威斯康辛能源 (WEC) 2005 Q4 法說會逐字稿

Good afternoon and welcome to the Wisconsin Energy year-end conference call and webcast. Before the conference call begins I will read the forward-looking language. All statements in this presentation other than historical facts are forward-looking statements that involve risks and uncertainties which are subject to change at any time. Such statements are based on management's expectations at the time they are made. In addition to the assumptions and other factors referred to in connection with the statements, factors described in the Company's latest Form 10-K and subsequent reports filed with the Securities and Exchange Commission could cause actual results to differ materially from those contemplated.

During the discussions, reference earnings per share will be based on diluted earnings per share unless otherwise noted. This conference is being recorded for rebroadcast and all participants are in a listen-only mode at this time. After the presentation, the conference will be open to analysts for questions and answers.

In conjunction with this call, Wisconsin Energy has posted on its website a package of detailed financial information on its 2005 fourth-quarter results at www.wisconsinenergy.com. A replay of our remarks will be available approximately two hours after the conclusion of this call.

And now I would like to introduce Gale Klappa, Chairman of the Board, President and Chief Executive Officer of Wisconsin Energy Corporation. Please go ahead.

Good afternoon everyone. Thank you for joining us on our conference call to review the Company's 2005 year-end results. Let me begin as always by introducing the members of the Wisconsin Energy management team who are here with me today. We have Rick Kuester, President and CEO of WE Generation; Allen Leverett, our Chief Financial Officer; Larry Salustro, our famous General Counsel; Jeff West, Treasurer; and Steve Dickson, our Controller.

I'm also very pleased to introduce Jim Fleming, who joined our management team just a few weeks ago. Jim will become the Company's General Counsel as Larry Salustro transitions to retirement. Jim as many of you know was formally Associate General Counsel at Southern Company in Atlanta, a company some of us are familiar with. But Jim is moving back to his Wisconsin roots and we are delighted to welcome him to the Wisconsin Energy team.

Thank you, Gale.

Overall I'm very pleased with what we accomplished in 2005. We made significant progress on our Power the Future plan and we continued to improve our financial and operational performance. Allen will review our results in detail in just a moment but as you saw from our news release this morning, we achieved adjusted earnings from continuing operations of $2.42 a share in 2005. On a comparable basis, earnings were $2.13 a share for 2004.

Our adjusted 2005 results exclude an after-tax gain of $0.14 a share from the reversal of state tax operating losses. For 2004, adjusted results exclude $0.29 a share in charges that the Company took for severance and early debt redemption costs.

Now just a few weeks ago on January 18, we announced an increase of 4.5% in the dividend on our common stock. The new quarterly rate is $0.23 a share which brings our annual rate to $0.92 a share. This new rate will be effective with the first-quarter dividend and that is payable on March 1. The increase reflects our stronger financial position and the confidence we have in our business plan. We have now raised the dividend in each of the past three years for a total increase in the quarterly dividend of 15% since the beginning of 2004. Our goal continues to be to raise the dividend on a consistent predictable basis at approximately half the rate of growth in our earnings per share.

Now I'd like to update you on our effort to upgrade the energy infrastructure in Wisconsin. As you know we call this our Power the Future Plan. Let me begin with our Port Washington project. In November of 2002, the Public Service Commission approved the construction of two 545 MW natural gas-fired units at our Port Washington site which is north of Milwaukee. On July 16, 2005, the first Port Washington unit went into commercial service on time and on budget. I'm also pleased to report that our new unit at Port Washington was selected by Power Engineering Magazine as the best gas-fired project of the year.

Construction of the second unit at Port Washington has two major phases, first is demolition of the remaining coal facilities at Port Washington and that is now nearing completion. The construction phase will start on schedule this spring and we expect to begin commercial operation in time for the peak summer season of 2008.

Now let's turn to the status of the two new coal-fired units at Oak Creek. Activity at the site which is south of Milwaukee began in earnest in late June following the Wisconsin Supreme Court ruling that allowed us to move forward. Since that time the major focus has been on site excavation, drilling of the down shafts in Lake Michigan for the water intake structure and building the necessary foundations in various areas around the site.

Bechtel Corporation, our major contractor has excavated now about 4 million cubic yards of material so far. That's about 70% of the amount expected for the entire project. Bechtel has reached final grade for the Unit 1 boiler building and is preparing now to pour the foundations in that area. Work on the lake is suspended until the summer when the remaining two down shafts are scheduled to be completed.

Engineering for the project is now about 53% complete and in the area of procurement, Bechtel has issued purchase orders and subcontracts covering about 80% of the total expected procurement. Overall project completion stands about where we expected it to be at 5%.

In other developments, on November 4 of last year, Madison Gas & Electric and Wisconsin Public Power agreed to collectively purchase a 17% ownership interest in the Oak Creek units. This is consistent with the plan that we have presented to you so it does not represent any change in the earnings stream that we expect from the new coal units. The minority owners will fund their pro rata share of the construction costs now on an ongoing basis.

As you know we have received all state and federal permits necessary to build the new units at Oak Creek and in September all parties agreed to dismiss an appeal of the air permit. So we now have final resolution of all legal challenges to the air permit. Certain other permits continue to be contested but they remain in effect unless and until overturned by a reviewing court or an Administrative Law Judge. Our plan is to have the first unit at Oak Creek in service in the summer of 2009. The second unit is scheduled to follow one year later in 2010.

Now turning to our nuclear operations. In 2005 we had a very busy year. We completed refueling outages and replacement of the reactor vessel heads for both Unit 1 and Unit 2 at Point Beach. Then right before Christmas on December 22, we received approval from the Nuclear Regulatory Commission for 20-year license extensions for both units. The operating licenses for Unit 1 and 2 are now extended to the years 2030 and 2033 respectively.

Also during 2005 Point Beach met all of the commitments associated with the confirmatory action letter that it provided to the NRC. Pending final NRC review and acceptance, all 143 commitments are complete.

Now I'd like to briefly discuss a formal review that we will undertake this year. It will regard our options for the ownership and operation of Point Beach going forward. As background in 2001 the Nuclear Management Company, called NMC, was formed to operate Point Beach and the nuclear power plants owned by XCEL, Alliant and Wisconsin Public Service. The operating licenses for these plants were transferred to NMC. Then after Consumers Power joined the group, NMC operated a fleet of eight units. However, the recent sale of the Duane Arnold facility in Iowa, the sale of the Kewaunee plant here in Wisconsin and the planned sale of Palisades by Consumers Power in Michigan has significantly reduced the size of the fleet operated by NMC.

