威斯康辛能源 (WEC) 2005 Q3 法說會逐字稿

Please standby, the conference is about to begin. Good afternoon and welcome to the Wisconsin Energy 2005 Third Quarter Conference Call. 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 anytime. 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, referenced 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 third 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.

Good afternoon, everyone. Thank you for joining us on our conference call to review the Company's third quarter 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, our Treasurer; and Steve Dickson, our Controller. We'll all be prepared to respond to your questions at the conclusion of our prepared remarks.

I am very pleased with our overall performance in the third quarter. Allen will review our financial results in detail in just a moment. But as you saw from our news release this morning, we earned $0.56 a share from continuing operations in the third quarter of 2005. This compares with $0.26 a share from continuing operations in the third quarter last year.

Our results last year, though, were reduced by $0.16 a share for charges related to severance and early debt redemption costs. Warmer than normal weather this summer, lower debt levels at Wisconsin Energy and effective cost control across our utility operations were all positive factors in this year's third quarter. One offsetting factor, the significant increase in fuel costs, was clearly a challenge for us.

Now I would like to update you on the continued progress on 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 megawatt natural gas-fired units at our Port Washington site north of Milwaukee. On July 16, the first Port Washington unit went into service on time and on budget.

The construction of the second unit which began last year has two major phases: First is demolition of the remaining coal unit at Port Washington and site preparation. This work is moving ahead on schedule. The second phase is the actual erection of the unit itself. This is scheduled to begin next year and we expect to reach commercial operation in time for the peak summer season of 2008.

Now, turning to the status of the construction of the two new coal units at Oak Creek. Following the Wisconsin Supreme Court's positive ruling in late June, we issued a mobilization notice to Bechtel Corporation that was followed by the full notice to proceed on construction activities at Oak Creek. Since that time, the major focus has been site excavation and drilling of the down shafts in Lake Michigan for the water intake structure. Bechtel has now excavated about 2 million cubic yards of material or about a third of the total amount expected for the entire project. In addition, a Bechtel subcontractor has finished two of four down shafts in Lake Michigan. Work on the lake is now suspended for the fall and will resume again next summer, when the remaining two down shafts are scheduled to be completed.

Engineering for the Oak Creek project is about 45% complete, as we speak and in the area of procurement Bechtel has issued purchase orders and sub-contracts covering approximately 75% of the total expected procurement amount.

Now, as we previously reported to you, the project cost of the Oak Creek units is expected to increase by approximately $50 to $55 million given the delays caused by the litigation. This represents an increase of 2.5% in the total cost of the project. We believe these costs are recoverable under the terms of the lease agreement approved by the Public Service Commission. Assuming recovery of these delay costs, we believe we have sufficient contingencies in place to complete the project within budget.

In other developments, we just recently received confirmation from Madison Gas & Electric and Wisconsin Public Power that they will collectively purchase a 17% ownership interest in the Oak Creek units. This is consistent with the plan that we have presented to you all along so it did not represent any change in the earnings stream that we expect from the new coal units. The transaction is scheduled to close in early November, at which time we expect to receive approximately $40 million of cash. This represents about 17% of the project cost to date. And then going forward, the minority owners will fund their pro rata share of the construction costs 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 this particular 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 Oak Creek unit on line in the summer of 2009 and the second unit in the summer of 2010.

Now turning to our nuclear operations, Point Beach Unit 1 was removed from service on September 24th for refueling, maintenance, and replacement of the reactor vessel head. Before the outage began, we received a license amendment from the Nuclear Regulatory Commission for the lifting and setting of the vessel head. As you may recall, the need for a similar amendment contributed to a longer than expected refueling outage for Unit 2, this past spring. The Unit 1 outage is progressing well, as we speak.

Then on September 28, Point Beach completed the final commitment associated with its confirmatory action letter to the NRC. Therefore, pending final NRC review and acceptance, all 143 commitments are now complete.

We are also making good progress on the license extension for both units at Point Beach. The NRC has issued its final environmental impact statement and has found that there are no environmental issues that would preclude license renewal for an additional 20 years of operation of the site. The current operating license expires in 2010 for Unit 1 and in 2013 for Unit 2. We expect to receive a final decision on license extension from the NRC by early 2006.

Finally, I should also mention that we set a new site record at Point Beach for continuous days of operation. The previous record for a Point Beach Unit was 361 consecutive days of service. When we took Unit 1 down for refueling in September, it had achieved a breaker-to-breaker run, operating for 472 consecutive days.

Now I would like to take just a moment to talk about the fuel markets and the impact that surging fuel prices are having on our operations. Although the headlines have been focusing on higher natural gas prices, we are also seeing some increases in the price of coal. Thankfully our diverse generation mix has helped to mitigate the rise in our fuel and purchase power costs for this year, but even so, we were under-recovered on fuel costs by $19 million in this quarter and by $34 million year-to-date. High commodity costs, stronger sales, and lower availability of coal-fired generation all contributed to this under recovery.

Our coal-fired generation has been hurt by the disruption of coal deliveries from the Union Pacific Railroad. This was caused, of course, by damage to the main tracks coming out of the Powder River Basin. Over the past few months, we have been seeing between a 15 and 20% reduction in the amount of Powder River Basin coal being delivered to our plants. Through coal conservation efforts, we are managing to maintain adequate coal inventories. But these efforts have added to our fuel costs. The Commission in Wisconsin has allowed us to defer these additional costs, and in the third quarter, we deferred approximately $8 million of incremental fuel expenses. Now, as you recall, we filed in February for increased rates to recover higher fuel costs, and on March 17 the commission approved our interim request for a $115 million increase in fuel costs, subject, of course, to audit and formal hearings. We expect the commission to make its final decision on our fuel case in the near future.

