阿莫林 (AEE) 2008 Q2 法說會逐字稿

Welcome to the Ameren Corporation second quarter 2008 earnings conference call. During today 's presentation all parties will be in a listen-only mode. Following the presentation, the conference will be open for questions. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded today, Friday, August 1, 2008. I would now like to turn the conference over to Bruce Steinke, Vice President and Controller. Please go ahead, sir.

Thank you, and good morning, everyone. I'm Bruce Steinke, Vice President and Controller of Ameren Corporation. On the call with me is our Chairman, President, and Chief Executive Officer, Gary Rainwater; our Executive Vice President and Chief Financial Officer Warner Baxter; our Senior Vice President and Chief Accounting Officer Marty Lyons; and other members of the Ameren management team.

Before we begin, let me cover a few administrative details. This call will be available by telephone for one week to anyone who wishes to hear it, by dialing a playback number. The announcement you received in our news release carries instructions on replaying the call by telephone . This call is also being broadcast live on the Internet and the webcast will be available for one year on our website www.Ameren.com. This call contains time-sensitive data, 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 futures 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 periodic filings with the SEC.

To assist in our call this morning, we have posted a presentation on our website that includes a slide that reconciles our earnings per share for the second quarter and first six months of 2008 to our earnings per share for the second quarter and first six months of 2007, on a comparable share basis. In the slide that compares out full-year 2008 earnings per share guidance to full-year 2007 earnings per share, again, on a comparable share basis. To access this presentation, you may look in the investor section of our website, under presentations or follow the link for the webcast. Gary will begin this call with an overview of key second quarter 2008 activities, and Warner will follow with a discussion of our second quarter 2008 financial results and 2008 earnings guidance. We will then open it up for questions.

Thanks, Bruce. Good morning, and thank you for joining us. This morning, we reported core earnings per share of $0.67 in the second quarter of 2008, which were comparable to the same period in 2007 and in line with our expectations. However, our GAAP earnings improved significantly, as there were some unusual items related to unrealized mark to market gains, a coal contract settlement and a Missouri Public Service Commission Order. Warner will go through these items in more detail in his remarks.

From an operational and regulatory perspective, a great deal of activity took place in our business in the first half of this year. Compared the first six months of 2007, the equivalent availability of our coal-fired units rose nearly 2% to 84% through June 2008. Importantly, our effective coal procurement and management strategies allowed us to run our coal plants at full available capacity, despite meaningful delays in coal deliveries at some of our plants due to significant flooding in the Midwest. In addition, we successfully negotiated a coal contract settlement with a coal supplier over higher fuel costs we expect to incur in 2008 and 2009 due to the coal suppliers' premature closing of a mine and termination of a contract. The settlement compensates us in total for the incremental fuel costs we expect do incur. Warner will also discuss this in greater detail a bit later .

Increasing costs of the fuel we need to run our business are indicative of the rising cost environment that our entire industry is facing. In particular, like our customers are seeing for everyday items, our business is experiencing significant cost increases across the board. This is occurring during a period when we also need to make substantial investments in our infrastructure for improved reliability and cleaner air. We've proactively taken actions to manage the cost increases especially as they relate to our fuel cost. To date, our actions have been very effective, and this is reflected in part in the large unrealized mark to market gains we recorded in the second related to the hedging of our diesel fuel cost exposure on coal transportation contracts. However our hedging activities and other proactive cost control activities cannot entirely eliminate the rising costs which are impacting all aspects of our business. These cost pressures, coupled with significant investments in our utility infrastructure have required us to seek rate increases for both our Illinois and Missouri regulated operations. In Illinois, the situation is particularly acute, with our utility operations recording a loss in the second quarter of 2008 and projecting returns on we equity of less than 4% for the year. Simply put, these results are not sustainable.

The current requested electric and gas annual revenue increase for Ameren's Illinois utilities is approximately $207 million, and the Illinois Commerce Commission staff has recommended an increase of approximately $87 million. The major differences are related to costs and plant additions that the Illinois Commerce Commission staff has recommended be disallowed from recovery for a variety of reasons . We clearly disagree with the staff's recommendations on these disallowance, and we've put forth a solid case to address these issues. The Ameren Illinois utilities have also requested gas revenue decoupling and electric distribution plant infrastructure rate adjustment mechanisms. We expect recommended orders from the administrative law judges in mid-August and final orders from the Illinois Commerce Commission in September with new rates expected to be effective in October.

