WEC Energy Group, Inc.
Q1 2008 Earnings Call Transcript

Published: 30 Apr 2008

[Colleen F. Henderson:]

Good afternoon and welcome to Wisconsin Energy's 2008 first quarter conference call. Before the conference call begins, I will read the forward-looking language

[Gale E. Klappa:]

Colleen, thank you and good afternoon, everyone. We appreciate you joining us on our conference call to review the company’s 2008 first quarter results. Let me begin as always by introducing the members of our management team who are here with me today. We have Rick Kuester, President and CEO of We Generation; Allen Leverett, our Chief Financial Officer; Jim Fleming, our General Counsel; Jeff West, Treasurer; and Steve Dickson, Controller. I am very pleased with what we accomplished in the of this year. We received a final order on our retail rate case in Wisconsin and we continued to move forward on our power the future construction plan. We also set new company records for financial and operational performance. Allen will review our results in detail in just a moment. As you saw from our news release this morning, we earned $1.04 a share from continuing operations in the first quarter of 2008. That compares with $0.85 a share for the first quarter last year. Now I would like to just spend a moment or two on our continuing effort to upgrade the energy infrastructure in Wisconsin. Our Power the Future plan is fundamental to the principal of self-sufficiency. Components of our focus on self-sufficiency include investing in two combined cycle gas fired units at Port Washington north of Milwaukee; construction of two super critical pulverized coal units at Oak Creek, which is south of the city and our plans to build a significant amount of new wind generation. As you’ll recall, back in November of 2002 the Public Service Commission approved the building of two natural gas fired units at our Port Washington site. The first unit at Port went into commercial service in July of 2005 on time and on budget. Engineering, construction, and commissioning for the second unit are now essentially complete and we’ve moved on to final tuning and testing. We fully expect the unit to begin commercial service before the end of the second quarter this year. The cost for unit two won’t be finalized for a while yet as several post operational items must be completed but the unit is projected to meet our financial expectations. Now let’s turn to the status of the two new coal fired units at Oak Creek. At the end of March, the project was approximately 55% complete, with unit one and common facilities at 65% complete and unit two at 27% complete. The project at Oak Creek can be broadly divided into three major systems -- power island, the bulk material handling systems, and the cooling water intake system. I’d like to brief you on the status of each of these major systems. Power island comprises the two units, each with its own boiler, turbine, generator, and air quality control equipment. Our contractor, Vectel Power Corporation, is continuing to focus their efforts on the time critical activities, including the erection and welding of pressure parts in the boiler. Work also continues on the installation of the unit one bag house that will remove particulate matter from the exhaust gas and on the selected catalytic reactor that will remove nitrogen oxides. Vectel is also preparing to install the coal conveyor that will move coal from the new coal handling system we’ve built to the units themselves. In addition, the 345 KV transmission line that will export power from the site has already been built. Turning now to the bulk material handling, our focus has been on clearing the old coal dock in preparation for the new limestone receiving and gypsum loading facilities. Limestone will be used to remove sulfur dioxide from the flu gas. Gypsum is the by-product that will be exported offsite and is expect to be used for the manufacture of wall boards. Elevations for the conveyor systems and transfer towers are proceeding well and ducting for underground utilities is not being installed. Expect this new system to be in service late this year or early in 2009 to support the start-up and testing of unit one next summer. Now I will turn to the status of the cooling water system and later, we’ll address the permitting issue. We have completed all offshore construction of the tunnel and the water intake. The tunnel will provide cooling water to the existing four units at Oak Creek and also to the two new units. Our contractor is installing mechanical and electrical equipment in the new Oak Creek pump station and expects to begin start-up of the system later this year. Now, a difficult winter clearly slowed construction progress at the site. However, Vectel is increasing its workforce to make up for lost time and continues at the moment to forecast that the units will be completed on or before the guaranteed schedule. The guaranteed schedule, as you may recall, calls for the first unit at Oak Creek to begin commercial service at the end of September 2009, the second unit following one year later in September 2010, and we are tracking within the approved construction budget. Also as you know, there are four major permits needed to build the facilities at Oak Creek. These include an air permit, a wetlands permit, a permit from the U.S. Army Corps of Engineers, and finally a water pollution discharge elimination permit. We have received all of these permits and each of them remains in effect unless it is overturned by a court or an administrative law judge. Back in September of ’05, we resolved all legal challenges to the air permit. Also, in February of ’06, we resolved the outstanding legal challenges to the wetlands permit. Our permit from the U.S. Army Corps of Engineers was received in May of 2005 and this permit relates solely to the building of facilities that are now already complete. To date, no appeals have been launched against this permit. On the last permit, the Wisconsin pollution discharge elimination system permit, a contestant case hearing was held during March of 2006 and in July of that, a Wisconsin administrative law judge upheld the decision by the Department of Natural Resources to issue the permit. Parties opposing the plant than filed for judicial review in Dane County Circuit Court. In March of last year, the Dane County Circuit Court issued its ruling -- the court affirmed and importantly respects the decision of the DNR to issue the permit, also remanded certain aspects of the permit in light of a federal case called River Keeper 2 that could affect power plants nationwide. Following that decision, two threshold questions had to be answered -- whether the new units at Oak Creek qualified technically as an expansion of an existing plant, and whether the water intake system we have chosen is still the best technology available. We believe that the additions at Oak Creek did qualify as an expansion of an existing facility and the Wisconsin Department of Natural Resources also believed this. However, in a decision last November, the administrative law judge in the case ruled that the units must be treated as a new facility for purposes of this permit. We have submitted to DNR a request to modify our permit and we have provided additional data to demonstrate that we comply with the rules for new facilities. We expect that DNR will issue a draft modified permit for public comment before the end of May. The bottom line is this -- we are convinced the water intake structure we’ve built is the best environmental solution. [inaudible] of the impact on the lake, it results in lower air emissions, less use of coal, and less use of Lake Michigan water than other types of cooling systems. And now I would like to update you on our Blue Sky Greenfield wind project. In February of 2007, the Public Service Commission approved the project as a traditional utility rate base investment. In late March last year, we signed an agreement with Vestas Wind Systems for 88 turbines. Each of the 88 turbines has a capacity of 1.65 megawatts. The cost of this project is expected to be approximately $300 million excluding capitalized carrying costs. Construction began at the site last summer and now all 88 of the wind turbines have been erected. Electrical wiring and mechanical completion are underway and in fact the first wind turbine was commissioned in early February and produced electric power for the first time on February 9. As of today, 52 of the 88 turbines have been commissioned and are capable of producing electricity. We expect to achieve commercial operation of the entire wind farm by the end of May. The project remains on schedule and on budget. Now Wisconsin, as you have head, has in place a renewable portfolio standard that increases from 5% in 2010 to 10% in 2015 at a statewide level. The standard sets targets for each of the utilities using an historical base line. Using that base line, approximately 8.5% of our retail electricity sales must come from renewable sources in 2015. Meeting the more aggressive 2015 targets will require several additional renewable projects. So to keep moving forward, we have exercised an option with FPL Energy to purchase all rights to a new wind site in central Wisconsin. We expect FPL will transfer the site to us within the next few months -- plan to install approximately 100 megawatts of new wind capacity there, with a projected in-service date would be late 2010 or early 2011. We are also close to receiving a decision from the Wisconsin commission on our request to install new air quality controls on the existing units at our Oak Creek power plant. This would require an investment of some $750 million. Hearings and final briefs on the project have been completed and we expect to hear from the commission shortly. If approved, the emission controls would be scheduled for service 2012. I should also mention two other brief regulatory matters. In January, we filed a rate request with the Michigan Public Service Commission for $22 million. We expect an order from the Michigan commission in the fourth quarter of this year. And on March 13, we filed a request with the Wisconsin commission to increase our fuel recovery rate, driven by the surging price of natural gas and the higher cost of transporting coal by rail. We expect these high fuel costs will continue at least for the remainder of 2008. The commission approved a $76.9 million annual increase which was effective on April 15. Revenues are subject to refund, of course, pending review and final approval. Allen will provide more information on fuel in just a moment, but it is worth nothing that fuel costs have continued to escalate since we filed this request. Finally, before I turn things over to Allen, I would like to give you a quick update on economic conditions here in Wisconsin. Overall, we continue to be pleased with how well our large commercial and industrial customers are faring. Kilowatt hour use in this segment was up 2% versus the first quarter last year. We saw a strong growth in the healthcare, chemical, mining, and primary metal segments. Also, manufacturing of equipment for export markets did quite well. However, we continue to see weakness in automotive parts and in the production of paper products. Growth in the small commercial and residential segments has slowed somewhat on a weather-adjusted basis. Electric usage in these segments grew, again on a weather adjusted basis, about 0.5%. Comparable growth rates that we saw in 2007 for these segments was about 1%. Forecast for housing stock growth and employment growth in Wisconsin have also declined recently but overall, I would say that our economy has held up quite well. We’ll continue to keep you posted as we move throughout the year. With that, I will turn the call over to Allen who will give you more details on our financial performance for the first quarter of 2008. Allen.

