and even as late potentially as a veto session next year, discussions around this potential matter could take place, whether it be in the form of general legislature or, certainly, as part of committee discussions, where, as you recall earlier this year, there were committee discussions around the auction process among other things. Of course, as we move along, there are many legal issues, as Gary described a little bit earlier, that need to be resolved, which then may provide different avenues as to how these matters may ultimately be addressed.

So, I think forums outside of the Illinois Commerce Commission proceedings to potentially address this issue.

Is there -- are there attempts to discuss this issue with interveners, or is that a very difficult road right now?

Well, as we've said all along, we're certainly willing to engage in instructed discussions around a rate increase phase-in plan to try and find a good solution for all the stakeholders. So we're certainly willing, and continue to be willing, to have meaningful discussions with all of the stakeholders along the way. In terms of when and whether and whom we're having discussions with, our policy has been not to really go out and say okay, what we're talking about with this party, or when we're having formal discussions or informal discussions because we think in the long run those types -- that type of information not particularly constructive to the overall process. But discussions have been and will continue to be ongoing among several parties to find a good workable solution.

Would you agree with Exelon's characterization that it's going to take some action at the further and their pending case their and/or the Cook County level before anything can really move forward?

Well, I think depending upon the timing of all of those things, I think -- for instance, not sure what the fork would role, don't see having to make their decision as critical to finding a constructive solution to this issue. As terms as to what may happen at Cook County, is not directly related, although because of the timing of that potential action, we may hear something by the end of the year, that may, in fact, be resolved prior to any final rate increase phase-in plan, for example, being resolved at the legislative level or otherwise.

So that could, indeed, happen. Whether one has to link to the other, I think is -- we're not so sure. We're not that that would necessarily have to be the case. Although, I think it could be likely. As Gary said before, we think this is not a particular process that's going to be done in a matter of weeks. We do think it will take some period of time to reach a constructive solution on this issue, and we firmly believe that more well thought out constructive solution, which may take several months, is better an an ill-conceived expediant one.

How do you expect the schedule to unfold at the commission itself?

The schedule related to what?

Procurement case. Will they just -- do you expect them -- do you expect parties to ask them to wait, or will they wait in and of their own accord?

I think, with regards to the procurement case, they -- I expect the parties to ask and wait. In fact, they need to make a decision by January in that particular case.

We expect an ALJ decision in late November and early December, and we would expect the ICC to rule in January on the procurement case, and that continues to move forward on schedule.

Of course, there are legal proceedings which are challenging that particular issue, so that could impact it, but otherwise, we believe the ICC will continue to maintain the existing schedule, which has been laid out.

Okay.

And then just one last question -- the cost of service filing in Missouri that you'll be making -- is that going to include this new method of allocating the generation between Illinois -- between Genco and AmerenUE, or is that -- will that adjustment be in the filings?

Yes. Yes, it would. We've been -- ever since the order, that has always been in our plans to make that filing. Even if the time decision has not been made by the FERC if that particular matter, we will reflect that in our numbers.

Okay. Thank you very much, Warner.

Your welcome, Doug.

Thank you.

Our next question from Philson Yim with Morgan Stanley.

Hi. Good morning.

Good morning.

Warner, has the year-over-year increases in fuel costs -- the guidance changed given that your yearly prices have doubled over the third quarter?

Phil, I'm sorry. I missed a little bit. You broke up a little bit. Could you repeat the question? I'm sorry.

Sure. Given the rise of PRV prices -- PRV coal prices -- has your guidance changed for year-over-year following coal costs?

I think -- let me try to address that. We've given guidance on coal and related transportation costs for multiple years. As we said earlier, it was 3% to 5% increase 2005 over 2004, and back in the second quarter, we expected that increase in 2006, to go up 5% to 10%, and in 2007, 10% to 15%.

In terms of those particular -- we're not changing our guidance there, but we're looking at the impacts of the delay in deliveries, as an example, may have on our future coal costs because to the extent we do not get deliveries this year, we do not -- and those deliveries actually take place next year to build up our coal piles, we are not able to lock in those prices that we have this year. We would, in fact, have to pay those prices at next year's prices, so we're taking a look at what those percentage increases may or may not be. We're not in a position to update you on that matter post-2005.

With regard to 2005, the numbers are out there. As we've said before, we're experiencing some increased levels of fuel and related purchase power cost for a variety of reasons, including the fact that, we're running our gas-fired peakers. Even our coal conservation strategies are going to increase some of our costs here in the fourth quarter as we burn incremental Illinois coal, as well as probably burn through our emission credits.

Great. Thanks.

What are you seeing as the net effect of the rise in coal prices? Is that raising off-peak prices and peak prices in Illinois so that, essentially, the net effect is zero, or -- ?

It's hard to really put a net effect number on it, but we do believe, as we said earlier, that because of rising coal and natural gas prices, that the power markets are seeing that. We believe that the increases that you've seen, as we announced today in our interchange sales revenues per megawatt hour are driven by, not just on-peak periods, but also off-peak prices. We continue to see those power prices remaining robust, not only through the third quarter, but throughout the rest of this year.

Great. Thanks very much.

As well as into next year, frankly.

Great. Thank you.

Sure.

Thank you.

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