威斯康辛能源 (WEC) 2006 Q4 法說會逐字稿

Good day and welcome to Wisconsin Energy Corporation 2006 and year-end earnings conference call. Today's call is being recorded. At this time, I'd like to turn the call over to Colleen Henderson.

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 2006 year-end results at www.wisconsinenergy.com. A replay of our remarks will be available approximately two hours after the conclusion of this call. Now, I would like to introduce Mr. Gale Klappa, Chairman of the Board, President and Chief Executive Officer, of Wisconsin Energy Corporation.

Colleen, thank you, and good afternoon everyone. Thank you for joining us on our conference call to review the company's 2006 year-end results. Let me begin, as always, by introducing the members of the Wisconsin Energy management team who are here with me today. We have Rick Kuester, President and CEO of We Generation, Allen Leverett, our Chief Financial Officer, Jim Fleming, our General Counsel, Jeff West, serves as our Treasurer, and Steve Dickson, Controller. Overall, I'm really very pleased with what we accomplished during 2006. We made significant progress on our Power of the Future strategic plan. We continued to meet our financial objectives and we improved our operational performance. Allen will review our results in some detail in just a moment, but as all of you saw from our news release this morning, we achieved adjusted earnings from continuing operations of $2.58 a share in 2006. This is an increase of 6.6% compared to 2005, when adjusted earnings from continuing operations came in at $2.42 a share.

Now, I'd like to spend just a moment on our continuing efforts to upgrade the energy infrastructure in Wisconsin. Our Power of the Future plan is fundamental to the principle of energy self-sufficiency. Key components of our focus on self-sufficiency include investing in two, combined cycle gas-fired units at Port Washington, which is north of Milwaukee, the construction of two, super-critical pulverized coal-fired units at Oak Creek, south of the city, and our plan to build up to 200 megawatts of new wind generation. Now, as you recall, back in November 2002, the Public Service Commission approved the construction of two, 545-megawatt natural gas-fired units at our Port Washington site. The first unit at Port Washington went into commercial service in July of 2005, on time and on budget. Engineering for the second unit at Port Washington is now essentially finished, and all major equipment has been delivered to the site. Construction of the second unit is currently about 35% complete, tracking on schedule and on budget. The unit is expected to be in commercial service in time for the peak summer season of 2008.

Now, let's turn to the status of our two new coal-fired units at Oak Creek. Activity at the site, as you recall, began in late June 2005, following a ruling by the Wisconsin Supreme Court that allowed us to move forward. Since that time, we've made significant progress on engineering, procurement, site excavation, foundations, structural steel, air quality control equipment, the coal-handling facilities, and the cooling water tunnel. During 2006, Bechtel Power Corporation, our primary contractor, finished moving some 6 million cubic yards of material to create the platform for the plant's main power block. During the second quarter of 2006, the boiler foundations for Unit 1 were completed, and we also began to erect the structural steel for the unit. During the third and fourth quarters, we continued erecting structural steel for Unit 1, and that steel has reached an elevation of 242 feet. The final boiler height will be around 280 feet. In addition to structural steel, Bechtel has been installing the boiler air ducts, coal silos, and coal piping in the main power block. Foundations for the Unit 2 boiler, and the turbine-generator pedestal are well-advanced, and Bechtel has completed the main underground cooling water system on the site. We've completed the chimney shell and have laid the foundations for the air quality control equipment. Bechtel is currently assembling the Unit 1 flu gas to sulphurization absorber vessel that's adjacent to the chimney. Construction of the water in-take system is also progressing well. Drilling of the water in-take tunnel under lake Michigan started in September of 2006, and today is approximately 8,150 feet in length or 89% complete. All four downshafts in the lake have been drilled and sleeved with 12-foot steel casings. The contractor has installed manifolds on two of the shafts, and the remaining two manifolds are expected to be completed later this quarter. We plan to connect the in-take screens upon completion of the new manifolds. The major upgrades we're making to the existing rail infrastructure and coal handling system at Oak Creek are also on schedule.

We expect the facilities to be turned over to the utility this year in the summer of 2007 as planned, to support coal supply to the existing units at the site. Engineering for the Oak Creek expansion is now more than 80% complete. Procurement of engineered equipment and supplies is 96% complete, and overall, at the end of December, 2006, the project stood at almost 25% complete. We continue to be very satisfied with the progress at Oak Creek.

Now, 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 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. In September of 2005, we resolved all legal challenges to the air permit. Also in February, 2006, we resolved the outstanding legal challenges for wetlands permit. Our permit from the U.S. Army Corps of Engineers was received in May of '05. To date, no appeals have been lodged against that permit.

On the final permit, the Wisconsin pollution discharge elimination system permit, a contested case hearing was held during March of 2006, and in July of last year, a Wisconsin administrative law judge upheld the decision by the Department of Natural Resources to issue this permit. Now, the parties opposing the permit, then filed for judicial review of the decision in Dane County Circuit Court. The Dane County case has been proceeding. All legal briefings were completed in December. Just a few days ago, however, a group called Clean Wisconsin, asked the judge to reopen the record for additional briefings, to take into account a recent decision against the U.S. Environmental Protection Agency by a Federal Appeals Court in the State of New York. On Friday of last week, the Dane County Circuit Judge here, decided that additional briefs were not necessary. The judge did reserve the right to hold oral arguments on the issue at a future date. We expect a final decision in this case sometime this year. Our plan, of course, remains intact, to have the first unit at Oak Creek in service in the summer of 2009, and the second unit scheduled to follow one year later in 2010.