[Allen L. Leverett:]

Thank you, Gale. As Gale mentioned earlier, our first quarter earnings from continuing operations were $1.04 per share in 2008, as compared to $0.85 in 2007. I will focus on operating income by segment and then touch on other income statement items. I will also discuss cash flows for the quarter and briefly review our earnings guidance for 2008. Our consolidated operating income was $218 million as compared to $185 million in the first quarter of 2007, for an increase of $33 million. Operating income in our utility energy segment totaled $207 million for an increase of $29 million over the first quarter of 2007. Before I discuss the primary drivers, I would like to remind you of a couple of developments that caused significant changes individual items in the income statement. First, last September we sold our Point Beach nuclear plant and entered into a long-term power purchase agreement with the new owner. Since we no longer own Point Beach, our results this year do not include operating or maintenance costs related to the facility, nor do we incur any depreciation or decommissioning costs associated with the plant. However, our fuel and purchased power costs this year have increased as a result of the power purchase agreement we now have. Also, as we mentioned in our February conference call, we expect to see a different quarterly distribution of costs and earnings this year as a result of the power purchase agreement. In addition, our income statement reflects $159 million of gain amortization. This item relates to the gain on the Point Beach sale that is being used for the benefit of our customers. The first quarter of 2008 we issued $74 million in bill credits to our customers and we also recorded a one-time $85 million amortization of the gain to match the amortization of $85 million of deferred costs. I would like to briefly expand on these two new items. The January 2008 Wisconsin rate order resulted in about a 17% increase in electric rates. This increase was needed to recover increased costs associated with transmission expense and environment expenditures, as well as the lease payments and O&M costs associated with our new power plans and our continued investment in renewables. However, our customers as a group will only see about a 3% rate increase for 2008 as the balance will be funded through bill credits resulting from the gain on the sale of Point Beach. While we look at the bill credits as a form of revenue, GAAP requires us to record the bill credits as part of the amortization of the gain as we are collecting the cash from the restricted cash accounts and not the customers. However, once all the Point Beach gain has been returned to customers, the full 17% increase will be paid by customers and hence reflected in operating revenues at that point. As I mentioned above, the January 2008 rate order allowed us to use $85 million of the Point Beach gain to immediately recover $85 million of regulatory assets related to deferred fuel and deferred bad debt expenses. This entry had no net impact on our operating income as the amortization of the gain was offset by the amortization of the expenses, but it did allow us to recover cash that had previously been spent on the deferred items. Now with these two items as background, I would like to address the primary drives in our utility operating income for the first quarter of 2008. First, we estimate that the extended cold and snowy winter increased our electric and gas margins by approximately $14 million. We also estimate that price increases to our wholesale customers increased revenue by approximately $10 million. A large part of this increase relates to rates that went into affect in May of 2007, so we do not expect to see a large annual increase for this item. Partially offsetting these items is the effect of the 2008 Point Beach PPA costs in excess of our 2007 operating costs. We estimate that this reduced operating income by $13 million. If you net all of the items above, this still leaves $18 million of positive items. In short, this $18 million represents the net impact of the January 2008 rate order on the first quarter alone. However, I want to remind you that we believe that this January 2008 rate order, taken in combination with the reduction in rate base from the sale of Point Beach, will be relatively neutral on an annual basis. Our rates were set assuming annual costs; however, there are some significant costs that are scheduled to be incurred later in the year. These costs include the Point Beach PPA costs in the third quarter and the depreciation on the new wind farms that we expect to begin in the second quarter. Operating income in the non-utility energy and corporate and other segments, which primarily includes We Power, was up by $4 million. The primary driver of this increase was the placing in service of the new coal handling facility at the Oak Creek expansion. Taking the changes for each of these segments together brings you back to the $33 million increase in operating income for 2008. Other income was down by about $2 million in 2008, the largest negative driver related to carrying charges on regulatory assets. In connection with the January 2008 rate order, we stopped accruing carrying charges on several regulatory assets as these assets were now considered part of rate base and setting rates. Earnings from our investment in the American Transmission Company are also included in other income and these earnings were up approximately $800,000 for the quarter. Total interest expense was down $4 million. This decrease is largely driven by our ability to capitalize interest related to construction activity. Consolidated income tax expense increased $13 million as compared to 2007. This increase was driven by higher earnings offset in part by a slightly lower effective tax rate. I expect that our effective tax rate this year will be between 36% and 38%. Adding these items brings you to $123 million of net income from continuing operations for the first quarter of 2008 versus $101 million in the first quarter of 2007. These earnings result in earnings per share of $1.04 in the first quarter of 2008 as compared to $0.85 in the first quarter of 2007. Now I would like to turn to cash flow. During the first quarter of 2008, we generated $344 million of cash from operations on a GAAP basis, which is down $19 million from the first quarter of 2007. While net income was up substantially, our uses of cash for working capital were also up, primarily in the area of accounts receivable