In Missouri, Ameren UE has requested an annual electric revenue increase of approximately $251 million. Ameren UE has also requested implementation of a fuel and purchased power cost recovery mechanism in this case. We expect to see the Missouri Public Service Commission staffs and other intervenors' initial recommendations at the end of August. An order is expected from the Missouri Public Service Commission in February 2009. The bottom line is that achieving constructive outcomes in these cases is critical to our ability to continue to invest in our infrastructure so that we're able to meet our customers' expectations for safe and reliable service as well as provide solid returns for our shareholders.

On other regulatory matters, earlier this week we filed a combined construction and operating license application with the Nuclear Regulatory Commission for a potential new unit at Ameren UE's Callaway Nuclear power site. Although we have not made a decision to build a second nuclear power plant at this time, seeking NRC approval and a license this week will preserve the nuclear generation option for the future. It also will position our Company to seek nuclear specific federal loan guarantees and production tax credits made possible by the Energy Policy Act of 2005. It's estimated that NRC review may require up to 42 months for completion.

The Company's decision on whether to build a second nuclear power plant depends on a number of factors, including state and federal regulatory and legislative actions, the forecasted demand for power, the effectiveness of energy efficiency initiatives and the projected costs and financing challenges of building an advanced nuclear plan compared to building facilities powered by other fuels or developing renewable resources.

On the environmental front, on July 11, 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that effectively vacated the Federal Clean Air Interstate Rule or CAIR and early and earlier this year, a court had vacated the Federal Clean Air Mercury Rule or CAMR. The U.S. EPA has 45 days from the date of the Court's decision to file a petition for a rehearing. After this, the remaining Court Appeal is the to file a petition for review with the U.S. Supreme Court. This decision surprised many in the industry, and we are currently evaluating the impact that these court decisions will have on our environmental compliance strategy. Included in the evaluation will be a review of other relevant environmental regulations. Under Illinois regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOX and SO2 controls. In addition, Illinois and Missouri must also comply with the existing federal ozone ambient standard, the federal fine particulate ambient standard and the clean air visibility rule. Both Missouri and Illinois were effectively relying on the the implementation of CAIR and CAMR for compliance with all these other regulations. The bottom line is that it's now very unclear how this matter will be resolved. We expect this uncertainty to persist until the matter -- further court appeals are played out, and it's also quite possible that congress now will get involved .

As I said a moment ago, this uncertainty has led us to review our environmental compliance strategies as well as the amount and timing of related costs. In addition, this uncertainty has affected the NOX and, SO2 emissions allowance trading markets, where market prices have decreased dramatically, forward off-peak power prices have also been negatively affected by the July court ruling. Warner will discuss the potential financial implications of these matters in a moment, but we believe that some form of NOX and SO2 regulation will ultimately be enacted through legislation or some form of EPA regulatory proceeding. Despite these uncertainties, we remain focused on our plan to generate meaningful shareholder value. Our plan includes making greater levels of investment in our regulated businesses in response to customer needs and expectations, seeking rate in creases and cost recovery mechanisms to reduce the impact of regulatory lag, and optimizing our non-rate regulated generation business . I strongly believe we can successfully execute this plan and that we'll be able to deliver strong long-term shareholder value in the years ahead. I'll now turn it over to Warner to walk you through

Great. Thanks, Gary. I would now like to refer you to the slide presentation on our website, as I provide a more detailed discussion of our second quarter 2008 records.

Turning first to page three of our slide presentation, today we announced second quarter 2008 net income in accordance with generally accepted accounting principles of $206 million or $0.98 per share. Compared to 2007 second quarter GAAP net income of $143 million or $0.69 per share. Excluding certain items in each year, Ameren reported second quarter 2008 core net income of $142 million or $0.67 per share compared with second quarter 2007 core net income of $138 million, or $0.67 per share.

We've reported several significant unusual items in the second quarter of 2008 that we have excluded from our core earning . Net unrealized mark to market gains from non-qualifying hedges boosted second quarter 2008 net income by $0.23 per share as compared to net unrealized gains of $0.02 per share in the second quarter of 2007. These unrealized gains primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012. These financial instruments effectively locked in diesel fuel transportation prices at the time we entered into the contracts. The large unrealized mark to market gain was driven by the skyrocketing value of the heating oil option contracts utilized to hedge this risk. Of course, the value of these non-qualifying hedges will vary over time based on current market prices.

