Ameren Corporation (AEE) Q1 2008 Earnings Report, Transcript and Summary

Good morning ladies and gentlemen; 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 is being recorded, today, Friday, May 2nd, of 2008. I would now like to turn the conference over to Bruce Steinke, VP and Controller. Please go ahead sir.

Thank you, Marry and good morning everyone. I'm 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 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 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 statement section in the news release we issued today and the forward-looking statements and risk factors section 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 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 Investors section of our website 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 the discussion of our first quarter 2008 financial results and 2008 earnings guidance. We will then open the call for questions. Here's Gary.

Thanks Bruce. Good morning and thank you for joining us. To begin I'm pleased to say that we're off to a good start in 2008. Our core earnings in the first quarter 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 cost throughout our business combined with significant levels of investment in our Illinois and Missouri regulated businesses continue 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 as 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 recognized that our Illinois electric customers have experienced sizeable 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 annual residential electric bill increases in Illinois to less than 10% in the first year for each utility's 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 cost, cost of plant additions, storm costs, and post test year reliability expenditures. The ICC staff also opposed our Illinois utility's request to implant 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 the key step necessary to actively pursue energy efficiency initiatives that can help our customers. It's important to note that the ICC staff and other interveners' recommendations in this case are just the start in the multi-step process. In April our Illinois utility's through the bottle [ph] 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 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 14, 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 said in the past we believe the ICC will fairly assess these issues in this case. In Early April AmerenUE filed their 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, AmerenUE also requested implementation of a fuel and purchase power cost recovery mechanism. We expect staff and interveners testimony by late summer and the decision by the Missouri public service commission is required by March 2009. This past Wednesday we received an accounting order from the Missouri public service commission that will give AmerenUE the ability to seek direct recovery of, and record as a regulatory asset, all or a portion of AmerenUE'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 Accepted 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 or our Taum Sauk pumped-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 in summer. We continue to believe that substantially all damages and liabilities caused by the breach, 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 and AmerenUE's Callaway nuclear plant site. As we've 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 31st, 2009. Beyond the purchases made through the option 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 annualize 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 the 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. And 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 put... be able to deliver strong long-term shareholder value in the years ahead. I will 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 website as that 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 Generally Accepted Accounting Principles, of $138 million or $0.66 per share. Including the 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 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 imbedded in our transportation contracts for coal we ship 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. Accumulatively, the current and prior year mark-to-market impact caused $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 year's 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 for the reversal of a 2006 charge related to funding commitments, below income energy assistance energy efficiency programs. Again we've 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 were 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 Missouri Public Service Commission electric and gas rate orders affective in June and April 2007, respectively. In late 2007, the agency [ph] authorized redesigned electric rates to reduce seasonal fluctuations for residential customers who use electricity to heat their homes. The affect of these redesign 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 this quarterly variances on earnings are lower than previously indicated, because the power cost 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, but it [ph] was also a benefit in the first quarter of 2008, earning $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 cost 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 a 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 2008 compared to the year ago period, as we continue to make significant incremental investments 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 and the quarter. Moving on to our 2008 guidance, and slide 4. As we stated in the our news release this morning, we reaffirm 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've 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 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. Financing costs are higher as a result the recent refinancing of our option rate debt. Since the beginning of the year, we have been very active in the capital markets as we've issued nearly $900 million of debt to refinance outstanding option rate securities and to repay short-term debt secured to fund out 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 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 by Illinois regulated and non 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 statements section of our press release. This concludes my prepared remarks and we will be happy now to take your questions. Question And Answer

Thank you sir. [Operator Instructions] And 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'll 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 nickel impact to 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 had indicated kind of $0.20 swing and this year it will be about $0.10. And if you want to see the specifics quarter-by-quarter, I guess, I'd refer you to the slide presentation that we put up on the website, which we kind of put that text, graphic back up there again.

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

Warner, you mentioned something about bookings on to the reg asset.

Yeah, 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 that we are under-collecting on the power supply cost, we've hung up as a regulatory asset. It will be recovered during the third quarter. So, again those numbers are negative 5 now in the first quarter; no impact on Q2, positive 10, on Q3; and a negative 5 on Q4.

Okay. So, this is just shifting timing around.

It's just timing, yes.

Thank you very much.

You're welcome.

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

Hi, good morning.

Good morning.

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

With regard to the first question let me try and answer that, then we will see if have that segment, otherwise we may have to do that one offline. But with regard to the three months ended 2008 for our legal reporting segment UE was at $63 million, CIPS was at $2 million, Genco was at $46 million, Sauk Core [ph] was $20 million, IT was $2 million, and then other Ameren Corporation was at $5 million for a total of $138 million.

Okay. So is it fair to say that the SIPS and IT were most hit by the timing issues of the rate design.

Yeah there has been 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 kind of spreads proportionally across the Illinois subs to their size.

The Illinois rate relief of course is partly in our unregulated generation business probably [ph] in the Illinois.

Yeah. I am sorry. Okay. Do you have the $0.05 there where with you or should I follow up later.

Basically two-third UE; one-third, Genco.

Okay. Great. Thanks a lot guys.

Sure you are welcome.

Thank you. Our next question comes from the line of, excuse me, Dan Jinken [ph] with State of Wisconsin. Please go ahead.

Good morning, Dan.

Good morning. I was just 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 if you have what the revenue impact would be of the 1% change ?

Sure, with regard to Missouri, the requested ROE was 10.9% with the capital structure of approximately 51%. In Illinois the requested was 11% with the capital structure ranging for those entities, ranging between 51% and 53% equity content. When you look at the 1% changed that we talk to you about in the past. And that's comparing what we are currently earning in our existing business to get to a 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 the 1% change is $50 million and that's about $0.16 per share.