Given these changes we believe it's prudent to evaluate a range of options for Point Beach which is a key asset in providing affordable energy for our customers. The range of options that we're planning to evaluate include continued operation by NMC; a third-party operator other than NMC; a return to in-house operation of the plant by Wisconsin Electric; and a sale of the Point Beach facility. We will be thorough and deliberate in carrying out this review during 2006 and of course we will provide you with an update when we have reached our conclusions in the fourth quarter of this year.

Finally, I'd like to review the results of our retail rate proceedings in Wisconsin. Last summer we filed retail rate cases for our electric, gas and steam operations across the state. On January 26, we received an order from the commission that resolves all of the cases. Let me briefly walk you through the results of each one.

As you know we did not propose a traditional case for our electric operations. Instead we proposed continuing a version of the five-year price freeze that has been in effect here since 2001. Under our proposal we would only increase prices for new generation, for transmission costs from the American Transmission Company and for higher fuel costs. The commission agreed with this approach and with our request and granted a total price increase of $222 million. Now of this amount, of the $222 million, $70 million was for new generation; $67 million was for charges from the American Transmission Company that were not currently in rates; $6 million was for renewable energy programs; and $79 million was for fuel.

The commission set a return on equity for Wisconsin Electric of 11.2% and a financial equity ratio in the range of 48.5 to 53.5%. The allowed return on equity previously was 12.2% with the same financial equity range.

The $79 million for fuel that I mentioned a moment ago was in addition to a $123 million increase that we received for fuel in November of last year. So our new fuel recovery rates reflect really the incredible volatility that we saw last year in natural gas prices. And under our proposal we will refund any overcollection of fuel costs that might occur for calendar year 2006.

Barring any unexpected increases in fuel prices, our fuel costs and revenues should be much more closely aligned in 2006 than they were last year. Last year we had a total underrecovery in fuel costs of $108 million associated with electric power generation. Of this amount, $72 million was associated with the extended refueling outage at Point Beach; costs associated with the MISO day 2 market; and the disruption of coal deliveries from the Powder River Basin. This $72 million was deferred for anticipated future recovery and the remaining $36 million was expensed.

Overall stepping back I believe the commission's decision was a fair outcome for our electric operations. It gives us a reasonable opportunity to recover fuel costs that are largely out of our control as well as costs associated with the infrastructure upgrades that are so sorely needed in Wisconsin. We'll work to manage everything else and Allen will cover more in detail on that point in just a moment.

Turning now to our gas and steam cases, they were far more traditional in our approach. The commission set an 11.2% return on equity for these operations along with the same equity ratio range that was approved for our electric business. This resulted in a $21 million increase for the gas operations of Wisconsin Electric; $39 million for Wisconsin Gas; and a two-year phase-in of $8 million for our steam utilities.

I should point out though that the customer usage assumptions that were used to arrive at these increases on the gas side of our business were based on projected usage before the leap in natural gas prices. Although we do receive dollar for dollar recovery of purchased gas costs for our gas distribution operations, we are exposed to variations in usage by our customers. And we are as you would expect seeing a customer response to higher natural gas prices. So even with normal weather usage per customer is likely to be lower than it was projected to be in the test period. This will make it quite challenging to earn the allowed rates of return in our natural gas distribution business.

Having said that, we view these rate decisions as fair and balanced outcomes for our customers and for our stockholders.

And on a final point as we wrap up 2005 and begin to look forward, we were very pleased to learn in January that Forbes Magazine named Wisconsin Energy one of the ten best managed utilities in America. This is a very positive recognition of the accomplishments of our management team.

Now I'll turn the call over to Allen who will give you more details on our financial performance for 2005 and our outlook for 2006. Allen?

Thanks, Gale. I'm going to focus my remarks this afternoon on earnings from continuing operations; information regarding earnings from discontinued operations is also included in the earnings package however. It may be helpful for you to refer to pages 8 to 11 of the earnings package as I review our results.

Earnings from continuing operations were $2.56 per share for 2005 versus $1.84 in 2004. On a consolidated basis, our operating income was $563 million versus $530 million in 2004 for an increase of $33 million. Operating income for the Utility Energy segment which is comprised of Wisconsin Electric, Wisconsin Gas and Edison Sault was $542 million compared to $529 million in 2004 for an increase of $13 million.

Positive earnings drivers in 2005 included favorable weather, lower employee costs, and price increases in our gas business. During 2005 we experienced a warm summer while in 2004 we had an unseasonably cool summer. The estimated impact of the weather was $39 million.

As we look at employee-related costs I want to remind you that in 2004 we incurred $28 million of severance costs. We did not have a similar charge in 2005 and we estimated that the lower number of employees resulted in a reduction in cost of $13 million.

Finally due to the timing of the 2004 rate order, our gas margins were improved by $6 million. All of these positive drivers totaled $86 million. Now the primary negative driver in 2005 related to underrecovery of fuel costs for electric generation. This was a $36 million drag on operating income as compared to 2004. Other negative items included increased nuclear O&M expenses of $11 million reflecting two scheduled outages. In 2006, we have only one scheduled outage. Other negative factors relate to increased bad debt costs at $9 million, increased benefit costs of $7 million and other items at $10 million. All of these negative drivers totaled $73 million.

Netting the impact of the positive and negative factors I just reviewed brings you to the $13 million increase in the utility segment's operating income for 2005.

Operating income in the nonutility energy and corporate and other income segments which primarily includes WE Power was up $20 million. The largest amount relates to the operating income of the new Port Washington plant that was placed into service in July of 2005. This unit added $19 million to operating income in 2005 and we expect to have a full year of earnings from this plant in 2006. Taking the changes for each of these segments together brings you back to the $33 million increase in operating income for 2005.

Other income was up $47 million in 2005. The primary driver of this increase was the fact that we did not incur debt redemption costs in 2005 but in 2004 we incurred $23 million for early redemption of debt. A number of factors drove the remainder of this change. Increased carry on deferred costs added $8 million; earnings from AFUDC added $6 million; and increased earnings from our investment in the American Transmission Company contributed and other $5 million when compared to the prior year.

Total interest expense decreased by $20 million in 2005 compared to 2004 due to the lower average debt balances. As you know in 2004 we used the proceeds from the sale of our manufacturing segment to pay down debt.

Now when we look at income tax expense you will notice that our effective tax rate is 33%. However, as we discussed in the second-quarter call in June of last year, we realized a $16 million benefit from the reversal of valuation allowances associated with the state income taxes. Our effective tax rate excluding the benefit of the state tax item I just mentioned was 36.5% in 2005 as compared to 37.7% in 2004. Adding these items brings you to $304 million of net income from continuing operations in 2005 versus $220 million of net income from continuing operations in 2004.

