威斯康辛能源 (WEC) 2005 Q2 法說會逐字稿

Good afternoon and welcome to the Wisconsin Energy 2005 second 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 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, 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 second 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 second quarter results. Let me begin by introducing the members as always of our 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 General Counsel; Jeff West, Treasurer; and Steve Dickson, our Controller. We'll all be available to respond to your questions at the conclusion of our prepared remarks.

Well, to start out, I'm obviously very pleased with our overall performance in the second 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 $0.48 a share from continuing operations in the second quarter of 2005. This includes a $0.14 per share gain from our ability to recognize state tax operating losses at the parent company level. Our $0.48 a share for this year's second quarter compares with $0.18 a share from continuing operations in the second quarter of last year. Warm weather in June, lower debt levels at Wisconsin Energy, and effective cost control across our utility operations were all positive factors in our strong second quarter.

Now I would like to update you for a moment on a number of developments with our Power the Future plan. Let me begin with our Port Washington project. In November of 2002, as you may recall, the Public Service Commission approved the construction of two 545-megawatt natural gas-fired units at our Port Washington site north of Milwaukee. I'm delighted to report that we've reached a major milestone at Port Washington in July. In fact, on July 16, the first Port Washington unit went into commercial service on time and on budget. Just a few days later, on July 21, we closed on the permanent debt financing for the unit. I'm pleased to add that the performance of the unit in terms of both capacity and heat rate, is better than the guaranteed levels.

Now, the construction program for the second unit, which was begun last year, has two major phases. First is the demolition of the remaining coal unit at Port Washington and, of course, site preparation. That work is proceeding on schedule. We expect to begin actual erection of the second unit next year. Our plan calls for the unit to be operational in time for the peak summer season in 2008.

Now turning to the status of our construction plans at Oak Creek. On June 28, the Supreme Court of Wisconsin reversed a lower court decision and reinstated the Public Service Commission's order approving construction of two 615-megawatt coal-fired units at our Oak Creek site south of Milwaukee. So the authorization granted back in December of 2003 by the Public Service Commission is once again in effect. Following the Supreme Court's ruling, we issued a mobilization notice to Bechtel Corporation to begin construction activities at the site at Oak Creek. That includes site clearing, staging of construction equipment, creation of new permanent site roads, and installation of environmental compliance measures. The project cost is expected to increase by approximately $50 to $55 million as a direct result of the construction delay caused by the litigation. This is a bit less than our previous estimate of $55 to $65 million and represents an increase of approximately 2.5% in the total cost of the project. We believe these costs are ultimately recoverable under the terms of the lease agreement between the We Power subsidiary and Wisconsin Electric. However, recovery is subject to our final calculation of costs and of course to review and approval by the Public Service Commission.

As you know we had previously received all of the state and federal permits necessary to begin construction of the Oak Creek units. Some of these permits continue to be contested but they remain in effect until and unless overturned by a reviewing court. So absent any further delays we expect to have the first unit at Oak Creek in service in the summer of 2009.

Now turning to our nuclear operations, on April 2, Point Beach Unit 2 was removed from service for refueling, maintenance, and replacement of the reactor vessel head. We expected to complete the work in just under 60 days. In mid-April however, the Nuclear Regulatory Commission advised Nuclear Management Company, that of course is the operating company that we've retained to operate Point Beach, that it was concerned about the removal of the old reactor vessel head and the installation of the new one, which is slightly heavier than the old vessel head. After extensive analysis the NRC granted a license amendment for Unit two and the vessel head was installed in late June. The refueling outage is now complete and Unit 2 reached full power again on July 16. The outage duration was 99 days. While this was clearly longer than expected Nuclear Management Company did an excellent job of managing the cost of the outage. As a result there was minimal impact on the O&M budget.

With regard to replacement power costs we filed a request with the Public Service Commission to defer the extra expense for fuel and purchase power that we incurred because of the unexpectedly long outage. That request was granted on May 27. We estimate that the additional costs totaled $18.6 million in the second quarter. Of this amount, $15.8 million has been deferred in the Wisconsin jurisdiction. We expect this to be recovered in future rates subject to commission audit and approval. This fall a new reactor vessel head is scheduled to be installed on Unit 1 at Point Beach during its regular refueling outage. Nuclear Management Company has submitted a license amendment to the NRC and we expect that any issues will be resolved before the outage work begins this fall.

We're also making I think very good progress on the commitments we made to the Nuclear Regulatory Commission after their safety inspections in 2003 and 2004. At this point we have completed 141 of the 143 commitments that we identified in a confirmatory action letter to the NRC. I should also mention that we recently set a new site record at Point Beach for continuous operation. As of today, Unit 1 has operated for 414 consecutive days. Previous site record was 361 days.

Now, before we give you a brief update on our retail rate activity I'd like to mention an item that could have operational and financial implications for our company in the second half of this year. In early July we received a notification from Union Pacific Railroad that a force majeure event requiring maintenance on its rail lines is expected to result in a 15 to 20% reduction in the amount of Powder River Basin coal delivered to our plants. Obviously we're working to minimize the impact to our fuel and purchase power costs but we simply can't determine what impact if any this might have on our final 2005 results.

Finally I'd like to update you on the three retail rate proceedings we have outstanding in Wisconsin. The first is the case we filed back in February to recover higher fuel costs. Our fuel costs, as many of you are aware, are being driven by greater reliance on natural gas to generate the energy we need to meet growing customer demand. On March 17, the commission approved our interim request for a $115 million increase subject to audit and, of course, to formal hearings. We expect the commission to make its final decision in this fuel case sometime in the third quarter. If the final amount approved is less than the interim amount we, of course, will refund the difference with interest.

