阿莫林 (AEE) 2004 Q3 法說會逐字稿

Good morning and welcome, ladies and gentlemen to Ameren Corporation's 2004 earnings conference call. At this time I would like to inform you that this conference is being recorded and that all participants are in a listen-only mode. At the request of the Company, we will open up the conference for questions and answers after the presentation. I would now like to turn the call over to Mr. Bruce Steinke, Manager of Investor Relations. Please go ahead, sir.

Thank you, Jeff. And good morning, everyone. I am Bruce Steinke, Manager of Investor Relations at Ameren Corporation. Here with me today is 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 for 1 week to anyone who wishes to hear it by dialing a playback number. The announcement you received in our news release carry instructions by replaying the call by telephone. In addition, we would like to welcome everyone listening to this call on the Internet. The webcast will be available for 1 year on our website, www.ameren.com.

This call contains time-sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements. Such statements include those about future expectations, beliefs, plans, strategies, objectives and financial performance. We caution you that there are various factors that could cause actual results to differ materially from those anticipated in the forward-looking statements. For additional information concerning these factors, we ask you to read the forward-looking statements section in the news release we issued today and the forward-looking statements and risk factors section in our 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 9 months of 2004, to our earnings per share for the same period in 2003. We have also included an updated 2004 earnings guidance slide that reconciles full-year 2003 earnings to our updated earnings guidance range for 2004. To access this presentation, simply follow a link for the webcast and then click on the link for the presentation, which is provided in a pdf format. Warner will begin this call with an overview of our third quarter 2004 results and some operating and regulatory matters, and Marty will follow with a more detailed financial review. We will then open it up for questions. Here's Warner.

Thanks, Bruce. Good morning, everyone, and thank you for joining us. This morning, we reported earnings of $1.20 per share for the third quarter of 2004, as compared to earnings of $1.70 per share for last year's third quarter. Earnings in the third quarter of last year included an unusual gain of 19 cents per share related to the settlement of a dispute over certain coal mine reclamation issues with the supplier. Excluding last year's unusual gain, our third quarter 2004 earnings of $1.20 per share, compared to earnings of $1.51 per share last year.

The decrease in earnings per share year-over-year was primarily due to the abnormally mild 2004 summer weather in greater common shares outstanding resulting from our prefunding of the Illinois Power acquisition. Net income for the first 9 months of 2004 was $2.44 per share compared to $3.02 per share in the first 9 months of 2003. Net income for the first 9 months of 2003 also included the coal mine reclamation settlement, gain of 19 cents per share, along with a gain of 11 cents per share that was recorded in the first quarter of 2003 for the adoption of a new accounting standard related to the recognition of asset retirement obligations. Excluding these 2 gains, net income for the first 9 months of 2003 was $437 million or $2.72 per share.

Once again, our operational performance during this past quarter was solid. However, this performance was overshadowed by the extremely mild summer weather we experienced during the third quarter. As a result, demand for power was significantly less this summer than during last year's near-normal summer weather conditions, which negatively impacted third quarter and year-to-date 2004 earnings as compared to 2003.

Increased common shares outstanding also reduced year-over-year earnings per share. In July, we issued approximately 11 million common shares. In addition to the 19 million shares we issued in February of 2004. These shares were issued to prefund the equity financing necessary for the Illinois Power acquisition, which we completed on September 30th. Consistent with our previous expectations, we believe this acquisition will be accretive to earnings by 5 to 10 cents per share over the next 2 years after closing. Marty will cover this matter in more detail later.

The completion of the Illinois Power acquisition during this quarter was a major milestone for our Company for several reasons. First, we were able to receive the necessary regulatory approvals for this acquisition in just 8 months. This achievement is among the best ever for companies in our sector. Second, and more importantly, completing this acquisition in such a timely manner now, permits us to turn our attention to integrating Illinois Power's operations with Ameren's, realizing our expected synergies and related earnings from the acquisition and improving the financial condition of Illinois Power. We are already making significant progress on all these fronts.

Immediately following the announcement of the completion of the transaction, the 3 major credit rating agencies increased IP's credit ratings to investment grade. Recognizing the commitment and actions we had already taken to strengthen IP's financial condition. In addition, the rating agencies affirmed Ameren's corporate credit ratings. We have already begun the process of reducing financing costs by calling for redemption $193 million of Illinois Power's high costs, 11.5% bonds pursuant to the bond's equity clawback provisions. At the same time, we are tendering for the remaining $357 million of Illinois Power's 11.5% bonds.

In addition, we are already working to convert many of IP's information systems in the spring of 2005. And its customer service system in the fall of 2005. And finally, we are immediately integrating our Illinois Energy delivery field operations. These are key milestones for the realization of synergies. The bottom line is that we're off to a very good start with the integration of IP into Ameren, and we are optimistic about the growth prospects associated with this acquisition.

Now, turning to other operating and regulatory matters. As I mentioned, from an operational perspective, we turned in another solid performance during the third quarter. The availability of our base load coal and nuclear generating plant Fleet in the third quarter of 2004 was approximately 95%, up slightly from 2003. And despite the much milder weather, our net capacity factors were roughly flat for 2003 at 81%. While coal supplies and related costs are affecting some companies in our industry, they are currently not having a significant affect on Ameren. Today, our coal supply inventory levels approximate 40 days of burn, consistent with historical levels.

The congestion on the rail transportation system has not significantly affected delivery of coal shipments to Ameren's plants. In addition, our coal supply and transportation needs are 95% hedged in 2005 and 75% hedged in 2006. While we expect to see increases in both the commodity costs of coal and transportation costs in 2005 and 2006, we expect these increases to approximate only 2% to 3% per year based on the fixed prices embedded in our contracts.

