威斯康辛能源 (WEC) 2004 Q2 法說會逐字稿

Good afternoon, and welcome to the Wisconsin Energy second-quarter earnings 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 second-quarter performance, 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 E. Klappa, Chairman of the Board, President and Chief Executive Officer of Wisconsin Energy Corporation.

Thank you and good afternoon, everyone. We appreciate you joining us on our conference call today to review Wisconsin Energy's second-quarter results. Let me begin by as usual, introducing the members of our management team who are here with me today. We have Allen Leverett, our Chief Financial Officer; Fred Kuester, President and CEO of New Generation. Larry Salustro, our Executive Vice-President and General Counsel; Jeff West, our Treasurer, and Steve Dickson, Controller.

All of us will be available to respond to your questions after our prepared remarks. As you saw in our news release this morning, our second-quarter earnings came in at 32 cents a share, that compares to 42 cents a share for the second quarter of 2003. As you recall from our last earnings call, a refueling outage at our Point Beach nuclear plant fell in the second quarter of this year as opposed to the fourth quarter of last year.

If you adjust for the timing of this expense, we actually delivered slightly higher operating earnings in this year's second quarter as compared to Q2 a year ago. Now, looking ahead to the fourth quarter, we should see a significant pickup relative to last year, since there will not be another refueling outage at Point Beach in 2004. I'm also very pleased to announce that on Monday of this week, we closed on the sale of our pump and water systems business to Pentair for $850 million in cash.

In addition, Pentair assumed approximately 25 million of outstanding debt. The gain on this sale, net of taxes, debt redemption costs, and fees, is expected to be between $1.00 and $1.05 a share, or 120 to $125 million. Now, this is significantly higher than what we projected back in February, and obviously, we're very pleased.

However, the gain on this particular sale does need to be viewed in the context of the significant losses our company booked on the sale and impairment of non-core assets over the past several years. During the past four years, we recorded nearly 90 million in net after-tax losses from those items. In a moment, Allen will discuss the use of proceeds from the transaction, as well as the background on the size of gain.

And now I'd like to update you on the progress of our power of the future plan. Let me begin with our Port Washington project. As you recall, the Public Service Commission approved the construction of two new natural gas fired units at our Port Washington site south of Milwaukee -- I take that back. That is -- my directions are messed up -- that is north of Milwaukee. Each unit will have a capacity of 545 megawatts.

Back in April, the Wisconsin Circuit Court Judge dismissed the first appeal of the Commission's order for the gas units, and that case is now closed. However, the same petitioner filed a second appeal challenging the Commission's reauthorization of our project. This case is pending before a separate Wisconsin Circuit Court Judge.

Although we cannot predict with complete certainty the outcome, it is important to note that the nature of this second appeal is essentially the same as the first. In the meantime, despite a rainy spring, construction on the first Port Washington combined cycle gas unit is now more than 45% complete. We expect the unit to be operational in July of next year and to be completed on budget.

Now in May, we filed an update of the State's capacity and demand situation as required before beginning construction of the second gas unit at Port Washington. Our latest model run shows that the need for capacity is even greater than when the Commission first reviewed the need back in 2002. In June, we received our last coal delivery at Port Washington -- that's nearly 70 years since we first began generating electricity there.

This fall, we will take the remaining coal units out of service at the site and begin preparation for construction of the second gas unit. That unit is scheduled for service in time for the peak season in 2008. Now we'll turn to the status of our construction plans at Oak Creek. Last fall, the Commission approved the building of two 615-megawatt coal-fired units at our Oak Creek site, south of Milwaukee.

The first of these base load units is scheduled to go into service in 2009, the second in 2010. I expect that Wisconsin Energy will own 83% of this capacity, or about 1,030 megawatts, and invest approximately $1.8 billion. As you know, there are legal challenges to the Commission's decision on these projects, and environmental permits that we need to obtain for the Oak Creek project. The authorizations for the coal units are the subject of six appeals, primarily raising environmental issues.

All of these appeals have been consolidated into one single case in Dane County Circuit Court. Briefings in this case are scheduled to be completed in September. We expect to receive initial decision on these appeals from the Court before the end of the year. In a positive development, the Town Board of Caledonia -- and that's the community immediately adjacent to our Oak Creek project -- approved an agreement with the company to mitigate the effects of our new plants on their community.

This primarily involves train traffic and roads. As part of the agreement, the town will drop its appeal of the Commission's decision. Another key step in the process is obtaining all major environmental permits for the coal units. We received the air permit from the Wisconsin Department of Natural Resources in January. As we expected, the air permit is being contested.

Hearings have been scheduled in October, with a final decision again expected in the fourth quarter. We are also working on permits for wetlands and water intake requirements, and on a permit from the U.S.Army Corps of engineers. We expect final decisions on these permits in the fourth quarter of 2004. Now, subject to the insurance of permits and satisfactory process on the litigation, we plan to complete some site preparation later this year and issue a full notice to proceed to our EPC contractor of the Oak Creek site in the spring in 2005.

Turning now to other developments. On May 10, we filed a price increase request for approximately $85 million for our electric and steam businesses. These increases are primarily related to continuing construction of Unit One in Port Washington, and costs associated with the initial work on Unit One at Oak Creek. We're asking that these price increases take effect next year in January of '05.