Now, I'd like to update you on our Blue Sky Green Field wind project that we've been working on for a number of months. In 2005, we purchased the development rights to this project, and we plan to build wind turbines with a combined capacity of up to 200 megawatts. On February 1st, just a few days ago, the Public Service Commission of Wisconsin issued an order approving the project as a traditional utility rate-based investment. The order authorized expenditures of up to $394 million including capitalized carrying costs, and depending on the size of the turbines selected. The amount assumes the $394 million amount assumes that 2.3 megawatt turbines would be used for each of the turbine sites. As provided for in the order, we are evaluating turbines that range in capacity from 1.5 megawatts, up to 2.3 megawatts. The final capital investment in this wind project is expected to be roughly proportional to the size of the final turbines selected.

Virtually all of the 88 wind turbine locations have received their permits, and we have been notified that the last several locations are indeed permittable. Also, the Department of Defense has now confirmed that no conflict exists with military radar or other military operations. So, from the standpoint of the permitting process on our wind farm project, we're good to go. Of course, we've also been thoroughly evaluating wind turbine equipment and our options there. We've entered into negotiations with a major wind turbine vendor for equipment that would enable us to achieve commercial operation of the wind farm in 2008. We've also secured an option, as you know, with FPL Energy for a turnkey installation of wind turbine equipment. Again, that would allow operation to commence in 2008. So, we expect to begin construction this year, and have our Blue Sky Green Field wind project in service, again, by the end of 2008. This will double the amount of wind capacity currently operating in the state of Wisconsin.

And now, an update on our Point Beach nuclear project. In late December, after an extensive review, we agreed to sell our Point Beach facilities to FPL Energy. FPL Energy owns and operates more than 30,000 megawatts of generating capacity in the United States, including six nuclear units. Concurrent with the closing of this transaction, and subject to commission review and approval, we expect also to enter into a long-term power purchase agreement with FPL Energy. This agreement would allow to us buy all of the output from the two units at the site, until the operating licenses' expire, in the years 2030 and 2033, respectively. Our goal in this whole process was to retain the benefits of Point Beach for our customers, and at the same time, obtain the efficiencies that drive from operating a fleet of nuclear plants. We're confident that this decision fully meets those objectives.

Now, as we mentioned to you when we discussed this subject in late December, the sale price for the land and property associated with Point Beach, as well as the nuclear fuel inventories, spare parts, and all other assets directly associated with the plant, the price is $998 million, subject to certain closing adjustments, such as actual fuel inventory. At closing, these assets are expected to have a net book value of about 472 million, and of this 472 million, approximately 72 million is financed outside of our utility rate base in a nuclear fuel lease. In addition, the asset sale agreement calls for FPL Energy to assume the entire decommissioning obligation for the plant. The disposition of the total decommissioning trust funds, of about $880 million, will be determined in the future. Approximately 580 million of these assets are in qualified trusts, and 300 million are in non-qualified trusts. We will retain the non-qualified trust for the benefit of our customers, in a minimum of 360 million in mid- qualified trust will be transferred to FPL Energy. The actual amount of qualified funds that are transferred will depend on decisions we receive from the IRS, as well as the Wisconsin Commission.

On January 5, we filed a formal application with the Wisconsin Public Service Commission, seeking approval to transfer ownership and operational control of Point Beach to FPL Energy, and approval to enter into a long-term power purchase agreement. Testimony was filed on January 22 and the Commission has scheduled a prehearing conference on February 14. Of course, several other state and federal agencies must review and/or approve various aspects of this transaction. They include the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Michigan Public Service Commission, and the Department of Justice. We're hopeful that we can receive all necessary approvals and close this transaction by the end of August.

As we look ahead now to the remainder of 2007, we expect to file a general rate case on our normal cycle for our Wisconsin Electric and Wisconsin Gas Utilities, and that filing we expect will be in May. We also expect that hearings will take place here in Wisconsin this fall, and new retail rates for the State of Wisconsin will go into effect in January of 2008. And one last note, we're very pleased that for the fourth time in the past five years, our company has been named the Most Reliable Utility in the Midwest. The award given by the P.A. Consulting Group was announced in November of last year, and is based on the company's performance for the year 2005. Now I'll turn the call over to Allen, who will give you more details on our financial performance for the year and our outlook for 2007, Allen.

Thanks, Gale. I'm going to focus my remarks this afternoon on earnings from continuing operations, but information regarding earnings from discontinued operations is also included in the earnings package. It may be helpful for you to refer to pages 8 to 11 of the earnings package as I review our results. Earnings from continuing operations were $2.64 per share for 2006, versus $2.56 a share in 2005. Now, on a consolidated basis, our operating income was 569 million versus 563 million in 2005, or an increase of $6 million. Operating income for the utility energy segment, which is comprised of Wisconsin Electric, Wisconsin Gas and Edison Sault was 533 million compared to 542 million in 2005, for a decrease of $9 million. Positive earnings drivers for this segment in 2006 included improved electric fuel cost recovery, an increase in natural gas rates, and one fewer planned refueling outage at the Point Beach nuclear plant. The most significant of these factors was the change in natural gas rates. This increased operating income $53 million. The favorable fuel recovery and lower nuclear O&M items, increased operating income 36 million and $11 million respectively.

The primary negative driver in 2006 was very mild winter weather. The weather reduced operating income $55 million as compared to 2005. Additional planned O&M expenditures at our fossil plants reduced operating income $35 million, a contract settlement in 2005, which did not reoccur this year, represented a $10 million reduction, and other items in total reduced operating income $9 million. Netting the impact of the positive and negative factors I just reviewed, brings you to the $9 million decrease in the utilities segment's operating income for 2006. Operating income in the non-utility energy and corporate and other income segments, which primarily includes We Power, was up $15 million. The largest increase relates to a full year of operation at the Newport Washington plant. Taking the changes for each of these segments together brings you back to the $6 million increase in operating income for 2006. Other income, including our earnings from the American Transmission Company, was up $28 million in 2006. Increased carry-on deferred costs in AFUDC added $10 million, increased earnings from nonconsolidated affiliates, including our investment in the American Transmission Company, contributed another $9 million, a gain on the sale of Guardian, $3 million, and all other items combined added a total of $6 million. Total interest expense was flat at 173 million.