In EPS terms this equates to $2.56 per share versus $1.84 per share in 2004.

Our results in 2005 included $0.14 per share gain for the reversal of valuation allowances associated with the state operating tax losses. Excluding this item our adjusted earnings from continuing operations were $2.42 a share in 2005.

As Gale mentioned, results in 2004 included debt redemption costs of $0.13 per share and severance costs of $0.16 per share. If you take out these items, our adjusted earnings from continuing operations were $2.13 per share in 2004.

Now I'd like to turn to cash flow. During 2005 we generated $577 million of cash from continuing operations. This compares to $599 million in 2004. The decrease was driven by increases in working capital and deferred costs, offset in part by a decrease in cash taxes.

We had capital expenditures of $745 million in 2005. $470 million of this was dedicated to our utility and other businesses and $275 million was for the generating units being constructed as a part of our Power the Future plan. In addition, we paid $103 million in dividends. At the end of 2005 our debt to capital ratio was 59.5% which compares to 59.3% at the end of 2004. However, if you net cash against debt in both periods, our net debt to capital ratio was flat at 59.1%. Now given the challenges we faced in 2005 related to working capital and deferred costs, we were very pleased with this result.

Capital spending in 2006 is expected to be approximately $1 billion. So we anticipate that our debt to capital ratio will increase somewhat over the course of the year. However, as we have stated in the past, our goal is to maintain our debt to total capital ratio at no more than 61.5% during the period we're constructing our new gas and coal-fired generation. This would exclude any environmental trust financing that we might complete since the bonds issued under this structure would not be our obligation.

We are using cash to satisfy any shares required for our 401(k) plan, options and other programs. Going forward, we do not expect to issue any additional shares.

Now before I touch on 2006 earnings guidance, I want to expand a bit more on the outcome of the rate case in terms of the returns that we would expect to earn in 2006. As Gale said, the electric rate case was not traditional in the sense that there were a large number of cost components for which we did not seek increased recovery. We agreed to forego or defer approximately $60 million of our estimated revenue deficiency on the electric side of our business. About $20 million of this represents the postponement of the recovery of deferred items.

Then through a reduction in the growth of benefit costs, we expect to be able to get approximately $20 million in savings. And finally, we're targeting another $20 million in savings across our business to close the remainder of the gap.

So in summary, we expect to implement steps that will put Wisconsin Electric which includes our Wisconsin Electric Gas operations on a footing to earn its allowed return on equity of 11.2% in 2006. Now given the challenges surrounding gas usage that Gale mentioned, I believe that our other natural gas distribution utility, Wisconsin Gas, will earn well below its allowed rate of return in 2006.

Now I'd like to wrap things up with a discussion of earnings guidance for the full year 2006 as well as some input for you on the first quarter. Our 2006 earnings guidance range is $2.47 to $2.57 per share. The anticipated earnings drivers for 2006 fall into four groups. First, price increases; next, changes in sales volume including the affects of weather; non-fuel cost increases; and finally, increased earnings contribution from the first unit at Port Washington. Let me take up each of these in turn starting with price increases.

In our electric operations, we received a total of $202 million of price increases for fuel. $123 million of this was received in connection with last year's fuel case and the balance of $79 million came in connection with the general rate case that was resolved in January. With these increases we expect to swing from the $36 million underrecovered position on fuel in the Wisconsin jurisdiction to being just at or slightly under a fully recovered position in 2006. This is expected to add $0.13 to $0.18 per share to earnings in 2006 as compared to 2005.

In addition to the increases for electric fuel, we also received a total of $203 million of price increases for nonfuel expenses in our electric operations; $60 million of this was received in connection with the carveout case resolved in May of last year and $143 million came in the general rate case. These increases will not have a direct impact on book income at the utilities. All of them are going to cover either lease payments being made by Wisconsin Electric to WE Power or to cover costs that were previously being deferred.

We received a total of $60 million in price increases at our two gas distribution utilities and another $8 million phased in over two years at our steam utilities. Given that these increases were not implemented until the end of January, the fact that the steam increases are phased in over two years, and that $25 million of the gas increases cover costs that were previously being deferred, I expect the net impact of the gas and steam price increases to be $0.15 per share.

Moving now to changes in volume. We estimate that a return to normal weather in 2006 would reduce earnings about $0.11 per share. The weather impact is expected to be partially offset by normal volume growth. So I would estimate the overall impact of volume to be neutral to slightly negative, say -$0.03 per share in 2006. Nonfuel cost growth is expected to reduce earnings $0.25 to $0.27 per share and another six months of earnings contribution from Port Washington Unit No. 1 is expected to add $0.07 per share.

So just to summarize each of these factors, the impact of increased price is expected to add $0.28 to $0.33 per share; the impact of volume including a return to normal weather is expected to be between a $0.03 per share reduction and neutral. Assuming that we achieve the targeted cost reductions I mentioned earlier the impact of nonfuel cost is projected to be a reduction of $0.25 to $0.27 per share. And finally, Port Washington is expected to add $0.07 per share. Adding these drivers together and translating into a range gives you $0.05 to $0.15 per share projected earnings growth in 2006 as compared to 2005. Adding this to the $2.42 base in 2005 brings you to the 2006 earnings guidance range of $2.47 to $2.57 per share.

Although we will not be giving earnings guidance for the first quarter, I did want to give you a feel for the earnings drivers that I expect compared to the first quarter of 2005. We earned $0.76 per share in the first quarter of 2005. We were in a fuel underrecovery position in that quarter and Port Washington Unit No. 1 was not yet in service. Both of these factors are expected to add to earnings in the first quarter of 2006.

Price increases will also be a positive factor but the extremely warm winter we've had so far will be a challenge. As a result, I expect earnings in the first quarter of this year to be modestly above the $0.76 per share level we were at in the first quarter of 2005.

So what that, I will turn things back over to Gale.

Allen, thank you very much. Overall we're on track and focused on continuing to deliver value for our customers and stockholders.

(OPERATOR INSTRUCTIONS) Andrew Levi at Bear Wagner.

Wow, I'm never first. I never even ask a question.

Wow, Andy. This is a first for you isn't it?

Point Beach, can you give us an idea of the earnings contributions to Wisconsin Energy?

Well, to give you a feel for the total plant balance, Andy, if you include the fuel, the nuclear fuel, the materials and supplies as well as the hard assets, it's about $400 million.

Of rate base you are saying?

About $400 million of rate base.

Do you sell any of that power wholesale?