Next are the general rate cases for Wisconsin Gas and the gas operations of Wisconsin Electric. We filed these cases on the first of June. 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 27.4 million, or an annual increase of 4.8%. The big drivers for both of these increases are the addition of new infrastructure over the past five years and the higher cost of natural gas that we put into storage for use during the peak winter heating season.

Finally Wisconsin Electric filed an electric 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 to recover extraordinary infrastructure and reliability costs. These are $67 million related to American Transmission Company charges that we're not currently collecting in our rates, $70 million related to the new generation we're building, and $6 million in costs for renewable energy programs. If our proposal is adopted there will be no additional base rate increases planned until 2008. The Company could, however, request increases for unanticipated fuel costs or for the implementation of renewable energy projects.

The Company has also proposed a flexible range for return on equity. This range anticipates returns for Wisconsin Electric within a bandwidth of 50 basis points on either side of our proposed ROE, which is 12.2%. Under this arrangement returns above 12.7% would be returned to customers as a one-time bill credit or through reductions in regulatory assets. If returns were to drop below 11.7% on the other hand, the Company would be eligible to seek rate relief. Public and technical hearings are set for October of this year, and a final order is certainly possible from the commission by year end. Now, I'll be happy to turn the call over to Allen who will give you additional details on our financial performance in the second quarter. Allen.

Thanks, Gale. I'm going to focus my remarks this afternoon on earnings from continuing operations but information regarding earnings from discontinued operations is included in the earnings package. It may be helpful for you to refer to pages 8 to 12 of the earnings package that we posted on our website as I review our results. As Gale mentioned earnings from continuing operations were $0.48 per share in the second quarter versus $0.18 per share for the same period last year. The results this quarter included a $0.14 per share gain associated with the ability to recognize state tax operating losses. If you take out this nonrecurring gain our earnings from continuing operations on an adjusted basis were $0.34 per share. Also, results in the second quarter of last year included $0.02 per share for severance costs. Adding this back brings earnings from continuing operations on an adjusted basis to $0.20 per share in the second quarter of 2004.

On a consolidated basis our operating income was $90 million versus $74 million in the second quarter of 2004, an increase of $16 million. Operating income for the utility energy segment, which is comprised of Wisconsin Electric, Wisconsin Gas, and Edison Sault, was $90 million compared to $74 million in the second quarter of 2004 for an increase of $16 million. Positive drivers in the quarter included weather, lower employee costs, and reduced O&M expenses for our nuclear operations. We estimate the warm summer weather added $10 million to operating income and lower employee costs added $5 million. Reduced nuclear O&M added $7 million. The primary reason for this was the elimination of the inspection and maintenance costs associated with the old reactor vessel head. Together, these drivers added $22 million to operating income as compared to the same period in 2004.

The primary negative driver related to retirement plans, and this was a $4 million drag on operating income. Other items reduced operating income a net of $2 million so together these items reduced operating income $6 million. Netting the impact of the positive and negative drivers I just reviewed brings you to the $16 million increase in the utility segment's operating income for the second quarter of 2005. Operating income in the non-utility energy segment, which includes We Power and Wisvest was a breakeven this quarter as well as in the second quarter of last year. Corporate and other income which includes our real-estate operations, was also level as compared to the same quarter last year. Taking the changes for each of these segments together brings you back to the $16 million increase in operating income for the second quarter of 2005.

Other income was up $7 million from the same period last year. The primary drivers of this increase were earnings from the American Transmission Company and carry on deferred transmission costs which were $3 million. In addition, we had $2 million of additional earnings from AFUDC. Total financing costs decreased by $8 million compared to the second quarter of 2004. Reduction in debt was the key factor with the total debt outstanding being down over $550 million on June 30, as compared to the same time last year.

Income tax expense was down $4 million this quarter. Our effective tax rate was 12.7% compared to 36.6% for the second quarter of 2004. This reduction was caused almost exclusively by the reversal of valuation allowances associated with state tax operating losses at the Wisconsin Energy level. The reversal was driven by the reinstatement of the Public Service Commission's approval of the new coal units which will ultimately result in additional income for state tax purposes at the Wisconsin Energy level. This increased our quarterly results by $16.5 million on an after-tax basis, or $0.14 a share. Now, we regard this as a non-recurring item, so without this the effective tax rate would have been 37.9% through June 30, of this year. We expect our effective tax rate from ongoing operations to be between 37.5% and 38% for calendar year 2005. Adding these items together brings to you $57 million of net income from continuing operations for the second quarter of 2005 versus $22 million of net income from continuing operations last year. In earnings per share terms this equates to $0.48 a share in the second quarter of 2005 versus $0.18 a share in the same period last year.

Let me turn now to cash flow. During the second quarter of 2005 -- during the first half of 2005, we generated $435 million of cash from continuing operations. This is down from the same period last year due to differences in the timing of cash tax payments. I expect these timing differences to even out over the remainder of the year.

Moving now to asset sales and financing. On June 1st , we closed on the sale of the Calumet Energy Center to Tenaska Power Fund for $37 million. Calumet is a 308-megawatt natural gas-fired peaking plant in Chicago. We expect to receive $32 million in tax benefits from this sale, so we estimate the total after tax proceeds to be $69 million. We recorded a gain of $4.7 million after tax in discontinued operations in the second quarter as a result of this transaction.

On July 21st , Port Washington Generating Station LLC closed on $155 million of 4.9% Senior Notes with a final maturity of July 15, 2030. This is a non rated private placement. The notes have an amortizing structure so the average maturity is actually just over 15 years. Proceeds from the sale of the notes were used primarily to repay short-term debt incurred during construction. With the closing of the financing that I just mentioned, we now have approximately $600 million of liquidity at the holding company level as we begin the construction of the coal units at Oak Creek.