In addition, in June, we filed a request with the Commission for recovery of $36.1 million of higher fuel and purchase power costs. Like many utilities, we've been experiencing higher gas costs and higher coal-transportation costs. On July 29, we received an interim order for a fuel increase for the full $36.1 million amount that we requested, and that of course is subject to refund pending hearings on the case. And those hearings are scheduled now in early October.

We expect continued pressure on our fuel costs going into next year, with the retirement of coal units at Port Washington and the addition of a new combined cycled gas unit, which will increase our natural gas consumption. The reactor vessel head replacement outages at our Point Beach plant next year will also cause us to burn more fossil fuel in '05 than we did in '04.

And while we have over 85% of our coal under contract for next year, we have experienced rail delivery problems in some instances, and the spot-market pricing for bituminous coal is, as you know, quite high. But a major positive is the fact that 75% of our coal originates from the Powder River Basin, and those prices have remained quite stable. Moving now to our nuclear units at Point Beach. On April 4, we began our regularly scheduled refueling outage of Unit One.

During the outage, we completed a reactor vessel head inspection and we identified a penetration nozzle that needed repair. The repair was completed, the unit returned to service on June 8. As you know, we plan to replace the reactor vessel heads for both units at Point Beach during next year's spring and fall refueling outages. Now, applications to extend the license for the units at Point Beach were submitted in February. Public meetings were held in June to gather the information necessary to prepare a n environmental impact statement.

The meetings went quite well -- attendees from across the state came to voice their support for the continued operation of Point Beach. The license retention process will take approximately 18 to 24 months to complete. Now, with that brief overview, we'll turn the call over to Allen, who has an in-depth look at our second-quarter numbers. Allen?

Thank you, Gale. As Gale mentioned, we earned 32 cents per share for the quarter versus 42 cents in the same period last year. And this includes 17 cents from continuing operations and 15 cents from our water systems business, which has been reflected as a discontinued operation.

I'm going to start my review this afternoon of the earnings by discussing the drivers of operating income, and then I'll move down the income statement to the items below the operating income line. Once we've gone through the earnings for the quarter, I'll provide you some additional detail on cash flow and the sale of WICOR, as well as an update on our guidance for the year. It may be helpful for you to refer to page 8 of the earnings package that we posted on the website this morning, as I make my remarks.

On a consolidated basis, our operating income from continuing operations was down $20 million for the quarter. Operating income for our utility energy segment was $74 million this quarter, which is down 17 million from the second quarter of 2003. The decline in operating income is primarily due to the timing of our nuclear refueling outage this year as compared to last year.

In 2003, the refueling outage was in the fourth quarter, while in this year it fell in the second quarter. Our nuclear O&M costs were $21 million higher in the quarter as a result. Earnings were also reduced by higher fuel and purchase power costs, higher benefit costs and lower litigation recoveries. A net reduction in fuel and purchase power cost recovery was a $6 million drag as compared to the second quarter of 2003.

This is the result of several factors, including a 5% increase in megawatt hour sales, the impact of higher natural gas prices, and higher coal and purchased power capacity costs. Somewhat offsetting the increased fuel and purchase power cost was the higher availability of several of our coal-fired generating plants. Higher benefit costs also resulted in a $6 million reduction in earnings, and lower litigation recoveries in 2004 also hit earnings by $6 million.

In the second quarter of 2003, we received a settlement of a claim related to the Giddings & Lewis litigation. Together, nuclear outage expenses, fuel and purchase power costs, higher benefit costs and lower litigation proceeds reduced operating income by $39 million. On the positive side, we had two items that increased operating income for the quarter.

Sales growth added $11 million to operating income, and also our bad-debt expenses were $8 million lower during the second quarter of 2004, as we received approval to defer residential bad-debt costs in excess of the amounts included in base rates. Together, these two items added $19 million to operating income as compared to last year. Netting the impacts of the drivers I just reviewed, along with a net increase of $3 million associated with other items, brings you to the $17 million decrease in the utility segment's operating income.

Our non-utility segment recognized 1 million of operating losses in the second quarter compared to 2 million of losses in the same period last year. Corporate and other operating income decreased $4 million in the second quarter. The primary driver of this decrease was the fact that we were able to capitalize $3 million of comps associated with the Port Washington lease in the second quarter of last year.

We did not have a similar item this year in the second quarter. Taking these three segments together brings you back to the $20 million decrease in operating income for the quarter. Other income for the second quarter was $10 million, or 3 million less than 2003, and this was primarily due to lower earnings on other investments. Financing costs were down $5 million in the second quarter. Lower average rates from [INAUDIBLE] associated with the redemption of $200 million of trust preferred securities at the Wisconsin Energy level, was the key driver in this decrease.

Taxes were $4 million lower relative to last year. Our second-quarter 2004 effective tax rate for continuing operations was 36.7%, as compared with a tax rate of 31.1% for the same quarter in 2003. For the full year of 2004, I expect that our annual effective tax rate will be approximately 37.5%. Net income at our manufacturing business, which was accounted for as a discontinued business during the second quarter, was $18 million, up 4 million from last year.

Adding this to the income from continuing operations of 21 million brings you to our 39 million of net income for the quarter versus 49 million last year. Now let me take a few moments to go over our cash-flow picture. During the first six months of 2004, we generated $494 million of cash from continuing operations. And this was $132 million better than the same period in 2003 and reflects improved collections and the favorable impact of gas removed from storage in the first quarter.