and unbilled revenues related to natural gas sales. We also expect to collect these receivables later in the year. Cash from operations was also reduced $48 million because of the timing of our contribution to our pension plan. This year the contribution was made in the first quarter, whereas last year it was made in the third quarter. On an adjusted basis, our cash from operations totaled $432 million. The adjusted number includes the $88 million of cash impact of the bill credits and the one-time amortization of the gain. Under GAAP, the cash from the bill credits is reflected in the change in restricted cash, which GAAP defines as an investing activity. From a management standpoint, we consider this an operating source of cash as it directly relates to the bill credits and the one-time amortization. In 2008, we will provide both GAAP and adjusted measures of cash flow. We believe the adjusted measure is more representative of the company’s ability to generate cash from operations for two reasons. First, the customer credits are being funded from the proceeds of the Point Beach sale that are set aside in a restricted cash account as opposed to from operations; and second, once all of the Point Beach proceeds have been returned to customers, our prices and hence customer bills will reflect the full cost of electricity without any credits. Capital spending was approximately $348 million in the first quarter of 2008, which is slightly higher than 2007 but on track with our annual plan. We expect to spend $1.2 billion of capital this year to support the PTF construction program, the addition of wind generation, and ongoing utility infrastructure improvements. In the first quarter, we paid $32 million in common dividends. On a GAAP basis, our debt to capital ratio was 57.6% as of March 2008. We were at 54.4% on an adjusted basis. This is down from our December 31, 2007 GAAP levels of 58.6% and 55.3% adjusted. The adjusted amounts treat 50% of our hybrid securities as common equity, which is the approach used by the majority of the rating agencies. Given the continued high level of capital spending in 2008 and the fact that no significant asset sales are planned this year, I would expect our debt-to-capital ratio to increase slightly as of December 31, 2008, as compared to December 31, 2007. Our goal now is to maintain our adjusted debt to capital ratio at no more than 60% during the period we are constructing our new gas and coal fire generation. We are using cash to satisfy any shares required for our 401K plan, options, and other programs. Going forward, we do not expect to issue any additional shares. Now I would like to wrap things up with a review of our earnings guidance for 2008. In our February 2008 conference call, we affirmed our 2008 earnings guidance in the range of $2.80 to $2.90 per share. This guidance was based on normal weather for the entire year, expected earnings contributions from the second Port Washington unit, and a full year of earnings from the coal handling system at Oak Creek. Offsetting these items was the loss of the rate base associated with the Point Beach plant as well as a lower authorized return on equity in the Wisconsin retail jurisdiction. While we were very pleased with the first quarter results, we are not in a position to change our 2008 earnings guidance because of the uncertainty related to the recovery of fuel and purchased power costs. As background, our original 2008 rates were based on natural gas prices of $7.60 per decatherm and diesel fuel prices of $2.84 per gallon. Our interim rate relief in April was based on natural gas prices of $9.23 per decatherm and diesel prices of $3.54 per gallon. Today, just under two months later, the projected natural gas prices are at $10.39 per decatherm and the diesel prices are at $3.96 per gallon. While we do not expect to file for another fuel rate increase, you can see that the continued increase in energy prices will have a negative impact on our business. In our original guidance, we estimated that our annual fuel recoveries would range from between being fully recovered and $15 million under-recovered. Today, with the dramatic rise in natural gas and diesel fuel prices, we estimate that we will have been $20 million and $40 million in under-recovered fuel costs. And this estimate includes the $77 million emergency increase we received effective April 15th. So our full year guidance remains in the range of $2.80 to $2.90 a share. We will not be giving any specific quarterly earnings guidance but I did want to provide some input to you on what to expect in terms of the distribution of earnings for the rest of the year. This will be the first full year that we will be operating with the power purchase agreement from Point Beach. As a result, we anticipate the quarterly distribution of earnings will be quite different in 2008 as compared to 2007. Because the power purchase agreement is designed to resemble the change in market prices throughout the year and those market prices are usually highest during the summer months, we expect the cost of the power purchase agreement will be highest in the third quarter. In addition, because we no longer own Point Beach, we will not incur the higher operating costs during the quarters when the nuclear units are shut down for refueling outages. These factors alone would increase our earnings by approximately $0.08 per share in the second quarter relative to 2007 and decrease earnings by approximately $0.20 per share in the third quarter. Also, keep in mind when you are making projections of our earnings for the second quarter of 2008 that in the second quarter of 2007, we booked a combined $0.08 per share in earnings from the settlement of a billing dispute with our largest customers and the sale of land in northern Wisconsin and upper Michigan. In summary, given these factors, along with the fuel recovery situation, I currently expect earnings in the second quarter to be flat to slightly down as compared to last year. Looking to the third quarter, I expect earnings to be down relative to the third quarter of last year because of the shape of the power purchase payment related to Point Beach. So in summary, while we are very pleased with our results to date, our annual guidance remains unchanged. Benefits that we have realized from the first quarter weather are expected to be offset by higher under-recovered fuel and purchased power costs and also we still have eight months of weather uncertainty ahead of us. So with that, I will turn things back over to Gale.