We had capital expenditures of $322 million in the first half of 2005, $208 million of this was dedicated to our utility businesses and $107 million was for our Power the Future construction expenditures. In addition we paid $52 million in dividends.

Now, as a part of our Power the Future plan we made a commitment that 5% of our energy requirements for retail energy sales would come from renewable resources by 2011. Last month we announced an agreement to purchase the development rights for two wind projects here in Wisconsin. We believe these projects will put us in a good position to fulfill our commitment. The ultimate cost to develop and construct these projects is expected to be from $225 million to $250 million. This investment was not previously included in our capital program. However, our financing and capital structure goals remain the same. Our goal is to maintain our debt to total capital ratio at no more than 61.5%, during the period we are constructing 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 second quarter our debt-to-capital ratio was 57.9% which compares to 63% at the same time last year.

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. Because of the wind projects that I mentioned we will need to sell additional assets. And for example,these sales could include real estate assets of those in WISPARK. Those assets alone currently represent nearly $65 million in book value.

Now I would like to wrap things up with a discussion of earnings guidance for 2005. Our results this quarter put us ahead of our plan for the year. However, given the fact that the third and fourth quarters are very significant in terms of earnings and the uncertainty surrounding our fuel and purchase power cost that Gale mentioned we're only going to adjust our earnings range for the one-time items that occurred in the second quarter. On an operating basis our earnings guidance range remains at $2.30 to $2.40 per share. On a GAAP basis our earnings guidance range for 2005 is now $2.48 to $2.58 per share. This includes $0.04 per share for the book gain on the sale of our Calumet peaking plant and $0.14 cents per share for the reversal of valuation allowances associated with the state tax operating losses at the Wisconsin Energy level.

Although we will not be giving earnings guidance for the third quarter I do want to give all of you a feel for earnings drivers in the third quarter. The earnings package includes a pro forma earnings base for the third quarter of 2004. This base excludes nonrecurring items and discontinued operations. It includes the impact of the share buyback and debt reduction associated with the sale of the pump business as if it had occurred at the beginning of 2004. For the third quarter of 2004 the pro forma earnings base is $0.44 per share. Now, I expect increased sales, including a return to normal weather, earnings from the new Port Washington unit, and the benefits of the workforce reductions that were made last year to be the key positive drivers for the third quarter. Benefit costs are expected to continue to be a drag on our earnings in the third quarter. The net of all these drivers is still expected to be positive resulting in modest growth in earnings in the third quarter. With that I will turn things back over to Gale.

Allen, thank you very much. Overall I think you see we had a strong positive second quarter. We're on track and focused on continuing to deliver value for our customers and stockholders. And now we'll be happy to take your questions.

Thank you. [OPERATOR INSTRUCTIONS] We'll go first to Ashar Khan with SAC Capital.

Allen, can I just go back, this quarter, to keep with your earnings guidance, so you would take $0.14 out, so you would be really at $0.34, correct?

Yes, $0.34 on an adjusted basis in the second quarter.

But aren't you -- if I'm right from your comments, at the end of the first quarter call you said you were expecting to be just slightly ahead of last year, that this quarter has come up nearly about $0.06 or $0.07 higher than planned.

Yes, the biggest driver for that obviously when I gave that prediction back in April, I couldn't predict what June weather was going to be like, so we had very very hot weather in June. So as you saw from the earnings package weather in the second quarter on a operating income level was about $10 million higher because of weather, and about eight of that, if you look at last year was cooler than normal, this year obviously was warmer than normal. If you adjust it back to normal operations I'd say we were probably 6 million better. That was a big driver certainly in the difference.

And am I correct, hasn't the July weather been pretty hot in the Midwest? I guess that's what we have been reading.

Off and on, yes.

Well, actually, if you look at cooling degree days for the whole month, they are somewhat above average but not extremely above average. What happened to us about the first 10 or 11 days of July we were actually significantly cooler than normal, then the last part of the month was a bit warmer than normal, as you've read.

Ashar, as we look now on our conference room window the time and clock temperature on the bank building across the street says 71 degrees.

Can I just go on the rate case filing, can you talk to us what would be the earnings impact of the rate case for '06?

Well, if you step back and look at what we have filed here, I mean, for starters, the big key question is going to be whether or not the package of things that we asked the commission to look at, whether they will look at them in the way that we're expecting them to look at it. And the big driver, of course, is going to be what is the final allowed return on equity. And whether or not the bandwidth that we've proposed, which would be somewhat novel for Wisconsin, is actually accepted. So I would expect if we get a reasonable, and we expect a reasonable reception at the commission that you could see normal what I would call normal utility growth in the preceding year.

Okay. How do you define normal?

Well, obviously, it's way too early to give normal earnings guidance for 2006, but you can look back historically at what normal utility growth is here, and that's what I would think we would expect.

Gale, just going back to the different portions and the transmission expenses are something which are underrecovering, right? They're something which are being -- asking to be kept whole on, so that's just -- that just improves the bottom line. Am I correct?

Let's go through the electric case for just a second. The roughly $70 million, or I think maybe -- is that right? Is that the precise number? $70 million for the transmission in effect that has no impact on earnings because what's happening now those costs are being deferred so they don't affect the P&L but obviously they affect cash. So if the commission approves that portion of the rate plan, that will just sort of -- it will, -- it will show up in cash but it won't show up in earnings, because you're deferring the cost now. On the PTF side as at least viewed by the utility, that's the same answer. Those costs are going through the income statement in any case.