Then as part of our general rate case, we expect that the Commission will use the most up-to-date natural gas cost estimates in its final analysis in December. And we are asking that those most up-to-date estimates will be used in setting rates for 2006.

Fuel prices are also having an impact on our natural gas distribution business. Although the Wisconsin rules allow dollar-for-dollar recovery of natural gas costs in the distribution side of our business, the higher commodity prices certainly impact collections, working capital requirements and customer usage.

Finally, I would like to update you on the remaining retail rate proceedings we have outstanding in Wisconsin:

We filed, as you know, a general rate case for Wisconsin Gas and the gas operations of Wisconsin Electric on June 1. For Wisconsin Gas, we have requested a rate increase of $53.2 million or 6.5%. For Wisconsin Electric’s gas business, we have requested a $27.4 million increase or 4.8%. The major drivers for these retail natural gas increases are the addition of new infrastructure and the higher cost of natural gas that we put into storage for use in the peak winter heating season.

On the electric side, Wisconsin Electric filed for a rate increase of $143.6 million, or 6.9% on the 1st of July. The filing includes a continuation of the five-year freeze on basic operating costs and provides for increases only to recover extraordinary infrastructure and reliability costs. These are $67 million related to American Transmission Company charges that we are being billed but not currently collecting in rates, $70 million related to the new generation we are building under our Power the Future plan and $6 million in costs for renewable energy programs. If the company's proposal is adopted by the Commission, there would be no additional base rate increases planned until 2008. We could, however, request increases for unanticipated fuel costs or for additional renewable energy projects.

We have also proposed that the Commission provide for a range on Return on Equity. The proposed range would cover a bandwidth, if you will, of 50 basis points on either side of a Return on Equity midpoint. Under this arrangement, returns above the upper end of the range would be returned to customers as a one-time bill credit or through reductions in our regulatory assets. If returns were to drop below the low end of the range, we would, of course, be eligible to seek a new rate increase. The Commission has scheduled hearings for mid November. A final order is expected by year-end for new rates to take effect in early 2006. We believe the Commission's final decision will balance the interests of all the parties involved.

And now, I will turn the call over to Allen, who will give you additional details on our financial performance throughout the third quarter. Allen?

Thanks Gale. As usual, I am going to focus my remarks on earnings from continuing operations, but information regarding earnings from discontinued operations is included in the earnings package that you all have. It may be helpful for you to refer to pages 7 to 10 of the earnings package as I review our results.

As Gale mentioned, earnings from continuing operations were $0.56 per share in the third quarter versus $0.26 per share for the same quarter last year. Results in the third quarter of 2004 included debt redemption costs of $0.09 per share and severance costs of $0.07 per share. If you take out these items our earnings from continuing operations on an adjusted basis were $0.42 per share in the third quarter of 2004. On a consolidated basis, our operating income was $129 million versus $100 million in the third quarter of 2004, for an increase of $29 million.

Operating income for the utility energy segment, which is comprised of Wisconsin Electric, Wisconsin Gas, and Edison Sault was $119 million compared to $102 million in the third quarter of 2004 an increase of $17 million. Positive drivers in the quarter included warmer summer weather, lower employee and severance costs, as well as the benefits associated with the settlement of a vendor contract.

We estimate the warm summer weather added $21 million to operating income, lower severance and employee costs added $15 million, and the vendor settlement added $10 million. Together, these drivers added $46 million to operating income as compared to the same period in 2004. The primary negative driver in the quarter related to under recovery of fuel costs for electric generation. This was a $17 million drag on operating income as compared to the prior year. Other items, which included nuclear O & M costs and higher employee benefit related expenses, reduced operating income a net of $12 million.

Together, these drivers reduced operating income a total of $29 million. Netting the impact of the positive and negative factors I just reviewed brings you to the $17 million increase in the utility segment's operating income for the third quarter 2005.

Operating income in the non-utility energy, corporate, and other income segments, which includes We Power, Wispark, and Wisvest was up $12 million. $7 million of this is due to Unit 1 at Port Washington going into service this quarter.

Taking the changes for each of these segments together brings you back to the $29 million increase in operating income for the third quarter 2005.

Other income was up $25 million in the third quarter compared to the same period last year. The primary driver of this change was related to debt redemption costs in 2004 of $17 million, which did not occur in 2005. Increased earnings from the American Transmission Company, increased carry on deferred transmission costs, and additional earnings from AFUDC in 2005 added a total of $6 million. Total financing costs decreased by $1million compared to the third quarter of 2004. Reduction in debt, offset somewhat by increased interest rates, was the key factor for this improvement.

Income Tax expense was up $20 million due to higher income in the quarter. Our effective tax rate was 37.8% compared to 38.7% for the third quarter of 2004. We expect our annual effective tax rate from continuing operations to be between 37% and 38% for 2005. Now, note that this excludes the favorable impact from the reversal of valuation allowances associated with State NOLs.

Adding these items brings you to $66 million of net income from continuing operations for the third quarter of 2005 versus $31 million of net income from continuing operations last year. In EPS terms, this equates to $0.56 per share in the third quarter of 2005 versus $0.26 a share in the same period last year.