Through the first six months of 2004, we repurchased approximately 1 million shares in of our common stock at a total cost of $31 million. Our financing plan calls for an additional $19 million in share repurchases this year. In addition, we are using cash to satisfy any shares required for our 401-K plan, options, and all other programs. Going forward, we do not expect to issue any additional shares.

On the use side, we spent $255 million in capital expenditures during the first six months of 2004, with $173 million dedicated to our utility business and 74 million for our Power of the Future construction expenditures. In addition, we paid $49 million in dividends. And as I mentioned in March of this year, we redeemed 200 million of trust preferred securities. At the end of the second quarter, our debt to capital ratio was 63.1% as compared to 64.4% at the end of the second quarter of 2003.

I expect that our debt to total capital ratio will be below 61.5% at the end of this year. So as you can see, we've made significant progress in strengthening our balance sheet. As Gale mentioned, we now expect to book a net gain of $1.00 to $1.05 per share on the sale of our pump and water systems business. Our previous guidance for the expected per share net gain was 15 to 20 cents per share.

And I believe the easiest way to understand the change is first to explain what has not changed since February, and then move to the key change that has occurred since we gave our initial guidance back in February. The upfront net cash proceeds are still approximately $740 million. Now this reflects taxes and direct selling costs.

Of this amount, $50 million is being used to repurchase common stock, $200 million to redeem trust-preferred securities, $300 million to repurchase long-term debt; 175 million to repay short-term debt; and $15 million after-taxes for premium on the long-term debt tender that expires at midnight tonight. All of this is consistent with our initial guidance that we gave to you in February.

However, we have now structured the transaction in a fashion that allows us to increase the tax basis of the Wisconsin Gas assets that are being transferred from WICOR to Wisconsin Energy as part of the trans transaction. For book accounting purposes, this step-up creates a deferred tax asset, which effectively offsets the impact of the cash taxes paid on current income. This is the driver for the increase in the gain on the sale.

Going forward, over the next 20 years or so, we will get the cash benefit of being able to depreciate the additional tax bases. In present-value terms, this is worth about $50 million at current tax rates. So I believe what we've accomplished is to make what was already a good transaction even better for our shareholders. The final item that I'd like to cover is our earnings guidance for 2004.

We are updating our earnings guidance for 2004 now that the sale of our water systems business is complete. For 2004, our guidance for operating earnings is now $2.28 to $2.38 per share. This includes water systems' earnings through the end of July, but it excludes the net gain of $1.00 to $1.05 per share we expect to record on the sale of the water business. Note that this gain figure is net of taxes, debt redemption costs, and all sales costs.

I am including in this net gain the 3-cent charge we booked for the redemption of the trust preferred securities in the first quarter. So, again, our updated guidance for operating earnings for 2004 is $2.28 to $2.38 per share. On a GAAP basis, we expect our earnings for 2004 to be $3.28 to $3.43 per share. So with that, I'd like to turn it back over to Gale.

Allen, thank you very much. Before we take your questions, I'd just like to mention that Wisconsin Energy recently was named the 2004 winner of the electric power industry's highest honor, the Edison Award. This award recognizes electric utilities that have made a significant contribution to the advancement of the industry.

In our case, EI recognized our innovation and leadership in expanding the markets for coal combustion products. We're honored to receive the award. And now, with Thomas Edison smiling down from on high, we will be happy to take your questions.

Thank you. Ladies and gentlemen, if you would like to ask a question at this time, you may do so by pressing the star key followed by the digit 1 on your touch-tone telephone. Again, star one for questions or comments. If you are using a speakerphone, please make sure to pick up your hand set or disengage your mute button to make sure that your signal reaches our equipment. Again star one; and we'll go first to Paul Paterson.

Hi, can you hear me?

We sure can. How are you, Paul?

All right. How are you doing?

Pretty good.

I was wondering, I might have missed this and I apologize if I did. What's the impact on weather for the quarter?

The impact -- well I'll let Allen answer specifically. The impact on weather is about zero compared to the second quarter of 2003. Very mild weather in both quarters. Allen?

That's exactly right. So quarter to quarter, it's almost no weather impact. I think versus normal weather, which is probably the other, uh, question you'd have, would be about $14 million on revenues versus -- if we had normal weather, we would expect another 14 million, uh, of revenues. But again, as Gale mentioned, if you go and look back at actual 2003 -- actual weather quarter to quarter -- not that different. Cool both quarters.

It has remained cool. We have not had a 90-degree day so far in July or August. I think someone just told me it was 63 degrees by the lake, but it is sunshining.

Okay, great. Decommissioning -- the new decommissioning fund, was there any benefit this quarter from that?

No.

Okay. And then in terms of the bad debt deferrals. I assume that just goes into rate base -- or is there some balancing account and you guys get recovery of that, you know, next -- how does that get recovered, I guess.

It gets put on the balance sheet as a regulatory asset and then it'll just be subject -- it'll be included as a subject in the next rate case.

Okay. Great. Oh, and by the way, the other -- the net present value of the $50 million in terms of the -- the tax benefit that you were able to do, um, with the -- with the sale, what I was was wondering is, how does that flow through in terms of actual -- you know, when will we get the impact, I guess, of that -- that -- that benefit? I mean, you guys have an after-tax benefit, and how will that lower, you know, capital costs, etc., going forward?