On the regulatory front, we have several cases pending. First, Illinois Power filed for a gas rate increase of $36 million in June 2004 with the Illinois Commerce Commission. Staff testimonies due in early November, hearings are schedule forward January 2005 and the Illinois Commerce Commission is required by law to issue an order by May 2005. We also have 2 intercompany asset transfer requests pending before regulatory bodies.

Earlier this month, we received approval from the Missouri Public Service Commission for the transfer of AmerenUE's Illinois Gas and Electric service territory to our Ameren CIBS subsidiary. The net book value of this distribution service territory transfer is approximately $125 million. However, the Commission's order contains certain conditions for approval of the transfer. Those conditions primarily address the regulatory treatment for certain pretransfer liabilities and require amendments to the joint generation dispatch agreement. Simply put, we believe these conditions are not necessary or appropriate for the transfer to be approved.

Consequently, last week, we requested the Missouri Public Service Commission to rehear or clarify its order. There is no deadline by which the Commission must act on our request, but we expect a decision in this proceeding by year end. At that time, we will determine our course of action related to this proposed service territory transfer. This proposed transfer also remains subject to the approval of the SEC and to the Public Utility Holding Company Act.

We are also seeking to transfer 550 megawatts of unregulated generating assets from Ameren Energy Generating Company into our regulated AmerenUE subsidiary. The net-book value of the assets being transferred is approximately $240 million. At this time, the only remaining approval required for this transfer to be completed is from the SEC under the Public Utility Holding Company Act. However, should the service territory transfer that I discussed previously not be completed, we would then need to seek Illinois Commerce Commission approval for the generation transfer. We are still targeting to have both of these intercompany transfers completed in time for their inclusion in the appropriate rate bases for our anticipated post-2006 rate cases in Missouri and Illinois. Otherwise, the timing of these transfers does not have an immediate financial effect on Ameren since electric rates are currently froze frozen in these jurisdictions.

One final note on the regulatory font, the Illinois Commerce Commission has concluded its workshops that sought input from interested parties on the framework for retail rate determination in the framework for generation procurement by customers after the current Illinois rate freeze ends in 2006. We actively participated in these workshops and supported a framework that would have all regulated Illinois electric transmission and distribution companies bid out [inaudible] requirements for generations in a New Jersey-type auction process. We have also supported a structure that provides for recovery from customers of the generation costs resulting from that auction. Others participating in these workshops are supportive of the framework proposed by Ameren.

We expect the Illinois Commerce Commission to issue a report on the workshop process later this year. But we do not believe the Illinois Commerce Commission will make final decisions on the final regulatory structure until sometime in 2005 after Ameren and other companies submit filings detailing their post-2006 plans. At the end of 2006, we expect to have a well-balanced portfolio of generation available for sale in Illinois. The majority of which will be low-cost base load coal fire generation.

Today, our unregulated units provide power to our regulated affiliates at $38.50 and $34 per megawatt hour under 2 contracts totaling approximately 3,000 megawatts through 2006. We believe these contracts are under market based on today's market prices for similar contracts. As a result, we believe we are well positioned to earn incremental electric margins in the post-2006 generation procurement environment in Illinois, as well as realize solid returns in our investments and regulated Illinois businesses. With that, I would like to turn the discussion over to Marty.

Thanks, Warner. At this point, I will refer to you our website as I provide a more detailed discussion of earnings results and other financial matters. 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 9 months of 2004 to our earnings per share for the same periods in 2003. We have also included an updated 2004 earnings guidance slide that reconciles full-year 2003 earnings per share to our updated guidance range for 2004.

In the third quarter of 2004, we reported net income of 232 million or $1.20 per share, compared to third quarter 2003 net income of 275 million or $1.70 per share. As Warner indicated, earnings in the third quarter of last year included a gain of 31 million or 19 cents per share related to the settlement of a dispute over certain coal mine reclamation issues with a supplier. Excluding last year's unusual gain, earnings for the third quarter of 2003 were $244 million or $1.51 per share. In the first 9 months of 2004, we reported net income of $447 million or $2.44 per share. Compared to net income in the first 9 months of 2003 of 486 million or $3.02 per share.

Net income for the first 9 months of last year included the coal mine reclamation settlement gain and the gain from the adoption of a new accounting standard of 18 million or 11 cents per share. Excluding these gains, net income in the first 9 months of 2003 was 437 million or $2.72 per share. As indicated earlier, our earnings in the third quarter of 2004 were significantly reduced by extremely mild summer weather and the issuance of common shares for the prefunding of the Illinois Power acquisition. We estimate the mild 2004 weather reduced earnings by an estimated 20 cents per share versus 2003.

Cooling degree days in Ameren service territory during the third quarter of 2004 were approximately 20% below 2003. In addition, according to the National Weather Service, summer weather in Ameren's service territory was the seventh mildest in the past 109 years and Ameren's Midwest region was the coolest in the continental United States in 2004. As a result, weather-sensitive residential electric sales decreased by approximately 9% during the quarter and weather held commercial sales relatively flat. Outside of the weather impact, electric margins in the quarter benefited from organic sales growth and improved margins from sales of excess power into the Interchange markets.

Organic sales growth boosted earnings by an estimated 11 cents per share as the economy in our service territory continued to show signs of improvement. Industrial sales in the third quarter were approximately 4% below 2003 due to the expiration of certain low margin nonregulated customer contracts outside of our service territory. These were contracts initiated by CILCO prior to Ameren's acquisition and were backed with purchase power contracts. Absent the loss of these contracts, industrial sales grew approximately 2% in the third quarter of 2004. As a result, we believe industrial trends continue to show the economy remains in a recovery mode in our service territory.

