阿莫林 (AEE) 2008 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Ameren Corporation 2008 first quarter 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) This conference call is being recorded today, Friday May 2, 2008.

I would now like the turn the conference over to Bruce Steinke, VP, and Controller. Please go ahead, sir.

Thank you, Mary, and good morning, everyone. I am Bruce Steinke, Vice President and Controller of Ameren Corporation and head of Investor Relations.

On the call with me today 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; our Vice President and Treasurer, Jerre Birdsong, 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 and our news release carry 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 Web site, www.ameren.com.

This call contains time sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited. I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements.

Such statements include those about future expectations, beliefs, plans, strategies, objectives and financial performance. We caution you that various factors could cause actual results to differ materially from those anticipated in the forward-looking statements.

For additional information concerning these factors, we ask you to read the forward-looking statements section in the news release we issued today 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 Web site that includes a slide that reconciles our earnings per share for the first quarter of 2008 to our earnings per share for the first quarter of 2007 on a comparable share basis, and a slide that compares our 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 Web site under "Presentations" or follow the link for the webcast. Gary will begin this call with an overview of key first quarter 2008 activities and Warner will follow with a discussion of our first quarter 2008 financial results and 2008 earnings guidance. We will then open the call for questions. Here is Gary.

Thanks, Bruce. Good morning, and thank you for joining us. To begin I am pleased to say that we are off to a good start in 2008. Our core earnings in the first quarter of this year were solid and overall consistent with our expectations. Our base load generation was up 4% and hydro plant output was up 55% over the prior year. Weather was also favorable and market prices for power were higher.

However, rising costs throughout our business combined with significant levels of investment in our Illinois and Missouri regulated businesses continued to negatively impact earnings. This is because our current utility rate levels are not sufficient to recover our costs and provide reasonable returns. As many of you know, in November of 2007, our Illinois utilities filed electric and gas delivery service rate cases with the Illinois Commerce Commission to increase their revenues by an aggregate of $247 million.

We certainly recognize that our Illinois electric customers have experienced sizable rate increases beginning in 2007 primarily because of higher power supply costs on which our utilities do not make a profit. During settlement talks with stakeholders last summer, we pledged to keep the overall residential electric bill increases in Illinois to less than 10% in the first year for each utilities residential customers. And our filings were consistent with that pledge.

In March, the ICC staff filed their direct testimony in the cases and recommended a total increase in electric and gas delivery service revenues of $48 million. The ICC staff recommended the disallowance of a portion of administrative and general costs, costs of plant additions, storm costs and post-test year reliability expenditures. The ICC's staff also opposed our Illinois utilities' request to implement cost recovery mechanisms for bad debt expenses and electric infrastructure investments.

However, the ICC staff offered limited support for our proposal to implement a rate adjustment mechanism for the decoupling of natural gas revenues from sales volumes which is a key step necessary to actively pursue energy efficiency initiatives that can help our customers. It is important to note that the ICC staff and other interveners' recommendations in this case are just the start of a multi-step process.

In April our Illinois Utilities, through rebuttal testimony, reduced these electric and gas revenue increase requests by about $27 million in the aggregate as they modified certain positions in response to proposals made by other parties. We also withdrew our request to implement cost recovery mechanisms for bad debt expenses. However, we vigorously defended the rest of our positions and filed additional support testimony with the ICC for other areas of proposed revenue increases which we believe should clearly be allowed and are supported by the evidence.

The next key dates in these cases are the ICC staff and intervener testimony due on May 14th, hearings in June, and an expected proposed order in August. Final decision from the ICC is required by the end of September. We look forward to continuing to present our case over the next several months. And as we've said in the past, we believe the ICC will fairly assess these issues in this case.

In early April, Ameren UE filed a request with the Missouri Public Service Commission to increase its annual electric revenues by $251 million. The increase request was driven by, among other things, higher fuel, greater reliability, and other expenditures and increased investments to meet environmental requirements and also meet our customers' expectations.

In the filing, Ameren UE also requested implementation of a fuel and purchase power cost recovery mechanism. We expect staff and interveners' testimony by late summer and a decision by the Missouri Public Service Commission is required by March of 2009.