[Gale E. Klappa:]

Allen, thank you very much. Overall we are on track and focused on delivering value for our customers and stockholders.

[Operator:]

(Operator Instructions) We’ll take our first question from Doug Fischer from Wachovia.

[Doug Fischer:]

Just a question about Oak Creek -- obviously coal construction has seen a lot of labor inflation and I know that is one thing that while you had protected yourself quite well against a lot of the escalation we’ve seen, that is one thing you are somewhat at risk for. Can you discuss whether the wage inflation, the added workforce, are issues that could cause the costs to go above what the current budget is?

[Gale E. Klappa:]

Sure. We’ll be happy to address that and if Rick would like to add anything to my comments, feel free. First of all, just to remind you about the manner in which we protected ourselves against wage inflation in the contract with Vectel. Essentially, in Vectel’s budget, they have planned for average annual wage increase in the craft rates of 4%. And again, the average annual is a very important element of that contract, so inflation in terms of the wage rates for the craft personnel of the site have to rise by more than an average annual of 4%. We are fortunate that when we began construction the early years came in slightly beneath that, so while we do have some exposure, there is not question that the contract and the shape of the contract and agreement that we made with Vectel does give us some protection. Now having said that, Vectel is adding workforce and they are going to be paying some higher rates going forward. But I don’t see any huge impact at the moment in terms of pushing us over budget simply from this particular element.

[Doug Fischer:]

And you would, of course, be able to go to the commission to argue the justification for any costs that might take you over the budget?

[Gale E. Klappa:]

Well, the commission authorized basically a dollar amount for the construction and then gave us a 5% additional amount that if prudently spent could be recovered for the plant. But right now we are tracking within the budget, not counting the 5%.

[Doug Fischer:]

Okay. Thank you.

[Operator:]

We’ll go next to Greg Gordon of Citigroup.

[Greg Gordon:]

Thanks. Good afternoon.

[Gale E. Klappa:]

Did you make it back from the wilds of Oak Creek?

[Greg Gordon:]

We did. It’s an amazing facility -- really truly immense infrastructure project.

[Gale E. Klappa:]

It really is. I’m glad you had a chance to see it.

[Greg Gordon:]

When we talk about -- you talked about the delta on the potential for fuel under recoveries going from a budget of 15 to potentially as high as 40. Given the way your fuel adjustment clause works, is that -- refresh my memory on how your fuel recovery mechanism works and how much of that delta, which is sort of $25 million pretax, might flow directly to the bottom line.

[Gale E. Klappa:]

I will start out and I will ask Allen to add as well. Again, our original financial plan for 2008 in the 280 to 290 range that we gave you was from zero, meaning fully recovered, to $15 million under-recovered. And as Allen is saying now, given the way fuel prices have really sky-rocketed and given our experience in the first quarter, even with the emergency fuel increase that we were granted, it’s looking like $20 million to $40 million. But again, I think Allen stated it well. If you look at the strong results in the first quarter offset with what we expect to be lower fuel recoveries than we had planned or worse under recovery than we had planned, we are still staying within the 280 to 290. In terms of how the fuel clause works here in Wisconsin, it is quite complicated but in an over-generalized term, there is a bandwidth, and that bandwidth on an annual basis is roughly plus or minus 2%. And so if your actual incurred fuel costs plus projected fuel costs go outside the bandwidth, that is when you can seek an adjustment in your fuel recovery clause. Allen.

[Allen L. Leverett:]

In the test that you do, Greg, one might ask well, if you are seeing these increases in fuel costs and you expect further increases, could you file another fuel case? Well, what will happen when they do the plus or minus 2% test that Gale mentioned for -- if you were looking at a subsequent fuel increase, they will assume, they will impute that the interim increase that they gave you was in effect at the beginning of the year for the whole year, so it is pretty difficult to trip again, if you will, and have two interim increases in a given calendar year. So given that and the run-up in the fuel prices, that’s what moves us to the $20 million to $40 million range that I mentioned and that Gale reiterated.