Consolidated income tax expense increased to $26 million as compared to 2005. Now, $11 million of this increase related to the ability to recognize state tax operating losses at the parent company level. We actually had a benefit from the ability to recognize these losses in both 2005 and 2006. However, the benefit recognized in 2005, was $11 million more than the amount recognized in 2006. The remaining $15 million increase in income tax expense was driven by higher income, as well as a slightly higher effective tax rate. Excluding the benefit of the state item I mentioned in both periods, our effective rate was 37.1% in 2006, versus 36.6% in 2005. Adding these items brings you to $312 million of net income from continuing operations for 2006, versus 304 million of net income from continuing operations last year. In EPS terms this equates to $2.64 per share, versus $2.56 per share in the same period last year. If you exclude the gain on the sale of our Guardian Pipeline interest of $0.01 per share, and the gain on the reversal of state tax NOL's of $0.05 per share, our adjusted earnings from continuing operations were $2.58 for 2006. Excluding reversal of state tax NOL's of $0.14 per share last year, the adjusted earnings from continuing operations were $2.42 for 2005.

Now I'd like to turn to cash flow. During 2006, we generated $730 million of cash from operations. This compares to $577 million in 2005. The improvement was largely driven by lower working capital requirements for natural gas and storage, and a significant reduction in deferred costs. We had capital expenditures of $929 million in 2006, 463 million of this was dedicated to our utility and other businesses, and 466 million was for the generating units being constructed as a part of our Power of the Future plan. In addition, we paid $108 million in dividends.

Our debt-to-capital ratio was 59.5% at the end of 2006. Now, this is the same level we were at year-end 2005. Capital spending in 2007 is expected to be approximately $1.4 billion. If we go to financial closing on Point Beach this year, I expect that our debt-to-capital ratio at year-end 2007 will be at or below 59.5%. If the sale does not close in 2007, I expect our year-end 2007 debt-to-capital ratio will increase from the 59.5% level. However, as we've stated in the past, our goal is to maintain our debt-to-capital ratio at no more than 61.5% during the period we are constructing our new gas and coal-fired generation. This would exclude the portion of any hybrid securities we may issue that would be treated as an equity equivalent by the credit rating agencies. We are going to use cash to satisfy any shares required for our 401(k) plan, options and other programs. Going forward, we do not expect to issue any additional shares.

Now, on January 18th of this year, we announced an 8.7% increase in our common dividend. The new quarterly rate is $0.25 a share, which brings our annual rate to $1 a share. This new rate will be effective with the first quarter dividend payable on March 1st. The increase reflects the confidence we have in our business plan. We've now raised the dividend in each of the past four years, for a total increase in the quarterly dividend of 25% since the beginning of 2004. Our goal continues to be to raise the dividend on a consistent predictable basis, at approximately half the rate of growth in our earnings per share.

Now, I'd like to wrap things up with a discussion of earnings guidance for the full year 2007, as well as the first quarter. Of course, 2007 is a transitional year in a couple of respects. From the standpoint of our Power to Future plan, 2007 is the bridge to the 2008 to the 2011 period, in which we expect to see significant earnings increases from our second gas fired unit at Port Washington, and our two coal fired units at Oak Creek. Also, we expect to divest our nuclear unit in 2007, and begin reinvesting in our planned wind projects. Our 2007 earnings guidance range remains at the $2.60 to $2.70 per share range that we provided you in December.

The anticipated earnings drivers for 2007 fall into four groups: Price increases, changes in sales volume, including the effects of weather, cost increases at our utilities, and an increase in our effective tax rate. Price increases are expected to add approximately $0.15 per share. This includes expected price increases for our wholesale electric customers, a full-year effect of the retail electric and gas price increases that were implemented near the end of January of 2006, and the second step of the steam price increase the Public Service Commission of Wisconsin approved in 2006. A return to normal weather and modest volume growth unrelated to weather are expected to add between 12 and $0.17 per share. Cost increases at our utilities are expected to reduce earnings 15 to $0.20 per share, and about $0.12 of this is being driven by increased depreciation expense. Finally, an increase in our effective tax rate is expected to reduce earnings $0.05 per share. So just to summarize, the impact of increased prices is expected to add $0.15 per share, the impact of volume, including a return to normal weather, is expected to be between a 12 and $0.17 per share increase, the impact of cost increases is expected to reduce earnings 15 to $0.20 per share, and finally an increase in the effective tax rate is expected to result in a $0.05 per share reduction. Adding these drivers together and translating into a range, gives you 2 to $0.12 per share projected earnings growth. Adding this range to the $2.58 per share base in 2006, brings you to our 2007 earnings guidance range $2.60 to $2.70 a share. This assumes full ownership of Point Beach throughout all of 2007. Once the closing of the sale occurs, we will update our earnings guidance. But, for example, if we close the sale on August 31st, I expect we will reduce our guidance range for 2007 by $0.05 per share.