This past Wednesday, we received an accounting order from the Missouri Public Service Commission that will give Ameren UE the ability to seek direct recovery of, and record as a regulatory asset, all or a portion of Ameren UE's 2007 storm costs. Those costs approximated $25 million. The amount of these costs that will be ultimately allowed to recover will be determined in our pending electric rate case.

We continue to evaluate the Commission's order; however, in accordance with generally accepting accounting principles, we may record a regulatory asset in the second quarter of 2008 representing the minimum amount that we expect to recover. Needless to say, achieving constructive regulatory outcomes in both Missouri and Illinois are essential in order for us to meet our customers' rising expectations, invest in our energy infrastructure on a timely basis, and deliver solid long-term returns to our shareholders.

In the first quarter of 2008, we also continued rebuilding the upper reservoir of our Taum Sauk pump storage hydroelectric plant. The cost of the rebuild is still expected to be in the range of $450 million, but completion is now scheduled for early 2010 due to weather-related delays this spring and summer. We continue to believe that substantially all damages and liabilities caused by the breech, including the cost of the rebuild, will be covered by insurance.

We also continue to proceed towards filing this summer a construction and operating license application with the Nuclear Regulatory Commission for a new unit at Ameren UE's Callaway nuclear plant site. As we have noted before, this filing does not mean we have made a final decision. It merely preserves the option for us to build a nuclear unit.

Finally, our Illinois Utilities successfully procured the remaining energy and capacity they need for the period June 1, 2008 through May 31, 2009 beyond the purchases made through the auction and swap agreements. For energy, the around the clock price averaged approximately $60 per megawatt hour and for capacity, the price averaged around $50 per megawatt day on an annualized basis. Our non-rate regulated generation marketing subsidiary participated in this process and was awarded a mix of on-peak and off-peak contracts totaling about 2 million megawatt hours for energy and a mix of various seasonal contracts totaling $6 million in capacity payments.

Next year, the newly formed Illinois Power Agency will be responsible for managing the power procurement process in Illinois. Recently a director has been named to head that agency and the planning process continues to move forward for next year's procurement activities.

As you can see, we are moving forward with the plan we outlined for you in January 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 increases and cost recovery mechanisms to reduce the impact of regulatory lag and optimizing our non-rate regulated generation business.

Of course, we are in the very early stages of executing this plan and I look forward to updating you on our progress. As I said in January, I strongly believe we can successfully execute this plan that will be able to deliver strong long-term shareholder value in the years ahead. I'll now turn this over to Warner to walk you through our first quarter 2008 earnings and 2008 earnings guidance.

Thanks, Gary. I would now like to refer you to the slide presentation on our Web site as I provide a more detailed discussion of our first quarter 2008 earnings. Turning first to page 3 of our slide presentation, today we announced first quarter 2008 net income in accordance with GAAP of $138 million, or $0.66 per share compared to first quarter 2007 GAAP net income of $123 million or $0.59 per share.

Excluding certain items in each year, Ameren recorded first quarter 2008 core, or non-GAAP, net income of $134 million, or $0.64 per share compared to first quarter 2007 core net income of $145 million, or $0.70 per share. We had several non-core items in the first quarter of 2007 and 2008 that we have excluded from our discussion of core earnings.

In the first quarter of 2008, the cost of the 2007 Illinois comprehensive electric settlement reduced earnings by $0.03 per share; however, this was more than offset by net mark-to-market gains from non-qualifying hedges, which benefited first quarter 2008 earnings by $0.05 per share. This is the first period in which we have eliminated mark-to-market gains or losses on non-qualifying hedges from our core earnings because the amounts in the past have been immaterial.

This quarter, we recorded significant mark-to-market gains principally on option contracts to hedge diesel fuel costs embedded in our transportation contracts for coal we shipped from the Powder River Basin. The sharp run-up in diesel fuel prices drove this gain in 2008. For comparative purposes we also carved out the net mark-to-market loss we had in the first quarter of 2007. This loss of $0.02 per share related primarily to energy swap transactions.