Third quarter 2004 electric margins benefited from a higher contribution to earnings from Ameren Energy as agent for AmerenUE and Ameren Energy Generating Company. Ameren Energy produced third quarter 2004 earnings of 13 cents per share, which was 3 cents per share higher than the third quarter 2003 on a comparable share basis. Energy market conditions were, again, very solid in the quarter, and our realized Interchange sales averaged $31 per megawatt hour versus $29 per megawatt hour in last year's third quarter. In addition, Interchange margins benefited from increased availability of low-cost generation as a result of the mild weather and solid operations. Given results today, we now expect Ameren Energy to contribute 55 to 65 cents per share to earnings in 2004 exclusive of the dilutive effect of the 2004 equity offerings.

Earnings in the third quarter of this year also benefited from an incremental $3 million in emission credit revenues or about 1 cent per share. We have now sold $30 million of emission credits in 2004 in line with our original expectations. On April 1, we implemented the final $30 million tranche of the 2002 AmerenUE Missouri Electric rate reductions. The net impact of this electric rate reduction, which was partially offset by increases to our gas rates in Missouri and Illinois was a negative 2 cents per share year-over-year.

During the quarter, we incurred higher employee medical and pension costs that reduced earnings by 4 cents per share in the third quarter of 2004 as compared to the third quarter of 2003. Depreciation expense rose 2 cents per share in the third quarter of 2004 due to increased assets. Dilution in financing costs reduced earnings by an estimated 18 cents per share in the third quarter of 2004 versus 2003, due primarily to the prefunding of the equity for the Illinois Power acquisition.

One final note on our third quarter results before I discuss our updated earnings guidance. In September, Ameren made a pension contribution of $295 million. This contribution allowed us to avoid pension-related insurance costs and should mitigate expected pension cost increases in 2005. Previously, we had disclosed our requirement to contribute on average approximately $115 million per year to our pension plan in 2005 through 2007. At this time, we expect that our 2004 contribution will eliminate any need to fund Ameren pension plans, including Illinois Power's until 2008.

Now onto our earnings guidance discussion. Our previous 2004 earnings guidance range was $2.70 to $2.90 per share. This morning, we announced that we have narrowed our 2004 guidance per earnings to be between $2.70 and $2.85 per share. As Bruce mentioned, we posted an updated 2004 earnings guidance slide that reconciles full-year 2003 earnings to our updated earnings guidance range for 2004. Our 2004 guidance remains subject to, among other things, plant operations, weather conditions, energy market and economic conditions, unusual or otherwise unexpected gains or losses and other risks and uncertainties outlined in the forward-looking statements of our release and the risk factors section in our filings with the SEC.

Our new earnings guidance includes adjustments for the earnings impact of the abnormally mild summer weather we had this year, improved margins from Ameren Energy and the expected benefit of Illinois Power's contribution to earnings in the fourth quarter of 2004. Our previous guidance included the dilution from the common shares we issued to finance the Illinois Power acquisition, but excluded any net income from Illinois Power. Due to the September 30 closing, we now estimate Illinois Power will contribute 8 to 12 cents per share to earnings in the fourth quarter. Illinois Power's expected earnings contribution for 2004 has been netted into dilution and financing on the slide we posted to our website.

We have also made adjustments to other line items to reflect actual results through the first 9 months. Since we announced the acquisition of Illinois Power, we have identified greater synergies and are realizing lower financing costs than expected. These incremental benefits have been largely offset by higher-than-expected power supply costs, including those to be recognized under purchase accounting due to increased power prices. The bottom line is that we continue to expect the Illinois Power acquisition to be accretive to earnings by 5 to 10 cents per share in each of the first 2 years after closing in line with our original expectations. Of course, our estimates will continue to be refined as our integration work and recapitalization plans proceed. And as we complete the solicitation for the remaining 30% of Illinois Power's power supply needs, which we anticipate to be completed by year end.

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

Thank you, sir. Our question-and-answer session today will be conducted electronically. If you would like to ask a question, we ask that you press the star key followed by the digit 1 on your ton telephone key pad. We also remind that you if you are using a speaker phone, we ask that you disengage your mute function to ensure that your signal can reach our equipment. We will take as many questions as time permits and proceed in the order that you signal us. Again it's star 1 for a question and we'll pause for just a moment to assemble a roster. Our first question today comes from Ashar Kahn from SAC Capital.

Good morning.

Good morning, Ashar.

I know there have been a lot of changes made and this reconciliation table, but could you just remind us, I guess if I'm right, to start off the year with a guidance, which was, if I'm right, somewhere the upper end was above $3 or so in January if I'm right. I just wanted to remain with that guidance and if you exclude the shares that you did for IP and all that, am I right, the only thing that would have hurt that original would have been weather?

Ashar, this is Warner Baxter. Let me see if I can address some of those issues. The original guidance that we issued at the beginning of the year was $2.90 to $3.10 per share.

Correct.

And then immediately after that, we lowered that then based upon the additional equity issuances, and so we went to $2.70 to $2.90 and then now we stand between $2.70 to $2.85. Some of the changes that we made, there are several. One, obviously weather, as you pointed out, two would be dilution, but I think thirdly, and as importantly, sales growth has changed rather meaningfully. Originally we had estimated sales growth to be between 15 cents and 30 cents per share for the range and that slide that we have for the guidance. Today, obviously, that number now stands between 40 and 55 cents per share. The primary difference there is, I guess there are two. One, organic growth is better than we originally expected. Originally we expected organic growth to be about 15 to 20 cents per share. Today, that organic growth we expect to be closer to 25 to 30 cents per share. The other piece relates to Ameren Energy. Going into the year, we expected Ameren Energy's earnings to be down about 10 to 15 cents per share based upon last year's numbers. Now we expect it to be either flat or maybe up to 10 cents per share.

Okay. If I'm --

One final thing I might point out, I'm sorry. The Callaway refueling outage was different, obviously, we had an outage which was extended further. And so I think our original guidance there ranged between, oh, I think it was up maybe 15 cents a share. Obviously, it came in at 22 cents.