That -- In effect, I mean, you step up the basis, you create this deferred tax asset, you unwind that deferred tax asset over the next 20 years, you know, basically according to the -- you know, the tax depreciation schedule that you would typically see for, you know, the gas utility, which is probably a 20-year makers. So you will see this unwind, this cash benefit, each year for the next 20 years. Next year, Paul, I would estimate, you know, back of the envelope, that's probably about a $4 million cash benefit.

Okay.

Okay?

I got you. Thank you very much.

And again, that will flow over 20 years. The depreciation of the tax asset will be done over a 20-year period, roughly.

Okay. Great. Thanks.

Thanks, Paul.

The next question comes from Andy Levy of Bear Wagner.

Hi, Andy.

Hey, guys, how are you doing?

Doing good.

I just want to understand something. For the year and also for the quarter, if you were to back out discontinued ops, what would the guidance in the quarter -- quarterly number be?

The guidance in the quarterly number, Andy?

The guidance or the actual, Andy?

No, no. For this quarter, if you backed out discontinued ops, what -- what was your operating earnings? And also for the year, if you backed out discontinued ops, what would your guidance be?

Give us a second, we'll be able to put that together here.

Well, income from continuing operations, so that would be totally without the -- the --

Water.

The pump business. Would be about $17 million. I'm sorry, 17 cents a share.

That's for the quarter or for the year?

That's for the quarter.

Okay. And for the year?

86 cents from continuing operations for the -- for the year. The first half --

First half of the year.

86 cents?

Eight-six. Yes, eight six.

So your guidance of 228 to 235 would be reduced by 86 cents?

No, no, no, no.

Go through the numbers again, Andy. If you go back and just look at the second quarter from continuing operations, we earned 17 cents a share.

Right.

So that -- just throw out the pump business, just 17 cents a share.

Okay.

If you go and look at the first half of the year, again from continuing operations, we earned 86 cents.

Okay. I'm sorry.

And then we're saying our guidance for the full year, absent any future earnings from the -- from the pump business, is 228 to 238.

So how much did you earn in the first half of the year from the pump business?

So from the pump business in the first half of the year, we earned 22 cents.

22 cents. So if you want to kind of do apples to apples, just on operating earnings, 228 to 235 you back out about 22 cents?

Yep, that's fair. But again it's 228 to 238, not 235.

Yeah. But remember, also, we're getting interest benefits because we're paying down debt --

Right.

Okay.

-- with the proceeds.

And that'll be in the second half of the year?

Well, some of it's already occurred because we -- we called the trust preferred.

How much do you think on the interest side you'll be saving this year?

Well, it's roughly -- the average rate's about 6% of the debt that we're taking out.

Okay.

Short-term debt cost is about one.

Quarter.

So about six% on $660 million, Andy. So --

Okay.

About 40 million of interest, if you had that for a full year, and you basically got that for three quarters of the year, so it's about 30 million pre-tax, which would be about 18 or 19 million after tax.

Okay. And, um, as you look -- any comments on next year, 2005, or is it too early for that?

Little bit too early for that, but we're working on it.

Okay. Thank you very much, guys.

Take care.

We'll go next to Dan Jinges, State of Wisconsin Investment Board.

Hi.

Hi, Dan, how are you?

Pretty good, how about you guys?

Are you warmer in Madison?

A little bit, but not much. Um, I wasn't able to write down -- you went through what the proceeds -- what the disposition of those were going to be, I wasn't able to get it all down.

Okay. We'll be -- we'll be happy to -- Allen will give the detail. We start with 740 million net after-tax proceeds, and we'll go from there.

Right. And then the first step -- again that's -- that's after-taxes and direct-selling cost, Dan, so you start with 740. Then we use 50 million of that to repurchase common stock; 200 million to redeem trust preferred; 300 million to repurchase long-term debt; 175 million to repay short-term debt; and then finally, about 15 million after-tax for the premium that I would expect to have to pay on the long-term debt tender.

Okay.

So if you add that up, you come back to the -- to the 740. So almost all of this is being used to pay down debt, is really the -- the short answer.

Okay. Have you done that tender yet, or is that still to come?

The tender, Dan -- the tender expires at midnight tonight, so I would expect to go to financial close tomorrow on the long long-term debt tender.

Okay. Um, I noticed on your -- your cash-flow statement, um, you had quite a benefit from working capital --

Uh-huh.

-- this year versus last year.

We haven't -- we'd be happy to have Steve Dickson, our Controller, explain that do you to you, Dan.

Yeah, Dan, if you go back to the first quarter, um, the lion's share -- about 110 of the 130 million -- relates to -- took place in the first quarter. And what happens is, as you know, in Wisconsin, at the end of December, we have gas in storage, and then we pull that out in the first quarter to heat. What happened is, we were able to pull out more gas in storage in the first quarter this year, and so it was a non-cash item. But that was all in the first quarter of this year. The impact on the second quarter was about $20 million.

Okay. Um, is that a normal seasonal effect you get from that, or -- ?

Yeah, pretty much.

You didn't expect a negative effect maybe in the third or fourth quarter, then or --

Well, what we're doing is we're injecting gas in storage in the second and third quarter, so yeah, that will be a use of gas. But it should be comparable to last year.

Okay. That's all I have, thanks.

Thank you for your question.

We'll go next to Neil Stein with John Lemon and Company.

Hi, good afternoon.

Hello, Neil.

Just a couple of questions. First, could you summarize for me some of the additional rate actions you need as the Power of the Future projects begin operation over the next few years?

Sure.

That you need the Commission to do?