Then there's a very small piece, I think it was $8 million, to be precise for renewable programs, but again those costs are being deferred now. So really, all of the costs, all of the items for the electric case at least, all of those would be beneficial to cash because you'd no longer be deferring costs but they wouldn't affect earnings. Now, if you move to the natural gas case, you're asking for -- we're asking for increase there, and then I would sort of drop back to what Gale said. Well, we don't know yet what sorts of allowed returns are going to be, what the commission is going to allow on the gas operations. We're going to have other costs that will go up on the electric side that we didn't request rate increases for. But at a high level that hopefully gives you a better feel for where this stuff shows up but it's pre -- too premature to start giving earnings guidance for 2006. Too early in the case.

Ashar, to expand on the point Allen made, which is very important about the charges from American Transmission Company, because we have had in essence a base rate freeze in the state of Wisconsin for five years the higher transmission costs that we're currently being billed for transmission service from ATC is not being recovered in our basic rates, but is because of the rate freeze, as Allen mentioned being put up as an asset on the balance sheet essentially. So this will -- we clearly need to have rate treatment associated with prudently incurred transmission costs. And what this request does is essentially try to get us even in terms of cash coming in the door equal to what we're being charged by American Transmission Company today.

And Gale if I can just ask on the strategic, now with the IPO of ITC, is there any plan for American Transmission Company to follow on a similar load?

Actually that's a good question and obviously a lot of people have been focused on the results of the ITC/IPO that took place this week. Let me just say two things first of all. American Transmission Company has a number of owners, we are an approximate 37% owner right now, but the governance structure at ATC includes 10 Board members and each Board member has a single vote. So even though we have a roughly 37% ownership we only have one vote on the Board, and clearly any potential IPO is a Board decision. So there's been no Board decision related to this, and there will be a number of issues that the Board, if it did come before the Board would have to evaluate. The first is is what would the valuation be. The second is, we would have to take a look at tax leakage, then there are other quantitative factors here that are very important, including the significant construction program that we're all counting on American Transmission to deliver so that we can keep reliability high in the state. So no plan at the moment but clearly that would be a Board decision and I wanted you to be aware of the governance structure at ATC.

But can that issue be -- is that something for consideration this year? Are those things being discussed?

At the present time there's no plan to -- that I know of to bring any decision before the Board this year.

Thank you.

You're welcome, Ashar, thank you.

We'll go next to Paul Ridzon with Key McDonald.

Actually, my question has been answered. Thank you.

We'll go next to Bob Weren with Bear Wagner.

Hello, Bob.

Hi. It's actually Andy, guys. How are you doing?

Hey, Andy. Bob in disguise.

Bob in disguise. Just two questions kind of back relating to the weather. Now, I guess your guidance, Allen that you gave for third quarter/the rest of the year up to now, does that incorporate July weather?

Yes. And so going back, at this point we're not going to change the guidance because of -- if you look at last year 55% of our earnings for the year were in the last two quarters, so there's still plenty of year to go from an earnings standpoint, and also as Gale mentioned, just quite honestly we have uncertainty about what the ultimate impact of this Union Pacific situation is going to be.

Is there something also incorporated in the third quarter for Union, the whole coal situation? Or are you just being cautious?

At this point it's an uncertain situation so we're being cautious. It's kind of hard for me to estimate a number. Because, again, we don't know.

And I missed the beginning of the call. Did you guys quantify that in any way?

No, we didn't.

Because I know you didn't file the 8-K and is there any other background that you didn't quantify that you can give us on that? Obviously it's a short-term item.

We'll ask Rick to give you a little more detail, but when you step back, and think about all the variables, it's almost impossible for the financial models to predict what the outcome might be here. But we want to make sure everyone understands this is not a reliability issue at the moment. Rick.

Yes, Andy, we got a notification on July the 6th that we would receive 80% to 85% of our expected deliveries. Our current inventories are adequate. What we've done to respond to that is obviously set inventory targets that we want to maintain at facilities, adjust the burn by changing the offer price into MISO during off peak times, closely monitor deliveries, transfer some coal between plants to optimize inventory, then make sure we adjust our gas volume forecast and our hedging program to reflect that we could be replacing coal energy with gas energy.

As Gale said it's not a reliability issue it's an issue of adjusting the burn in off-peak periods. It's really too early to estimate what the impact is going to be. It's going to be dependent on market response to this, it's going to be dependent on weather, it's going to be dependent on the performance of the Union Pacific Railroad. So we want to get some time under our belt before we want to step out and say what the impact is going to be.

And, Andy, as you know, we do not necessarily have dollar for dollar recovery of fuel costs under the fuel rules in Wisconsin, and that's why we're being cautious here.

I know you have that 2% band.

Yes.

So I guess some way kind of just to look at it if you just wanted to be conservative is to kind of use that 2% band as the worst case, because after that you can file, right?

Well, it's not quite that--.

Mold your opportunity cost losses by changing the mixture of the coal, having a lower -- I mean, a higher -- higher -- what's the word?

Higher natural gas use?

Btu.

Oh, higher Btu's. All right. Well, as Rick said, I mean, this is a pretty complicated model question. I mean, the first is -- the first uncertainty is we don't know exactly what the coal deliveries are going to be from Union Pacific. That's kind of problem one. Problem two is, we're not great at predicting weather. Problem three is, we are now bidding our units into MISO every hour, and we're in a brand-new market here that started April 1, and it's almost impossible to predict what the market response across MISO is going to be to a shortage of Powder River Basin coal. So again, I think we've taken the appropriate steps to conserve coal where necessary. We don't have a shortage at the moment, and we think it's appropriate to be cautious here until we get through the peak summer months and have a much better feel for whether this really will have any impact.

Thanks. You guys are doing a great great job.

Thanks, Andy, we appreciate it.

You deserve a big pat on the back.

Thank you, sir.