So, Warren, just going back to, if the dilution and weather had not happened, that's my main question. If dilution and weather had not happened, things as it turned out during the year because of higher organic growth and other things and all that, you would have probably come at the higher end of the 2.90 to 3.10 number. Is that a fair statement?

Without doing all of the math, I think clearly we would have been solidly within that 2.90 and $3.20 per share range. Whether it had been totally at the upper end, I'd have to go forward and do all of the math and, obviously make a fair amount of assumptions. I think I've outlined, Ashar, the major changes that took place from the beginning of the year until now.

If I can just follow up on the Illinois process. Yesterday, Excellon on their call mentioned that people are going towards the New Jersey-style auction and could I just get your comments about what you are seeing and from your point of view, how it will get resolved and what the next milestones are as we lead on to this process for the next year, year and a half?

Sure. Happy to do that. I think with regard to the overall process, as we said, the workshops have concluded. We would agree, generally the process and the conclusions from the workshops are leaning towards a New Jersey-type of auction process. And in fact, in terms of it's not just Excellon and Ameren but other parties and suppliers who are at the table, are in favor of some type of process that gave us the most fair and equitable way. In terms of milestones, there very well could be a report prepared by either the Illinois Commerce Commission's staff or maybe even dealing with Commerce Commission which simply summarizes the results of the workshop process to try and put, at least on paper what all the thinking was behind that. That could be shared either just among the Illinois Commerce Commission. I know that there's some in the legislature who may have some interest in seeing such a report. That may happen by the end of the year.

Probably more importantly looking ahead, the process by which we see the procurement process, as well as the rate-making process get into place is that early next year, I would say in the spring of next year, we would expect both Ameren and Excellon to file or make tariff filings that as part of that tarrif filing will outline in detail our view of the post-2006 procurement process which would be then this New Jersey auction-type of process. It would be in the form of a tariff filing because we -- as our structure is such that the generation costs that will result from this procurement will ultimately be passed through to customers, and so therefore we have to amend the appropriate tariffs for customers post-2006. We would ask, at this point we would expect to ask the Commission to rule on that by the end of 2005 so we would be in a position to have an auction take place as early as the spring of 2006 and certainly no later than the fall of 2006. So that's how we sort of see it playing out here over the next 12 to 18 months.

And Warner, can you remind us what your contractor generation rates are currently and what you are seeing as a forward market price right now?

Sure. We have 2 contracts to our regulator affiliates for the 3,000 megawatts that we mentioned. The CIPS contract, which basically is about 8 million megawatt hours under that contract, that's at $38.50 per megawatt hour. The CILCO contract, which is about 6 million megawatt hours, that stands today at $34 per megawatt hour. And, of course, everyone has their own view of the forward curve. And we even mentioned, I believe Marty mentioned as well as I as part of our discussion, that we believe those prices are below market. Probably if you would look out today, it would not be unreasonable to look at those same types of contracts, now those are specific types of contracts. They would probably have market prices, which could range around $45 to $47 per megawatt hour today, based on today's market prices.

I appreciate it, thank you.

You're welcome.

Our next question will come from Smith Barney's Greg Gordon.

Hi, Warner, how are you?

Hi, Greg, how are you?

On that question, you just said, sort of let's call it $46 the midpoint and let's call the average price 37. You're implying that the sort of load serving premium in your region of the world would only be about 24 or 25%. That's a little bit lower than what the guys in the northern part of the state quote as being sort of the quote unquote spread over the forward curve or, you know, so what's the -- do you think just because of transmission constraints and whatnot in your region of the country that the premium over the forward curve with load serving would be somewhat lower? Because when I look at Midwest Power prices right now, they average around $35.

Well, you know, Greg, I guess everyone sort of has a view of a forward curve. I think in terms of how we view it, we think that in general we tend to maybe be -- maybe on the conservative side. I don't know all of the details that went into our friends from the north in terms of how we projected that number. But we think the numbers we gave were not unreasonable. Could they have some upside to it? Certainly. That's possible. I think in general we think that it's an appropriate number. At this point in time.

Great. Then the second question I had was you quoted a $30 million revenue number from the sale of emissions credits?

Yes.

Did you quote a volume number in terms of the number of credits you sold?

We did not quote a volume number. And I don't have that really with me, but I will say that certainly with the run-up in prices for emission sales, the volume of credits that we sold this year were meaningfully less, at least in part from what they've been in the past.

When we think about your business planning in terms of the contribution from emission credit sales, do you think of it in terms of a annual volume metric target for the number of credits you're going to sell or do you think about it in terms of the annual earnings contribution that you would expect to get from those credits?

I guess, Greg, in terms of that, the way we think about it ultimately is that we use these emissions credits primarily for environmental compliance purposes. So frankly, each and every year we step back and say what should we do with these emission credits for environmental compliance purposes which has a tendency to impact the ultimate capital expenditures and the timing of those capital expenditures we have to make. So certainly historically what we've done for UE, and this is where we have the link in terms of emission credits is that we've historically sold about $20 to $30 million dollars of emission credits for UE.

Now, there has been recently, and especially this year, a significant run-up in terms of the prices for emission credits where they're probably up over 200% compared to where they've been in the past. So in terms of answering your question, it isn't really just a dollar contribution or even a volume, it's probably more on the volume side in terms of what we think we need to do to meet our environmental compliance needs. And then we'll monetize those excess credits as we deem fit based upon market conditions.

Right. As the value of the credits rises, the decision to build versus consume them becomes different, right? You know, you'd rather, all things being equal, when a credit becomes more valuable, it becomes an easier decision to spend capital, right?