Sure. We'll be happy to do that. And I think the best person to give you the detail on that is our General Counsel, Larry Salustro. Let me turn the mike over to Larry. Larry?

Neil, we have, uh, pending now a request at the Public Service Commission for, um, $85 million, which is a -- 4, 4.5% in increase. And if that is approved, it would be effective in January 2005. Thereafter, um, as we continue to pursue these projects and we continue to invest, the additional request that we would have would be included in the regular rate-case cycle, the next one of which would be effective January 2006 under the regulation that we have right now.

And, um, let's see. What were the 85 million be for specifically?

Um, it's for a number of things, but the majority of it is for the investment that we've made in Port Washington. The Port Washington power plant. There are other items in there, but that's the majority.

And then --

Also for -- as Larry pointed out, the majority is for the continuing work at Port Washington. Also, a small piece of it would be for the initial work at our Oak Creek coal site.

And as you move forward and you make these requests, would it be for capital you've already invested as opposed to capital you'll be investing prospectively?

Well, under -- under the way the particular law works in Wisconsin, basically, we get cash carry of the construction costs on these plants that have been approved. So we would -- we would basically file a -- you know, what we will call a carve-out request, specifically focused on the carrying costs of the construction. And then the Commission would take a look at that and we would probably have one of those annual carve-outs each year.

Apart from the normal rate case?

It is forward looking.

And those carve outs are apart from the normal rate-case cycle?

That is correct. Although, we do have -- and I'll let Larry speak to this. I mean, we do have -- under the current agreement with the Commission, we do need to file some form of general rate case in the second half of '05 for new general rates, our new base rates, that would be put into effect January 1, '06. So I would suspect that our -- that would normally be a carve out would be included in that second-half filing. Larry?

Neil, the carve-out terminology and the procedure comes from the fact that we have a general rate freeze subject to certain exceptions that we've had since, I think, 2000. 2005 is the last year of that rate freeze. And beginning, um, for rates effective in 2006, we would return to the regular rate-case cycle, which is filing every other year.

Oh, and then carve-outs won't be required then?

No. That's right. Carve-outs would not be required, um, because the rate freeze from which things are carved out. Or -- Yeah, doesn't exist anymore. So we would go back to the regular rate-case cycle.

Okay. And then just moving on. Any update on coal hedging? Gale, you made some comments on the last conference call on that topic?

I'm sorry, you cut out, we did not -- can you ask your question again, please?

Yeah, just an update on coal hedging. On the last conference call, you made some comments about some cost pressures, uh, on contract renewals going over the next year or so.

Right. We do have the lion's share of our -- of our coal needs for next year under contract. I'm going to ask Rick to give you kind of a breakdown of what he's seeing in the coal markets. We mentioned in the -- in the script that we are going to see some continuing pressure on our fuel clause, in part because we're going to be burning more fossil fuel next year than we did this year in light of our two outages at Point Beach next year compared to one this year and in light of the fact that the 70-year-old coal units at Port Washington are being retired to make room for the construction of the second unit at Port Washington. And then of course you have the general pressures on the coal markets themselves. Rick?

Okay. If you look at -- thank you, Gale. If you look at next year, we're in pretty good shape, as Gale mentioned when he went through the original earnings call, in terms of having coal under contract for next year. Our coal contract start to fall away in 2006, where approximately 38% of the coal that we use will need to be -- we will need to put new contracts in place for 2006 -- and we burn about 12 million tons per year. And then by 2007 we'll have to replace -- we'll have to buy about 90% of the coal -- or establish contracts for about 90% of our coal. In other words, we have about 10% of our coal for 2007 under contract. We are seeing volatility in the coal markets, mostly in the bituminous coal. Most of our coal we purchased from Powder River Basin, and we would expect to continue to purchase from Powder River Basin over the next several years, at least throughout -- out until 2009. So we -- we're not seeing the volatility in our primary source that we are seeing in bituminous coal. We purchase right now about -- right now, somewhere around 12% of our coal is bitombnous coal. So I would say in the next year, we'll look in pretty good shape, we'll start to see some more pressure in 2006 in terms of price of coal; and then 2007 we'll have to replace a pretty good portion of our coal contracts. However, to reiterate what Gale says, we'll be burning more gas next year -- we've got two longer nuclear outages to replace reactor vessel heads and retiring some smaller units at Port Washington to start construction. So we will see increased pressure on the fuel next year -- not so much from the price of coal, but just the change in newel mix.

And have you been having any problems with the rails?

We've had some problem coming out of Colorado, not -- not out of Powder River Basin, but we've burned some -- about 7% of our coal is Colorado coal. We've had some delivery problems there. And we've had to replace maybe three -- 300,000 tons, something like that, with some -- some higher spot-price coal, but, you know, 12 million ton burn per year, that's relatively minor.

Okay. Thank you very much.

You're welcome, thanks for your question.

And we'll go next to Paul Ridzon with Key McDonald.

I had a question on the seasonality of WICOR earnings. Was this a particularly strong quarter or is this following the usual seasonality?

This really follows the usual seasonality. Uh, the WICOR -- the -- WICOR earnings, the -- the earnings from the pump and water systems business, uh, very much are front-end loaded into the early spring-selling season. So we didn't see anything abnormal this year in the profile or -- of WICOR earnings compared to a year ago. Basically exactly what we expected.

Thank you.

Thank you.

We'll return for a follow-up from Andy Levy with Bear Wagner.