[Greg Gordon:]

So that is in fact an amount that we need to deduct from earnings as being under-recovered, not deferred -- under-recovered and a drag on earnings?

[Gale E. Klappa:]

That is correct, Greg.

[Greg Gordon:]

Okay. Thank you.

[Operator:]

We’ll go next to Paul Ridzon at Keybanc.

[Paul Ridzon:]

I have a question on the skewing of earnings from the purchased power. What -- it is going to be an $0.08 help in the second quarter, $0.20 drag in the third. What was the impact on the first?

[Allen L. Leverett:]

In terms of the first quarter, I believe we -- well, remember in the rates that we have, we fully recover -- well, that was built in to the rates but I think in the first quarter alone there was a $64 million increase for the Point Beach PPA, but that was included in rates, if I’m taking your question.

[Paul Ridzon:]

So we should see a $0.12 benefit in the fourth quarter, if there was no impact on the first?

[Allen L. Leverett:]

Yeah, I think it’s about $0.06 negative in the first quarter.

[Gale E. Klappa:]

It was a slight drag in the first quarter.

[Allen L. Leverett:]

If you are looking not versus plan but versus the actual of ’07, it was about $0.06 drag. So I think it would be closer to a $0.06 drag in the fourth quarter as well.

[Paul Ridzon:]

Six cent help in the fourth quarter? If you’ve got plus $0.02 in the second quarter, minus $0.20 in the third, so we still need to pick up $0.12 somewhere, right?

[Gale E. Klappa:]

We’re looking at our sheets here, Paul.

[Allen L. Leverett:]

I think it’s in the fourth quarter, Paul, you would have a turn in the fourth quarter.

[Gale E. Klappa:]

Yeah, you would have to have -- you’re right, Paul. You would have a turn in the fourth quarter.

[Paul Ridzon:]

So we were neutral in the first quarter?

[Gale E. Klappa:]

No, a slight drag, about a $0.06 drag in the first quarter.

[Allen L. Leverett:]

Relative to ’07 -- $0.08 help in the second quarter, again relative to ’07, and then a $0.20 drag in the third quarter.

[Paul Ridzon:]

So we should see about an $0.18 pick-up in the fourth quarter?

[Gale E. Klappa:]

No, I don’t think that big, Paul. Steve, go ahead.

[Paul Ridzon:]

If it’s going to add to zero --

[Steve Dickson:]

No, it’s not going to -- it won’t add to zero and the reason is because -- there’s a couple of reasons. One of the reasons is that we lost the rate base and so it will hurt us on earnings because we lost the rate base. So on a year to year basis, it will be a reduction to earnings. The other thing that happened, if you are comparing ’07 to ’08, is because of the way the PPA, the costs will be higher in ’08 and one of the reasons is because there is going to be two outages at Point Beach, so in effect we’ll have higher purchase power. So you can’t say that it’s zero for the entire year. It will be down if you are just looking ’07 to ’08. However, the key factor is that the costs were considered when rates were set in 2008.

[Paul Ridzon:]

Okay, I get it. The 2% band on fuel, what’s that in millions of dollars?

[Allen L. Leverett:]

Twenty-million dollars -- so $20 million up or down.

[Paul Ridzon:]

If we saw another spike in fuel so that you could potentially file again, and you were granted and then prices came down, would you have -- how do the refund mechanics work? Could you potentially get back some of what you had to forego to do your first filing before the refund kicked in? Or would it be --

[Gale E. Klappa:]

Paul, that would be highly unlikely. I think the way you should look at it is what’s gone is gone. There is very little look back to past -- in fact, there’s no look back to past under-recoveries other than obviously you incurred the under-recovery and we are projecting higher fuel costs, so when you put that together, that went above the 2% bandwidth.

[Paul Ridzon:]

And lastly, I’m just -- I’m tracking weather about normal but certainly an improvement over last year. Is that what you saw?

[Gale E. Klappa:]

No, actually it’s colder than normal.

[Allen L. Leverett:]

If you look at heating degree days versus the 20-year average, it was about 8.5% above average. (Multiple Speakers)

[Paul Ridzon:]

Okay, thank you very much.

[Operator:]

We’ll go next to Paul Patterson at Glenrock Associates.

[Paul Patterson:]

If you could just -- the other net that we are talking about here, the $18 million, is that the net -- most of that is the net impact of the rate order, correct?

[Allen L. Leverett:]

But [some] on the first quarter because as I mentioned in the call, I mean, you’ve got timing of costs within the year but the rates are essentially levelized. But if you look at the net impact of the rate case, taking into account that the reduced rate of return and the loss of the Point Beach rate base, you are really looking at the utility being down in terms of earnings contribution in ’08 versus ’07.

[Paul Patterson:]

Could you just go through that again?

[Gale E. Klappa:]

In Q1, we did see the $18 million impact but when you look across the year, the rate case will actually be neutral to slightly down, the outcome of the rate case on the utility’s earnings. I think that is what Allen is trying to say.

[Paul Patterson:]

Okay, and that’s because of timing?

[Gale E. Klappa:]

In large part, the timing of expenses. That’s correct.

[Paul Patterson:]

Okay, and Greg asked my question on the fuel case, so I think I’m okay on that, on the fuel interim increases and what have you.

[Gale E. Klappa:]

Very good.

[Paul Patterson:]

Thanks a lot.

[Operator:]

We’ll go next to Michael Lapides at Goldman Sachs.

[Michael Lapides:]

A quick question here, just following up from something earlier -- on O&M costs, what should we think as the annual run-rate for O&M costs this year?