No, it is all dedicated to our retail operations.

What is the timing on making a decision one way or the other?

As I mentioned in the call, we're going to be looking at a range of options here. We will do it very thoroughly. We would expect to come to conclusions in the fourth quarter.

So whether you put it up for auction, you keep it or whatever you do, it will be between October and December that you'll let us know?

That is our thinking, Andy. Absolutely right.

Thank you very much, guys. Good luck on 2006.

Ashar Khan at SAC Capital.

Good afternoon. Gale, can I ask you what makes I guess the three other owners, CMS, LNT and WPS elected to sell? Could you tell us why Wisconsin, WEC, what makes it different from those three guys? Why it would not elect the same option? And you mentioned three other options as part -- or you get four options. So I'm just trying to find why would WEC, if all the others took the decision to sell why would WEC take any other decision rather than to sell? What makes it different? Why you would pursue any of the remaining three options?

I'll ask Rick to also chime in with his view on this. But first of all obviously we can't speak for any of the other utilities. But if you step back and look at Point Beach as part of our portfolio, it's a very, very significant piece of our portfolio. In fact, the Point Beach capacity provides about 20% of the energy we provide to our retail customers. So we're not going to take these decisions lightly and we thought it was very important to walk through every practical option with objectivity and detail before we made a final decision.

And by the way one of the other companies which NMC operates nuclear units for right now, XCEL, has come to a different conclusion. They've decided, as I understand it, not to sell. So bottom line is we haven't drawn any final conclusions. We think the time is prudent for us to make a very deliberate, thorough review of our practical options. Rick?

I agree with what Gale said. I also might just add that none of those companies that made a decision to sell made so based on NMC performance. I think all the owners are very pleased with the performance and the improvement in performance that they've gotten out of the units. So there were other business reasons at work for those other owners. Don't want anyone to interpret that there is a displeasure with NMC's performance. It's really simply every company has to evaluate their situation, their customer needs, their portfolio and make a decision based on that.

Yes, but if I can interject -- I just want to understand your situation. XCEL, I know they mentioned it is because of political pressures they're trying to get facilities for their nuclear fuel storage and everything passed through the commission in which the state. Because of political reasons they can't sell. So they are like in a box. But if I am right, you are under no political reasons with the way you're dealing with the state because WPS went through it which would hamper you from selling it.

And secondly I guess one of the owners did mention to us that with lesser plants under NMC control which I guess Gale you mentioned in your opening remarks, they though NMC was no longer a competitive operator of plants with lesser plants at their hands. Do you share that? I think that that was implied in your comments in the beginning. But I want to confirm that or not. Because one of the owners specifically made that point that with lesser plant ownership, NMC no longer becomes an economically viable institution.

I will address this and Rick will as well. Let me make it very clear, we have not concluded that NMC is not a viable operator. In fact if you look around the country at the size of fleets, certainly there are some major nuclear consolidators but there are other operators around the country doing very well with the size of fleets that NMC would have. So we have not made a conclusion that NMC is not a viable operator. Clearly when you go from eight units, a fleet of eight units to a much smaller base, that is one of the reasons why we need to step back and take a look.

But we have not concluded that NMC is not a viable operator. And as Rick mentioned, NMC's track record in improving the performance of every one of the plants that it has operated has been quite positive. Rick?

I agree. I might just add that we have taken steps on the NMC Board to adjust the size of NMC for a lower number of units. But I'm exactly where Gale is; right now NMC has six units. If Palisades leaves, it will have five units. There are a number of examples around the U.S. where a fleet of that size or lesser size can operate very successfully. I don't think there is a threshold you cross where you say this is not viable. And that is why we want to take some time to take a look at it, to understand our situation as a Company and make a decision of what we're going to do.

Allen, can I just go back to the projections. If I heard you right you said for '06 you don't expect any fuel underrecoveries? Is that correct?

No, what I said was I expect to be at best fully recovered and we might still be slightly underrecovered for the year.

Okay. And then secondly if I'm right in your factors, you didn't mention anything from earnings from the nonconsolidated transmission company. Are you expecting those earnings to be flat year-over-year?

They're going to be very close. If you look at the most significant source which would be ATC, although the earnings stream of ATC is continuing to grow, our relative ownership share is going to go down between 2005 and 2006 with the build out of the Arrowhead-Weston line which as you know all of the equity for that line is being put in by Wisconsin Public Service and Allete over in Minnesota.

Could you tell us what that change in ownership is going to be from year-end 2005 to year-end 2006?

Approximately our year end in '05 we were just over 33% ownership share. I would expect our ownership share at the end of 2006 to be just under 30%, so say probably around 29.5%. But again, Ashar, it's a lower percentage but it's a larger company. So I'm not expecting a contraction in the earnings contribution but certainly not any growth to any significant degree year-over-year because of the reduction in the ownership share.

And how much capital are you expecting to put in this year if any?

Well, if you look at the ATC dividend policy, they pay out 80% of their earnings in dividends. So roughly if we are at the same level of earnings in '06 that we were in '05, you'd have about $35 million worth of dividends from ATC. So after tax, that is probably about $20 million, say. And I expect we will put in a similar capital contribution. So from a cash standpoint dividends out after tax versus capital contribution back in -- we'll be about a push -- about neutral in 2006.

Okay. And if I can end up, Gale, I joined a little bit late. Can you just mention a little bit about review of the putting it into an IPO? Where you stand or anything to update?

Ashar, I'd be delighted to. I think in summary we're certainly open to a range of alternatives with our ownership share in ATC. The Board of ATC of course has the ultimate decision on what if anything changes regarding to the structure or ownership of ATC. We are one member of the Board and we will certainly give our input in any evaluation that the ATC Board makes. But as I mentioned we're open to a range of alternatives and as the discussion moves forward, we will certainly make our input.

But can we get a decision in 2006 in the first half? Is there some kind of a decision expected by the Board whether they continue with this or not continue with this on the agenda for the year?

Ashar, I don't believe the ATC Board, and again it is their ultimate decision, has made any determination about any timetable for any review.

Okay, thank you.

Paul Ridzon at KeyBanc.

It's my understanding that there is no potential overrecovery of fuel? Did I hear you say you have to refund any overrecoveries?

As part of our -- that is essentially correct. As part of our agreement in fact we proposed this particular approach with the Wisconsin Public Service Commission last fall. Essentially we said that our goal was not to make money on fuel. And what we said was as part of this rate package, this non-traditional rate approach that we and the commission settled on we would refund any fuel overrecoveries that might occur during 2006. The commission accepted that. That is our plan and that is what we will do if there are any fuel overrecoveries.