Although we will not be giving earnings guidance for the first quarter, I did want to give you a feel for the earnings drivers that I expect compared to the first quarter of 2006. Now, the quarterly pattern of earnings in 2007 is expected to be somewhat different than the pattern we saw in 2006. This is being driven by the timing of maintenance outages at our power plants, which in turn drives quarterly electric fuel cost recovery. In 2007, our plan generation outages are largely scheduled for the spring. Whereas in 2006, they were more clustered in the fall. The effect of this is to increase fuel expense in the first half of the year, and decrease fuel expense in the second half of the year relative to 2006. Now, we earned $0.88 per share in the first quarter of 2006. If you build from this level to make your estimate for the first quarter of 2007, you should take into account that the change in the timing of fuel recovery alone is expected to reduce quarterly earnings $0.10 per share. Remember, though, this is strictly a timing issue intra-year. For the full year 2007, I currently expect we will be fully recovered on electric fuel expenses. With that, I'll turn things back over to Gale.

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

At this time, we will open the call up for questions from analysts.

[Operator Instructions ] We'll take our first question from [inaudible].

Good afternoon.

Hi, [Resa], how are you?

Very good, how about yourself?

Fine, can you hear us all right?

Absolutely.

Very good.

I think you mentioned a CapEx in 2007 is 1.4 billion. I'm sorry if I missed it, but what portion of that is for Power of the Future?

Allen has all the details.

Of the 1.4 billion, as I would expect, about 700 million of that to be for Power of the Future, roughly another 240 million for our wind projects. So combined, 740 million -- 940 million rather.

And how about CapEx for 2008 and 2009? I guess, in the press release it said 3 billion over three years, if I'm not mistaken.

I would expect to come in at right at about a billion dollars in 2008, and roughly 800 million in 2009.

And what portion of those two numbers are power Power Of the Future?

Sure. In 2008, I would expect Power of the Future to be 475 million, and in 2009, I would expect 200 million.

Great, thank you very much.

You're welcome, Resa.

We'll go next to Ted Heyn, Citigroup.

Hi Ted, how are you today?

Not too bad. Just a quick question to follow up on the CapEx, the increase for '07, is that largely due to the fact, I think you were projecting for '06 to spend over a billion and it looks like you came in closer to 900. Is there some timing that you didn't spend in 2006?

That -- well, I think it really more relates to the wind projects. Originally when we talked about the wind projects, we were thinking the expenditures would be in late '08, maybe even spreading into '09. And in this outlook we're really pulling them forward so that we can bring the wind projects online in 2008, as Gale described.

Understood. And just a little more detail on the approval from the commission on spending on the wind. How much did they approve again?

They approved -- go ahead, Allen.

They approved up to $394 million, including capitalized carry during construction. But that 394 million assumed 2.3 megawatts per turbine. So 88 turbines, if I'm doing the math right, would put you at about 200, 202 megawatts, somewhere in that range. But there's flexibility to use turbines ranging all the way from 1.5 megawatts to 2 .3 megawatts. So, as Rick and his team go through the optimization of the sites and work with the vendors, we'll choose turbines in that range, and obviously where we come out in that range of sizing, will drive the capital expenditures.

As I mentioned in the prepared remarks, Ted, where we end up against the 394 million, really will be pretty proportional, it's pretty linear, in terms of whatever size we choose as the most optimal for the site in terms of size per wind turbine. But the commission in its order has given us the flexibility to negotiate the best possible deal we can with wind equipment vendors, and maximize the site to the best we can from an economic standpoint.

Understood. When you guys think about wind moving forward past the Blue Sky project, I know that you have an option within the Point Beach agreement to take a farm from FPL, or land from FPL, to build out more wind. When do you think about, kind of layering on the next layer of wind, to meet your renewable portfolio standards?

Well, if you stand back, it's a very good question, Ted, if you look at what is driving us in terms of wind construction, it's clearly the compliance with the renewable portfolio standards that was put into law here last year. This particular Blue Sky Green Field wind project will get us close, not completely there, but this will get us close to our 2010 requirement. Then we need to begin looking at, what do we need to do to hit the 2015 requirement, where the 10% from renewable sources goes to 15%. So clearly, just given the economics of renewable energy sources, wind continues to be the very best alternative, given the scale we need. And we will be looking beyond, in our planning models, very soon here, but we've got to get this one under our belt first. But this one will get us fairly close. The Blue Sky Green Field wind project will get us fairly close to the 2010 requirement. And then we'll have to have a significant ramp-up before 2015.

Understood. Thank you very much.

You're welcome, Ted.

We'll take our next question from Doug Fisher with A.G. Edwards.

Good afternoon, Doug.

Good afternoon, Gale. Just a couple of questions. Real estate sales in '06 and '05, can you, how much was Wispark in each year?

This is Steve Dickson, he's going to give you the details, Doug.

Yes, basically, as you know, as we talked about in the past, real estate sales are winding down. For Wispark in 2006, the proceeds we received were about 20 million, and then in 2005, it was about 54 million. So, going from 54 down to 20. As we said in the past, that's a business that we're winding down. And their earnings really weren't significant in either year.

And Doug, I guess, as you look, just to add to that, as you look at what real estate remains, if you look at unregulated real estate, stuff outside of the utility, in total there's about $100 million worth of real estate, about 60 of that is at Wispark, and another 40 is in other unregulated subsidiaries. So about 100 million left. So there's, relatively speaking, not very much left.

So Steve, just to rehash, earnings not significant but the proceeds were 20 and 54?

That's correct.

That's correct.

And then could you comment on the financing plans for '07?

Sure, and if I could maybe talk about it at least for the holding company for 2007 and 2008 combined. As I look at term financing, so long-term financing at the holding company itself, I would expect that we would do anywhere from 5 to $600 million worth of long-term financing between 2007 and 2008 at the holding company. Now, down at the Wisconsin Electric Power Company level, I would expect term financing, so, again, long-term debt, term financing in 2007 for Wisconsin Electric, to be about 500 million. Then I wouldn't expect to be doing any long-term financing at Wisconsin Electric in 2008, but we would do another bond offering at We Power in 2008, because that's the year that we would expect to bring the second gas unit on at Port Washington. And if we size that similar to the financing we did in July of 2005, that would be about $158 million.