We'll go next to Scott Ingstrom with Satellite Asset Management.

Hi, Scott.

Just a follow-up a little bit on these rail questions. Is -- I assume that the maximum variability comes with extended hot periods in the sense that if you have cool weather it's not going to be so much of a problem, it's not so hard to predict. Is that accurate?

Semi but it's really -- and I'll let Rick opine on this -- it's really more complex than that. Some of the ability to conserve coal is is whether or not you can ramp the units down at night. Rick, would you agree with that?

Yes, basically most of the coal units are base load. So what this means is just in off-peak times, typically at night reducing the load, keeping the coal there for the peak periods and switching over to whatever the next best-priced resource is in MISO. That might be our new combined cycle project. And how much inventory people have across the footprint and what's available for them to bid in in those nighttime periods I think is going to be a big variable. It's hard for us to predict. So yes, weather could have a factor but there's multiple factors across the MISO footprint.

I was just wondering if you could comment on how your experience was with this issue during the most recent extended heat wave?

We didn't see any reduction during the peak periods of coal-fired generation. And at night we adjusted our price. I'm not sure, given the heat that we really saw much of a difference. I think we were up in the combined cycle power during the night anyway.

Last question, are you comfortable talking about what your actual days of inventory are?

We'd rather not get into that. I'd just say we have adequate inventory. We've always been relatively conservative on our inventory and we have adequate inventory right now.

Obviously for competitive reasons we'd prefer not to say more than what Rick has said. We have adequate supplies at the moment.

Thanks a lot.

Thanks.

We'll go next to Paul Patterson with Glenrock Equity.

It's Glenrock Associates. How are you, guys?

Fine. How about you, Paul?

All right. Just wanted to ask you about, first of all, I virtually cut out when Allen started speaking, and I apologize if Allen already went over this but the depreciation number for the quarter went down, in your income statement and I was wondering what drove that and if you could just describe that a little bit, is one question I have, then I have some questions--.

Well, let me start with depreciation, then we can move to your other questions. If you look at depreciation expense in the quarter, it was $82 million in the second quarter of 2004. It's $79 million in the second quarter of 2005, and that's shown on page 4 of the earnings package. Really the driver for that, and you'll remember this from the first quarter of 2004, possibly, Paul, we have to rebalance our nuclear decommissioning trusts each year so by the rules of the commission it has to cross through 60% equity at least once in the year. So we had to rebalance the nuclear decommissioning trust, and that resulted in basically a contra depreciation expense, and that was about a $3.5 million impact if you look at depreciation.

In addition you will recall in the third quarter of last year we took some asset impairments, we wrote down some assets so that reduced depreciation expense. I would say that's probably another $1 to $1.5 million. So you have those adjustments going -- serving to reduce depreciation and then obviously we increased plant in service and that increased but the net of the two is the reduction that you see on page 4.

So about $5 million is sort of unusual depreciation benefit? Is that right?

I would say $4 to -- yes, $4.5 yes, about right.

Okay. Then back to the rate case. What was the ROE at the last 12 months on a weather-normalized basis for the utility?

If you look at the 12 months ended June 30, and look at actual returns at the WEPCO level it was like 11.3% and I guess you would really have to adjust for weather as well as severance because you remember we had some severance costs in the third quarter of last year. I would say if you adjusted for both of those we' probably at 11.5%.

Okay. And then you mentioned the transmission regulatory asset. You're asking for a $70 million recovery. How big is the asset itself and over what period of time are you planning recovery according to the case?

Well, if you look at June 30, we had $140 million asset up on the balance sheet, regulatory asset up on the balance sheet for the deferred transmission costs that Gale mentioned. If we received the $67 million increase for the transmission cost that Gale also mentioned, if we receive that, basically that would just make us current, meaning we'd be collecting enough in current rates to cover the current tariff from the American Transmission Company. So you wouldn't be -- on an out of pocket basis you'd be even, however you wouldn't have anything in rates yet to start bringing down the regulatory asset that's on your balance sheet. So I would still expect that that regulatory asset would grow somewhat over the next couple of years. But only to the extent that you accrete interest. You wouldn't add any new under recovery, if you will.

Why aren't you asking for more recovery I guess and also just, isn't this basically a filed rate doctrine issue? Isn't this basically something that you really should have very high assurance of recovery of now?

Well, certainly the ATC is a federal jurisdiction utility for rate making purposes but they are also a public utility in Wisconsin. So the Public Service Commission of Wisconsin has to approve each and every one of the capital projects of any size, probably anything over about $1 million they would have to approve. So I would expect that the commission has been on board, they've understood the capital that's going back into the business, so, yes, I would feel very good about our prospects to recover these costs.

I agree with Allen, and to your question as to why we didn't ask for a lot more, if you look across our balance sheet, and this is not different than most other utilities in the country, we have a number of regulatory assets and we will work those off in cooperation with the commission over time. We just felt like this was the appropriate level to ask for right now.

Okay. Then also, just back on the -- not to hit this rail thing to death but is there a possibility that you guys could get a -- get with this final -- with your fuel recovery case currently underway, and the final decision, I guess from what I understood, wasn't determined, could you amend that or would you start again at that 2% bandwidth thing if you did find that there was a large amount of expense or what have you? Do you follow me?

I certainly do, and the answer to your question is the commission, by its procedure, will look at all currently incurred costs up to the time of its final decision. So it will incorporate into its final decision and its final order, in other words, whatever our permanent new fuel recovery rate will be, it will incorporate our actual experience for the number of months in which we've had the interim increase in effect and it will also look at a future gas strip price so, yes, we will probably get some reflection of whatever impact has been incurred in the new fuel rate. And again, I don't want us to -- I don't want our cautiousness here to alarm everyone. We think we're being appropriately cautious, but we have solid fuel recovery rules in Wisconsin, and our reason for our caution is that we just -- there are just so many variables right now that it's impossible to predict the impact. But I wouldn't get overly focused on this as some kind of a humongous negative.