[Allen L. Leverett:]

Let me take you through, maybe just talk about the first quarter because there are a number of items that go through the O&M account that aren’t probably what you or I would think of as day-to-day operating costs for the business. If you start with the $303 million that we had in the first quarter of ’07, the first thing that caused the variance, 8 versus 7, was the fact that we amortized about $44 million worth of cost. That was that one-time, the recovery of those costs but we had to amortize those on the income statement and there was an offsetting entry in gains. So there was a $44 million increase for that but then there was $38 million that went the other way because we don’t have Point Beach O&M anymore. So the net of those two together is about $6 million, so that was the $6 million increase. Then we incurred or expect to incur -- we incurred $16 million of additional ATC costs in the first quarter. Then we also incurred $36 million of other regulatory amortizations. So if you put all that together, that adds up to $361 million and what’s left is in my mind, if you look at day-to-day operating costs, it was about a $9 million increase, which is about 3%, which is a long answer to your question but if you look at day-to-day operating costs, I still expect those to be around 3%. So at or below inflation but we still, you know, we’re going to have these other items that are causing noise, if you will, in the O&M account.

[Michael Lapides:]

Okay.

[Gale E. Klappa:]

-- noise, Michael, but they are covered in rates.

[Michael Lapides:]

Right, they are covered in rates, just double-checking. The $16 million of ATC costs, that’s just increased O&M at the AT, meaning literally guys with hardhats at ATC and that’s already embedded in the 2007 rate case?

[Gale E. Klappa:]

Some of them with soft hats -- it’s already embedded in the rate case.

[Allen L. Leverett:]

Right, so if you take -- another way to look at it is if you take say roughly a quarterly base of $325 million, because that would sort of adjust for some of the noise and then escalate that at 3%.

[Michael Lapides:]

Okay, so we --

[Allen L. Leverett:]

Other amortizations sort of ride on top of that.

[Michael Lapides:]

So when we think about the year-end run-rate, do you see any other significant changes to O&M besides these items you’ve outlined plus the 3%?

[Gale E. Klappa:]

No, that should do it.

[Allen L. Leverett:]

No, I don’t see any other items, Michael.

[Michael Lapides:]

Okay, thank you.

[Gale E. Klappa:]

Michael?

[Michael Lapides:]

Yes?

[Gale E. Klappa:]

Michael, a question for you -- we’re all wondering, speaking of O&M, if the snacks are going to be any better at your conference this year?

[Michael Lapides:]

I promise. I promise. All you have to do is take one look at my waistline and you can know I’ve never turned down too many good snacks.

[Gale E. Klappa:]

We’ll see you in a few weeks, Michael.

[Michael Lapides:]

Thanks, guys.

[Operator:]

We’ll go next to Maurice May at Power Insights.

[Maurice May:]

Michael just asked one of my questions but I’ve got one more question -- unrecovered fuel for this year estimated at $20 million to $40 million. How much of that applies to the first quarter?

[Allen L. Leverett:]

Well, we under recovered fuel in about I think $15 million in the first quarter.

[Maurice May:]

Fifteen-million?

[Gale E. Klappa:]

Correct.

[Maurice May:]

Okay, and that is gone forever?

[Gale E. Klappa:]

Largely, I think that’s the way to look at it, yes.

[Maurice May:]

Okay, good. That’s the only question I had left. Thank you very much.

[Operator:]

We’ll go next to [Edward Hine] at [Catapult].

[Edward Hine:]

Maury actually just stole my question. I guess the other thing I was going to ask about was just a little bit more color on the wholesale pricing. I think this is the first time we’ve seen it in your earnings walk and I know that Allen, you said it is probably -- it was rates that went into effect in May so it is not going to probably reoccur, but if you can just give us a little more color on what’s gone on there.

[Allen L. Leverett:]

Yeah, and the reason why it hasn’t factored into earnings releases very much is because before May of last year, I think you had to go back five years before there was a base rate increase, at least for wholesale customers. But Ted, what we implemented in May of last year was a so-called formulary of tariff, so you’ve got a tracker that tracks your [inaudible] costs, so in addition to a fuel clause where you have escrow accounting in the wholesale jurisdiction, you also have this cost tracker. So there was a big catch-up that occurred, if you will, in ’07 because there hadn’t been an increase in base for five years and now as we go through time, I would expect to see modest increases in wholesale prices. But that $10 million, just to bring it full circle, but that $10 million -- I mean, we already included in our plan the fact that we would have this wholesale increase in ’08 as compared to ’07.

[Edward Hine:]

And then just to clarify; are these wholesale sales tariff-based or are they kind of like opportunity sales because you are long --

[Allen L. Leverett:]

These are tariff-based. That’s why I said it’s a formulary tariff. So for example, the primary customer is Wisconsin Public Power and it would be under the terms of a long-term power agreement.

[Edward Hine:]

Okay, so this won’t be if you see fuel rising and under recoveries being pressured, it’s not going to be an offset because you have length that is selling into the market?

[Allen L. Leverett:]

No, this is a separate jurisdiction.

[Gale E. Klappa:]

-- approved tariff-based rates.

[Edward Hine:]

That’s very helpful. Thanks a lot, guys.

[Operator:]

We’ll go next to Dan Jenkins from the State of Wisconsin Investment Board.

[Dan Jenkins:]

Good afternoon.

[Gale E. Klappa:]

Not it’s spring and a young man’s fancy normally turns to the strength of our balance sheet, right, Dan?

[Dan Jenkins:]

Yeah, I’ve had enough of the cold with winter, so --

[Gale E. Klappa:]

Well, the tulips are coming up, Dan. What can we do for you today?