And again, that would be as we bring that unit into commercial service.

It would be in conjunction with commercial operation of the unit, Doug.

And you mentioned hybrids, would that be part of the holding company?

Yes, if we did it, it would strictly be at the holding company. So that's sort of five to $600 million basket, if you will, of long-term financing at the holding company. I would see doing potentially a combination of hybrids and long-term debt, but in total, if you look at the amounts we did between those two types of securities, it would be between five and 600 million spread over the 2007 to 2008 time frame.

And any color as to what proportion of that you might expect to be hybrids?

We're very much, Jeff West and his team are still evaluating that. But I really wouldn't want to put a number on it at this point, Doug.

And then sales, obviously, were hurt by weather on both the gas and the electric side. Can you give us any numbers in terms of unit sales, weather-adjusted? Is there still underlying growth?

Doug, yes. A couple of things, as Allen looks at his weather-adjusted numbers for you. What we're seeing, and you think about what happened in 2006, we had the mildest first quarter literally since temperature records began. And then we had a very mild second half of December. So, largely in terms of our gas operations, and the electric operations for that matter, the decline in sales came first quarter compared to normal, and in the fourth quarter. So you see the decline in residential consumption very much driven by weather. We continue to have good customer growth, we've had in excess of 1% customer growth on the electric side, and about 1.1, 1.2% growth in customers on the gas side. It's the other piece that's affecting short term, the economy here right now, is really several industry sectors. Iron ore mining, paper production, food processing, and very significantly automotive part suppliers. Those are the four segments of the industrial economy here in southeastern Wisconsin that have really been quite soft, and that had an impact on our industrial sales. I hope that helps bring the picture for you. Allen, weather adjusted?

Yes, maybe this puts some numbers around it, for you Doug, if you look, versus normal. So, look at 2006 versus normal, instead of looking at 2006 compared to 2005. Swing versus normal was about $32.6 million. So meaning in total, 2006, if you look at a margin level, was $32.6 million below normal. So it if you had a swing back to normal, that would be a $32.6 million swing. Of that 32.6, roughly 14.4 was in the electric business, and roughly 18.2 was in the gas business. So that's -- that would be probably be helpful to you as you sort of look forward to '07. So that would be the impact versus normal. And I think as Gale was saying, from a qualitative standpoint, we've still been having some headwinds, if you will, in the industrial sector in the areas that he mentioned.

Okay.

Did we respond to your question?

Yes, thank you.

You're welcome.

We'll take our next question from Michael Lapides with Goldman Sachs.

Hi, Michael, how are you doing today?

Hey, guys. I'm fine, and you?

We're doing real well. It's cold here, we're doing real well.

It's cold here as well. I wish it would be a little bit warmer, but I guess for your sake, it's a good thing to be ice cold.

You know, a good hearty winter keeps the blood flowing.

A couple of easy questions, first on O&M expense, and I think you talked about it a little bit in the introductory remarks, Allen, but I want to double back with you. Fourth quarter O&M was up substantially from the prior year, can you talk about which of that component, and I think it's a total of almost like 60 or 65 million bucks, how much of that is recurring versus, kind of, one off?

Yes, let me talk about the fourth quarter and then also, sort of give you a little bit of color for '07. I think when you look at our O&M results, there are a couple of adjustments you have to make, to sort of get something that's meaningful to the basic business. You're right, if you look at just the raw variance, fourth quarter of '06 versus fourth quarter of '05, it's right at $65 million. But then when you peel back and see what's in there, about 41 million of that 65 is associated with things that I would refer to as regulatory amortizations. You know, for example, there's $17.5 million of that 40 that's for increased tariffs at American Transmission Company that we're recovering in rates. There's about 4 million for bad debt, that in previous years we didn't have in rates and we deferred now in 2006, we have it in rates and we're no longer deferring it. So, you have revenues to cover that. There's another 17 million that's for the carrying costs of the new units that we're building in PTF. So, if you take out that $41 million that's the really not associated with the basic O&M in the business, you're left with a variance of something closer to $24 million. As you look at that $24 million, almost all of it was associated with O&M planned maintenance at our fossil plants. So, I think you have to peel back a bit to understand what's really going on with O&M in '06. What might be more helpful to you is sort of looking forward at O&M. As I look to 2007, I would actually expect fossil to be down slightly because the maintenance schedule will be lighter in '06 -- I'm sorry in '07 than it was in '06. Nuclear O&M will be up, but just very slightly. All the rest of our basic business, at least from an O&M standpoint, is flat, and then what you're really left with are those depreciation expense increases that I talked about, and financing cost increases at the utility. So, from an O&M standpoint, we're basically looking at a pretty flat year-over-year outlook, '07 versus '06.

And as Allen said, Michael, if you strip out these regulatory amortizations that were covered in our 2006 rate case, our basic O&M at the utility was pretty darn flat.

Right.

One kind of follow-up question regarding financing plan, and you talked a little bit about hybrids and maybe over the years I've missed it, but I didn't realize that that -- we view hybrids, if they have an equity component, as -- while it's smaller, it's still somewhat of an issuance of additional diluted shares.

I disagree with you on that, Michael. These do not have any sort of replacement provision where you would issue shares. So, if you had a situation where you didn't pay interest on the hybrid securities, there's no provision that's built in here where you would issue equity to pay those deferred interest payments. There's some securities where you're right, where they do have that provision, you could have something happen with the diluted share count. The types that we're looking at wouldn't have any impact whatsoever.

So, you're not looking for things like converts or that type, you're looking more at things like, I don't know, the go old fashioned toppers, or quips or something along that line.