Sure. And when is the schedule for them to make their final decision?

At the moment, Larry, end of third quarter? Is that correct?

Yes, this is Larry Salustro. We expect the hearing sometime in August and then a decision sometime in the third quarter.

Do you have a procedural schedule with the regular rate case that you just recently filed not too long ago here, back to the regular rate case that we talked about?

Actually public and technical hearings in October.

Thanks a lot.

Thank you very much.

We'll go next to Doug Fischer with A. G. Edwards.

Just a couple. A lot of my questions have been asked, but just a little clarification. Allen, you gave an approximation of the weather impact versus normal. I know it was a $10 million operating income plus versus last year. I didn't catch what you said your guess was, it was versus normal.

Yes, and let me just take you through that again. You're absolutely right, $10 million was the estimated impact at the operating income level versus last year, but, of course, last year was a bit cooler than normal. So if you look at this year in the second quarter at a margin level, okay, so at an operating income level, we were $4 million better than normal. Last year, second quarter of 2004, we were $6 million below normal, and there you have your $10 million swing, actual to actual. Does that make sense?

Yes. I got a little confused earlier. And have you gotten any reaction at all from the staff or anything as to this filing of this rate case? Because it's different from a cost of service and a straight cost of service. Do you expect them to do a straight cost of service calculation as they look at this whole thing?

Doug, this is Gale. We will have ample room for discussion and reaction from the commission and the staff over the next few months. At the present time they're, because of the newness of the filing, no real reaction at this stage of the game.

I think that's it given the other questions that have been asked. Thanks.

Thank you, Doug.

We'll go next to Michael Lapides with Hibernia Capital.

Real quick question on the balance sheet. You've got a decent amount of short-term debt and currently maturing long-term debt. Just wanted to hear your thoughts on plans for treatment of that.

At the end of June 30, let me just flip to my summary here on short-term debt, we had $83 million worth of short term debt at the parent level, and we had about $165 million, or $167 million of short-term debt at the two utilities combined. Now, you will recall that I said that we did a bond offering at the We Power subsidiary. That was the $155 million offering. So once we completed that offering we went to financial closing on July 21, we actually paid down all of the short-term debt at the holding company, so we have no short-term debt presently at the holding company and we actually have about a $54 million invested cash balance at the holding company. So that's sort of the situation at the holding company right now.

And, obviously, as we spend on Oak Creek through the end of the year, we'll start going through that cash balance, and then I would expect to build up a short-term debt balance again at the holding company by the end of the year. As it relates to the operating companies, or the utilities, if you will, and this is pretty much the normal level of short-term debt that I would have expected middle of the year, it will go up between now and the end of the year as we build up gas storage, but we're kind of in the normal variability range on short-term debt. Does that help?

Yes, that helps. Follow the question just on the transmission side. Just curious what you're kind of thinking in terms of ATC's CapEx over the next couple of years.

Well, I think in terms of their capital spending plan, I've seen for the next ten years, of course, they have $2.8 billion capital spending plan in terms of an annual capital budget it probably wouldn't be appropriate for me to -- it's a separate company. It wouldn't be appropriate for me to talk about their capital spending. But in terms of their impact on us this year I would expect to probably put a $10 or $11 million capital contribution down to them this year to help them support their capital budget. So right now, my total investment in ATC is $191 million, so I would expect that to go up slightly between now and the end of the year with that additional capital contribution.

Okay. Thank you.

Thank you, Michael.

We'll go next to Steve Gambuzza with Longbow Capital.

Did you file for a change in your authorized equity ration as part of your general rate case filings at the utility? And if so can you let us know what the proposed common equity ratio is?

We did not. In the case gas we filed -- I'll just ask Jeff West?

In the gas case we filed for between 53 and 54% equity ratio and on the electric side it was 57%. Those are both on a financial -- on a regulatory capital structure basis.

Okay. On the electric, were you at 57% or were you a little bit lower than that? In your last rate order, which as I know is quite old?

I believe we were a little lower than that.

Exactly right.

Closer to 53%.

53.5, if I recall correctly.

Thank you very much.

You're welcome, Steve. Take care.

We'll go next to Dan Jenkins with the State of Wisconsin Investment Board.

How's the weather in Madison, Dan?

We're happy to see it cooler, but I don't know if you guys are.

No, no, Dan, you don't understand. See, the hotter is better.

I had a couple of things here. Just, first, on your large commercial and industrial sales, I notice it was up about a percent in the quarter, which could reverse the negative change in megawatts from the first quarter. Do you expect that type of gain to continue, or are you seeing an up-turn in the industrial activity?

Dan, that's a good question. What we're really seeing, when you look into the details of that large commercial and industrial category, what we're really seeing is very, very, almost flat, but just slight growth from the industrial customers, where the real growth is coming from is the non manufacturing or commercial side of the business. So large commercial is showing quite good growth and I think we will -- it's very hard to tell as the economy moves up and down, but where we're really seeing the turn is not necessarily across the heavy manufacturing industries, it's really across the larger commercial customers. The other thing that I would point out is we continue to see in our region, and I'm very pleased about this, because I think it's a sign of the diversifying economy in greater Milwaukee, we're continuing to see really good customer growth as well. So the two things that are contributing to the sales growth are just sheer growth in the number of customers, and then a pretty consistent uptick in large commercial.

Would you expect that portion of that large commercial would have then been weather related?