Another significant item excluded from core earnings in the second quarter was a lump sum payment from a coal supplier for expected higher fuel costs for unregulated generated operations in 2009 as a result of the premature closure of a mine in late 2007 and the resulting termination of our contract. We had mentioned this issue in our analyst day, and our 2008 earnings guidance and 2009 fuel cost guidance assumed we would be made whole by the supplier. Indeed, this was the case. However, based on the terms of the settlement, the entire $60 million we received was recorded in the second quarter. We estimate that approximately $27 million, or $0.08 per share of the settlement relates to 2009 costs, and we have excluded that portion of the settlement from our 2008 core earnings. While we have not yet provided earnings guidance for 2009, you should note that whatever you were assuming for earnings in our non-rate regulated generation segment, those earnings will now be an estimated 0.08 per share lower because of the lump sum settlement benefit we received this quarter. Again we have been fully compensated for the impact of the mine closure and the 2009 earnings impact has been fully offset by funds received in 2008.

In our first quarter call, we also highlighted the storm related order we received from the Missouri Public Service Commission and the possible earnings impact. This order gave Ameren UE the ability to receive direct recovery in its pending electric rate case and record as a regulatory asset all or a portion of am Ameren UE's 2007 severe storm costs for about $25 million or $0.09 per share. In the second quarter of 2008, Ameren UE recorded the minimum amount it expected to receive in the current rate proceeding. Which is $13 million or $0.04 per share. We strongly believe that full recovery of these storm costs is appropriate and are seeking recovery of the entire $25 million of costs in our pending rate case. Since we originally carved out the severe storm costs as an unusual item in 2007, we have similarly carved out the expected recovery of these costs this year.

Finally, the net cost associated with the Illinois comprehensive electric rate release through customer assistance settlement agreement reached in 2007, reduced GAAP earnings by $0.04 per share in the second quarter of 2008 . As Gary said earlier, our second quarter 2008 core earnings were comparable for the same period in 2007, net earnings for both the second quarter and first half of 2008 were consistent with our expectations.

To summarize our results, higher electric and gas margins and the benefit of not having a Callaway nuclear plant refueling and maintenance outage in the second quarter of 2008 as occurred in the second quarter of 2007, largely offset the higher fuel prices, increased spending on utility distribution system reliability and coal-fired plant operations and maintenance as well as higher other operating expenses.

Continuing with slide three of our presentation, results of the 2007 Missouri Electric and Gas rate cases added $0.02 per share to earnings in the second quarter, compared to the year-ago period. The effective seasonally redesigned rates in Illinois did not have much impact on earnings in the second quarter . You may recall that in late 2007, Illinois Commerce Commission authorized redesigned electric rates to reduce seasonal fluctuations for residential customers who use electricity to heat their homes. The impact of this rate redesign is expected to be revenue neutral for the year. Other electric and gas margins increased $0.18 per share in the second quarter of 2008 primarily as a result of higher power sales and higher realized electric margins. While there was a modest negative in the second quarter, reducing earnings by $0.03 per share compared to the prior-year period. Cooling degree days were 26% below 2007, and 2% below normal in the second quarter . However, the milder weather resulted in greater access generation being available for off system sales. Consequently higher power prices for all system sales, significantly reduced the impact of weather.

We continue to experience higher costs for fuel and related transportation which reduced second quarter 2008 earnings by $0.08 per share. This increase was split evenly between our Missouri regulated and our non-rate regulated generation segments. As previously discussed, the coal contract lump sum settlement associated with our increased 2008 costs favorably impacted second quarter core earnings by $0.10 per share. Lump sum settlement effectively offsets the fuel price increases we are experiencing and expect to experience for the balance of the year as a result of the premature contract termination. Earnings were also favorably impacted by the fact that there was no refueling and maintenance outage at Ameren UE's Callaway nuclear plant in the second quarter of 2008, as occurred last year. This increased earnings by $0.16 per share. The Callaway plant is scheduled for a 25 to 30-day outage in the fourth quarter of this year.