No, we understand that. I mean, that's all certainly a factor. As we are not only mindful of that dynamic, but certainly, we keep our eyes on the changes, seems to me, some respects the constant changes in environmental laws. So each and every year, we go through a process that evaluates our overall environmental compliance strategy and those factors are, as you said, things that weigh into that.

Final question, Warner. Your CapEx budget as articulated in your last 10-K, does that fully imbed in it at this point what you view as your knock socks and mercury environmental compliance costs or should we expect you guys to give us an update on that in the next annual capital expenditure forecast?

I think with regard to that, Greg, we would certainly continue to update our numbers based upon our view of where environmental laws are going to change. So that the dollars that we quote over the next 5 years are dollars which we know we're going to spend, which include some environmental CapEx, but we have not reflected in our sort of formal 5-year CapEx plan certain environmental CapEx that I would consider somewhat speculative at this point in time. I think if you go through the disclosures that we have both in the K and updated in the Q, we kind of lay out the types of numbers which are both in our formal 5-year forecast and those which are ranges around capital expenditures we may incur depend upon the ultimate determination from an environmental standpoint.

Thank you, Warner.

You're welcome, Greg.

And moving on. We will go to Paul Ridzon with Key McDonald.

What have you earned year-to-date in Ameren Energy in cents per share?

Sure, Paul. With regard to the year-to-date earnings cents per share is 45 cents per share for Ameren Energy compared to last year's 41 cents on a comparable share basis.

Did you realize a tax benefit from this large early contribution to the pension plan?

Yes, we will. That'll be tax deductible.

And you realize that in fiscal '04?

We -- I'm sorry, Marty.

This is Marty. We actually were able to push some of that deduction back to 2003 because we made the contribution prior to September the 15th. So we got a 2003 deduction and some in 2004 with, you know, immediate cash benefit resulted from that. Just a normal tax deduction for the contribution.

How much is going to benefit '04? Or what is the '04 benefit from this early contribution?

I would suggest that the $275 million net of tax that number's about 180 million.

And what hit '03?

Well, I guess it's all cash that we actually received ultimately this year. We pushed it back from a tax perspective, but as you net sort of the actual tax flows for this year, we will -- we look at it as sort of a net of tax of about -- close to 180 million.

The contribution was 295 million, we get a tax deduction for that, so the net cash outflow is 180 million. There is no earnings pickup in the current year associated with that if that's what you are driving at.

In future years kind of benefit with regards to a higher asset balance?

Yes. In the future years, we will pick up an earnings benefit associated with that contribution. We assume in our pension assumptions an 8.5% return, so you would expect to see about, you know, pretax 8.5% multiplied by the 295 million contribution. Now, how that actually ends up coming out in our future pension expense will be impacted by other assumptions in the pension calculation. Obviously, we'll have to look at where the discount rates are at year end. We'll have to look on our asset returns to date this year. Those kinds of things factor into the determination for next year, but there clearly will be a benefit of the $295 million contribution. And I would also point out that, you know, there will be some financing costs associated with the fact that we did put $295 million into the pension plan that came out of general corporate assets.

Warner had mentioned that synergies at IP were better than anticipated and there's financing opportunities. You kind of made a comment against power costs. Is that offset by power costs, partly offset, more than offset? Can you give a flavor of the relative magnitudes?

Paul, the way it worked out. Remember when we started the overall process, we expected a 5 to 10 cent earnings per share accretion resulting from the Illinois Power acquisition, and obviously that was back in February. Since that time, we're able to take a look at all of our original assumptions, and as a result, not just original assumptions, we have now better plans in terms of obtaining incremental synergies from the Illinois Power acquisition. Especially in part of the general administrative area. Those were favorable.

Secondly, the overall expected financing costs for the acquisition that we realized in terms of the number of shares that we had to issue for this particular acquisition were better than we originally planned, so that, too, is favorable. Those were largely offset by increased power costs. Keep in mind that at the beginning of the acquisition, and as part of the deal, we had hedged over 70% of our power supply needs with DMG [ph] with the other 30% Marty mentioned that we have out for bid currently. Even though we had our cash needs hedged at the beginning of this acquisition, the accounting model requires you to reflect as part of your income statement going forward for purchase power, the -- basically the prices for power at the date we closed the acquisition, so September 30th. So since the time we announced the acquisition through September 30th, power prices rose based upon a similar type of contract for the 2800 megawatts, about 10 to 15%. That's sort of the largely offset. At the end of the day when you still shake those things up, we still remain within our original expectations of 5 to 10 cents per share of accretion over the next 2 years for Illinois Power.

Thank you. Just one -- can you just give some flavor on the post-'06 initiative. It's my understanding that the legislature is going to play nothing but a spectator role here. Is that the right way of looking at it?

Our view is that, number one, there is no legislative requirement to have the post-2006 procurement as well the overall regulatory framework be established. There are no needs to go to the legislature. Two, I think the legislature will be interested in keeping an eye on the overall activities. Whether the legislature themselves try to place themselves in the middle of it, I guess I can't speak for that. At this point in time, we don't see any signs of that, but there is no requirement for the legislature to be involved.

Okay. Thank you very much and go Red Sox.

Wait a minute!

Go cardinals. [ laughter ]

Thanks, Paul.

And we will now move on to Karen Miller with UBS.

Good morning. Two questions. First is, can you give us some idea how you can hope to continue to improve the balance sheet of Illinois Power going forward and specifically with reference to additional debt retirement? And second, you mentioned the 2 contract prices for CILCORP and CIPS. Have you given any indication what you are paying under the Dynegy contract?

Sure, this is Warner Baxter. With regard to -- let me start with the second question first. With regard to the Dynegy contract over 2005 and 2006, we'll pay anywhere from $42 to $44 per megawatt hour. Today, Illinois Power pays Dynegy approximately $49.50 per megawatt hour under a different contract but that's the payment that goes out. That's your second question.