Actually, no. I mean, large commercial customers are not all that weather sensitive. So I do not believe that a lot of that was weather. Clearly in the residential side, very weather sensitive and big in percentage increases as you saw from our news release and our package, in residential electricity used in the second quarter driven by the June weather. But large commercial, not normally very weather sensitive.

Okay. Then on your cash flows, there's about a $70 million decline from the working capital contributing to your lower operating cash flows. Do you expect that to reverse, or what was behind that?

As I mentioned, and you may want to flip to page -- get you to the cash flow statement, page 7, of the package that we sent out, you'll notice that cash taxes that we paid, we paid $100 million worth of taxes on a cash basis in the first six months of 2005, and that compares to $58 million in the same period of 2004. So a very, very big part of the roughly $60 million swing in cash from operations was that difference in cash taxes, and I do expect that to turn around over the course of the year. It's just really a timing difference in the cash taxes. And I think I mentioned on the call we had back in February, somebody asked me what I expected cash from operating activities to be for the calendar year, and I would expect it to be in the $600 to $620 million range for the calendar year.

Okay. What are you expecting for the second half for CapEx now that you have all the approvals for your construction program?

In the first half of the year we spent $315 million, and $208 for the utility, $107 for the coal and the gas units. Looking to the second half of the year, I would expect to spend probably around $500 million in the second half of the year, roughly $300 of that at the utility, and the balance, $200 million, at -- for PTF, for the gas and the coal units. And that's according to plan. I mean, that's right on plan.

Okay. Will you have to raise financing related to that, or do you expect to come to the markets at all in the second half?

I don't expect to do any long-term financing at the holding company, nor do I expect to do any long-term financing at Wisconsin Electric Power Company in the calendar year. At Wisconsin Gas we may do a small long term offering in the fourth quarter.

And obviously no new additional equity.

Right. And then if you could just refresh my memory on the balance sheet, you have a billion of investments and what's -- I imagine your ATC is part of that. What else is--?

Yes, $109 to, well, just look on page 6, $1.21 billion of investments are on shown on the balance sheet. Roughly $750 million on our nuclear decommissioning trust. Roughly $250 of that $750 are the non qualifieds and the balance $500 are qualifieds. So $750 for NDTs and $192 million for American Transmission Company. So that squares up $942 million for you. And candidly the rest of it is sprinkled -- it's like Guardian Invest -- Guardian Pipeline Investment. I mean there are a bunch of other cats and dogs if you will.

Are those other items the kind of things you're talking that you might sell or?

Yes, that's very possible, those types of items.

As Allen said we have a variety of noncore assets which we would certainly consider selling.

Okay. Thank you. That's all I had.

Thank you. Take care.

We'll go next to James Thalacker with High Bridge.

How are you doing, James?

Good. How are you? Actually, Michael Lapides asked my question on ATC.

All right. But you can't come up with another one, James?

Not today.

Take care.

We'll go next to Nathan Judge with Atlantic Equities.

Hi, Nathan. How are you?

Well, it's raining here, Gale.

You're up late. And you're up late, Nathan.

Just a question on the excess budget, or the over budget cuts that you've incurred. What is your intention to recover that? Are you going to address that currently or are you going to wait to the end to look at the overall budget? I'm speaking of Oak Creek coal plant.

Okay. Well, essentially we believe that we can build the plant for the budget approved by the commission plus the 5% cap plus the force majeure costs. That's our current thinking, and our current belief, and we will have discussions along the way with the public -- we already have obviously had discussions. We will have continuing discussions along the way with the Public Service Commission. But they're aware of our current strong belief, that if you look at the approved amount, plus the 5% cap that was approved, plus the force majeure costs that we discussed earlier on the call that we believe we can bring the plant in for that amount. We'll continue to work and talk with the commission along the way to see how we want to cast -- and how we want to make the request for the recovery.

Actually, just stepping back to -- and looking at the industry, seems like it's increasingly likely that the energy bill will be passed. The first question would be to you is, out of the energy bill are there any particular things that Wisconsin Energy would benefit from?

We've done a quick analysis, Nathan, of the conference committee report, the conference committee obviously was debating the differences between the house version of the energy bill and the Senate version, and we now think there is a merged conference committee report coming out. We think there are about four items that would be positive in terms of at least cash impact and we'll let Allen walk through those.

Yes, and there's four. Just real quickly, Nathan, first, I would expect that we could get 84-month, or seven-year tax depreciation on pollution control equipment, so that would obviously be beneficial. The next area is in the area of nuclear decommissioning trust. My understanding is, basically, and I'm over simplifying somewhat but basically you can take and get qualified NDT treatment for all of your nuclear decommissioning trusts so you will no longer have this division where you have qualified and nonqualified trusts. So obviously that would be beneficial from a tax standpoint. We would get faster depreciation for gas distribution and electric transmission. I believe it would go to 15 years in the version that I saw. Finally they would extend the section 45 these production tax credits on renewables, they would extend those I believe to December 31, of 2007. So those are the four areas, if you will, that I would see being potentially beneficial to the Company.

Have you quantified those benefits?

Well, we certainly -- when we were looking at our Washington office at different bills we tried to score some of the benefits, but I -- it's nothing that I would want to put out right now. But what I would say is, I mean, none of these are home runs. There's no significant windfall or anything like that from any of these items. They're all relatively small for us.

But from a cash standpoint obviously helpful.

Just one of the other items in the energy bill looks to be repealed is PUHCA, which some are speculating that within the industry there will be increased M&A transactions and a possibility of increased consolidation. From Wisconsin's point of view, Wisconsin Energy's point of view, what would that transpire for the Company, then perhaps just a broader perspective?