To be more specific, we're looking for things that would give us right down the middle of the fair way basket C, to Moody's rating scale, or for hybrid equity treatment. So, you get about an imputation of 50% equity from the rating agencies. But we're not looking at anything that's convertible or affects share count, either basic or diluted.

Great. Thanks guys.

You're welcome, Michael. Take care.

We'll take our next question from Nathan Judge, with Atlantic Equities.

Nathan, how's London today?

It's cold here as well. It's cold everywhere.

It hasn't gotten below zero, has it?

Well, no. But it's relatively colder, so it feels probably colder than it really is. I just have a couple of follow-up questions. And actually, I just wanted to look at the O&M again, if I could. But you, in your guidance you did talk about cost increases, including O&M would go up about 15 or $0.20 of which $0.12 was depreciation. Is the additional amortization that you saw in '06 flowing through to '07, or what's kind of driving that? Because you did mention O&M is actually going to be what you expected to be down.

Yes, you just sort of take regulatory amortizations to the side, because they essentially don't impact book income, and just look at the things that affect book income. That was the cost increase in at least earnings per share terms that I was talking about between 15 and $0.20 a share. And of that 15 to $0.20 a share, $0.12, Nathan, would be for depreciation, about $0.04 a share for additional financing costs at the utility, and another $0.04 a share for taxes other than income taxes at the facility.

Oh, that's clear. Okay. It's not O&M costs then?

Not traditional utility operating O&M, not at all.

Right. Just also on other income, that had gone up quite considerably in '06 and clearly there's some benefits from ownership in ATC as well as [inaudible] and carrying costs. As we look out to 2007, I did not hear anything, or comment about other income. Should we kind of look at that as a sustainable level at that 90 to $100 million level?

Well, I think as you look at other income and look at the drivers, there was AFUDC and carrying costs, and I would certainly expect those to continue as a similar level. We'd have a nominal amount of growth at ATC, but otherwise, I would expect to be pretty stable at the level of other income that you saw in 2006.

But as you increase your investment in some of these new plants, wouldn't the AFUDC carrying costs go up?

Well, there's very little that we have that you would get AFUDC treatment for, because remember, the Oak Creek plant and the Power Of the Future, the Port Washington plant, you don't get AFUDC, you don't get book income for those, you just get cash/carry. There would probably be a nominal amount that we would have for wind but that depends when in the year we start spending the capital for the wind.

Allen's right, other than some minor other utility upgrade projects like substations and distribution upgrades, really the only major element on which we would get some kind of AFUDC or carrying cost like AFUDC would be the wind project.

Right. So, could you just kind of break down other income and how much of that is ATC? I'm a little bit confused about, is if there aren't any projects, then why do we expect AFUDC and carrying costs to remain at these high levels?

Well, we expect them to remain at about the same level they were in 2006. I think that was your question, whether you could see any year-over-year change. In terms of the income from ATC, we actually now break that out separately on the income statement. But in 2006, for the -- so, for the 12 months ended December 31st, 2006, equity and earnings for ATC was $38.6 million, and that compares to $34.6 million in calendar year 2005. So, about $4 million worth of growth year-over-year. But, as I look at other income in total for 2007, I would expect it to be pretty similar to other income in total that we saw in 2006.

Fair enough. Just on ATC, could you just update us on any reviews of that business and any progress, or otherwise on the opportunities in that business itself as far as monetizing it or not monetizing it?

Be happy to, Nathan. As we have mentioned to you before, ATC has a very active board of directors, any decision about any change in structure or ownership of ATC rests with that board of directors, and the business continues to truck along. And again, any decision would rest with the board of directors, and we have one vote.

And my final question is, you didn't highlight your customer service, and the reliability has been very strong. I know, Gale, you've been very focussed on trying to improve customer service, as coming from your predecessor, but could you just give us some of the metrics, some of the updated metrics over time, that now that it's been several years and where we are, and where you have to take it from here?

I'll be happy to, 2006 was the best year, since this company began measuring about a decade ago, the very best year for customer satisfaction. We had a very significant uptick in customer satisfaction. We ended the year with total satisfaction, both very satisfied and satisfied customers right around 90%. So, we've made enormous strides in the last three or four years in improving customer satisfaction. We'll see as the national surveys come out, but right now, just looking at the underlying metrics, it appears that we're knocking on top half of the top quartile in the industry on customer satisfaction.

Very good. Thank you very much.

You're welcome, take care, Nathan.

We'll take our next question from Dan Jenkins with the State of Wisconsin Investment Board.

Dan.

Hi, good afternoon.

How are you?

A little cold.

Yes, Dan, last time you and I saw each other, I think it was Vegas.

Right. A little warmer there.

A little warmer there, and I assume you want what went on there for you, to kind of stay there, is that right, Dan?

No, I had a couple of things on the balance sheet.

Okay, moving right along. Dan, the payment can come to me directly at 231 West Michigan.

I was just wondering, the short-term debt is up about double, is that related to the Power of the Future construction?

Let me just take you through that. If you look at short-term debt at the end of the year, of that, say, roughly $900 million worth of short-term debt, about 575 million of it was at the parent, and the remainder, the balance, was at the Wisconsin Electric and Wisconsin Gas. The level that's at Wisconsin Electric and Wisconsin Gas it's very normal levels which you would see related to the working capital cycle. The level that you see at the WEC parent was influenced very much by maturity that we had in April of 2006. We had a $250 million maturity at WEC in April, and we chose, given the uncertainty with Point Beach, we chose to leave that in short-term debt through the end of the year. So, that 250, if you will, is a bit of a -- it's just a timing difference we would expect to term that out this year. So, as I look at the short-term debt levels within the context of the overall debt levels at the company, it's right according to plan. And, in fact, if you look at the increase in net debt overall, 2006 versus 2005, there was only an increase of $300 million in debt in 2006, and it's kind of interesting if you go back to 2005, it was the same increase, 300 million in 2005. So we had a very consistent, sort of, in absolutely terms, increase in debt each year and, of course, since the debt-to-cap ratio has been steady, that means we've been growing equity in lock step with that increase in debt.