With regard to the first question, we've been very clear that we plan to recapitalize Illinois Power and improve their overall financial condition. We intend to, at a minimum, insert equity into Illinois Power of approximately $750 million. And that $750 million will be primarily to reduce high cost debt associated with the Illinois Power. Of course we've tendered for the $550 million at 11.5% bonds. And we will take a look at existing outstanding debt of Illinois Power utilizing obviously potentially various call provisions and the like to determine which debt we believe is appropriate to continue to improve their overall financial condition.

So you have approximately $200 million of additional debt retirement you can do based on the equity infusion?

Again, that's sort of the simple math.

Except absent the premium that you pay?

Absent the premiums and of course we have the option of infusing more equity. We said at a minimum is 750 million.

Okay. Thank you.

You're welcome.

We will now go on to Bear Wagner's Bob Warren for our next question.

Hi. It's Andy Levy. Actually most of the questions were asked. Thank you very much.

Okay, Andy. Thank you.

Before taking our next question, I would like to remind you that if your question has been answered, you may remove yourself from the queue by pressing star 2. Now we will move on to Copia Capital's David Grumhaus.

Good morning, guys, how are you?

Fine, David, how are you doing?

One quick question. On the accounting on the purchase power on the Dynegy contract, what price was that reset to?

Ultimately the accounting is to the purchase power for the DMG contract?

Yeah, exactly.

Ultimately, again it was up 10 to 15% from our original assumptions.

From where you were.

Yeah.

Okay. That's just based on where you all surmise the current power prices are at?

Yeah. The way it had to work at the beginning when we did the estimates and the accounting amount is that you estimated what you believe power prices should be at the time you are going to close, and of course, we had assumptions as to when we'd close, and we look and forward curves and say okay -- not only just at forward curves but you have to then factor in a similar type of contract. Obviously, this is a bit of a unique contract having 2800 megawatts of power going out. So it isn't just as simple as picking up the forward curve and saying this is it. There are a lot of other factors that went into went into the original assumptions and ultimately what we finalize the numbers with. In general, as I said, the numbers went up about 10 to 15% from our original assumption.

So you have the old contract through the end of '04 and then you have the new contract for 2 years, is that right?

That is correct.

And you would amortize that 10 to 15% increase over the 2-year period.

I'm not sure if it would be quite amortization. Basically, you sit there and you mark to market what you think the contract is and ultimately that's what you reflect in your income statement. So I don't know if I'd call it amortization. It isn't quite that way. That's ultimately the model.

Okay, great. Thanks.

Sure.

And we'll take our next question from Greg Schultz with SAB Capital. Mr. Schultz, your line is open if you can check your mute button, please. Hearing no response from the line, I will move on to Mr. Steve Fleishman with Merrill Lynch.

Hey, guys.

Hey, Steve. How are you?

Good. Just to kind of close the loop on the Illinois Power contracts and such, when we get to 2007 and everything gets rebid out, I assume that price will go to market assuming they do a competitive bid. And then you'll purchase the power or, you know, serve some of it off of your own generation?

Yes, Steve. Number one, I think your first observation is correct. It'll go to market rates because of the competitive bid, and then from Illinois Power's perspective, you know, I think it's certainly possible that Illinois Power will have different suppliers or different mix of suppliers that we have today. I think it's certainly very possible that some of those mix of suppliers will include some of our own affiliates. Obviously today for CIPS and CILCO that's 100%. We would not only look at Illinois Power, and I speak about CIPS, CILCO and Illinois Power, it will be less than 100%. But we do expect to serve still a meaningful portion of our load under that competitive bid process.

Let me ask a question maybe in a little different way. If you look at 2005, 2006, with Illinois Power based on their frozen generation rate and the contract you have with Dynegy and I guess you don't know what this other contract will exactly be, do you make a margin on serving that polar load? Is it earnings neutral or do you lose money?

Well, you know, I think it's a little bit difficult to say whether just on the generation component because when Illinois Power froze their rates, it was a bundle rate, and it was done, you know, probably better than 10 years, 15 years ago.

Right.

So, you know, when we look at it that way, we don't look at it in that sort of specificity. We obviously looked at the overall transaction itself, and so when we come up with our 5 to 10 cents accretion, we put all of the factors associated with Illinois Power, including the synergies, financing synergies, as well as power supply costs.

Okay. Maybe asking a question another way. When you go and reunbundle the rate in '07, is there significant T&D spending that's not been covered in the kind of embedded wires rate that might be in there?

I think clearly from Illinois Power's perspective it's been over 10 years relatively speaking since they've had an opportunity to change their electric rates. Clearly, they have made meaningful investments into their system. We expect their rate base to be approximately 1.9 billion post this acquisition. And that will continue to make between now and the time we actually go into the rate-making process, continue to make incremental investments. So I think in general, the bottom line is we do expect that the overall rate base in investments will be greater and making process which obviously is an outboard trend in terms of overall T&D rates.

Okay, so my summary, I guess, question on this line of questioning would be, if you look out to '07 as you kind of did with CILCO and CIPSCO and think about it with the full package of Illinois Power as well, is '07 an opportunity for Illinois Power to potentially have better performance than in '05/'06, given that you could have a chance to recover T&D and maybe potentially sell more of your excess power into their polar or at least make sure you don't lose any money on the polar?

Sure. I think, Steve, a couple observations. One is, yes, we do believe in terms of the overall T&D because of the investment the Illinois Power has made, there's potentially upside there. I wouldn't stop at Illinois Power, frankly. I think you have to look at both CIPS and CILCORP, we see in the overall T&D business 2 entities that have not had rate increases on the electric side of the business for some time. Secondly, in terms of the ability to sink our excess generation certainly being a part of myso [ph] post-2006 and even, frankly before that, would give us the ability to move that generation to places that we may not be able to move it today. So all those factors, I think weigh in. That's outside of the generation procurement process that we've been discussing.