Let me turn now to cash flow. During the first nine months of 2005, we generated $563 million in cash from continuing operations. This compares to $586 million in the same period of 2004. The timing of cash tax payments continues to impact our cash position relative to last year. I still expect these timing differences to even out in the fourth quarter. However, the working capital increase that Gale mentioned earlier will be a factor in the fourth quarter. We had capital expenditures of $503 million in the first nine months of 2005. $307 million of this was dedicated to our utility business, and $190 million was for our Power the Future construction expenditures. In addition, we paid $77 million in dividends.

Our goal is to maintain our debt to total capital ratio at no more than 61.5% during the period we are 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. At the end of the third quarter, our debt to total capital ratio was 58.2%, which compares to 58.3% at the same time last year. We are using cash to satisfy any shares required for our 401K plan, options, and other programs. Going forward, we do not expect to issue any additional shares.

Now, I'd like to wrap things up with a discussion of earnings guidance for 2005 as well as the fourth quarter. On an adjusted basis for the year, our guidance range for earnings from continuing operations remains at $2.30 to $2.40 per share. However, we now expect to be in the upper-end of this range. On an adjusted basis, we earned $1.66 per share year-to-date from continuing operations. So if you do the math, that effectively puts our fourth quarter guidance at $0.69 to $0.74 per share. Now, this is below the earnings from continuing operations on an adjusted basis of $0.80 per share in the fourth quarter of 2004. I have added back $0.07 per share from severance costs in the fourth quarter of 2004 to arrive at this $0.80 cent number.

Part of the reason for this reduction is the fact that we have a nuclear refueling outage in the fourth quarter of this year but did not have a similar outage last year. The cost of fuel needed for power production, the degree to which sales volumes in our natural gas distribution companies are negatively impacted by the high natural gas prices, and weather, are expected to be key variables in the fourth quarter. On a GAAP basis, our earnings guidance range for 2005 remains at $2.48 to $2.58 per share. This includes $0.04 per share from the booked gain on the sale of our Calumet Peaking Plant and $0.14 per share for the reversal of valuation allowances associated with the state net operating losses that I mentioned earlier. So with that, I will turn things back over to Gale.

Allen, Thank you very much. Overall, we had a strong third quarter. We're on track and focused on continuing to deliver value for our customers and our shareholders.

And now we would now like to take your questions. The question-and-answer session will be conducted electronically today. If you would like to ask a question, please do so by pressing the "star" key followed by the digit "one" on your touchtone telephone. If you are using a speaker phone, please make you're your mute function is turned off to allow your signal to reach our equipment. We'll take as many questions as time permits. Once again, please press "star one" on your touchtone telephone to ask a question. We'll pause for just a moment to give everyone an opportunity to signal.

Our first question today is from Paul Patterson from Glenrock Associates. Please go ahead, sir.

Good afternoon.

Hi, Paul. How are you doing?

All right. The vendor's settlement, could you elaborate a little bit more on that? And what are we likely to see from that going forward?

Sure. I'll be delighted to. The vendor settlement related to technology that we are using for automated meter reading and, very simply, it was a onetime adjustment in cash that we received from the vendor. I don't expect any additional impact going forward. And as you know, in a business this size there are lots of contracts that require adjustments back and forth. And I don't see this as a particularly unusual item, but in terms of cash we received it was $10 million, and we thought it would be appropriate to highlight it.

Okay. And we probably won't be seeing that going forward with respect at least to this one. Do you think there are other opportunities for these kinds of things going forward? I mean...

Well, certainly not with this particular vendor. This was just a onetime contract adjustment that was called for under the contract.

Okay and then just a -- could you refresh on what the -- ROE that the utility has for the last 12 months ended this quarter on a regulated basis?

Allen?

Yes. Let me start with Wisconsin Electric. And if you adjust for – adjust back to normal weather and adjust for severance costs, the regulatory return at the Wisconsin Electric level is about 11.9%. Okay so that's at Wisconsin Electric. If you look at Wisconsin Gas we did it on the same basis, meaning on a regulatory basis, the return for the 12 months ended September 30 was about 8.5%. So, 11.9% for Wisconsin Electric, 8.5% for Wisconsin Gas.

And what were the equity ratios there again?

The equity ratio, I believe was approximately 56%.

Okay. And then just finally, I'm not completely clear on the fuel recoveries. You said you were allowed to defer some of it and you got an interim rate increase. What exactly is happening with this negative $17 million and how should we look at that going forward?

Okay. Allen and I'll both take a crack at this for you. It's probably helpful to step back and think about how the Wisconsin Fuel rules work, as they do work a little differently here than they work in a number of other states. Essentially, we have to in essence get behind on fuel recovery before we can file for an adjustment in the fuel cost recovery rate.

Right

And we knew we were going to be with the spike in both gas and coal prices, but largely gas prices. We knew we were going to be under recovered, so we filed earlier this year after we began to actually see the impact of the higher gas prices. We filed for an emergency fuel increase, which the commission granted us very shortly after we filed, I believe it was within 30 or so days. We have been collecting on an annual basis about $115 million of additional fuel costs in this interim period. The Commission is, I think, close to a decision. All the testimony is in, a decision matrix has been published, and I expect in the near future the Commission will make its decision on the outstanding fuel case.