[Dan Jenkins:]

Snow is finally gone -- just trying to get a little more clarity on the cash flow and then the financing requirements. I guess if you could give me a sense on when this amortization of the gain, kind of how long that will run and when it will fall off, and then be reflected --

[Gale E. Klappa:]

Dan, the amortization of the gain, and we’ll let Allen fill in all the details, but basically in the form of bill credits, the amortization of the gain will run for three years, particularly for Wisconsin retail customers. So that’s -- you want to think about this over a three-year period for Wisconsin retail. For federal, for our wholesale customers, there will be one-time payments but for Wisconsin retail, three-year amortization.

[Allen L. Leverett:]

And then Michigan is about 18 months, Dan.

[Dan Jenkins:]

Okay. Will that be a similar size then throughout the period or what we are seeing in the first quarter or --

[Allen L. Leverett:]

No, no, it’s very -- I believe it is fairly front-end loaded but you will see this item for the next, you know, at least three years. But you know, I would just stress though what’s built into rates going back to the Wisconsin retail discussion, is the 17% increase. So over time what happens effectively is the gain runs off, what you’ll -- what was an amortization of gain will show up in operating revenues on customers’ bills. So from a cash bottom line standpoint, it is just what account it is coming out of. But from a bottom line, the cash is coming to the company as if you had a 17% increase.

[Gale E. Klappa:]

Just a portion of it is coming from the restricted cash account and a portion coming from customers, and that portion, as Allen said, will differ from year to year as the bill credits run off.

[Dan Jenkins:]

Right. I was just trying to get a feel for the cash from operations and how that relates to the income statement, but --

[Allen L. Leverett:]

And I think if you flip to page five of the earnings package, you can see the change in restricted cash is about $88 million. So if you were trying to come to FFO number, then you could take the 344, add all or whatever portion of the 88 from restricted cash you view as operating, at least half of it is, at least the amount associated with the $74 million, and then keep in mind the timing on the pension payments, which was a $48 million cost in the first quarter of ’08, which we didn’t incur in ’07 because of the timing of payments is different. I think if you start with the 344, adjust for those two things, you can come to kind of an estimate of the FFO.

[Gale E. Klappa:]

Dan, we really think that going forward, it’s appropriate to look at the change in restricted cash as revenue, because in essence, as we get that cash out of the restricted account and into the company, it is taking the place of revenues that otherwise would have come from customers under rates, under the rate case that’s been approved.

[Allen L. Leverett:]

And then in terms of if you wanted more detail, Dan, on the pattern of the credits, we had a discussion in the 10-K where we lay out at least in Wisconsin what we expect the pattern year by year to be in the credits.

[Dan Jenkins:]

Okay, and then the last thing I was wondering is, given that the Port Washington and wind is coming into rate, or into operation and the first quarter you have basically $1 billion of short-term debt and your CapEx was ahead of the cash from operations -- what are the financing needs for that coming?

[Allen L. Leverett:]

A couple of things on the debt level. Remember of course that during construction, we are putting in effect the construction debt is being, for We Power, is being funded up at the holding company. And then as we do the permanent financings at We Power, we bring that down. So in the first quarter of last year, we had $900 million outstanding. The first quarter this year, end of first quarter we had $1 billion outstanding. But another difference between those two quarters, Dan, is remember we had to buy in our auction rate securities at the utility, so that added $150 million. So apples-to-apples, it’s really 900 versus 850. In terms of financing that I would expect for the rest of the year, I expect to do a financing for the second Port Washington unit. That will be approximately $156 million and in fact, we did the pricing of that last week. That’s a private placement. We expect to reissue the auction rate securities this quarter and then I would expect later this year, probably some time in the fall, we would do up to $500 million worth of unsecured debt at Wisconsin Electric Power Company.

[Dan Jenkins:]

Okay. Thank you.

[Operator:]

We’ll go next to Scott [Angstrom] at [Bleinhelm] Capital Management.

[Scott Angstrom:]

A couple of quick more fuel questions. I’m sure you are having fun with all these fuel questions, so I will add to the pack. Allen, you focused on gas and diesel prices. You did not mention coal. Is that just because of where you are hedged or are there any other reasons?

[Allen L. Leverett:]

Well, in terms of our coal procurement philosophy, we are essentially -- we are covered one year out, so other than transportation costs, which can float and do float with diesel fuels, which that’s why I talked about diesel, really have a locked number on the commodity cost of coal one year out.

[Gale E. Klappa:]

That was included in our rate projection back in the last rate case. In other words, the higher contract price for coal was embedded in the rate case that has been decided and the order in place.

[Scott Angstrom:]

Got it. Okay, second question kind of thinking about this currency under-recovery and what -- not necessarily a look back but hypothetically let’s say gas prices went to -- I’ll just throw numbers out in the air -- $12 or some range that exceeded the 2% which allowed you to make a filing, and it turned out to be some sort of temporary spike that allowed you to do the filing and then prices came in; would the amount then that you are over earning, whether or not it was actual recover of past under-recoveries, would it effectively be the same thing or would that be held subject to refund going forward?

[Gale E. Klappa:]

Well, any interim increase in fuel that is granted by the Wisconsin Commission is subject to review and refund if circumstances change. And usually the commission takes up to six months once an interim fuel rate recovery increase is in place to do their final auditing and come to a final order. So really by the time we would be getting a final order, my guess is it will be pretty close to the fourth quarter. But let me add one other thing that really takes your hypothetical in a bit different direction -- as the year goes on, we hedge obviously a certain portion of our natural gas costs, a certain portion of our other fuel costs, each month. So as the year goes on, the volatility, unless there is an extreme change in the spot markets for the month ahead or two months ahead markets, the volatility should dampen, not grow. Rick, you agree with that?

[Frederick D. Kuester:]

Yeah.