Thank you very much.

You're welcome.

And we will now move on to Ducain Capital and Zach Shriver.

Hey, Warner and Marty, how are you guys?

Fine, Zach, how are you doing?

Fine. Just on this Illinois Power accounting issue. We spoke sort of conceptually about 5 to 10 cents of accretion originally. We spoke about the positives being higher synergies and increased sort of financing benefits from taking up the high-cost debt offset by the negative of the purchase power accounting under the purchase accounting for the transaction. Is there any way you can break that -- and the net of those things brought us back to the 5 to 10 cents. Is there any way we can sort of look at the gross components of that? What was the gross increase in the synergies? What was the gross increase in the financing benefits? And what was the gross higher purchase power amortization expense? And then Fleishman's insightful, I might add, point in terms of the structural, the negative falls off in '06, then the structural benefits should theoretically continue into '07, so we can just sort of look at that and its component parts, that would be great.

Let me try and do the best I can. I don't have all of the component parts, Zach, but let me try to break them down piece by piece. Number one, you're observation and I think Steve's observation, this issue, if you even characterize it as an issue, that's not the appropriate way. This does fall off after 2006 meaning that this contract gos away after 2006. This purchase accounting issue goes away after 2006 and the structural pieces of generation frame work are firmly entrenched after that and so should there be benefits with our low-cost generation, which we believe there will be, they will be certainly at the ready.

Secondly, with regard to sort of the big pieces, basically, we see general and administrative synergies today being approximately $30 to $35 million, and obviously, they ramp up. We don't get those obviously this minute because we have to do some of the things I spoke about before. Converted the systems, integrate the operations. But over sort of the next year or so, we expect to be running full throttle in terms of those administrative synergies. Those are probably from where we originally started was closer to $15 to $20 million in synergies. So they obviously approved. The financing synergies --

I'm sorry, Warner, 15 to 20 originally?

Yes, approximately is when we announced the acquisition.

And that was at the full run rate?

Yes.

Got it.

In terms of the financing costs, there are really 2 pieces there. One you hit on. It's the financing savings that we have as a result of taking out some of the high-cost debt. That's about $90 to $100 million and that really hasn't changed a whole lot relatively speaking. The other financing synergy, which I alluded to, is in our original assumptions, we had assumed a certain amount of equity that we would have to issue to maintain Ameren's overall credit ratings, as well as that was obviously based upon the level or the various stock prices that we would be able to issue our stock for in both February and July. We did, in terms of all those things based upon discussions with the rating agencies and the like, we did better. I don't have sort of a specific number in terms of better, but we did better than our original estimate.

Then the third piece, which you alluded to is the purchase power agreement. Again, you know, we had some original assumptions as to what we thought purchase power costs would be at the time of closing. We're not prepared to give out what our original assumptions are versus what they are today, but they have risen 10 to 15%. And so they largely offset, I'm not saying entirely, they largely offset those numbers. Now, the only piece associated with the purchase accounting and the PPA, which is still pending, relates to the 700 megawatt contract which is still out for bid. We're well in the middle of that already and hope to have that really locked up here very soon in terms of finalizing those contracts. Certainly by the end of the year. The other piece, the valuation and all that stuff that is now done and we move forward. That is already embedded into the 5 to 10 cents per share of accretion which both Marty and I have been discussing.

Sort of theoretically in '07 versus '06, we have 2 structural benefits. Number one, the negative bleed of the purchase power expense rolls off and this sort of mark-to-market issue, and you could have the contract step up from the sort of the low market price to something closer to market, with the risk of that being where do gas prices and emissions credits end up btween here and there.

You know, I don't know how you characterize bleed, and I'm not sure I understand exactly what you mean. The bottom line is this mark-to-market issue goes away post-2006. You look fundamentally at our existing generation, which we can take into the marketplace and what price we can sell that generation. That's really what it is. That's the incremental benefits based upon at least today's market prices that we would expect to achieve.

Is there a double-whammy positive though to think about or do you think it's a single whammy?

I don't know if I would call it double-whammy positive, I think it's just it is what it is.

Okay.

There's clearly, I think our view is if you talk about the positives is what we talked about before, we're going to be able to sell very low cost coal-fire generation into the marketplace in Illinois, which we are getting at 38.50 and 34 today. Who knows what 2007 will be. We'll let you look at your own forward curves, but based on today's prices, those contracts are on the market. And two, throughout our Illinois T&D companies, we'll have the ability to hopefully recover rate-based investments that we made throughout those companies over the last decade and get appropriate recovery for all those, including for obviously what has been an increasing cost environment relatively speaking in terms of the employee benefit costs and the like.

You know what? I think this is the way to ask the last question which is what kind of regulated ROI have you earned given that you have already unbundled all of the Illinois T&D companies with the generation separation? What's been the last 12 months ROE at of Illinois Power under the Dynegy ownership within the last 12 months ROE at CIPS and CILCO and so forth?

That's a good question. Let me just tell you, one, in our gas rate cases that we just completed last year, we were able to get allowed ROEs from the Commission approximately 10.5%. Now we've been focusing a lot on Illinios, remember we have Missouri, too.

Sure.

And we were able to get, for all practiacal purpose while it was a settled amount, it was about 10.5% ultimately in terms of ROEs there. So that's what's been allowed. In terms of what we're actually earning, and that's on the gas side. On the electric side of the business, we are earning for both CIPS and CILCORP have been in the single digits on the electric side. CILCORP probably close to the 7%. CIPS is probably even overall lower than that as well or right about there. Illinois Power, generally speaking, has been on or around 9 to 10% in terms of ROE. Now of course, those are based on reported numbers. So as you go into a rate-making process, there are a lot of adjustments that are made and so those are just reported numbers. The rate-making process will take care of itself when we make those filings in 2006.