Plant operations and maintenance expenses increased by $0.06 per share in the second quarter of 2008 as compared to the same period in 2007 as a result of increased maintenance activity. Distribution system reliability and maintenance expenditures reduced earnings by $0.08 per share in the second quarter of 2008, compared to the year-ago period as we continue to make significant incremental investments to improve reliability and customer satisfaction. Financing costs increased $0.03 per share in the second quarter of 2008 over the prior-year period as a result of the refinancing of auction rate securities and other long-term debt payments. Labor and employee benefits, bad debt, depreciation and amortization and other expenses also increased year over year in the quarter.

Moving on to our 2008 guidance in slide four. As we stated in our news release this morning, we reaffirmed that we expect our core or non-GAAP earnings to be in the range of $2.80 to $3.20 per share. We also increased expectation for 2008 GAAP earnings to be in the range of $2.80 to $3.20 a share, up from the previous estimate of $2.68 to $3.08 per share. The increase in our GAAP earnings guidance was driven by the $0.08 per share benefit from the coal contract settlement related to expected 2009 costs and the $0.04 per share positive impact of the Missouri storm accounting order as previously discussed. The estimated $0.12 per share negative impact of the Illinois comprehensive electric rate relief and customer assistance settlement agreement has been excluded from core earnings guidance since the beginning of the year, and offsets the new items I just mentioned, resulting in our current GAAP and core earnings guidance being the same.

Ameren's consolidated and segment guidance for 2008 assumes normal weather, and is subject to, among other things, regulatory decisions and legislative actions, plant operations, energy market and economic conditions, severe storms, unusual or otherwise unexpected gains or losses, and other risks and uncertainties outlined or referred to in the forward-looking statements section of our press release.

I will also note that any net unrealized mark to market gains or losses from non-qualifying hedges will impact GAAP earnings, were excluded from our GAAP and core earnings guidance as the Company is unable to reasonably estimate the impact of any gains or losses due to the volatility of markets. We have adjusted a few line items on our reconciliation of 2008 earnings guidance to 2007 actual earnings. Most noteworthy are the increase in estimated bad debt expenses and other expenses which are reflective of the rising cost environment and economic conditions we are facing in our businesses, as Gary described earlier. These were offset by expected improvements in several other areas. Again, as we stated in the past there's a range of outcomes that could occur around any of these plan estimates.

As Gary noted earlier, we have recently seen some very volatile markets for power and NOX and SO2 emission allowances. Since July 1, power and emission allowance prices have fallen . Several factors can be driving this volatility, including the recent CAIR ruling, falling natural gas and crude oil prices and the economy among other things. Due to the potential for these types of volatile market conditions, our risk management practices have historically required that we proactively sell forward our excess generation to mitigate the impact of these market uncertainties. Such a policy is intended to mitigate deep declines in the markets as we have recently seen. It also accepts the fact that sales may not be made in the market peaks as well. To illustrate, entering 2008, we had hedged approximate little 85% of our systemwide generation, and currently we have hedged approximately 95% of our expected total 2008 generation.

Looking ahead, we're now focusing only on our non-rate regulated generation business, we currently have hedged approximately 80% of this expected generation for 2009, which is up from 60% at the beginning of the year. While we have hedged much of our exposure to declining market prices, we still have approximately 5 million megawatt hours of our total generation unhedged for the balance of 2008 and about 6 million megawatt hours unhedged in our non-rate regulated generation business in 2009. Consequently, the deep declines in power prices that we recently witnessed should they persist and still have meaningful impacts in our financial results for 2008 and beyond. Having said that and as we have stated before, we remain bullish on long-term power prices. In addition, we believe that short-term power crisis will see modest strengthening from current levels as we move through the rest of the summer cooling and tropical storm seasons. Of course, we can't predict with certainty where power prices, for that matter, or other commodity prices will be in the future. Market conditions are unpredictable, and that is why we employ the risk management practices that we do . We will provide greater levels of specificity around our view of our future power, fuel and other commodity prices when we update our long-term guidance letter this year.

Turning now to the recent significant market decline for emission allowance credits, we are certainly aware these declines have resulted in other companies announcing potential large impairments of their emission allowances. As a result of the recent market declines, we have also evaluated our mission allowance bank for possible impairment. The bottom line is that we do not foresee any impairment of our allowances based on our intention to use our bank announces as part of our generation emission compliance strategy.