But also, in Wisconsin, as part of the general rate case, there is another opportunity under the Commission's rules to reset the fuel. And traditionally it's my understanding that the Commission has looked at both base rates and fuel clause rates in a general rate case. So we should see, probably, two different fuel decisions coming up here in the next couple of months. One to resolve the outstanding fuel case that we filed earlier this year and under which we're collecting interim rates, and then another resetting we trust, as the Commission makes its final decision in the general rate case in December.

Okay.

But basically, what has happened is that the spike in natural gas prices that we have seen in the last few months has really pushed our fuel costs above what we're collecting in the interim fuel case. That's what's really going on.

And can these guys - I guess in the interim fuel case, can they adjust for that issue in that one or do you have to wait for the general rate case before they can solve that issue, if you follow me?

We would expect, and let's just say for talking purposes that the Commission makes the decision in November. They haven't set a final date. But, let's assume for a minute they make a decision in November on the interim fuel case. We would expect them to update and refresh their numbers based on the latest published NYMEX gas prices. So, they do have an opportunity to adjust as they put in their final analysis and make their final determination.

Okay. So that would mean the bleeding would stop at that point in time and you wouldn't need anything? I mean assuming that prices don't go up anymore, with that -- does that pretty much solve the issue or do you still foresee that there a potential need to go in for even higher recovery in December?

Well, I do follow you, Paul. And the answer is if we could tell you today what natural gas prices were going to look like in December, I could give you that answer.

Right.

But if natural gas prices in December are where they are today, there probably would be an additional $80 to $85 million in the Wisconsin jurisdiction that would be needed.

Okay. That's really helpful.

Thank you for your questions, Paul.

Just want to let you know that if you find that your question has been answered, you may remove yourself by pressing the "star" key followed by the digit "2". And we will go next to Nathan Judge of Atlantic Equities.

Hi.

How are things across the pond?

Dark and rainy.

Okay. Thanks for staying up late.

No, it's my pleasure. Just a quick question on -- a follow-up question on that. If I recall, you were trying to -- there was an initiative where you were trying to reduce that waiting time and for the percent band on fuel costs, outlining on the electric side in this general rate case. Is that still par for the course or has that changed since the last time?

Good question, Nathan. We have proposed something a bit unique in the general rate case for fuel costs. As you know, there are a number of gas analysts who are hoping and thinking that natural gas prices will trend downward next year, once we get the hurricane season behind us and once production gets back to normal in the US. And what we have essentially said is our goal is not to make money on fuel. We would like to exactly recover our prudently incurred fuel costs. So, what we have essentially said in our latest filing with the Commission that's part of the general rate case is that if we end up over-recovering on fuel next year, we will pass it back to customers. We would also like there to be really no bandwidth on fuel. In other words, we would like to get to a point next year where there would be zero variance in fuel cost and fuel rates collected. But coming with that is a promise that if fuel prices come down beneath the level where the Commission has allowed us to recover in '06, then we would true-up at the end of the year and refund any over collection.

So, as I look at it, can you just recall - just -- and you may have answered this earlier, but could you remind us how much of unrecovered fuel costs you would perhaps have incurred in 2005 that would not repeat in '06?

That is a little difficult to tell because we have the fourth quarter yet to come. But, Allen can reiterate the number in terms of our under-collections for the first nine months.

Just on an actual basis, Nathan, the under recovery through the end of September 30 would be $34 million. That's the actual under recovery year-to-date or at least through September 30.

Great. Thanks. That's just what I was looking for. The next question that I had actually had to do with receivables. Clearly, we are going into a period of time when if you're correct in your assessment on high natural gas prices for '06. There is a chance of high receivables. Could you tell us what you've done perhaps to look at that, and how that is handled actually in the state?

Let me just sort of give you the background on where we are right now with net working capital. And when I say net working capital, take accounts receivable plus inventory, less accounts payable. Okay, so that's the definition of net working capital. If you look at where we were at the end of the September, if you take AR plus inventory, less AP, we were about $576 million of net working capital.

Now, that compares to $560 million for the same period of 2004. So, we are only up a modest amount, if you look third quarter to third quarter. However, I would expect the working capital balances to continue to grow through the end of the fourth quarter. And a big driver for that is obviously going to be what happens with the natural gas business. You finish with your storage at the end of October, so it would be another month of putting injecting gas into storage.

Generally, Nathan, about 40% of the gas that our customers use in a heating season is already in the can, already in storage at the end of October. So, about 40% is already in your working capital balances. Then, another 35% is hedged and then 25%, although you have commitments to buy the gas or the opportunity to buy the gas at spot prices. So, when you talk about working capital, the uncertainty is really one of what those spot prices look like because they are going to impact 25% roughly of your cost of gas, and how the customers behave because we don't know yet what sort of dial down effect we might or might not see from customers. So, there is a bit of uncertainty on supply as well as demand. But, sitting here today, I would expect working capital balances at the end of this year to be above where they were last year.

On bad debt expense, is there a full recovery mechanism in the States?

Well, what happens on bad debt, you have a certain amount of bad debt, if you will, on an annual run rate that's built into rates.

And that's about $28 million.

And that's for electric and gas combined. So, that's about $28 million. To the extent that our actual experience is more than $28 million, you take the excess above $28 million and we are allowed to defer it. So, you’re out the cash which affects working capital, but you are able to defer the impact and put it up on the balance sheet from an income statement standpoint.