And that is measured on a calendar year basis -- that is you look at the calendar year situation in 2006 on electric fuel.

That is correct.

Can you kind of hang some numbers on what you are seeing as far as demand destruction? I imagine it's probably pretty hard to isolate mild weather with demand destruction and then just follow on what kind of bad debt are you experiencing.

It really is at this stage of the game, you are correct, Paul. Difficult to differentiate demand destruction from weather destruction. And we've had a lot of weather destruction here. I think as Allen mentioned for January, it's actually been incredible. It has been in terms of average temperature in Wisconsin this past month the warmest January since you were born, Paul, in 1880. It really has been an incredibly unusual winter.

I don't think based on one month of very, very unseasonal temperatures that we can do a good job for you of stripping out what is demand destruction and what is weather driven. In terms of bad debt again, very, very early in the winter. Our arrears are slightly higher than they were at the same time this year or the same last year but not anything that overly concerns me at the moment.

Just maybe a little more color on the bad debt in terms of what we experienced in 2005. From an income statement standpoint, any bad debt expense above $28 million is deferred. So we experienced the $28 million worth of bad debt expense which went through the income statement and we deferred another $16 million in 2005. So at this point at least I think that is a reasonable estimate for 2006.

However, we actually in the gas rate case we did get some additional rate recovery for the bad debt. I don't expect as much to be deferred this year. But in terms of a total bad debt expense, deferred plus what goes through the income statement, we're projecting something pretty similar in 2006 compared to 2005.

Allen is correct. And one other piece of color. As we ended 2005, our arrears greater than 60 days were actually lower than they were in the prior year. So we're actually going into a difficult winter in reasonably good shape.

Given the regulatory change on bad debt, what is the worst you can do in -- absorbed through the income statement?

I think it's about $44 million for residential now. There's not really any significant degree of bad debt for commercial and industrial. So on the residential side, the most that you could take through the income statement which again is covered in rates (multiple speakers), about $45 million.

But 28 ran through the income statement last year?

That's right. $28 million through the income statement, another $16 million was hung up on the balance sheet.

What is the worst that could run through the income statement this year?

Well again you get escrow accounting for everything above the level that is not covered in base rates. The maximum income statement exposure at least for residential would be $45 million -- anything in excess would go to the balance sheet and again commercial and industrial --.

-- is almost zero.

It's pretty negligible.

Very negligible.

Just back to demand destruction. Did December billings show anything tangible?

Actually December billings were balanced to the other side of the ledger. We had a very cold first two weeks of December in Wisconsin. And again, on a very short time period, as you know, it really is difficult to strip out what is weather and what is pure demand not associated with weather. I don't think because of the weather anomalies in both December and January we can give you a good feel just yet. We sure will be able to though I hope by the end of the winter.

Okay. Thank you very much.

Reza Hatefi of Zimmer Lucas and Partners.

Good afternoon. I think you guys mentioned a $1 billion CapEx guidance for '06. I was wondering what portion of that is for WEPCO and what portion for Power the Future?

Sure. It's roughly half and half, actually. So roughly $500 million for the utility, and the balance $500 million for WE Power.

Great. And that $500 million at the utility, that was sort of already built into the final rate base because I know it's a forward test year for the rate case, correct? Is that a right way to think about it?

Well, as a Gale said, I mean the gas cases were traditional. So, yes, it is certainly built in there. The electric cases, you kind of had a carveout, so you did a non-traditional. But in terms of if you look at the documents in the rate case filing, they envisioned that kind of spend.

And how much was spent on Power the Future in '05?

In 2005, I believe it was right at 400 million. Let me get you -- hang on a second; let me get a better number on that. Let's see, 2005, $300 million, I'm sorry, and basically $500 million on the regulated business. So $500 for regulated, $300 million for PTF, for Power the Future.

Great. And in your '06 guidance, what is the tax rate you are assuming?

I think a good range for effective tax rate would be that 36.5 to 37.5% range. I think we will be in that range again.

And finally, you mentioned the year-over-year growth at ATC which should be somewhat flattish. How should we think of it afterwards, maybe '07, '08? Would percentage or would actually the net income maybe start ramping back up a bit, or how should we think about that?

Well, it should certainly start ramping up again, but that will be very dependent on which of the projects that they proposed are actually approved. When I say they, which of the projects that ATC has proposed are actually approved. So I would really be a little leery of giving an estimate for the income growth profile for ATC.

Allen is correct. Once the ownership percentages kind of settle out after the capital is spent for the Arrowhead-Weston line, then really the income growth will be heavily dependent upon the capital spending program at ATC and which projects move forward the fastest.

And also you guys mentioned two 80 MW wind projects, which each will cost about $125 million. What is the status of those two? I guess they were supposed to go on line in '07 if built.

We will ask Rick to take that. Right now, we're looking at potential in-service in '08, and we're actually putting together all of our filings right now. We would expect to make a filing with the Public Service Commission for a certificate of convenience and necessity sometime in the next couple of months. Rick.

Gale is exactly right on that. The other factor will be basically turbine availability, and we'll be working through that in the first part of this year.

Great. If they're going to be in service in '08, we should probably assume money will be spent maybe in '07 timeframe?

Yes.

Great, thank you very much.

Paul Patterson, Glenrock Associates.

Good afternoon. I just wanted to check on this Point Beach thing again. With the fewer plants outstanding, and I know that you talked about some decrease of expenses, is there any expectation you're going to have higher A&G expense or higher costs associated with Point Beach?

Rick is the Chairman of NMC, so we will ask Rick.

This year because we've got one outage, Paul, we would expect lower overall O&M in budget. And we have factored in any changes that would be resulting from ownership changes at the NMC level.

What would those ownership changes -- can you quantify that? Is that substantial? In other words, that increase in expense?

No it's not. In overall O&M budget, Paul, it's not. We've adjusted the infrastructure and it's not substantial, no.

The second thing I wanted to ask you guys was the non-traditional approach. It looked like if I heard you right Wisconsin Gas you guys expected to underearn there? Is that correct?

That is correct and let me re-explain why. The filings for Wisconsin Gas because of the procedural rules for a rate case in Wisconsin, those filings were made in May. And I believe we may have updated some numbers in June. But those filings were made and put in the record prior to the huge run-up that we saw in natural gas prices. So basically our belief is that we will see some customer response in terms of lower usage per customer as a result or as a response to higher prices. We were not able because of the rules on evidence and when the evidence had to be entered into the record, we were not able to get our view of lower per usage per customer into this rate case.