Hi, just one more quick question.

We confused the heck out of you, Andy, did we?

Yeah. Just going forward, just -- you know, I mean I understand there's a lot of stuff that Rick's talking about and all that, but just for base earnings, as you know, we grow 2005, should we be using like a 210, 220 range, is that kind of --

Let Allen -- Allen can walk you through the specific math. I think we've got you real curious.

Maybe a better way to think of this is -- you go back to our original guidance for 2004, if you'd never had the WICOR sale, you know, nothing, just -- the business as configured before the sale of WICOR -- what we said was our range was 233 to 243. Then we said that if you strip WICOR out for a full year and then took into account the share-repurchase program that I mentioned, as well as, you know, sort of annualized the interest-cost savings, you needed to take somewhere between 13 and 15 cents off that 233 to 243 if you're going to get sort of a full-year, you know, net impact of WICOR going away and make ing the changes in the -- in the capital base that we talked about.

So that would be full-year '04 without WICOR, but with some interest benefit.

Right. And then if you want to roll forward to '05, I mean you'd have to put on top of that some utility growth and put on top of that the fact that we'll have a half a year contribution from Port Washington Unit Number One next year. And then you could build up your -- your '05 number from that. Is that -- is that a little more clear?

I think so. But -- I mean, so you're saying your base earnings, getting -- you know, 1, 105 and as we get into the end of '04 we should be using about a 230 type number to grow off of, is that correct?

That's not what I said. Um, what I said was that you take WICOR -- if you configure the business with WICOR, my '04 base would have been 233 to 243. Then if I take off of that WICOR for a full year and the -- and the positive benefit from a share repurchase and debt redemption, you take out 13 to 15 out of that range, and so you do that math. I mean, that new range effectively is the base for -- for '04, if you will.

The bottom end of that range is, like, 218.

Okay. I got it. Thank you very much.

Okay, Andy, thank you. Appreciate your patience.

We'll go next to Michael Peach with Hibernia South Coast.

Hi, guys. One quick question -- actually, I apologize, two questions. One, um, can you all give a little bit of insight in terms of the rate case that's coming up, that'll be effective January '06? Specifically, are you concerned about a potential rate reduction due to the substantial other rate increases that are occurring in Wisconsin for the New Generation? Um, that's the first question. And, second, could you just give the actual timing for the nuclear refuel outages during '05?

Sure. I'd be happy to handle those for you. First of all, in terms of any particular insight related to the '05 rate case, again we will not be making that filing until the second half of 2005. Uh, really, way too early to give you any sense of how that rate case might turn out. Uh, probably the earliest we'll file is May of 2005. You know, lots of variables in the case, but a couple of things I think to take into account. We have had a rate freeze, as Larry said, since the year 2000. Clearly, as with virtually every other corporation in America, health care costs have increased significantly, uh, you know, interest rates on the rise compared to where they were, you know, in the early -- in the earlier years. There are lots of -- there's lots of costs that the Commissioner's going to have to take a look at. But we don't see anything particularly unusual about the case, other than the company hasn't had one in about four years. In addition to that, there have been other -- one thing you may want to take a look at, the Commission has here in Wisconsin been through at least two other base-rate cases from other Wisconsin utilities in the last 12 months. And the way they've adjudicated those cases, I think gives you a sense of how they're looking at the issues related to any normal utility here. So that's about I think -- and Larry's shaking his head yes. I think that's about as much insight as we can give you at this point in time. And then the second question, Rick, if I remember correctly, the second quarter and the fourth quarter of next year in which we will have the -- the units at Point Beach out for refueling. And as we mentioned, we are also planning to replace the vessel heads on both units during those refueling outages. I hope that's helpful.

That's very helpful. Thank you.

You're more than welcome.

We'll go next to Madula Merdy with Lucas Partners.

Madula, how are you?

I'm doing well, thank you. Good afternoon.

Good afternoon to you.

A couple of things. One, you talked about the amount of coal that needs to be contracted, and you indicated about 12 million tons in 2006, and you said a substantial portion for '07. I'm wondering, can you give us the quantity for '07, as well as '06, and then can you divide those between the Powder River Basin amounts and the non-Powder River Basin amounts?

Madula, we burn about 12 million tons annually.

Okay.

All right. And we'll have to recontract for 38% of that in '06 --

Okay, I apologize.

90% in '07; and over 75% -- over -- over 80% in those years will be Powder River Basin coal.

All right. So just to make sure I've got the math here right. That the 12 -- 38%, that means [INAUDIBLE] 4.6 million tons, and then the difference would be -- is it about -- by -- for '07, you have to do 90% of 12 million?

Yes. Between now and then, we will be -- we will have our contracts expire such that we'll have to, um -- we've got price exposure to 90% of our coal for that year.

Okay. But the actual quantity by the time you end '06 going into '07, how much needs to get done?

Quantity's about the same over the years.

Okay. So about another 4.6 million the same time?

Four to five million a year.

Okay.

The quantities of coal we burn won't change until [INAUDIBLE] comes on-line the latter part of the decade.

Okay, so the average 4 to 5 million of the year and of that, you said 80% is Powder River?

We average 12 million a year, without replacement. Replacement is -- yeah, you're right. You're right.

And 80% of that 4 to 5 each of those two years will be Powder River Basin.

Roughly, roughly.