One final thing before we turn it over to questions. I would like to announce that Doug Fischer has joined Ameren to head up our investor relations group as Bruce focuses on his new Controller responsibilities. I expect many of you know Doug very well from his years of experience as one of the leading sell side analysts in the utility sector for A.G. Edwards and most recently Wachovia. We are excited to have Doug join our team. Bruce and Doug will be working over the weeks ahead to transition responsibilities. In the meantime, continue to call Bruce with any questions . We will send out a note to our distribution list when it is the right time to begin communicating directly with Doug.

Thank you, sir. (OPERATOR INSTRUCTIONS) And our first question comes from Greg Gordon with Citi. Go ahead, please.

Good morning, gentlemen.

Good morning, Greg. How are you doing.

I'm hanging in there. How about you guys.

Great. Thank you.

I was just looking at the forward power curves in relation to the commentary you made about your incremental hedging, and it doesn't -- I know markets have been extremely volatile, but it doesn't look like 2009, around the clock prices in Illinois or the Midwest are meaningfully different today than they were January -- the first couple weeks of January, which, right before you gave your analyst presentation. So we had a huge run-up in prices -- we know prices have come back down. But as you look at the guidance you gave for short and long-term earnings based on the markets at the time are you seeing something different from what I'm seeing? Were prices materially lower? And is that why you felt you had to disclose it?

Thanks. This is Warner. Your observation, I think, is accurate. On analyst day, we gave ranges for the future, a range in between $48 and $54 per megawatt hour. That included 2008. If you look today, you would see a range approximating $50 to $52 per megawatt hour. As we said even then and as we said just a few minutes ago, we think that the fundamentals in the marketplace will continue to drive those prices upward. But by and large, they're very consistent with what we have said before.

So if anything, the incremental hedges that you did -- you were putting them in on a regular basis over the course of the year. There were several prolonged trading periods where you could have garnered higher prices in that range?

Yes. That's certainly -- we'll give more specificity around there, but certainly earlier in the year our hedge strategy was to try and take some of that risk off, and certainly, as you pointed out, the power prices were stronger in the first half of the year. So we had those opportunities. Absolutely.

Thank you.

Sure.

Thank you. And our next question comes from Dan Jenkins with the State of Wisconsin Investment. Go ahead, please.

Good morning.

Good morning, Dan.

First of all, I was wondering if you could give a little more color on what the issues were with regard to the core decision on the environmental laws or regulations, and--?

Dan, this is Gary Rainwater. I won't profess to be an expert on environmental rules, but my take on it is that the courts decided the rule making was fundamentally flawed, because it didn't address emission reductions on a state-by-state basis. And the court's interpretation was that it should have addressed those reductions state-by-state rather than over a broad region. So for that reason, the court sent it back to EPA -- somewhat with guidance that it needed to take an entirely different approach which then raises a whole lot of questions about where we are, because it took years to develop the care ruling. Our industry felt it was in general a pretty good ruling. We really didn't expect it to be thrown out in the way it was. And now it's -- we have no idea how long it will take to develop another rule making. Ultimately, though, we have to do something do reduce SO2 and NOX. There's no question about that. Just a question about how long does it take for the EPA or for the legislature to decide what the final requirements are going to be.

Okay. Does that change your environmental CapEx plans in any way, or--?

We are reevaluating our environmental CapEx plans, and the question there is, well, what do we reevaluate them based on? There is a possibility that some of our scrubber projects could slip ; and, of course, we would like to be able to defer those CapEx requirements, if it is at all possible. There is probably a greater possibility that it could slip in -- those requirements could slip in Missouri, because Missouri adopted the federal Clean Air and America Mercury standards pretty much straight in line with the federal requirements, while Illinois set requirements that were somewhat more stringent and developed its own multi pollutant rule making. Now the Illinois rule making was also based on CAIR and CAMR and the assumption that those rule makings would stand . So we're uncertain where the Illinois requirement leaves us as well. But we're certainly focused on deferring any capital expenditures here that

Okay. Another thing I was curious about is your Illinois rate request, and you mentioned -- you asked for 207 and the staff was at 87, I think. So I was curious if you could break down the main items that are behind that difference.

Warren can probably fill you in on the details. There are a couple of big ticket items. One is allocation of A&G costs and one is the inclusion of additional plant investment in the rates, but Warner?

I think Gary you hit on really the two main items that are out there. And so -- and Dave, we put our case before the administrative law judge now on those particular issues, and we expect to hear from the administrative law judge here in August with a final decision coming from the ICC in September. Those are really the two big ticket items among other smaller ones, but those are the main drivers.