Cumulatively, the current and prior year mark-to-market impacts caused a $0.07 per share favorable variance in year-over-year GAAP earnings. Other items which we excluded from core earnings include the impact of severe ice storms in the first quarter of 2007 which reduced earnings by $0.09 per share. In addition, a Federal Energy Regulatory Commission order retroactively adjusting prior years' regional transmission organization costs reduced first quarter 2007 earnings by $0.05 per share.

Finally, there was a benefit of $0.05 per share in the first quarter of 2007 from the reversal of a 2006 charge related to funding commitments for low-income energy assistance and energy efficiency programs. Again, we have excluded all of these items from our core earnings comparisons. As Gary said earlier, our first quarter 2008 core earnings were consistent with our expectations. Core earnings in the first quarter of 2008 are below the same period in 2007 principally because of higher fuel prices, increased distribution system reliability spending, and the impact of electric rate redesign in Illinois.

The earnings impact of these unfavorable items was reduced by, among other things, improved generation levels, higher power sales prices, the impact of colder than normal weather on natural gas and power demand, and the benefit of the 2007 Missouri rate cases. The results of Missouri electric and gas rate cases added $0.06 per share to earnings in the first quarter compared to the year ago period.

This includes the benefit of higher electric and gas rates as well as lower depreciation and decreased tax expenses pursuant to the Missouri Public Service Commission electric and gas rate orders effective in June and April 2007 respectively. In late 2007, the ICC authorized redesigned electric rates to reduce seasonal fluctuations for residential customers who use electricity to heat their homes.

The effect of these redesigned rates shifted $0.05 per share of earnings out of the first quarter of 2008. The new rates were also expected to shift earnings out of the fourth quarter of 2008. These earnings are expected to be recovered during the third quarter of 2008 with no impact on full-year earnings. I should note the magnitude of these quarterly variances on earnings are lower than previously indicated because the power costs associated with the rate redesign are being recorded as a regulatory asset.

Other electric and gas margins increased $0.16 per share in the first quarter of 2008 primarily as a result of increased generation output and higher power sales prices. As Gary said earlier, our base load generation was up 4% as base load plant capacity factors increased from 79% to 82% and hydro plant production was up 55% due to heavy rains. In addition, power prices were stronger in the first quarter of 2008 over 2007.

Weather was also a benefit in the first quarter of 2008 adding $0.03 per share over the prior year period and $0.02 per share compared to normal. Heating degree days were 11% above 2007 and 6% above normal. As expected, we experienced higher costs for fuel and related transportation, which reduced first quarter 2008 earnings by $0.09 per share. Two-thirds of this was in our Missouri regulated operations and about one-third was in our non-rate regulated generation segment.

Plant operations and maintenance costs increased $0.02 per share in the first quarter of 2008 compared to the year ago period due to increased outage costs between periods. Distribution system reliability and maintenance expenditures reduced earnings by $0.06 per share in the first quarter of 2008 compared to the year ago period as we continued to make significant incremental improvements to improve reliability and customer satisfaction. In addition, we had several smaller storms that added to these costs in the current year quarter.

Finally, other labor and employee benefits, bad debt expenses, depreciation and amortization, other taxes and other expenses increased year-over-year in the quarter. Moving on to our 2008 guidance and slide 4, as we stated in our news release this morning, we reaffirmed that we expect 2008 GAAP earnings to be in the range of $2.68 to $3.08 per share and core, or non-GAAP, earnings to be in the range of $2.80 to $3.20 per share.

The $0.12 per share difference between GAAP and core earnings guidance is because of the estimated negative impact in 2008 on GAAP earnings of the 2007 comprehensive electric settlement agreement among parties in Illinois. We have also not assumed any net mark-to-market gains or losses in our guidance. Regarding specific items on the reconciliation of 2008 earnings guidance to 2007 actual earnings, we have increased expected electric margins to both realized and expected higher power prices.