So essentially, the rates were set assuming and if my memory serves me correctly, I think the rates were set based on an assumption that the typical residential customer would consume like 990 therms per year. And we believe, although time will tell, that it will be materially less than that. In essence we think that difference in individual usage per customer compared to what was used to set the rates will make it difficult for us to earn the rate of return.

Okay --

Now that is at Wisconsin Gas.

That's at Wisconsin Gas. Now could you remind us what the rate base is and how much of an under earnings you are going to have and when you think you might get recovery of that?

The equity for Wisconsin Gas regulated equity is about $412 million. In terms of being able to get any recovery of that, I certainly don't see that this calendar year to be able to get the recovery out that. Maybe there is some potential in 2007. But no potential in 2006.

What does that -- essentially where are we? How much lower are we talking here?

Well I'd really rather not put a projected rate of return out there yet. I mean this early in the year. But again to what Gale said, when you filed your case with a 990 therm level per residential customer and you're expecting significantly less, it's going to be a drag on the returns.

Right. Now the second sort of question with this non-traditional approach is that you guys have been aggressive in cost cutting and keeping rates from going up for customers. On the other hand you do have infrastructure needs. So I'm wondering as we go further along with all the stuff that you guys are building or what have you, whether or not you might expect to go in again I guess?

The commission actually has expressed a desire for all of the Wisconsin utilities to get back on what was a traditional rate case schedule for the state basically every two years. I think the expectation of the commission is that in the late spring, summer of '07, we would file a prospective test year for new rates to go into effect on January 1 of '08. Larry?

That's right.

Larry says he's about to retire but he agrees.

That's right too.

And do you feel that for 2007 you'll probably still be able to maintain the ROEs or do you think that you'll have -- do you think you'll experience any regulatory lag I guess with that kind of a schedule?

Well if you look at, and again I mentioned in my comments that we clearly laid out the need to cover the cost of the investment we're making in the infrastructure for the state, in generation and through ATC and transmission. And then we clearly need to recover our fuel costs. And the commission has been, I think, very supportive of that concept. And we have stepped up to the bar and said we will do our dead level best in this interim period to manage everything else and that's my expectation.

Okay, I just wanted to clarify that. And could you tell us what the regulated ROE was that you earned for 2005?

If you look at the electric operations, so WEPCO including the gas LDC through there. We were very, very close to the allowed rate of return on equity which was 12.2%. And then at Wisconsin Gas, we earned closer -- and again this would be on a regulated basis at Wisconsin Gas, so that would be excluding the goodwill, excluding the deferred tax -- the big deferred tax asset that you would see on their books, regulated return right at 7%. So it's 7% return on equity at Wisconsin Gas. And right at a 12.2% return at Wisconsin Electric Power Company.

Okay, then just to circle back here, the Wisconsin Gas that might be -- you might go in a little bit earlier for recovery in that situation as opposed to the WEPCO portion? Is that possibly 2007 maybe for that?

Well you can't go in -- you couldn't get any rate relief for Wisconsin Gas that would affect calendar year 2006. There may be a potential to get some rate relief that would affect part of 2007 but not all of 2007. And then WEPCO, I think Gale has already gone through that.

Yes, he has. I just wanted to clarify that. So we might get something a little bit earlier for Wisconsin Gas in 2007?

No guarantees.

No guarantees.

And it would not affect -- it wouldn't be for the full year. It would only be a partial year at best for '07.

There are never guarantees. I appreciate it. Thanks a lot guys.

Michael Lapides at Goldman Sachs.

Michael, how are you? Congratulations on your promotion.

Thank you, thank you very much. Real quick question just kind of thinking about the transmission business ATC a little bit. I recall hearing earlier on this call talking about an ownership stake that was just south of 30%. And that is a little different I think than what had been communicated roughly I think this time last year where kind of the bottom level of your ownership stake was supposed to get down to about 33% and kind of hold constant from there from I think 37.5, 38%, 1.5 years ago. Any reason for that change?

No. Go ahead Allen.

I think what we said, Michael, was that we'd be about 33% at the end of '05. I think when I talked about this before I said we'd be about 30% at the end of '06. It's very consistent with what I said before. In terms of a book equity investment which is another way to kind of think about this, at the end of 2005 I mean it was about $205 million was the equity investment. It's a pretty big asset from an earnings as well as an equity investment.

All of this, Michael, is in terms of the ownership percentage change is really, as I mentioned earlier, being driven by the capital that is spent on a major transmission project called the Arrowhead Weston line. When ATC was formed, Wisconsin Public Service out of Green Bay already had that line under development, if you will, and under discussion with the Public Service Commission. As part of the formal formation of ATC, essentially since Wisconsin Public Service was going to put in all the equity for Arrowhead Westin, they would get pro rata credit in the ownership structure of ATC.

But as Allen said, I wouldn't worry too much about the slight changes in percentages because ATC has a very needed and very sizable construction program and our equity investment in ATC will continue to grow.

When you think about ATC's rate base five or six years down the road, I mean it's just south of $1 billion roughly now. What is kind of the long-term projection from what that rate base is 2010, 2012 timeframe?

The ten-year plan and this is public, their ten-year plan would have them spending almost another $3 billion on electric transmission over that ten-year period. A lot of that money are for very large 345 Kv projects that would be if they're approved, if they're built would be in service at the latter part of that decade. But very, very significant in terms of the -- at least projected investment.

Last question on the wind plants. Can you repeat again -- I'm sorry I missed that part -- about the size of the plants, the two wind plants, the cost of them and when you would have them in rate base?

Sure. We will ask Rick to give you the specific details. Our current thinking would be an in-service date in 2008. We're about to in the next couple of months file our formal request for a certificate of need from the commission. So a lot of work is being done right now to put that request together. And we are stepping into the shoes of a developer that was really not moving forward with the wind project. And we need wind as part of our portfolio here. Rick?

The project we stepped into the shoes of was 80 MW per project and there's two of them. So a total of 160 MW. We're looking at what the optimum size of the turbines is, where technology is going so that number could go up or down a little bit. And the dollar investment is in the range of $250 million. And that again that could vary depending on the number of turbines we put in and the size of turbines we put in.

And then depending on how fast the CPC end process goes forward at the commission, it will affect the timing obviously of when those dollars are spent as well.

But current thinking and again we are just now getting to the final stages of making all these decisions so that a filing can go forward. I would expect a filing certainly within the next 90 days.

Okay, thank you, guys.

Dan Jenkins, State of Wisconsin Investment Board.

Dan, how are you?

Good, how about you?

Did I see you on that footage with the groundhog the other day?

No, that wasn't me.

That wasn't you. I'm glad to hear that. What's going on, Dan?