And as Allen said, you see that pattern in the face of $930 million of capital investment that we made last year.

Right. Also, just to clarify, you know, when you talked before about the long-term financing, you said five to 600 million, '07/'08 at the parent, or at the holding company.

Right.

Then you said 500 million at Wisconsin Electric, I think, but that would strictly be in '07; is that correct?

That's right. And depending on market conditions, we could spread some of that into 2008. But $500 million worth of term financing there and then another roughly, $158 million worth of term financing in 2008 at We Power in conjunction with the commercial and service date of the second port unit.

Okay, and then just kind of looking into '07 weather-wise, obviously, January's been extremely cold, at least the last two-thirds of it or so.

About the last one-third.

So how on -- are you -- have you been heating degree days higher than normal, or about normal or, you know, or what's kind of look so far in the first quarter?

Well, if you look at January, actually total heating degree days were slightly below normal. We had a very mild, very mild first half of January, reasonably normal weather for much of the second half, and then a cold snap, the arctic cold that has gripped the region here for the last week or so, really didn't hit until about the last two days of January. So, when you look at January as a whole, nothing alarming, but just slightly below what one would consider normal heating degree days. February so far, obviously, has been huge. In fact, on Sunday and Monday of this past week, we set two new all-time gas delivery records for a 24-hour period. In the Monday gas delivery record was 6.6% above the record we set back in the winter of 2004. So, demand has been, because of the weather, extraordinarily strong in the first few days. My guess is that when we see our reports this week, that we will be about normal if you combine the first week of February with all of January, and back on track.

Okay, and that compares to last year where it was milder, quite a bit milder than normal, right?

Oh, gosh. Yes, last January was the mildest January since 1880.

Okay. All my --

I don't even think they had slot machines, Dan, in 1880.

I think they did, but they -- [ LAUGHTER ] They weren't quite as fancy as the ones they have now.

Yes, exactly.

Okay, all of my other questions have already been answered, so thank you.

We appreciate your interest, Dan, you take care.

Okay, thanks.

We'll take our next question from Scott [Sencheck] with [inaudible]

Hi Scott, how are you today?

I'm hanging in there, trying to get over the Bear's loss last weekend, but I guess you guys are pretty happy about that, wearing green up there?

Exactly, and Brett Farve is coming back -- And what have you done with Andy?

Andy had to take off a little early today, so -- But, just a quick question for you. On the, I guess it's the water discharge permit, just wondering if you can go over the best-case and worst-case scenarios.

Sure, I'll be delighted to. Best-case scenario, obviously, is that the Dane County Circuit Court Judge agrees with both our company and with the issuer of the permit, the State Department of Natural Resources, that the permit is completely valid and that there's no change required to the permit. And the judge makes that ruling sometime this year. That's, I think, the best case. And in our judgment, a very reasonable case. Worst case, well, clearly the judge has a couple of alternatives, we believe. The three practical alternatives that the judge has in this overall case is, Number 1, she could affirm the validity of the permit, which means nothing changes. Secondly, she could invalidate the permit. And thirdly, she could remand the permit to the State Department of Natural Resources for either further clarification, or some modest change. I think those are her three options. Again, we believe, really there's nothing new here. The Federal Appeals Court decision that the opponent cited in their request basically to reopen the record in the case, our view, and the view of the State Department of Natural Resources is that, that Federal Appeal's Court decision really has no meaningful impact on this permit which was issued by the state, not by the federal government. In fact, the State Department of Natural Resources, that's kind of the state EPA, in their submission to the court last week, they basically said very bluntly, the River Keeper Two case, that's this Federal Appeals Court case, is neither controlling, nor persuasive as an authority in this case. So, we're hopeful that this will just continue to proceed and the case will come to a reasonable conclusion here in the matter of the next few months.

Got you. One more question. I guess in the rate case that you guys will be filing, shortly, I guess, just kind of wondering which major costs that you guys will be filing to recover?

Well, Allen and I will both take a shot at that. Clearly, there are additional required by law costs that we will be allowed to recover, and we will ask to recover in the rate case for our continuing investments in Power of the Future. I mean, that's clearly Number 1. Number 2, we will be needing to recover additional costs for the ongoing upgrades and system reinforcements that we're needing to make as our customer base grows, and as we need to replace aging equipment on our distribution system. So, there's Power of the Future capital that needs to be recovered, there's normal utility upgrade and growth capital that needs to be recovered, and then, I'm sure some modest O&M increases that we need to continue to recover. We have essentially, in terms of base rates for normal operations for the utility, we've been flat for eight years. And we've done a very, very good job of cost control. At some point, some modest increase will be necessary. So, those are three areas that definitely we will be looking at in the rate case. And as Rick is pointing to me, we'll also have some environmental capital that will need to be recovered.

Okay, great. Thanks a lot, stay warm, guys.

Thank you.

We'll take our next question from Paul Ridzon with KeyBanc.

How are you today, Paul?

Good, yourself?

Doing well, sunshining, oh, just barely double digits, we're doing real well.

What's the mechanism that Point Beach is going to come out of rates? Is it just going to be a rate case filing, or is it just an [inaudible] arrangement, or, how is that going to work?