Great.

And interestingly enough, our folks have worked very hard on this with customers. Our actual customer arrears are running lower through the first nine months of this year than they were for the comparable period last year. So, we are actually going into the peak winter heating season in better shape in terms of customer arrears and bad debt than we were a year ago.

Good customer service probably has something to do with that. With regard to MISO and then it's my final question. Thank you for obliging me. But, on MISO, could you just give me an idea just how things have progressed over the past couple of months and did that improve now?

I'm going to ask Rick Kuester, who runs our generation business and heads our commodity group and our power trading group, to answer your question, Nathan.

Nathan, I think, to start with, we have not seen any problems or issues with reliability. So the lights have stayed on. There are obviously -- when you get into a new market like this, there are learning curves that we are on and that other market participants in MISO are on. And I would say, as we have moved forward, we are seeing a resolution of issues. We saw higher dispatch of peakers at the beginning of MISO then we're seeing now. So some of that's coming down. You know, I would say, we are still on a learning curve. We are seeing some benefits from being in a broader market in terms of the price of power. I mean we are no longer strictly in bilateral transactions. So I would say, things are progressing as would be expected with the implementation of this type of a market.

Nathan, when we talked to our Board the other day, we gave MISO a passing grade, so far.

Thank you very much for your comments.

You're welcome. Thank you for your questions, Nathan.

And we will go next to Doug Fischer from AG Edwards.

Well, thank you and good afternoon.

Hi, Doug. How are you?

Hi, Gale. Just a couple of questions. With regard to the electric rate case, the staff has filed its testimony with a 10.9 % ROE, etcetera, etcetera, and their revenue requirement was about $205 million before any upward adjustment for today's fuel costs, which I guess would be that $80 to $85 million you talked about. And you are at $144. I guess that is about $20 million, I think, that's related to some deferrals. Well, you know, maybe you can't be too specific. Can you just address your commitment to earning a reasonable return, even though -- in '06, even though this represents a challenge?

Oh sure. I'd be happy to, Doug. But let me start out with, I think, with something that's pretty important as the premise for the entire rate case. We’ve essentially filed a very different approach to the rate case this time around. We did not file a traditional case. And the fundamental premise for the case was -- there were a number of costs, like transmission charges from American Transmission Company, for example, that are completely out of the bounds of our control. I mean we get billed for transmission costs, for power that we must provide to our customers, and that's a cost we simply need to recover. But we don't directly influence that cost. The premise of our rate case was that we will manage -- it's going to be difficult, but we know how to do it -- we will manage the costs that we can control. And therefore, we went in and said, "Here are several costs that are really outside the bounds of normal operations. And allow us to recover those prudently incurred costs, and we will try our dead level best to manage everything else." That was the fundamental premise of the rate case going in. So along with that is a continued commitment to earn reasonable returns for our shareholders.

Other than fuel costs, are there developments that have happened over the last few months that have made it more difficult for you to achieve a reasonable return in '06, since you've filed the electric case?

We filed the electric case on July 1. Candidly, other than fuel costs, we haven't seen anything that would change our minds. And again, you know, we understand the challenges ahead of us, but we haven't seen anything since the 1st of July that would either make it easier or more difficult than what we anticipated.

Can you comment at all as to whether those plans might involve some onetime charge that we might somehow exclude from earnings, as a result of some efforts to achieve that?

Doug, I think, it is a little bit too early. We are not even through the technical hearings. We have a lot to go here in the next 45 days or so, on the rate case. I think, it's little too early to comment on that particular question.

And then, is it possible to pancake fuel requests? Because, you obviously, filed -- broke through the band filed early in the year and then that wasn't enough, given what happened with natural gas prices. Could you have filed a second case, so that you wouldn't have the shortfall that you had in the summer?

Well, remember now, we did file for deferral of extra costs associated with our coal conservation efforts. And we also had some Point Beach deferral costs. Remember, we had an unanticipated situation that really no one could have anticipated at Point Beach in the spring. There have been really two other approaches to the Commission for deferral of fuel costs, in addition to the interim increase that we are currently collecting.

Is it theoretically possible to pancake those types of requests?

I will ask our general counsel. Larry, in theory, what would you say?

Douglas, this is Larry Salustro, in theory, your collection of rates under the interim would somehow have to not be sufficient to keep you within the band. So, you have to have the interim and then you have to be out of the 3% band. So, whether it's theoretically possible, I don't know. You would have to have that on a historic basis. That second case, like the first one, is not a projection, it's your actual experience. I don't know what percent increase in natural gas costs would get you to that point, but it is pretty high. Whether that was permitted or not, there is something about it that is not orderly. Questions of two surcharges on customers' bills, what we have is the opportunity, because of filing a rate case, and as Gale says, it is typically zeroed out, as far as fuel costs on a projected basis. And this way of handling it I think is much less confusing to customers and much easier to understand and pretty much gets us back to the same place.

I hope that responds to your question.

Yes, Thank you.

One other point that I think is worth making on this whole fuel situation, we did a little analysis a couple of weeks ago, and in looking at the reliance on natural gas-fired generation, state by state. And there are 27 states in the US that have significantly greater reliance on natural gas for electricity generation, then does our Company or then does Wisconsin. So I think you are going to be seeing, given what's happened with the natural gas prices our relative competitive position here, even with the increases that we need to cover our natural gas and coal cost, you'll be seeing our relative competitive position improve materially.