But what were the -- what was kind of the idea behind that? Was it just--?

Part of the issue related to the plaintiffs allowances related to a documentation issue for lack of a better term in terms of some of the invoices that were reviewed by the staff and were, I guess, in dispute. We believe we satisfactorily provided that documentation to show that the investments that we've made were, indeed, put into the ground, if you will, and so we feel strongly that that documentation is going to be satisfactory; but of course, it 's ultimately up to the Illinois Commerce Commission that they review those facts and circumstances.

Okay. And then, I noticed the industrial sales sales are down. Is that -- do you think there's an impact from the economy, or is there a specific factor going on in--?

I'm sorry , Dan. You're breaking up. Can you repeat

Yes. The industrial sales in December were down. I was wondering if you think that's an impact from the economy or are there other factors going on in your service territory that would cause the industrial to be down?

Dan, we really haven't seen much decline and when we look at sales in general, we see pretty solid growth in the residential commercial sector, with just a moderate downturn in industrial and net-net, some positive growth. So I wouldn't say that our economy has been in recession, but it 's just sluggish. And your guess is as good as mine where the economy will go over the next year. Speculation is all over the map on that.

Okay. And then the last thing I was wondering is your short-term debt is well over $1 billion. Do you have any plans to term that out, or how are you going to address that?

We'll let Jerry Birdsong address that, who is our VP and Treasurer.

Yes. We do have plans on terming that out on our analyst day presentation . We gave the information on what the expected negative free cash flow was for the year, and we have termed out approximately half of that amount that was just over $1 billion in total. And we will continue to term that out and complete the rest of it during the remainder of

Okay. Thank you.

You're welcome, Dan.

Okay. Thank you. And our next question comes from Paul Ridzon with KeyBanc. Go ahead, please.

What level of EA sales were kind of in this year's budget or guidance.

I'm sorry, Paul?

Are we -- Paul, we had included just the 5 million that we were allowed to sell in Missouri under the last rate order.

Yes. That's correct. And then how much of the mine settlement did you book in this quarter?

$0.10 per share.

And you're calling that ongoing?

Yes. It was two parts to it, Paul. There were the $0.08 that we carved out that relates to '09, and the cents that's related to higher costs we expect to incur in 2008. We're calling the current-year piece ongoing, and the 2009 piece non-ongoing.

Yes, because simply, as I said, this is Warner. As you know, we're incurring incremental costs in both 2008 and 2009. So the piece that we were paid for in the second quarter for 2008, those monies will go to offset the incremental costs that we incur throughout this year . And then for those that were paid in advance for 2009, that's what we've carved out of core earnings

Are you going to put that back in '09?

At this point in time, what we've simply done is just carved it out as an item. Certainly we've identified it as a difference compared to where we were an analyst day, but we 'll end up carving it out or not. I guess that remains to be seen. I think, the most important thing is that people are aware that the fuel cost information we have given you at the beginning of the year had already factored that Exxon settlement out. But on a GAAP basis, that will not show up that way next year .

Okay. I understand. So there could be a sense that disappears from earnings if you don't add it back--?

Yes. If you had factored that back into your non-rate regulated generation, that's what we said, if you have that in there on a GAAP basis, that will go away.

Okay. Thank you very much.

Sure.

Sure.

Okay. Thank you. And our next question comes from Yiktat Fung with Zimmer Lucas Partners . Go

Good morning.

Good morning.

I just have a couple quick questions with regards to the Missouri rate case filing. I think Union Electric updated their filing in the middle of June. I was wondering if there's another opportunity for an update as the case progresses in the test year.

I'm sorry . You're break breaking up a little bit. You're asking the question whether there's an opportunity to update further our existing rate case in Missouri, and maybe Marty, you can

Correct.

Sure. Right now, as we mentioned earlier on the call, the rate request stands at around 250 million, and there will be pro forma adjustments made to the test year through to September of 2008.

Okay.

And those pro forma adjustments, those have already been made in the update that was filed in the middle of June of this year, right? I'm sorry. You were breaking up. Would you mind repeating that question?

I'm sorry. Does the June filing already include these pro forma adjustments through September '08?

No, I don't believe it does.

Okay.

The June you're talking was basically when we made the filing we used nine months of actual and three months of budget, and so the June filing was replacing that three months of budget with three months of actual essentially through March 31.