[Scott Angstrom:]

Okay, so what you are saying then is given the kind of lag in terms of getting these final orders, it is difficult for what I was describing in terms of a temporary spike for you guys to benefit and capture anything you may have lost before?

[Gale E. Klappa:]

It could happen but it would take a pretty convoluted situation.

[Scott Angstrom:]

Okay, great. Thanks a lot, guys.

[Operator:]

We’ll go next to Nathan Judge at Atlantic Equities.

[Nathan Judge:]

Good afternoon.

[Gale E. Klappa:]

Are you back in the U.S.A.?

[Nathan Judge:]

I am and it’s very nice; I actually have a conference call -- your conference call -- in the afternoon instead of at night, so that’s --

[Gale E. Klappa:]

There you go.

[Nathan Judge:]

Just on the fuel costs, assuming that natural gas prices and commodity prices remain flat, I would suspect that in the fourth quarter after getting your final order, you would be inclined to go in for another rate or a fuel clause adjustment. Would that be reading it right?

[Gale E. Klappa:]

Nathan, actually again, the rules in Wisconsin require actual and projected to be more than 2% above what you are currently collecting. So again, we would look at the situation at the time but unless our projected fuel costs were above that bandwidth, then we wouldn’t really be able to go in for another adjustment.

[Allen L. Leverett:]

But you are asking for 2009, Nathan?

[Nathan Judge:]

That’s correct, yes.

[Allen L. Leverett:]

So you have to trip the band on an actual basis, so the way -- the scenario you are talking about, say you get your final order from the commission this fall. So then you’d have this new final rate in place. You would take that rate with you into ’09 and then before you could go back in in 2009, you would have to under-recover on an actual basis in a given month, under-recover and then be projected to under-recover also for the full year.

[Gale E. Klappa:]

And that’s before you can file.

[Allen L. Leverett:]

Right.

[Nathan Judge:]

This is a perhaps a little bit more difficult one to answer, but in a hypothetical situation where gas prices and commodity prices were to remain flat from these levels, what now would be the rate impact of adding the new coal units at Oak Creek versus what you had expected let’s say a year ago?

[Gale E. Klappa:]

I don’t think any of us have quite calculated that, but there is no question that once the new coal units come into service at Oak Creek, our fuel recovery clause will flatten or go down. I mean, that’s what we had expected. Now we’ll see what happens with natural gas prices and coal prices. But it’s not going to be a negative, I don’t believe.

[Nathan Judge:]

Let me ask it a different way -- at what price, let’s say hypothetically natural gas needs to be in order for the actual addition, the savings that you’d get from the low cost coal plants to actually offset the marginal cost of fuel that you would be running otherwise, and therefore the impact to rates would be negligible.

[Gale E. Klappa:]

We’ll have to actually go back and try to calculate that. I don’t think we can do that in the room here without giving you an answer that we -- we want to make sure we give you a correct answer and we don’t --

[Nathan Judge:]

But it would be fair to say that the rate increase needed now for customers is increasingly smaller as these fuel costs are coming in higher probably than what you expected maybe six or 12 months ago?

[Gale E. Klappa:]

The only reason I think any of us are hesitating is we’ve seen on the spot market for coal pretty substantial increases. I think on the spot market in the first quarter of this year, Powder River Basin coal is up over 20% and Appalachian coal is up over 60%. Now, you look back to last August and natural gas prices are up 95%. But it is so volatile that it’s really difficult to project that far ahead and give you a precise answer. But we’ll certainly give it a shot.

[Nathan Judge:]

Thank you very much.

[Operator:]

We’ll go next to Paul Ridzon from Keybanc.

[Paul Ridzon:]

Your ’08 rates are based on your forward look on coal, so how do you protect yourself when your ’09 coal rates start kicking in? Do you have to trip the bandwidth again?

[Gale E. Klappa:]

We would have to trip the bandwidth but much of our, as Allen said, we are covered virtually 100% with contract coal for ’08 and I am looking at -- and we are probably 60% to 65% covered for next year. So again, that’s embedded in our rates currently.

[Allen L. Leverett:]

But Paul, your predicate is right though. You still have to under-recover on an actual basis before you can come in for interim relief in 2009.

[Gale E. Klappa:]

That is simply the way the rules work here in Wisconsin.

[Paul Ridzon:]

I hate to beat a dead horse on this question but I am still a little confused. If we take the sum of the four quarters, skewing -- what will the sum be? Is that the --

[Gale E. Klappa:]

Are you talking about fuel under-recovery?

[Paul Ridzon:]

No, just from Point Beach.

[Gale E. Klappa:]

Back to Point Beach, all right.

[Allen L. Leverett:]

I would say it would be about negative $0.12. So if you look at the timing impacts and the fact that, as Steve Dickson pointed out earlier, the fact that these PPA payments effectively are taking the place for us what would have been return on capital, if you net all that together, it’s about a $0.12 negative year over year.

[Paul Ridzon:]

I thought it was supposed to be just about neutral in the year.

[Allen L. Leverett:]

No, because we lost -- it’s neutral to customers because what they were paying in rates to us is about the same as what we are paying on the PPA, but remember we owned the asset, we were getting earnings. So we are no longer getting earnings from the asset, so that’s why you have negative if you look at a whole year from the sale of Point Beach for the shareholders, it’s a negative $0.12 in ’08 versus ’07.

[Paul Ridzon:]

The $0.12 is the loss of the return of [inaudible] on Point Beach?

[Gale E. Klappa:]

Yes, that is correct.

[Paul Ridzon:]

Okay. I understand now. Thank you.

[Gale E. Klappa:]

All right. Well, I believe that concludes our conference call for today, ladies and gentlemen. Thank you for taking part. If you have any other questions, please call Colleen Henderson. She is available in our investor relations office at 414-221-2592. Thank you much. Have a good day.