Okay, secondly, in terms of the $85 million filing, previous to Power of the Future, you would have annual carve-out filings for items that were excluded or permitted outside of the rate freeze. I'm wondering, outside of the Power of the Future items, are there any amounts that kind of relate to those kinds of items in the -- in the rate filing?

Madula, by and large, no. We did have in a prior year, uh, in our gas business, we -- we had constructed and completed a major -- a major lateral that connected us to another pipeline source coming up into Wisconsin. That, for example, was the subject of a considerable amount of a carve-out a year ago. But -- but by and large, no, nothing like that going forward and nothing like that in this particularly current filing.

And as I recall, I think the Wisconsin Gas had gotten a rate increase I think last year or early this year, will there be any rate activity at Wisconsin Gas, um, for 2005?

None that is planned at the moment, not -- not in advance of the -- of the filing in May of '05.

Okay. And one last question. If we're looking ahead to the fourth quarter, um, here in the second quarter you had $21 million of nuclear O&M and $6 million of fuel costs relating to the Point Beach outage. How does the fourth-quarter numbers compare to what we've just experienced in the second quarter that would kind of reverse out?

Well, I think the one thing you can certainly look at -- again, the purchase power piece will move around, depending upon weather, depending upon demand, depending upon how the units are running; but we can give you a good sense on the -- on the nuclear O&M. I mean, a good chunk of that 21 million was specifically related to the outage. So I would say -- you know, 16, 17 million of O&M that occurred in the second quarter of this year will not recur in the fourth quarter. So we should get -- we should get at least that much pickup.

Okay. I guess maybe what I'm asking here is that if we were looking at the fourth quarter of '03 in a similar table when you would have looked at the adjustments you would have had a negative delta for nuclear O&M relating to the outage.

Correct.

Would that number have been greater than 21 million, comparable, less than 21 million? That's -- I'm just wondering whether that kind of number's available.

Madula, if you look at last year's nuclear refueling outage, it was shorter than the one that occurred in the second quarter this year, because remember, we had to repair a nozzle in the vessel head. And that extended the outage. So we would have experienced more nuclear O&M in the second quarter of this year than we did for the refueling outage in the fourth quarter last year. That's why I was guiding you toward that 16 to $17 million number.

Okay. I just want to make sure we were talking apples and apples. Thank you very much.

Am I making sense, Madula?

Yes, you are.

Great, thank you. We'll go next to Jessica Rutledge with Lazard.

Hi, a couple of more quick questions. First, back to the coal issues. How many dates of inventory do you have at your coal plants these days, given those rail issues that you experienced?

We keep about -- about 45 days worth of inventory and we may be slightly below that ;but the rail inventory -- I mean the rail issues have -- have, again, just -- makes for a small percentage of our coal, and that has not been a significant factor in our inventories.

Okay. So 45 days is just your standard operating procedure?

Right. Right. I mean, it fluctuates throughout the year. We start at had a 45, it goes up and down, we build up for the winter and then -- and then go down. But the rail deliveries has had a minimal impact on our inventories.

Okay. And what you were saying about continued pressure on the fuel clause next year, I wanted to sort of take this back to that 3% band that you have before you get to go out for collection, um, I'm assuming you're probably also pretty close to the low end of that fuel band this year. So if we're just looking year-over-year, should we just assume you're at the low end of the fuel band both years at the utility?

Well, that's a good question, Jessica. Let's back up for a second. Uh, in order to file a -- for a fuel clause recovery increase -- in other words, in order to file for an in increase in your fuel recovery rate -- you have to -- you have to basically pierce the band.

Right.

And we -- we believe we pierced that band, uh, just a couple of months ago, and that's why we filed for the $36.1 million annual increase in fuel rates that the Commission gave us the interim order for just a few days ago.

Uh-huh.

Um, so we have to -- in order to give you -- I'm not trying in any way to not answer the question, but we will collect roughly 5/12ths of that 36.1 million in the remainder of this year; and then, you know, how -- how we look against the band in early next year is really going to determine -- is going to be determined an awful lot by weather early in the year, and by how well the units are running. But, you know -- and our system here, uh, you get into gas after about 4,000 megawatts of demand. It weakens your hydrocoal and nuclear -- we can serve about 4,000 megawatts of demand very cost effectively.

Uh-huh.

Then we get into gas. So it's very difficult to project unless you're good at predicting the weather. So we've -- we really can't give you at this stage of the game exactly where we're going to start the year in that band of fuel-cost recovery. But I think the very good news is that this Commission understands how volatile fuel prices can be and what effect that can have on a company, and they've been very responsive under the law to our requests when we've had to have one regarding increases in fuel-cost recovery.

So that's -- that's certainly reasonable. Just -- for our benefit as we track this. Is there some -- I don't know, either aggregate fuel cost or some reference, gas or coal price, that we should be watching to figure out when you're going to be getting back to a level where you need to request more collection -- or what's going to be pushing you back to the edge of that band?

I wish it was that simple, Jessica.

Yeah, I know. Never is.

We can't just look at one number, but one number Rick and I look at an awful lot -- well, two numbers we look at an awful lot, uh, you know -- 12-month strip and spot-gas natural gas prices --

Uh-huh.

-- which actually have improved lately.

Uh-huh.

And the other thing we pay an awful lot of attention to, because we have a lot more affect on it on management, and that's our -- our forced outage rate at the plants. And Rick's done a really good job, and his team, and our forced outage rates have really been moving in the right direction. Our coal units have run well this year.