I see. So there will be yet another update that updates the pro forma through September '08?

Yes, there will be.

Okay. Thank you. And just one clarification question. Before you were talking to Greg about power pricing and you gave some sort of a range of 50 to $52 per minimum hour, can you just remind me what year is that for?

That was really for 2009 and '010 that we were talking about there?

Thank you.

Sure.

Thank you. And our next question comes from Steve Gambuzza from Longbow Capital. Good morning.

Hey, Steve. How are you?

Good thanks. You mentioned you were going to update your longer term earnings guidance later this year. You usually provide full-year guidance with the first quarter earnings release -- or with the fourth quarter earnings release; is that correct?

Yes. With regard to this year's, we did in January, and we had provided that advance of our year end conference call, about a couple, three weeks. Our expectation would be that we would come in either late this year or early next to, and manage similar to where we had provided 2009 and beyond earnings guidance; and then, of course, if there is a meaningful update to 2008, we would do that as well.

Okay. Great. And then, just to make sure I understood some of the commentary regarding the CAIR changes that's impacting your CapEx budget, is it fair to say it's unlikely to have a significant impact on your Illinois spending, but may have more of an impact on your Missouri spending long-term?

Steve, I wouldn't characterize it as that at all. I think we were looking at both Missouri and Illinois. I think Gary said, it was likely it would be more Missouri. We don't disagree with that. But I think as we step back, we're looking at all of our alternate I was . We have to think about the changes in laws. So it would be premature to speculate in terms of magnitude, but I would say that it would not have -- it could potentially have a material impact on Illinois. It's just too early

But does this impact, the settlement agreement that you signed with the governor?

Certainly that agreement is out there, and it is part of the or regulations, if you will, and so -- but having said that, there's still maybe some opportunities for us to manage our capital expenditures within that framework.

Thank you.

Sure.

Okay. Thank you.

(OPERATOR INSTRUCTIONS) And our next question comes from David Grumhaus, Wachovia Capital Partners. Go ahead, please.

Hi David. How are you.

Good. How are you?

Good thanks.

A couple of questions on the rate case. You touched a little bit on Illinois. Obviously you have got these two large items. Do you see where the staff coming on these things or if the staff has missed something? I know you talked a little bit about giving them some receipts on the plans and those type of things, but what's your confidence level that you're going to be able to get the commission?

Well, I'm sorry. I didn't mean to interrupt you. You know, I think the bottom line is that we strongly disagree with the views that were expressed. We put forth what we believe is very good evidence to address the A&G cost issue as well as the capital rate-based edition issue, and so we've -- and so, in terms of confidence, we feel confident in the position we've taken, and that ultimately will be up to the Illinois Commerce Commission to assess that. But -- and when we look at the positions taken, we think that our view is the correct one.

Okay. Over on Missouri, I saw that Empire got their fuel clause this week. Does that give you more confidence that you're going to be able to get something like that? Is yours patterned after that? Do you have any reactions to it?

Sure. Well, as you know, Empire just received their order the other day, and we're still in the process of reviewing the details. But from what I've seen in terms of the fuel adjustment clause, their order looks very close to the request that we had made in our pending -- in our pending rate case. And similarly, the ROE that they received, which is 10.8% is very similar do the ROE that we requested in our rate case. So while we don't know the details, it certainly appears that they received a constructive regulatory order, and that's certainly what we're seeking in Missouri as well, is a constructive regulatory order so we can continue to do the things that we're doing in terms of making investments in the infrastructure and improving customer service and satisfaction. So always precedent, I believe, is a good thing, and as we've said before, and Tom Voss has said it in our analyst day, and we've said it consistently throughout that we feel confident that we'll have fair treatment in Missouri rate order -- or the Missouri rate case as well as the opportunity to receive the fuel adjustment clause.

Are settlements possible in either of these two cases, or is it your expectation they will go through the full?

I would say, with regard to Illinois, settlement is really past that stage at this point in time.

Right .

I think we're at the stage where it is going to be before the ALJ and the Illinois Commerce Commission here very shortly. And Missouri, certainly. I mean, I think there's always the opportunity to settles aspects -- certain aspects of the case as well as potentially the entire case. But I'll tell you where we sit today is very early in that process.

Right.