Okay. Thank you.

Thank you, Doug. Take care.

We will go next to Paul Ridzon from KeyBanc McDonald.

Hello Paul.

Can you hear me?

We can. How are you Paul?

Good. Yourself?

Doing fine.

You have got a $28 million bad debt, kind of tracker, embedded rates. Where are you now? Where were you September 30, '04 and 12/31 '04?

While we are looking up numbers, let me give you a general response to that. We had, I believe last year we were in the $38 million to $40 million range, in terms of total bad debt expense. Now again, above the $28 million, the difference between the actual bad debt expense and the $28 million is deferred. From everything I have seen, we are tracking in about the same range. Allen and Steve are nodding their heads up and down, yes.

Yes.

We are tracking about same range.

Right. But, then the big uncertainty, obviously, Paul, is going back to my comments that I made in my prepared remarks. What do gas prices look like in the fourth quarter and what is your bad debt as a percentage of that look like? So, if you had experience like you had last year, I would, sort of, expect total bad debt expense for the year to be, something like, $40 million. But, it could possibly be well in excess of that, depending on what kind of winter we have and then the payment experience.

And again, Allen is right. The fourth quarter is the big question mark. But I will I say and reiterate what I mentioned earlier, going into this winter season, our total customer arrears, different from bad debt - our total customer arrears are in better shape than they were a year ago.

Paul Ridzon That difference is just a matter of how far in arrears, until before they declare bad debt?

As you know, you age your receivables. And essentially, you go from current to 30 days to 60 days, to 90 days, to really past due. The difference is, candidly, more effective collection in working with customers.

What are the rules in Wisconsin with regards to disconnects?

We have like many other states - we have “no disconnect” rules. And I believe, starting November 1, we can no longer disconnect any customer, and that “no disconnect” period, extends through tax day, April 15.

And lastly, I know, it's still early, but have you witnessed any demand destruction on the gas side?

Little too early to tell. We really haven't had any weather cool enough to bring out any heating demand at this point in time. We just don't have any indication, right now, of any demand destruction. And again in Wisconsin there is not a lot of industry that is incredibly reliant on natural gas for their printing processes. What you're going to see, in terms, of the industrial side and demand destruction for natural gas, it's going to be in heavy chemicals, it's going to be in plastics processing, that kind of thing. Wisconsin does not have a lot of that type of industry.

So you expect to see it primarily on the residential side the “put on a sweater” type of thing?

I know you have a picture of Jimmy Carter in your office, yes.

Thank you very much.

Okay. Thank you.

We will go next to Ashar Khan from SAC Capital

Good afternoon.

Hi Ashar. How are you today?

Pretty good. Gale, could you just remind us what the dividend policy is, as we look in into next year, when you usually raise your dividend? Can you just remind us, you know, what's the dividend policy of the firm is?

Sure. I will be delighted to. We have a stated dividend policy, as you know. And that is during this period of time when we have major construction spending ongoing, and that would be through 2010, our policy will be to, our goal really. will be to raise the dividend annually if it all possible at about half the rate of growth in earnings per share. Allen, anything you want to add?

We have done a little better than that at last two years, but Gale you are exactly right, going forward, our goal is roughly half the rate of earnings growth.

Okay. And Allen, how do you define earnings growth. Because you know this year was like a flat year versus last year and next year is, you know, you pick up because you are in a more normalized pattern. So should we look at it '06 versus '05 or is it on a normalized growth rate over a longer period of time? How should we look at it?

Well, yes, fairly speaking half the rate of earnings growth. You know, you would like to provide for stable and predictable increases, but rather not ratchet up and down, dividend increases year-to-year, too unnecessarily. I think if you just generally shoot a line, and you look at earnings growth from continuing operations, then the increase in dividends will be about half the rate of increase in earnings growth from continued operations.

Okay.

Allen is right. We're going to look at that not one year-to-year but over a reasonable period of time.

Okay. And then as I -- at one point I got disconnected. Could you elaborate where you are in terms of looking at transmission and strategy for transmission and the American Transmission Company?

Sure. We'll be delighted to do that. As I mentioned on previous calls, when we have been asked this question, any structural change or ownership change in American Transmission Company is really a decision from the Board of Directors of ATC. We are one member of the board, we are about a 38% owner of ATC, but we have one vote on the board. Clearly, I'm very confident that the Board of ATC will want to look at lots of different options and lots of different potential structures and analyze what is best from a fiduciary standpoint for the long-term for ATC. But it is a Board decision and we will make input at the right time, at the appropriate time into that Board decision.

But is that decision contemplated by the end of this year? Gale, is there some timing to that?

Again, I wouldn't preclude or attempt to speak on behalf of the ATC board for any particular timing. But currently the ATC is a very active board and very cognizant of all the issues. There are 10 members on the board. There are five separate owners, and there are outside directors. And again I think at the appropriate time, you know the ATC board will look at its options and make a reasonable decision.

And I apologize, if I can just end up. As you give your guidance for the fourth quarter, I know the question was asked -- what should we look into that as fuel under recovery that you have estimated for the last quarter?

Would Allen handle that one please?

I would rather not give a specific projection of fuel under recovery, but I guess what we tried to do, you know, is look at what we think our fuel costs will be in the fourth quarter and adequately give you an earnings range. And I guess, I think in terms of the gas price outlook, you know, we are factoring in what current gas prices look like That has been updated.