Well, we will, let me separate that into two pieces for you. The first is that we would assume that when the commission makes its decision, and assuming the commission approves the sale of the unit, at the same time they would make an adjustment in base rates. Then in terms of the, -- or they might say, well, we'll just leave it as is, but the extra purchase power costs that you would incur would offset the earnings from the plant staying at rate base. So, they have a couple of options there.

Okay.

Then, as we work our way through the full details of the 2008 rate case, in other words, the rates that would go into effect permanently for January 1, 2008, we would expect that all of the sale of the cash benefits to customers associated with the sale of Point Beach would become then worked through in the rate case. So, I think we'll see two pieces here. We'll see some action taken, obviously, assuming the commission approves the sale, at the time of the sale, and then a final resolution of all the benefits from the sale, plus all the other rate requests that we need to put in front of the commission, all of that would get rolled together in the formal rate case proceeding. Does that make sense, Paul?

And then you mentioned that you're still sizing your turbines for the 88 towers. Will all 88 towers have identical sister turbines?

Rick is saying they absolutely will. Rick?

What's fixed in our Blue Sky Green Field project is the number of sites, but we will buy turbines on a volume basis and we will buy them all from the same manufacturer. So, they will be either all 1.5's, 1.65's, 2.3's, but they'll be all the same size.

And then, I think it was FPL was indicating that as they were -- as technology was delivering larger turbines they were having some meaningful capacity factor issues with those turbines. What's the vintage of the turbines on the top end and what reliability do you expect if you go there?

I'm not familiar with the FPL problems, but we are looking at 2007 turbines. So, we're not looking out multiple years. We're looking at proven technology. So, given this is our first wind farm we would not be getting too far out on the development curve, so to speak. And I feel pretty comfortable that the stuff we're currently engaged in negotiations with is proven technology and we wouldn't be seeing any kind of leading-edge problems there.

Are you far enough along at the site to have an expected capacity factor?

We've done the wind studies and we've got -- we have file capacity factors with the commission. Right off the top of my head, I don't recall, but I want to say they're in the mid-20s.

Yes, mid to high 20s.

Okay. Thank you very much.

You're welcome, take care.

Ladies and gentlemen, we have time for one more question, it comes from Paul Patterson with Glen Rock Associates.

Good afternoon, Paul.

Good afternoon, guys.

How you doing, Paul?

I'm doing okay. I'm a little slow on a few of these things, I apologize for going over them again.

Paul, that has never happened before.

Yes, unfortunately -- in terms of the operating cash flow and the depreciation, I mean, you guys mentioned, there's a regulatory amortization that fell off; is that correct?

One more time, we didn't hear you at the end there, Paul.

I'm sorry, the depreciation and amortization went down because of a falloff in a regulatory amortization; is that correct?

Well, what we did there in the context of the rate case that was filed in 2005 and decided in early 2006, the commission stretched out the depreciable life for Point Beach. So, almost all of this impact that you're seeing on the income statement related to depreciation is associated with the lengthening of those depreciable lives. And the reason they did that is because we expected to get relicensing for the plant, so you had a 20-year life extension.

That has no [indiscernible] impact is that right?

I'm sorry, Paul, one more time?

That has no net income impact because your rates reflected that, I would assume, right?

It was factored in, so.

Yes, that is correct.

Okay. Then I'm looking at the cash flow statement, I guess, if we back out working capital, it seems the cash flow went down, I guess, particularly because of the deferred income tax and investment tax credits?

Our cash taxes were somewhat higher in 2006, so that's right. And what you had as an offset was working capital. And working capital really had two aspects that had the gas storage, the gas inventory, but also you had a situation where in 2005 you had a significant amount of costs that were deferred that weren't covered in current rates, and then in '06 and '07 you got recovery of that.

Okay. But then the deferred income tax, how does that go -- what's the treatment of that in '07 and beyond? I mean, what do you expect to happen there? Is that going to be a negative or is that going to be a positive?

Well, I would expect in 2000, looking to 2008, 9, 10, looking out in those years, you're going to be closing a significant amount of investment to plant and you should be generating a significant amount of tax depreciation. I would expect actually deferred taxes to actually be a source of cash, as opposed to use of cash, if you will, in those periods when you start closing that investment to plant.

Right. What was it in 2006 again?

Well, remember, you had a significant amount of bonus depreciation that we took in 2005 associated with the first Port Washington unit. So, there was a tremendous amount of tax depreciation that was taken. In fact, I think we were able to depreciate roughly a third of the unit for tax purposes in 2005, and obviously, I couldn't do that again in 2006.

Okay, I got you. And then finally, I apologize for going over this again, but the hybrids you guys are planning on issuing, do not have a dilutive impact. What are these hybrids that you're talking about, they don't have any equity component, is that it, or --?

Well, the one that's probably closest to a real deal that's been done, Wisconsin Public Service issued $300 million worth of hybrids, I believe, in December, or late last year, if it wasn't exactly December, and again, they're just the so-called Basket-C hybrid securities. And they're not convertible securities. I mean, effectively they're subordinated debt, but they're so deeply subordinated, that the rating agencies give you about 50% equity credit, if you will, when they run your ratios.

Right, okay.

In fact, it's deeply subordinated debt, to be quite honest.

So really, a hybrid, I guess, is more of a just a nip or something like that.

Well, that's what the investment bankers call them.

Your friends in the investment banking business call them hybrids.

Okay. I appreciate it, thanks a lot, guys.

Paul, take care.

That does conclude our question-and-answer session. At this time I would like to turn the call over to Mr. Klappa. Please go ahead.

Thank you, we appreciate your interest and that concludes our conference for today. Again, we thank you for participating. If you have any other questions, Colleen Henderson will be available in our Investor Relations Office, and her direct line is (414)221-2592. Take care, everyone.

This concludes today's call, you may disconnect at this time.