What was the prior ROE allowed for

The prior ROEs that we're allowed in Illinois generally were around 10% and in Missouri were 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. 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... 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... start from the very top. With regard to the overall impact on Missouri, the storm costs were $25 million, those are pre-tax dollars. And 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 cast. 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 recorded as regulatory assets.

And what on the... was there are any particulars as to what criteria the commission might use to decide between 0 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 asset should commence... should have commenced back in January of '07. Our view is that the amortization of that regulatory asset should commence as of the date 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 in excess of year or two of amortization, which would lower the $25 million found ratably then. So that's really the substantive difference. In terms of that, I think the Commission obviously will have the ability to look more closely and connect with [ph] the rate case in terms of the appropriateness of those costs and whatever regulatory policy they deem appropriate for the recovery of those unusual cost or extraordinary costs, in this case.

Okay, thanks Warner.

You are welcome, Doug.

Thank you. [Operator Instructions] And our next question comes from the line of David Grumhel with Wachovia Capital [ph]. Please go ahead.

Good morning, David.

Good morning guys. Nice start to the year.

Thank you.

Couple of quick questions for you. Following up on the ROE question, with you taken down Illinois on the year. What sort of ROE are you implying in guidance? I think you sort of been around five or six?

Well I think with regard to guidance, of course. We said at the beginning of the year in Analyst Day that we expected the Illinois regulated segment to earn 5%, we've 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 and 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.

So, I am assuming guidance reflect some pick up in rates from Illinois?

Overall guidance would reflect some constructive regulatory outcome in Illinois. Absolutely.

Settlement in either state. Are those possible, are those... is that something you look for, is that's something that's unlikely, can you give us any assessment on that?

Sure, with regard to settlement, and as you know in the past we've 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. And so I wouldn't suggest that either in Missouri, Illinois that we don't have that possibility to move forward and would welcome any of those opportunities... at a minimum to limit 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... the case would run its full course, the 11 months, and so therefore you go through the normal regulatory process. In the past, the 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 the Illinois we've obviously further along down that process. In Missouri we are just getting started. So the possibilities are certainly there, but the handicap well [ph] that's indeed distinct possibilities, it's just too difficult to say.

And then last question for you. Can you just talk a little bit about usage trends? I guess weather normalize... to your best guess on whether normalized, both on the gas distribution and on the electric side?

Sure. I think overall, David, what we are seeing and maybe your question gets to some of the impacts or potential of the economy. We are still seeing relatively solid sales. We have seen a little bit of pullback in some of our industrial sales this quarter. As you know one quarter is kind of difficult to sort of peg that and say you really have a trend. So, as we've 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 downtime, we typically don't have the spikes, one way or the other, in our business then maybe some others and 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 question. Of course, you know 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 effect things. And Gary I don't know in terms of the overall economic situation in the reason, do 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 a recession and we are seeing in that in the numbers that we're looking at for sales growth. We are seeing some growth still in residential and commercial with industrial down just slightly which is typical for us. And 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 with that, 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.

Good morning, Gregg.

In the Missouri case what would be the ultimate updated timeframe you'll be looking at to give a price of your coal usage and then for that period what's hedging level?

Well, I guess in terms of the case itself. I'll have Marty touch on, sort of, what the test chair [ph] we found and what the known and measurable updates are that we found in the case or at least what we... that we proposed in the case, I think he can mention some of those [ph].

Sure Gregg... 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 a test year of March 31 with updates, however, to June 30th. In terms of your fuel cost question, the fuel cost that are locked in, are those up really through January 1st. We would of course update through June 30th. 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 pretty stable throughout the years, so effectively its January 1st, 2008 cost that are reflected in the rate case.

I'll also add to that, Gregg, in terms of where we're at and hedged. I means those are known and measurable, we are 100% hedged for our coal and transportation costs of 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 in our normal measurement.

And the way the fuel cost 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 multiyear basis. More inline with what other states would have.

Gregg, this is Marty again. Under the state law that established and enabled fuel adjustment clauses. There is 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, why 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 re-file for these, the fuel adjustment clause, so that all the costs that 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.

Hi 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 few years?

Sure, with regard to the environmental clause, the Commission did issue rules associated with the environmental clause within the last 30-60 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 are going to be rather difficult to administer going forward. And in fact, we have raised some of those issues with the Commission in an agenda session made. They looked like they were... they in their discussions 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 step 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 the Commission is... 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 is inline with or varies from what Aquila got?

Sure, I'll let Marty address that.

Yeah, Doug, this is Marty again. In terms of the fuel cost that we have purposed... we've proposed to run through the fuel clause our fuel costs as well as our off system sales in the way it would be proposed to work is in this case they would establish sort of a net based fuel cost amount which would be fuel cost less all 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. And we've requested to be allowed to adjust rates up to three times annually for those changes. The 95% that we would be allowed to turn through the fuel clause is consistent with the Aquila fuel adjustment clause that they received.

And what's you argument. Obviously they didn't... haven't given you that in the past. And I think the argument has been that you have coal-based generation and lot more base-loads in 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?

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 those costs significant, but they are also volatile. And I think just evidence in the recent marketplace just continues to show that the overall volatility of coal related transportation costs. So we think that case is even stronger in terms of where we are at. 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 cost and off system 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 in the State of Missouri that has a fuel adjustment clause already, whereas in 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 fuel adjustment cost.

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 midnight on playback, and for one year on our website. 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 for dialing in.

Thank you. Ladies and gentlemen that will conclude today's teleconference. If you would like to listen to replay of today's conference, you may dial in 2303-590-3000 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.