Okay. Thank you, sir

You're welcome, Ashar. Thank you for your questions.

And we will take a question from Reza Hatefi from Zimmer Lucas Partners.

Good afternoon.

Reza, how are you today?

Very good. Thank you.

Gale Klappa What have you done with Vidula?

Reza Hatefi. Oh he’s busy somewhere else now.

Allen, I think you mentioned that over the last 12 months from September to September your regulated ROE at Wisconsin Electric was a 11.9 %ROE. Is that sort of weather normalized and/or fuel normalized? Or would that be lower because I think you guys have had some nice weather this year and so forth?

Actually, we already adjusted for weather and severance, so that's all adjusted out. And I try to kind of put it on a normalized basis, sort of to the extend I could.

And what kind of rate base is that based on?

Well, In terms of the equity, that would be about $2.2 billion of equity at Wisconsin Electric and about $360 million of equity at Wisconsin Gas.

Okay. And my earlier understanding was that in 2006 your fuel clause changes to -- the threshold goes from 10% to 8% and the band goes from 3% to 2%, is that still true?

That is true, I think the other change that occurs that will actually subdivide fuel cost into two categories. I believe that the terminology they use is volatile and non volatile. And so the volatile component, and an example of volatile would be the cost of natural gas,, and the cost of coal. You would actually measure the band versus that smaller subset of fuel than you do now. So you're right, you tighten the band. So 2% and 8% versus 3% and 10% now, but you also measure that on a smaller basis.

So we could think of going forward from '06 onwards, fuel under recovery should play a much smaller role I guess in your earnings.

Well, All other things being equal, that's certainly true. But obviously, if we have very volatile fuel markets. It’s kind of hard to imagine it being more volatile than this year. But if you had more volatility, the tighter bands may just keep you even.

Allen is right. All things being equal, you would expect substantially less under recovery then we're seeing this year. But at this stage of the game, I don’t think anyone wants to predict what will happen in the fuel markets. In fact, we those two different markets, so that one stable and one volatile, we really should change those to volatile and really volatile!

Great. Thank you very much.

Thank you.

We will go next to John Hanson from Imperium.

Hi, John.

Good afternoon.

How you are doing John.

All right. Well I'm doing great because all my questions have been answered. Thank you.

Rock and roll, thank you.

And we will take a question from Dan Jenkins from the State of Wisconsin Investment Board.

Afternoon Dan.

Good afternoon.

Dan have you brought your sweaters out of storage yet?

I got my blanket from the cleaners - does that count?

Any teddy bears in there?

No.

No. Okay. But you didn't call to here this. What's on your mind Dan?

Couple of things. I missed the first few minutes, so hopefully this is not redundant. On your income statement, I noticed in the quarter at least your operating and maintenance expenses were down slightly. I was kind of wondering what was behind that – will it continue to be more flat than maybe it has been the first six months of the year going forward?

Yes. In terms of the drivers of O&M, if you look on I believe it's page 7 of the earnings package where we look at quarterly drivers, we did have lower employee costs of about $2 million, and then we also have this contract settlement that we talked about that was actually a $10 million benefit to O&M. And then we had severance last year. So you have to really net all of those out, if you will, to get a run-rate. And I believe if you do that, you get roughly flat to slightly up, actually.

Okay. So the '04 quarter was somewhat was probably higher than...

Yes, largely driven because of severance costs in that quarter.

Okay. Then I was wondering on your cash flow statements, there is about $100 million for the nine months, there is about $100 million decline in the working capital and other. And what was driving that?

And I remember that that measures the change that you saw over the nine month time period. So there would be the change from December of '03 to September of '04 versus the change from December of '04 to September '05. And what you saw in the former period was you had a pretty warm winter in 2003 and so you didn't use as much gas as you typically would have out of storage. And instead of pulling that gas out of storage in 2003, you pulled it out in '04, which benefited working capital in '04. If I making sense? You didn't have that recur in 2005. So that is a very, very big part of this delta in working capital that you are seeing. But in terms of as opposed to looking at a flow variable if you look at kind of as a stock variable, and look at the total working capital and the business, September of '04 versus September of '05 we are only up about $15 million.

Okay. So basically why you're saying you had less inventory building in '04 than you've had in '05 because you had more gas in storage essentially.

You’re all over it, that’s exactly right.

Okay. Then I was wondering.

But then you haven't turned your heat on yet.

No. You mentioned that some of the on your statement that some of the positive factors from the warmer weather were offset by the sharply higher fuel costs and greater reliance on natural gas to produce electricity. I was kind of curious, was the driver of that usage in natural gas was that just the new units going on or is that the fact that you had trouble getting coal?

No, no. It's actually, it's a very good question Dan. It's actually a combination of three things. Obviously, to help meet peak summer demand, we brought on a new natural gas fired unit at Port Washington 545 megawatts. That unit because of warmer summer temperatures ran a tremendous amount this summer. That's one element. The second is purchased power. Again we are -- on many days, particularly in the summer, and until we can get our Oak Creek unit online, and add to our capacity, we're a net buyer. And virtually all of the purchase power that we're buying is fueled by natural gas. And then thirdly as we mentioned in the call, Union Pacific Railroad declared a force majuere on some of its coal deliveries coming out of the Powder River basin to us. And so we have had higher costs as we’ve tried to preserve our coal inventories at our major coal fired power plants. Rick, anything to add?