In addition, we also increased our estimate for depreciation and amortization expenses as well as financing costs. The financing costs are higher as a result of the recent refinancing of our auction-rate debt. Since the beginning of the year we have been active in the capital markets as we have issued nearly $900 million of debt to refinance outstanding auction-rate securities and to repay short-term debt secured to fund our construction program.

As you know, early this year, the auction-rate securities market collapsed. We moved quickly to obtain the necessary regulatory approvals to refinance approximately $600 million of the $800 million auction-rate debt that we had outstanding. I am pleased to report that our auction-rate securities that had high default interest rates in the event of an auction failure have been successfully refinanced. The remaining $200 million of our auction-rate securities have reasonable default interest rates; however, we will continue to monitor market conditions for these securities.

We have also modestly revised the expected contribution to 2008 core earnings of our Illinois regulated and non-rate regulated generation business segments as shown on slide 5. We have lowered the range by $0.05 per share for the Illinois regulated segment primarily because of higher financing and bad debt costs, and raised the non-rate regulated generation segment by the same amount because of higher power prices.

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 statement section of our press release.

This completes my prepared remarks and we will be happy now to take your questions.

Thank you, sir. Ladies and gentlemen, at this time we will begin the question-and-answer session. (OPERATOR INSTRUCTIONS). Our first question comes from the line of Paul Ridzon with Keybanc. Please go ahead.

Warner, can you run through the rate redesign impacts again? I kind of missed that.

Sure, Paul. Happy to do so. I think what we will do, I'll have Bruce run through some of the specifics on a quarter-by-quarter basis.

Paul, on the first quarter, we had a $0.05 impact, the rate redesign, and I think if you go back to our investor day, we had $0.13 and for the full year, at the investor day, I think we'd indicated had a $0.20 swing and this year it will be about $0.10. If you want to see the specific quarter-by-quarter, I guess I'd refer you to the slide presentation that we put up on the Web site, which we kind of put that [text] graphic back out there again.

Of course as we said in the past, Paul, this has no impact on full-year earnings, this is just a shift between quarter and quarter.

Warner, you mentioned something about booking some of the reg assets or --?

Yes. Paul, what that is, is basically when you look at the impact, the amount we gave you in the first quarter was the revenue impact and a piece of that of course is the power supply cost which is just, effectively a pass through to the customers.

So what we have done is the amount we are under collecting on the power supply costs we have hung up as a regulatory asset that will be recovered during the third quarter. But again those numbers are negative $0.05 now in the first quarter, no impact on Q2, positive $0.10 on Q3 and a negative $0.05 on Q4.

Okay. So this is just shifting timing around?

It is just timing, yes.

Thank you very much.

You're welcome.

Thank you. Our next question comes from the line of Scott Engstrom with Blenheim Capital Management. Please go ahead.

Hi, good morning.

Good morning.

Just looking for reporting segment or filing company break down by net income and then additionally do you have with you there, how the mark-to-market would break out between the reporting subs?

Yes, with regard to, Scott, to the first question, let me try and answer those and then we will see if we have that by segment and otherwise we might have to do that one off-line.

But with regard to the three months ended 2008, for our legal reporting segments, UE was at $63 million, CIPS was at $2 million, Genco was at $46 million, CILCORP was $20 million, IP was $2 million, and then other Ameren corporate was at $5 million for a total of $138 million.

Okay. Is it fair to say that the CIPS and IP were most hit by the timing issues of the rate design?

Yes. The most significant impacts there were certainly rate redesign as well as incremental reliability spending year-over-year and they were favorably offset generally by some improved weather conditions in this quarter.

And the $0.03 of rate relief spreads proportionally across the Illinois subs to their size?

I am sorry. The Illinois rate relief, of course, is partly in our unregulated generation business and partly in Illinois.

I'm sorry. Okay. Do you have the $0.05 there with you or should I follow up later?

Basically it is two-thirds UE, one-third Genco.

Okay. Great. Thanks a lot, guys.

Sure. You're welcome.

Thank you. The next question comes from the line of Dan Jenkins with State of Wisconsin. Please go ahead.

Morning, Dan.