Well, Nathan, I know you're a close personal friend of Warren Buffet, so -- actually, my honest view is that the repeal of PUHCA would have almost no impact on the outlook for Wisconsin Energy. I just don't see that as a major difference for us one way or another, candidly. I really don't.

Great. Just one of the third quarter drivers, third quarter of this year drivers that I thought would have been mentioned, and perhaps I was just misunderstanding, would have been the addition of the Port Washington plant unit. Is there a reason why -- or perhaps I just missed it?

I think you missed it, Nathan. It was mentioned as one of the factors. We would expect earnings contribution in the third and the fourth quarter for that matter from that plant.

I was just checking on that. Thank you very much.

Thanks, Nathan. Hang in there.

We'll go next to John Hanson with Imperium.

Just a quick question here on the deferral replacement power cost for Point Beach, just make sure I understand the process here, now the $18 million, then you deferred $15--.

$15.8.

Some part of that. That deferral is that for the entire replacement power for the outage or just for a certain part?

No, again, we have a number of jurisdictions. We have a Michigan jurisdiction, we have a wholesale business, so basically the higher number we gave you was the total replacement power cost, then we have to break that down to the Wisconsin jurisdiction. So the lower number, I believe it was $15.8 million, is what we deferred for replacement power cost for the longer than expected Point Beach outage for the Wisconsin jurisdictional customers.

Right.

In the second quarter.

Right. I understand the jurisdictional issue. I guess my question is the timing. Is that for the -- just some excess amount for the outage or for the entire outage?

No, that's just for the excess amount of the outage compared to what had been planned. The part that was out of our control, the part that we could not have predicted.

Okay. And that's something that's been done in the past and has worked out okay?

Yes, it has been done in Wisconsin in the past, and -- I mean, we're very pleased. I think the Wisconsin Commission understood that this longer than planned outage was really a factor that we could not have predicted and could not control, and so we did receive approval to defer the amounts on May 27, and, of course, that deferral now will be subject to future audit and future discussions with the commission. It's subject to future recovery, of course.

Then, John, just to be clear, there will be an additional amount that I expect that we will defer in July because I think the unit didn't come to full power until the 16th . So there will be an additional little stub in July, and we'll report on that when we do our earnings call.

This is just through the end of June, the numbers we gave you.

And the place for that discussion to occur on that is in your general rate case or in a separate proceeding?

Likely to be in the fuel case.

The fuel case, great. Thank you very much.

Thank you.

We'll take a follow-up from Paul Ridzon with Key McDonald.

I have another question. Just going back to Point Beach. Is there any concern of prudence reviews or anything? Replacement power?

You're always subject to prudence reviews, but in this case, we think the facts are very, very solid.

And then switching gears to Powder River Basin, some bears out there suggesting that this issue could push into 2006. What's your current thinking and how soon can piles be rebuilt and could this be an '06 issue?

The letter -- I'm going to ask Rick to comment as well, but the letter from Union Pacific that we referred to earlier, really outlined a force majeure event that would reduce our coal deliveries potentially 15 to 20% from the contracted levels through the end of November. Rick?

Yes, that's right. You've hit on a point I think is correct. Is that during the following year there will need to be some rebuilding of inventories, as inventories are burned down below target levels. But it's way too early to predict how long that's going to take and who would be affected. So we'll just have to take a look at that in the future.

And where did you say your piles are at?

At normal levels right now.

Adequate levels?

Adequate levels right now.

Thank you very much.

Thank you.

We'll take a follow-up from Michael Lapides with Hibernia Capital.

What's the trend in the last year, year and a half, from the PSCW regarding other companies that have had GRCs in your state and what kind of ROEs and equity component structures have they allowed?

In the last two major cases, the commission has allowed an 11.5% return on equity, so I believe this would be in the Madison Gas and Electric case and the Wisconsin Public Service case. They were both 11.5%.

And Wisconsin Power and Light as well.

That's right. And in terms of the equity that's allowed, my understanding is 57 -- 56, 57% on a consolidated basis. So that's been the going rate, so to speak, in the last few cases.

Thank you.

You're welcome.

We'll go next to Doug Fischer with A.G. Edwards.

Doug, you're last but not least.

Well, thanks. And it's sort of another follow-up question on something that Allen said that I missed. I guess I'm a little slow today. The investments of $1 billion 750 is nuclear decom, and what were the other two pieces?

Yes, the $750 was nuclear decommissioning. Of that $750, $500 was the qualified trust, $250 was the non qualified trust. So total of $750 for nuclear decommissioning, and then ATC was $192 million. So that gets most of the assets.

And where is the real estate, then?

There's a little bit of WISPARK in this, what would you say, Steve?

Under $20 million.

Under $20 million. That would be accounted for as an investment.

Wispark in total has about $120 million of assets. To the extent they have property, plant, and equipment, that's in property. To the extent they have investments in partnerships, under $20 million is in this line item.

Doug, what may have thrown you off, is you were saying $1.750 billion. I think you may have misunderstood Allen. It was $750.

No, I'm sorry, I had that correct. So Wispark, I was just trying to parse out Wispark. There's $20 million in here. Then there is -- what did you say? How much in--?

Probably another $100 in PPE, property, plant, and equipment.

So the total Wispark is maybe $120?

Yes, $122 actually at the end of June, book value.

Okay. Great. Thank you.

Thank you, Doug. Take care.

That concludes our question-and-answer session for today. I'd like to turn the conference back over to you for any additional or closing remarks.

I think we've had a good call. Thank you so much for participating, and we'll see you again next quarter.

Thank you, everyone. That concludes today's conference. A replay will be available in two hours by dialing 1-888-203-1112, or 1-719-457-0820. Once again, that's 1-888-203-1112, or 1-719-457-0820. Thank you for your participation. You may disconnect.