Got it. Thanks so much, Warner, very helpful.

You're welcome.

We'll now move on to Dan Jenkins with the State of Wisconsin Investment Board.

Hi.

Hello, Dan.

I just have a couple questions kind of if you can give some color on the sales in particular, industrial sales were down and I just wondered, you know, is that just economic weakness in the service territory or is that the specific customer types or, you know, could you give me any color on that?

Sure, I'd be happy to do that. The reasons why industrial sales are down this quarter are primarily due to the fact that when we acquired CILCORP, as you know it is a deregulated marketplace in Illinois. They had -- they were able to secure many customers outside of their service territory. The way they back those up is with purchase power contracts and so they are very low margin. Those contracts simply rolled off this year and were not ultimately renewed. But that was part of the deregulated marketplace. If you step back and exclude those low margin sales from CILCORP, in fact our industrial sales went up 2% this quarter, and for the year, they're up I believe I think 3 to 4%. So I believe Marty pointed it out in his talking points that we continue to see the economic conditions in our service territory to be in a recovery mode. So industrial sales have been solid. The economy continues to be -- it's not a hockey stick type of economy in terms of growth, but it's solid customer growth. I think I'd even point out the fact that commercial sales during this quarter, which they are a weather-sensitive type of customer, not nearly as much as residential, but commercial sales were flat given the fact that we had one of the coolest summers over the last 100-plus years. So these are all signs that I think the economy is remaining solid on the overall service territory.

Okay. And then similarly, I was wondering the EEI, you know, is down quite a bit in the quarter and for the year. The outside sales you're showing for EEI?

Right. EEI is an affiliate that now we own 80% with the acquisition of Illinois Power, but at the time for our results for the third quarter, we own them 60%. By and large, those sales are down quite a bit. I'll turn it over to Bruce to comment on a couple of those things.

Yeah, Dan. That line is a little bit deceiving because what happens is that those are sold through Ameren, the sales are sold through as opposed to outside, EEI sales get shown as residential commercial and industrial. So overall their sales aren't down, it's just where it's being reflected in that analysis you were looking at.

We were able to take EEI when they have excess capacity there and sell it to their affiliates. So we are a 60% owned affiliate, now 80% post the IP acquisition. So it'll really more of a presentation. The other thing, they had a contract with the DOE that basically is expired, and those sales have been down, but those are very, very low margin sales under that contract.

Okay, thank you.

You're welcome.

And our next question comes from David Frank with Zimmer Lucas Partners.

This is actually Leon Dubalt with Zimmer Lucas.

Greetings.

Can you guys give your weather impact versus normal for this quarter?

I think by and large for this quarter, I think Marty had stated that the weather last quarter was generally pretty normal. So the impact on a quarter basis is pretty close to the 20 cents, it's probably 15 to 20 cents. We like to believe we're exact in terms of weather, but it's probably 15 to 20 cents compared to normal for this quarter.

Thank you.

And Peter Su with Lazard Asset Management has our next question.

Good morning.

Good morning, Peter.

I just with have one clarification question in regard to the purchase power contract, that change that was made as of the closing of the M&A transaction. I know, Warner, you mentioned that the hedge is for the supply we're probably done well before the closing date and approximately 70% of those done. So does that mean that it's more of an accounting adjustment for the change in earnings outlook and less of a cash issue?

That is exactly right. That is exactly the way to put it. It was actually the 70% was hedged as part of the agreement with Dynegy. And so this is basically kind of a mark-to-market accounting issue that you have to follow for purchase accounting. So the only cash change from our original estimate will come with regard to this 30% that we are currently out for bid.

I see. Could you just remind us again when that 70% of the supply was locked in?

It was locked in at the time we announced the transaction with Dynegy, DMG is Dynegy Midwest Generation. So that was part of the overall deal for the acquisition of Illinois Power that we had entered into at the same time, a 2800 megawatt PPA with Dynegy Midwest Generation. So it was locked in and hedged immediately.

That's right. Okay, thanks a lot.

You're welcome.

And the final question in our roster comes from Greg Schultz with SAB Capital.

This might have been asked. I was on and off the call. In terms of the forward prices that you were sort of throwing out there, is that around the clock? Average?

Yeah, that was fair in terms of that part similar type of contract is really what I would suggest that is.

So right now, you are locked in at 35 and you are saying when those are off, based on where you think markets could be, it could be 45 or something?

That would be based upon sort of looking ahead of a similar type of contract based upon our view of what forward prices would be. That's not post-2007, it's really more looking at '05 and '06 type of prices.

Sure.

It was really to give just some color around that. Everyone has their own view of what forward prices could be, but it's more basically a low filing type of contract what we have with those CIPS and CILCORP. The daily marketplace, obviously, is obviously different than what I just described there.

Yeah. What are you seeing daily?

You know, what we saw basically, I saw 5 by 16. In the third quarter, we saw prices that probably ranged from $40 to $50. What we see probably for the fourth quarter in their range today, 35 to 45 bucks relatively speaking. So those are meaningful changes compared to where they were last year. That's probably up about 40 to 50% from those similar prices.

Right.

If you look at offpeak, the 7 by 8, you are probably looking at prices here this fourth quarter, really have been fairly consistent throughout the year 20 to 25 bucks. Which, again, is up about 30% from the prior year?

What's the usual mix? Should I just take the average?

I don't know if it's quite that way. It depends, I wouldn't just take a simple average, frankly. Depends upon the time of year.

Right.

Summer versus -- obviously we have quite a bit of length coming in the fourth quarter. We have fewer maintenance outages than what we've had in the prior years. So we have obviously more on-peak than we would during the summertime.

Okay.

At this time, there are no further questions in our queue. I would like to turn the call back over to our speakers today for any closing or final remarks.

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