Yes. And that was referred to..

Yes. And those higher costs -- the higher cost related to our coal conservation efforts we have deferred with Commission approval.

Do you have what the likely percentage of generation from coal, gas, nuclear and purchased power this year versus last year?

We sure do. Rick, do you have it right in front of you?

Yes. Last year, we were about 60% -- 61% coal generation, this year we are about 58%. Last year we were about 24% nuclear, this year we're going to be about 20% and these projections for this year. And purchased power last year was about 14%, this year it's probably going to be about 16%. Natural gas last year was relatively small, 0.2%. This year its going to be about -- excuse me; 0.2% last year, about 3% this year. So there's a large increase, but we brought on a new unit this year.

And the reason why our nuclear generation, according to Rick's projection, is expected to be down this year compared to last year is we simply have two refueling outages, normally scheduled refueling outages at Point Beach this year where we had only one last year.

And the spring outage went longer than expected also because of (inaudible).

Okay. And then speaking of that when is the Unit One at Point Beach expected to be back up?

We're about 30 -- a little over 30 days into the outage, and we typically don't put out timeframes, but I just would say that we are about where we would expect to be right now. That outage is going very well. We don't see any major issues there.

As Rick says the outage is going as planned at the moment.

And have you already done the -- reactor vessal head replacement or is that still yet to come?

The reactor kit is now set. We still have testing and other things to do, completion of putting some of the control rod drives testing on, but we've set the reactor. So the old one is out of containment and the new one is in containment and on the vessel.

Okay. Thank you.

Thank you.

And we will go next to Jonathan Rojewski from Pequot Capital.

Rojo, How are you today?

Hi, everybody. How is it going?

Going good.

I was wondering if you could just provide some additional detail on the CapEx budget? I know, Allen, you mentioned something earlier in the call, but relative to the four business units outlined as Wisconsin Electric, Wisconsin Gas, Edison Sault, and then I guess Power the Future, if you could just sort of walk us through what the expectation is for this year and then maybe a forecast for the upcoming years?

Let me just start with the regulated business, which would be Wisconsin Electric, Wisconsin Gas, and Edison Sault. My projected spending for 2005 is about $500 million for the regulated business. If you look at Power the Future, which would be the new gas units as well as Oak Creek that would be about $315 million. So -- and then there are some other little cats and dogs outside regulated and Power the Future that would bring the projected spend in '05 to about $824 million or $825 million for 2005. As I look forward to 2006, capital spending will be up somewhat in '06 relative to '05. Sitting here today I would expect the capital budget in '06 to be approximately $900 million.

Okay.

And again that's driven by the increased spend on our Power the Future units.

Sure. And then, I guess, Allen, any projections relative to 2008 and '09? I mean obviously in '09, '10, you guys will finish the coal units. Or maybe if you can't be specific, if you could just remind everybody sort of how you expect that spending to occur? I mean I know that you guys have given the total cost for the build, but maybe how over the four years or so of spending how you expect that to be spread out?

I mentioned the roughly $900 million of CapEx for 2006. I'd really rather not give projections for '07 and '08. But what I will say is if you look at our overall spending plans, PTF plus the regulated business, I really expect the peak year to be 2007. So the peak annual expenditure will be in 2007, and will be somewhat lower in 2008. So you'll continue to see an increase in annual CapEx going through 2007, and then you'll see it start tailing off. That's helpful, hopefully.

Okay. And then, I guess one last question regarding CapEx. It would be the $500 million that you quoted for the regulated businesses in '05, is there anything going forward in the future that would cause in your mind that number to change materially up or down?

Well, I expect to go down because this is the year that we've been spending a significant amount of money on pollution control equipment. And in fact, we had about $140 million of the budget this year at the regulated companies for a scrubber at one of our plants.

And that is replacement as well.

Yes.

So it should go down. Allen is right.

Okay. Yes. I think that's important to note. What was the total cost for the vessel head, Allen?

It was $52 million.

Okay.

That is for two vessel heads.

Right. For both of them?

Yes. A total of $52 million.

Okay. And then any other additional CapEx regarding scrubbers or environmental that you guys need to spend in the forward years?

Well, the total plan for environmental on existing units was $600 million over the period from 2003 to 2013. I believe through the end of this year, and Rick check me on this, but I believe we will have spent $350 million roughly of the $600 million through the end of this year. So we've spent well over half through the end of this year. And that I think it will be not quite as lumpy, you know, it will be spread out a little more over the '06 to 2013 period. So about $250 million to go over the next seven years.

Those costs were very front end loaded and we're largely -- we're working our way through the front end loading as Allen said.

Right. Okay. Wonderful. Thanks for taking me through that. That was really helpful.

Thank you. We appreciate it, Jonathan.

All right. Good luck. Bye.

That concludes our question and answer session today. At this time, I would like to turn the call back over to Gale Klappa for closing or concluding remarks.

Thank you. That completes our conference call for today. We appreciate your participating, and we appreciate your questions. If you have any questions or comments, Colleen Henderson will be available in our Investor Relations office. Her direct line is 414-221-2592. Thank you very much. Good afternoon, everybody.

And just a reminder for the playback information, it will be available in two hours from now. You may reach the playback by dialing 1-888-203-1112 and using the pass code 72 -- I'm sorry; 2417641. Again that number to dial for the playback is 888-203-1112 with the pass code 2417641. Again, thank you for your participation. You may disconnect.