Hi, good morning. I was wondering on the rate cases in Illinois and Missouri, if for each of them you could give me the requested ROE and then the prior allowed ROE and then do you have the, what the revenue impact would be of the 1% change?

Sure.

The requested ROE?

With regard to Missouri, the requested ROE was 10.9% with a capital structure of approximately 51%. In Illinois, the requested ROE was 11% with a capital structure ranging for those entities with a range between 51% and 53% equity content. When you look at the 1% change we have talked to you about in the past, and that's comparing what we are currently earning in our existing business to get it to our allowed ROE, a 1% change in the Illinois business represents about $27 million of pre-tax income or approximately $0.09 per share, whereas in Missouri operations, a 1% change is $50 million and that's about $0.16 per share.

Okay. What was the prior ROE allowed for --?

The prior ROEs that were allowed in Illinois generally were around 10% and in Missouri it was 10.2% in the last rate case.

Okay. Thank you.

You're welcome.

Thank you. Our next question comes from the line of Doug Fischer with Wachovia Capital Markets. Please go ahead.

Good morning.

Morning, Doug.

Good morning, a lot of the questions have been asked, but just a quick question on the storm reg asset. Remind us what your total expense was and how much might -- what the range might be of actual potential recovery? And then I assume that potential regulatory asset is not in your GAAP guidance for the year?

Let me answer, I'll start from the very top. With regard to the overall impact on Missouri, the storm costs were $25 million; those are all pre-tax dollars. So our range of potential outcome in the rate case is up $25 million, and that's what will be considered in the next rate case. And then, you are correct, with regard to any regulatory asset that we would establish, that is not included in our GAAP guidance for the recovery, the potential record of those regulatory assets.

And what, on, were there any particulars as to what criteria the Commission might use to decide between zero and 25 or is that all left to the rate case?

Doug, when you look at the order I would say there were no specifics in there. I mean, one of the major issues that is being addressed relates to the appropriate amortization period for those regulatory assets. The staff believes that the amortization period for that $25 million of regulatory assets should have commenced back in January of '07.

Our view is that the amortization of that regulatory asset should commence as of the day of the final order in our next rate case. And so, that obviously would be a difference between the amortization periods where you might have an excess of a year or two of amortization, which would lower the $25 million down ratably then.

So that is really the substantive difference. In terms of that I think the Commission obviously will have the ability to look more closely in connection with the rate case in terms of the appropriateness of those costs and whatever regulatory policy they deem appropriate for the recovery of those unusual costs or extraordinary costs in this case.

Okay. Thanks, Warner.

You're welcome, Doug.

Thank you. (OPERATOR INSTRUCTIONS). Our next question comes from the line of David Grumhaus with Copia Capital. Please go ahead.

Morning, David.

Morning, guys, nice start to the year. Couple quick questions for you. Following up on the ROE question, with you taking down Illinois on the year, what sort of ROE are you implying in guidance? I think you've sort of been around 5 or 6?

Well, you know, I think with regard to guidance, of course, you know we said at the beginning of the year on analysts day we expected the Illinois regulated segment to earn 5%. We have lowered that to 4% because of these incremental financing costs and some incremental bad debt expenses that we cited in our talking points as well as the press release. So, our original guidance was closer to 5% ROE for them.

Okay. And you are expecting a rate order there, I think, in time for the fourth quarter?

That's correct.

Right. So, I'm assuming guidance reflects some pickup in rates from Illinois?

Overall guidance will reflect some constructive regulatory outcome in Illinois, absolutely.

Settlements in either state, are those possible or are those, is that something you will look for, is that something that is unlikely, can you give us any assessment on that?

Sure. With regard to settlement and as you know in the past we have always sought to work constructively with interveners in the case or parties to the case to try and settle either the entire case or certain issues. So I wouldn't suggest that either in Missouri, Illinois that we don't have that possibility to move forward. And we welcome any of those opportunities at a minimum to delimit some of those -- the issues which are pending.

In terms of in Illinois, typically, even if you have a settlement or even a partial settlement, historically that as the case would run the full course, the 11 months and so therefore you go through the normal regulatory process. In the past, in Missouri in the last case, we settled certain issues with certain parties throughout the case but that case, of course, ran its full course. That could still indeed be the case in this particular Missouri case, but with Illinois we are obviously further along down that process, in Missouri we are just getting started.