As you know. We're still going through the data review process, and we expect to see the staff's position and others a little bit later this summer. But if you recall in Missouri, they actually put on their agenda settlement dates, where the parties actually do get together to try to talk to the issues to try and minimize the level of issues that ultimately go before the Commission and potentially settle the entire case.

Okay. There's very helpful. Thanks. Guys.

Okay. Thank you. And our next question comes from Michael Lapides with Goldman Sachs . Go

Hey, guys. A quick question on your non-rate regulated generation. Can you give an update -- and you may have done it and I just missed it, on coal hedging incremental to what you talked about in January? Coal and rail. I'm sorry, all in.

Yes. You did miss it, but we can give you an update on some of it in terms of what we've done on the coal and transportation side. As you know, we've historically, have a historical approach to where we try and layer in our hedges for coal and transportation over time, and consistent with that approach, we've done more since the beginning of the year. Going into 2008 and focusing on unregulated generation, which is what I think where your question was. Basically for 2008, analyst day, we were 100% hedged. Of course, that's where we're basically at now.

During analyst day, we were out there for coal and transportation for 2009, net range of around 70, 72%. We have done -- we have increased our percent closer to 85, approximately 85% today, and then, in 2010, we were -- for the non-regulated, we had hedged 16% of our total coal and transportation costs. That number has now moved up to in excess of 25%. Now, that seems like a low number, and let me tell you why that seems like a low number. That's because out in 2010, we have not locked up our transportation contracts yet for our unregulated generation, which as you know is a meaningful portion of our costs. Having said that, we have, on the coal commodity side, hedged up to 70% of our coal commodity for 2010. So we have made meaningful progress, and we are currently in good-faith negotiations with our rail suppliers to try and secure our needs for a little bit of 2009 and then for 2010 and beyond.

Got it. And can you just give roughly what the breakout -- PRB coal right now is around $15 or $16. With the breakout, how much of the total cost is coal versus rail?

Generally speaking, a rule of thumb in the past has been about two-third has been rail, and a third coal .

Okay. Got it. Thank you, guys.

You're welcome, Michael.

Thank you. And our next question comes from Alex Kania with Merrill Lynch. Go ahead, please.

Good morning.

Good morning.

A quick question on the 2008 guidance and how things are shaping up year to date. Just one that kind of stood out to me. I was just wondering if you could give a little more detail on it was the dilution in financing. You're running about $0.03 down for the year to date to period, and I think the full-year guidance is about $0.12 and I was just wondering, what are the pieces of that that we should be looking a this year?

Sure. I tell you, the principle driver of that change related to the refinancing of auction rate debt . If you remember obviously the credit markets, what happened to them earlier in the year, we had a fair amount of that auction rate debt primarily in both our -- in both our Missouri regulated and Illinois regulated businesses. We very quickly went out and refinanced that debt during the first half of the year. And nd obviously at rates that were higher than what we're -- probably very low rates historically, around 3 or 4%. They have not been refinanced at the 5 to 6% type of rates . So that incremental piece is what's driving it. And then -- and then, so, therefore, those increases are primarily in the Missouri regulated and Illinois regulated businesses. That's where

Okay. Great. And just another question just on the -- any updates on the development of capacity in the ancillary markets and MISO rail?

Sure. Andy Serri, who you met at analyst day, who is the President of Ameren Marketing Company, can probably give you the best updates in terms of what's going on in the ancillary services market and a little update on the capacity as well.

Yes, Alex. Good to hear from you. MISO did certify, John Barrett their Chief Operating Officer did certify that they are ready for a September 9, start of the ancillary services market in MISO. And we are as other market participants and the whole industry is preparing for the start on September 9. MISO is probably -- we're probably talking a year, year and a half, two years before a formal capacity market developments in MISO. Right now there is a capacity market that is fairly robust, but it is strictly bilateral at this time.

Great. And just the last follow-up question would be, have you seen any trends in those bilateral capacity prices recently for the past quarter or two ?

Yes. The bilateral capacity market for 2009, 2010 is in that $60 to $70 per megawatt day range, and for '10 and '11, we're seeing the range in range of $70 to $80. As we said back on our analyst day, we're shooting for that 75 to 80% hedge on our capacity.

Great. Thanks, guys.

No problem.

Thank you. (OPERATOR INSTRUCTIONS) And we have no further no further audio questions at this time. I'd like to turn the conference over do management for further statements.

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