First of all, I was wondering on your cash from operating activities the big change there is the working capital and other I was wondering if you could give me a little more detail on what was going on there?

Sure. Probably the easiest, probably already there but just flip to the cash which I believe is on page seven of the earnings package. At least the statement of cash flows. And the big driver as you mentioned if you look at '05 was really that working capital and other category which was actually a use of cash of $140 million. It really is broken into two components, and Gale mentioned the deferred fuel costs. So that was very, very large, almost $75 million worth of deferred fuel costs. So we actually incurred those costs from a cash standpoint but because they were deferred you don't see them on the income statement as an expense. That is a big piece of it.

Another big piece is related to gas in storage. If you look at our gas in storage at the end of '05 as compared to 2004, in dollar terms we had $40 million more gas in storage which is almost all because of not so much volume -- we had almost exactly the same volume of gas -- it was just so much more expensive to purchase that gas and put it in storage. So really between deferred fuel and working capital you get the bulk of the swing that you are seeing here in working capital and other.

That deferred fuel should then reverse then in --?

Well, we would certainly anticipate at some point to be able to get rate relief for that.

The commission did give us some adjustment going forward in the gas business for our carrying costs on gas inventory.

Right. But in terms of -- I think your question is probably looking to '06.

Right.

Do you expect another big deferred balance? I would certainly hope not given what's happened with the increase in the fuel recovery rate. In terms of natural gas prices, I will not hazard a guess on where natural gas prices are going. I hope that we're not going to see another $40 million increase in inventory.

But we are preparing in terms of the liquidity at the utilities, Wisconsin Electric which has a gas company as well as Wisconsin Gas, we look at a range of scenarios to make sure that if we did have another big excursion in gas prices that we have sufficient liquidity to fund the working capital.

Another way to look at that, Dan, as Allen said, is related to the carrying costs on gas in storage for our gas distribution business, if average natural gas prices over the course of 2006 don't vary greatly from 2005 then you would not expect to see any swing.

The deferred fuel piece, the $75 million you were talking about, would that be recovered at some -- during '06 or will it take longer?

Well the earliest that you would be able to even get an opportunity would be in 2008. So that balance is sort of deferred hanging up on the balance sheet and then you would have an opportunity to go in and talk about some sort of unwind to that reg asset in the '07 case. But you wouldn't see any cash until 2008.

Okay, so that wasn't -- that is a deferral beyond what you had in your last case then?

That is correct.

Yes, in '05, right.

Also I was wondering as far as any debt issuance plans, I know you have about 250 million that comes due on April 1 and then of course the billion of CapEx. I was wondering if you're looking at any -- raising any money through debt?

In terms of capital market issuance in 2006, you are right; we do have a $250 million maturity at the holding company in April. I'll expect to temporarily at least take that out with commercial paper. And more likely than not not turn that out, not take that to the capital markets at least in this calendar year. At the utility at Wisconsin Electric Power Company, I would expect at least capital markets somewhere in the range of $300 to $500 million worth of issuance this year. But that would all be in the second half. And I don't expect any capital market issuance at Wisconsin Gas this calendar year.

Okay. On the Point Beach, you mentioned that you're looking at your alternatives and one could be – you could potentially sell that. If you were able to sell that for above book value, given the depreciation and carrying costs and so forth recovered from customers, would the PUC or PSC, would they try to -- would they look to recover any of that or would that all go to shareholders or how would any gain on that sale be handled?

Dan, the honest answer is a good question but very premature. We've got a thorough objective review to get our way through and we're going to do that. So we have not made up our mind on what the best option is. When we do we will certainly update you. If that requires any regulatory action we will certainly discuss that as well. We have an open mind and we're going to thoroughly review our options and come to conclusions in the fourth quarter.

Okay. You have what the capacity factors were for each of the Point Beach units in '05?

I'm looking at Rick. I don't know if we have them in the room with us. Again the capacity factors in '05 would have been influenced by the fact that we had two planned refueling outages. Business has run very well though.

I do not have those. About 20% of our energy came out of nuclear last year but we had two long outages. I would expect that to go up slightly. Our forced outage rates were very low last year. We set a record on Unit 1 in terms of continuous days operation. So we could get that for you but other than the lengthy refueling outages, plants ran very well.

That record run that Rick talked about was 472 days between refueling outages. The units have run very well.

Okay. And then you said I think one refueling outage in '06?

That is correct. In the fall.

And that is at which unit?

At Unit 2.

Yes, Unit 2.

And I assume that would probably be a shorter and less costly outage because you're not going to have the heads and --?

Yes, we are not going to do a vessel head replacement. So the plan would show us that we're going to have a shorter outage. Actually we've still got to execute but we would expect it to be shorter.

Okay, that's all I had. Thanks.

Nathan Judge at Atlantic Equities.

Up late again, Nathan.

Yes I am. I was actually going to tell you I think for the first time it's been colder in London for January than it has been in Wisconsin.

Oh my gosh.

Anyway. Allen, could you just remind us what -- how much cash carry there was in 2005?

When you say cash carry, I'm sorry, Nathan, specifically related to what?

It's the cash that WE Power gets on the leases that doesn't impact earnings for Power the Future?

I'm going to ask Steve to pull that out. But I would say off the top of my head it's probably in the neighborhood of $40 million. But I'll let Steve give us a precise number.

Yes, just to refresh your memory, we are able to collect revenues on the cash carry. And that stops when the plant goes in service. The amount for 2005 was about $55 million. In 2004 it was about $38 million. And so if you think about in 2005 Unit 1 at Port Washington went in service but we had significant construction costs at the Oak Creek facility. So the number you asked for is about $55 million.

What would that be for '06?

I haven't given out a projection of that but I mean our construction work in progress balance at the end of '05 I think in total was $600 million and probably roughly at least half of that was related to Power the Future. I'm expecting another $500 million, as I mentioned, in response to another question in CapEx.

Great. Thank you. Just on ATC, I just wanted to -- the $3 billion being spent with regard to the regulatory changes improving the ability to replace in transmission lines, do you think there's a greater chance that that $3 billion will be put in place? And if it were -- could it possibly come in earlier than expected?

Nathan, this is Gale. I honestly don't expect a significant earlier spend than what we're seeing in the ATC plan. These are complicated projects. They require in some instances acquisition ownership of land. I wouldn't expect the ATC spending to ramp up any more quickly than they have in their plan.

On the other hand, I do think you are correct. Given the need for transmission and given the federal policy that is incenting transmission construction, the likelihood of the spend is greater I think -- the likelihood of the $3 billion plan actually being spent is probably greater than it was two years ago.