So the possibilities are certainly there, but the handicap of that is indeed a distinct possibility, it's just too difficult to say.

And then last question would be can you just talk a little bit about usage trends, I guess weather normalized to the, your best guess on weather normalized both on the gas distribution and on the electric side?

Sure. I think, overall, David, what we're seeing -- and maybe your question gets to some of the impacts of potentially the economy - we're still seeing relatively solid sales. We have seen a little bit of pull back in some of our industrial sales this quarter. But one quarter is kind of difficult to sort of peg that and say you really have a trend.

So as we have said in the past, when you look at overall usage as an organization, even as an area, whether we have an economic boom or an economic downturn, we typically don't have the spikes one way or the other in our business, than maybe some others in higher growth regions may see.

Okay, and gas distribution side, same thing, not too much conservation, you felt pretty good about demand on that side?

So far that's true. Of course, we've had stronger weather, but even when you normalize it, we haven't seen a meaningful change I would say here in the first quarter that would affect things. And, Gary, I don't know, in terms of the overall economic situation in the region. Do you have any other comments on that?

Well, David, the feeling by most people in our area is that the economy is soft, but not really in recession. We are seeing that in the numbers that we are looking at as far as sales growth. We are seeing some growth still in residential and commercial with industrial down just slightly, which is typical for us.

I think, as Warner mentioned, that we are not affected very much by the economic cycles in St. Louis. The economy here never seems to drop quite as low as it does in other parts of the country. And then when we rebound it doesn't rebound quite as vigorously as other parts of the country. So we just are not very sensitive to that and don't pay a lot of attention to it.

okay. That's helpful, guys. Thanks.

Thank you. Our next question comes from the line of Gregg Orrill with Lehman Brothers, please go ahead.

Thanks a lot. Good morning.

Morning, Gregg.

In the Missouri case, what will be the ultimate updated time frame you will be looking at to give them a price of your coal usage? And then for that period, what is your hedging level?

Well, I guess in terms of the case itself, I'll have Marty touch on sort of what the test year we filed and what the known and measurable updates are that we filed in the case, or at least that we have proposed in the case. I think the Commission itself can consider some of those.

Sure, Gregg, on the -- this is Marty -- in the case that we filed, as you are probably aware, we had a rate base of about $5.9 billion which represented in a test year of March 31 with updates however to June 30. In terms of your fuel costs question, the fuel costs that are locked in are those up really through January 1. We would, of course, update through June 30, and to the extent that the Commission allows us to update further to the end of September, we would do that as well.

However, as you probably know, most of our -- really all of our coal and coal transportation contracts which are the largest component of our overall fuel costs in Missouri, those rates generally change around the first of the year and then stay pretty stable throughout the year. So effectively, it is the January 1, 2008 costs that are reflected in the rate case.

I'll also add to that, Gregg, in terms of where we are at in hedged; I mean, those are known and measurable. We are 100% hedged for our coal and transportation costs in Missouri, as well as when you look out to '09, we have the vast majority of that already taken care of. For both coal and transportation in excess of 85%, 90% hedged entirely for both of those. So those amounts are out there and are known and measurable.

And the way that the fuel clause is going to work going forward in Missouri, is there any, I guess the question is, is there any potential to get that without having to come in for a full case or to look at it on a multi-year basis, more in line with what other states would have?

Gregg, this is Marty again. Under the state law that established and enabled fuel adjustment clauses, there's a requirement that fuel adjustment clause be established in the context of a rate case. So, it really can't be established outside of a normal rate case.

Additionally, under that law, rate cases are required every four years while you are using a fuel adjustment clause. And to the extent that we would come in for a rate case in between those two sort of milestones, we would also be required to, again, refile for the use of a fuel adjustment clause so that all of the costs that Union Electric is incurring can be considered at that time. So, the short answer to your question is, no, we really don't have the ability to establish a fuel adjustment clause outside of a rate case.