Do you expect to see continued improvements in the forced outage rate into next year?

Rick's very conservative, but it wouldn't surprise me (laughter).

All right, then.

He's shaking his head at you Jessica.

Oh, no. Come on, Rick, you can do it. Thank you very much. I think that'll do it for me.

You're welcome, Jessica.

We'll go now to David Smith with Smith Barney.

Good afternoon, guys.

Hey, David, how are you?

Very good, thank you. Just on the WICOR deal. Can you give us a sense of how much you're going to lose in sales on that for the first half? And kind of what we should have been thinking of in terms of margins on that business?

Well, the annual revenues are roughly 750 million from the -- from the pump business. So -- On an annual basis, we would lose -- on revenues about 750 million. Margins -- Mr. Dickson is looking through his material right now and he can probably give you a better sense on margin. Again, what we've said in terms of net effect, is about 13 to 15 cents a share on an annual basis for earnings per share less going forward because of the absence of the pump and water systems business.

Pump and water. Okay. What kind of growth rate were those revenues putting up?

5% to 7%.

Okay.

[INAUDIBLE]. David, for the -- for the six months, um -- and what we have done in the press release is we've stripped out the -- the pump company and the discontinued operations -- but for the six months, their operating revenues are about 417 million; and again, those are stripped out of the -- the revenues on the income statement, that's buried within the -- the line item, net income from discontinued operations.

Okay.

And their pre-tax income was about 43 million for the six months and last year, it was about 39 million. But again, all that is -- is a -- condensed into the one line item -- net income from discontinued ops.

What would the revenues in the prior year have been on the 417 this year?

It was about 384 million.

Okay. That sounds great. You mentioned seasonality in there. Do they tend to be kind of like a 60/40 split in the first half to the second half?

Probably closer to 65/35.

Okay.

Again, the spring-selling season, uh, is a very big time of the year for pumps and water handling systems. So generally -- and that's why we're saying -- if you look at our -- our guidance now and what we've done with our range for the second half of the year, the range has come down at the top end and bottom end about a nickel.

Right.

Because the -- because the earnings are front-end load loaded in the year on that business.

Okay. Great. What kind of D&A does that have for the year, would they get?

D&A really isn't that significant. I think it's, um -- I think it was about 23, 24 million is what their D&A is on an ongoing basis.

On a yearly basis?

Yeah.

Okay. Great. Thanks a lot, guys.

You're welcome, take care, David.

We'll go next to Ashar Khan with SAC Capital.

Good afternoon. Gale, I might have missed this in the beginning, I apologize, but did you mention in any of the questions what the ROE, the regulated business is earning, the electric business?

We will be happy to look that up for you if we have it in the room, but we did not mention it in the script. We are looking here to see if we have it in the room.

On the electric side, the -- the rate of return is 11.6%. And that's through the end of June.

I don't know if you heard, Jeff. He's saying that the achieved ROE on the electric side of the business for the first half of the year, 11.6, 11.6%.

I appreciate. And can I just ask, Gale or Allen, when would you come to the Street with your '05 forecast?

Good question. We'll probably come to the Street with our '05 forecast at our year-end earnings call when we give you our -- when we give you our year-end earnings. That's pretty much the way we've done it and the way we plan to continue to do it.

So that would be February of next -- early February.

Very early February. Late January or early February.

I appreciate. Thank you very much.

Thanks for your question, Asher.

And ladies and gentlemen, we will take our final question from Madula Merdy with Lucas Partners.

Hi, Madula.

Hi. One last thing in terms of the regulatory proceedings on, um -- for the rates. Can you update us on -- just in terms of the milestones, you know, staff and all the processes leading to the final decision, probably in mid-December or whatever that is?

I will ask Larry if he has any idea yet what -- what specific process or milestone dates the Commission would use. Larry?

Well, for the -- for the carve-out case, we have yet to have hearings. We expect to have them probably in October. And then although the Commission in the past has attempted to have whatever rates they decide -- whatever rate changes they decide effective in -- in January, um, that's not -- that's not statutory. But that's what they try to do, so we would use that as the most likely effective date this time also.

Does that mean the staff recommendation would be before the hearings in September?

The way they do that, the staff will make its recommendation during the hearing process. Um, and then we go through -- we continue through the process, and then the Commission makes its decision at the end.

And then the same -- same schedule for the FOC purchased power?

Um, the -- the fuel hearing -- it generally will be in the fall also. Um, so I think you can -- I think you can say that they will be running together -- not literally together, but, um, October -- Octoberish. Um, that fuel recommendation is a little -- fuel case -- is a little different to the extent that we're already collecting those rates on an interim basis, subject to refund. So if it goes a little shorter or a little longer than January 1st, it's -- it's less -- you know, less important, because we've been collecting subject to refund in the meantime. Carve-out case, we're not authorized to increase our rates until the Commission issues its final order.

Thank you very much.

Thanks, Madula.

And ladies and gentlemen, that concludes today's question-and-answer session. At this time, I'd like to to turn the conference over back to the speakers for additional or closing comments.

Thank you very much. If there are no other questions that concludes our conference call for today. We really appreciate your support and your participation. If you have in additional questions today or down the road feel free to Colleen Henderson. She's available in our Investor Relations office at 414-221-2592. Again, that concludes the call. Thanks for participating, have a good day.

Once again, ladies and gentlemen, that concludes today's call. Thank you for your participation, you may disconnect at this time.