Just to clarify this. With regard to the ease of putting that into place, do you believe the recent rulings have enabled you to more easily put this ATC to put this into place?

Actually the one development that I think has been very positive for ATC and they've done a good job on this, they have really convened a stakeholder group. The stakeholder group has been citizen groups, normal interveners in rate cases, the utilities themselves and commission staff. They've really held working groups to try to work through the transmission plan. And they've really amended their transmission plan in response to the input from these groups.

At the local level I think yes there had been federal developments that are positive but I think the most positive at the working level development has been the way ATC is approaching the execution of this plan and the input they're getting from all kinds of stakeholders. I think that will make life substantially easier because they are getting buy-in for the projects that are needed and they are taking input very seriously.

How many megawatts would there be post the full build out of this plan for ATC -- would there be I guess imported into the state?

Oh, goodness. We honestly don't -- I don't think anyone has calculated that. I'm looking around the room. We honestly don't have an answer for you on that. They're talking about several major additional transmission lines obviously. And to put that in perspective, Wisconsin only has five lines, four to the South, one to the West, that can move any substantial amounts of power in and out of the state. Those five lines compare with say Minnesota which has something like 16 lines. So there's a long way to go in terms of upgrading the transmission network in the state.

Absolutely. Thank you very much.

Doug Fischer at A.G. Edwards.

Just a couple questions. Can you, Allen, could you elaborate a little bit on the -- obviously you have the $60 million shortfall, $20 million of is deferrals. Elaborate on the other two $20 million pieces? I'm not sure I caught entirely what you said during your discussion of '06 guidance there.

Of the total 60, $20 million was foregoing recovery of deferral costs. So that doesn't affect the income statement. The other 40 --.

Are you pointing out or you're going to attempt to recover in the future?

On the deferred? Yes, I would expect at some point probably in the '07 case you would go try to get recovery of that. But then just sort of following along with your question, the next 20 million we're really projecting to get from really slowing down the growth in medical costs, benefit costs, primarily, medical. And then the final $20 million is really going to come from across the business, Doug. No one area in particular but if you look just sort of sprinkled throughout the enterprise, really trying to hold the line on expense growth. Hopefully let attrition take its course in a number of areas.

So we're in the process of getting that last $20 million addressed. We're still working on that. I expect it's achievable at least in 2006.

So even though we're here in early February you have a reasonable expectation of achieving the full $40 million-- those two pieces in calendar '06?

Yes, that is our goal.

Yes.

Okay. Can you talk -- and then the Wisconsin Gas, this potential for possibly some base rate relief in late '07, what are you -- are you saying you would file along with WEPCO in the spring of '07 and you're just throwing out the possibility that maybe rates could go into affect before the traditional beginning of '08? Is that what you're saying? I'm a little confused as to the basis for that potential.

Doug, this is Gale. Let me try to clarify. Under the commission's normal schedule, we will have to file data for the rate request in the late spring, early summer of '07. That would be for Wisconsin Electric and Wisconsin Gas and if necessary for the steam utilities. But clearly for Wisconsin Electric and Wisconsin Gas. Under Wisconsin law, if you are earning a deficient return, there is nothing that says you can't go in with a special request. We haven't finalized any option yet. We have to work our way through this year and see what really materializes in terms of the difference in per usage per customer. But remember there is nothing -- there is no law or regulation that says if there is a material deficiency, you can't file at any time. That is really what we're saying.

Okay. That is helpful. I appreciate that.

You are welcome.

Are you eligible -- obviously there will be some changes in fuel costs for '07? Would you expect a separate fuel filing for '07 even though you wouldn't be in for what we would traditionally call base rates?

Remember, Doug, that is a good question. Under the Wisconsin fuel rules, essentially there is a bandwidth. And for '07, we will be back under that bandwidth. Unless we are going to trip the bandwidth one way or another there wouldn't be a rate filing.

So it would really be just under the fuel rules?

That is exactly right, starting back in '07. Our agreement with the commission regarding fuel and refund of any over recovery is for calendar '06 at the end of calendar '06, using '06 as the measure. And then we're back under normal fuel rules in 2007.

One other just point related to the fuel rules. There's a lot of concern about how the fuel rules operate and the complexity of the fuel rules in Wisconsin. I am pleased that the Wisconsin Commission has opened a docket. It’s very early. They just opened the docket. There's no schedule yet. The Wisconsin Commission did open a docket to review the fuel rules with input from all the stakeholders this year.

Okay. Thank you. And then one last question. On the refueling outage there is no estimate as to the cost what diminution of costs there would be versus what you experienced with two outages this year?

Well a typical refueling outage, O&M for a typical refueling outage is in the $13 to $15 million range.

So we had only one of those but it would be -- one shorter outage than the two outages that we had in calendar '05.

And refresh my memory, the two outages cost how much in '05?

O&M alone would have been $16 million apiece.

Each. Yes. North of $30 million.

Okay, thanks.

Shalini Mahajan at UBS.

Just a follow up on Doug's question. In the positive -- in the drivers that you gave out for 2006 guidance I did not see a positive variance of one less outage in '06 compared to two long ones in '05.

It's embedded in the -- when I talked about the non-fuel O&M that change is embedded in there. That is a positive and obviously a lot of other things that go the other way, '05 to '06.

So how much -- what would the positive impact of one less outage? Is that $0.6 to $0.08, something around there?

Roughly $15 million pretax.

Which is about $0.07.

Despite that you have your non-fuel O&M costs increasing by $25 to $27 million '06 over '05. Could you kind of elaborate on what are the various expenses that is driving up so drastically?

There are a number of O&M credits, if you will, that we had in '05 that I don't expect to recur in '06. In the third quarter, as I recall, we had a $10 million settlement with a vendor which was an O&M credit in '05 that won't be repeated in '06. We had about $6 million worth of litigation settlements in 2005 that I don't expect to recur in 2006.

Other areas for example property and revenue taxes I expect will be up $10 million, so $0.05 a share. It's just a lot of things. No one thing in particular. That’s just a huge budget buster but all these put together you have fairly significant increases in costs.

That's it, thanks.

Well that concludes our conference call today. Thank you so much for participating. If you have any other questions, I bet you've ask them all but if you have any other questions, feel free to call Colleen Henderson in our investor relations office. Her direct line 414-221-2592. Have a good day. Thank you very much.

And that does conclude today's conference. A replay of the conference will be available today at 4:00 PM Central time. To access the replay please dial 1-888-203-1112 or 719-457-0820 and use pass code 8134006. Again, thank you for your participation. You may now disconnect.