Okay. Thanks.

Thank you. (OPERATOR INSTRUCTIONS). And our next question is a follow-up from the line of Doug Fischer with Wachovia Capital Markets. Please go ahead.

Good morning, again.

Hey, Doug.

Hi. Just while we are talking about the fuel clause, maybe you can just update us, refresh us on the environmental clause situation and where we are at and how that might play forward here over the next years?

Sure. With regard to the environmental clause, the Commission did issue rules associated with the environmental clause within the last 30 to 60 days. As we have stated, we did not file for an environmental cost recovery mechanism in this particular case. Number one, because the existing rules that were approved by the Commission actually were going to be rather difficult to administer going forward. And, in fact, we raised some of those issues with the Commission and in an agenda session, they looked like they were -- in their discussions, it looked like they may, indeed, consider modifying those rules to be more user friendly prospectively.

But then, secondly, the other point from our perspective on the environmental clause is that most of our environmental capital expenditures, frankly, are occurring in years 2009 and beyond. And so, when we stepped back, we decided not to proceed to seek for the environmental clause in this particular case; however, it is certainly an important mechanism that we will seek to potentially use in future rate cases.

So we believe the Commission will reconsider the existing rules. If they do so, they will have to go through the typical rule-making process. But the Commission has not made a final determination on that as of yet.

And then remind us of the nature of the fuel clause that you requested to the degree that it is in line with or varies from what Aquila got?

Sure. I will let Marty address that.

Yes, Doug, this is Marty again. In terms of the fuel clause that we have proposed, we have proposed to run through the fuel clause our fuel costs as well as our off-system sales. And the way it would be proposed to work is, in this case, they would establish a net-based fuel cost amount which would be fuel costs less off-system sales. And then prospectively, after the new rates are set, any deviation in those net-based fuel costs, whether they go up or down, 95% of those changes would run through the fuel adjustment clause. We have requested to be allowed to adjust rates up to three times annually for those changes. The 95% that we would be allowed to run through the fuel clause is consistent with the Aquila fuel adjustment clause that they received.

And what's your argument, obviously, they didn't -- haven't given you that in the past. I think the argument has been that you have coal based generation and a lot more base load than some of the other utilities and a few of the other small utilities in the state. What's your argument to overcome that objection to giving you the fuel clause?

You know, I think, Doug, this is Warner again. As we look at it, we clearly believe we put evidence in this case to show that not only are those costs significant but they're also volatile. I think just evidence in the recent marketplace just continues to show that the overall volatility of coal and related transportation costs.

So we think that case is even stronger in terms of where we are at. And I think the other piece to remember is that in the last case, issues surrounding the fuel clause in general, there were several that made it a more complicated issue, things like the joint dispatch agreement, being the first time it was really considered and reviewed by the Commission in the context of determination of fuel costs and off-systems sales margins, as well as the EEI contract, among other things.

So, those issues have now been resolved and, in fact, we have better historical data that will make those issues, we believe, an easier exercise not just for the Commission but also for the other parties in the case. And then, lastly, is the fact that indeed there is a utility the state of Missouri that has a fuel adjustment clause already, whereas in the last case we were the first one to seek that in the state.

So all of those things we believe give us confidence that we will be successful in this upcoming case associated with the fuel adjustment clause.

Okay. Thanks.

Thank you. And there are no further questions. At this time, I will turn it over to Mr. Baxter for closing comments. Please go ahead, sir.

Great, and thank you all for participating in this call. Let me remind you again that this call is available through May 9 on playback and for one year on our Web site. The announcement carries instructions on listening to the playback. You can also call the contacts listed on our news release.

For those on the call who are financial analysts, please call Bruce Steinke or Theresa Nistendirk. Media should call Tim Fox. Contact numbers are on the news release. And again, thank you all for dialing in.

Thank you. Ladies and gentlemen, that will conclude today's teleconference. If you would like to listen to a replay of today's conference, you may dial in to 303-590-3000, or 1-800-405-2236 and enter the access code of 11112418 followed by the pound sign. We thank you again for your participation today and at this time you may disconnect.