威斯康辛能源 (WEC) 2010 Q4 法說會逐字稿

Good afternoon. Thank you for holding, ladies and gentlemen. And welcome to Wisconsin Energy's conference call to review 2010 year-end results. This conference is being recorded for rebroadcast, and all participants are in a listen only mode at this time.

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. And our earnings per share will reflect the dilutive shares of as December 31, 2010. Also, unless otherwise noted, the earnings per share figures stated on this call will not reflect the effects of the two-for-one stock split that will occur on March 1, 2011.

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 2010 year-end results at www.wisconsinenergy.com. A replay of our remarks will be available approximately two hours after the conclusion of this call.

And now I would like to introduce Mr. Gale Klappa, Chairman of the Board, President and Chief Executive Officer of Wisconsin Energy Corporation.

Colleen, thank you. We found Colleen under seven feet of snow this morning but she's doing fine. Good afternoon, everyone. We appreciate you joining us on our conference call to review the Company's 2010 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, General Counsel; Jeff West, our Treasurer; and Steve Dickson, Controller.

Allen will review our financial results in detail in just a moment. But as you saw from our news release late yesterday, we reported earnings from continuing operations of $3.84 a share for 2010. This compares with $3.19 a share for 2009. During 2010, we began to see an economic recovery across the region we serve, as well as a return to more normal weather. Our earnings were also boosted by nearly a full year's contribution from our investment in the first expansion unit at Oak Creek. Overall, I'm very pleased with our financial and our operational performance for 2010. From customer satisfaction to network reliability to completion of our Power the Future plan, the Company made great strides during the year.

Now I'd like to spend just a moment on our continuing effort to upgrade the energy infrastructure in Wisconsin. Our Power 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 natural gas-fired units at Port Washington, north of Milwaukee, the construction of two super critical pulverized coal units at Oak Creek which is south of the city, and building a significant amount of renewable generation. I'm delighted to report that since our last call, Unit 2 at Oak Creek passed all of its performance tests and was placed into commercial service in the early morning hours of January 12, 2011. You may recall that the guaranteed turnover date for Unit 2 at Oak Creek was November 28, 2010. However, during the final stages of testing, Bechtel experienced vibration problems with one of the main boiler feed pumps for Unit 2. During December and early January, Bechtel addressed the technical issues and we were able to reach agreement on a number of other contractual items, clearing the way for the unit to achieve commercial service. As part of that agreement, Bechtel will pay liquidated damages totaling nearly $6 million as compensation for not meeting the guaranteed date. The $6 million will ultimately be passed on to the benefit of our customers.

Now, the critical performance measures that Bechtel was required to meet before Unit 2 was declared ready for commercial operation included an efficiency test, various emission tests, a capacity test and a 15 day reliability run. And I believe the results of these tests are of particular note. The efficiency test, or as we call it, the heat rate test, measures the efficiency at which the unit converts fuel into electricity. The more efficient the unit, obviously, the less coal we have to burn, and therefore, the lower cost per each unit of electricity produced. For Unit 2 at Oak Creek, the demonstrated heat rate is more than 6% better than the guarantee, and places this unit among the most efficient base load power plants anywhere in the country.

With regard to emissions, we have been even more impressed by the plant's performance. The recorded emission level for each of the 15 pollutants measured at the stack is significantly lower than the levels allowed by our permit. In many cases, such as sulfur dioxide, particulate matter and mercury, the levels actually were a fraction of that allowed in our permit. The guaranteed capacity of each unit is 615 megawatts net, and that means that the unit must be capable of delivering 615 megawatts into the transmission network. During testing, the output was measured at 625 megawatts, and we believe the unit can actually deliver more than 625 megawatts based on the extra margin available in both the boiler and the steam turbine generator. Or to put it simply, we're getting more capacity and more efficient capacity than we paid for.

Turnover of Unit 2 at Oak Creek is a significant milestone and brings to a conclusion the development of the conventional generation in our Power the Future plan. The program was conceived, as you recall, just over a decade ago to insure that our customers would have a source of competitive reliable power for years to come. And to insure that Wisconsin and the Upper Peninsula of Michigan would have an energy supply network that could support new jobs and economic growth. It's not been an easy journey. Along the way we even took an interesting detour to the Wisconsin State Supreme Court. But I'm delighted with the perseverance and the dedication of our staff and our contractors who delivered on the largest construction effort, by far, in the history of the state. Of course, this is not the end of the road. We still have much more to achieve. In particular, we'll be focusing in the year ahead on unit reliability at Oak Creek. And to that end, I'm pleased to report that Unit 1 achieved an average availability during November, December, and January of more than 94%, and continues to operate very well.

Now, as you know, we also have a number of other major projects underway that form the foundation for our next leg of growth. Construction is proceeding very well on the second largest project in our history, the upgrade of the air quality controls for the existing coal-fired units at Oak Creek. At year-end, the project was 65% complete. We're investing, as you may recall, approximately $910 million, including allowance for funds used during construction for the installation of wet flue gas desulfurization, and selective catalytic reduction facilities. We expect these air quality controls to be completed in 2012.

Another prime example is our investment plan for renewable energy which is designed to meet the standards that are currently in place in Wisconsin. These standards call for an increase in the amount of electricity supplied by renewable sources from 5% in 2010 to 10% in 2015 at a statewide level. Now, the standard sets targets for each of the utilities in Wisconsin using a historical baseline. Using that baseline, approximately 8.25% of our retail electricity sales must come from renewables by the year 2015. Nearly three years ago, we purchased a new wind farm development site approximately 45 miles northeast of Madison. The site, called the Glacier Hills Wind Park, is an ideal location for our newest wind farm. In January of a year ago, the Wisconsin Commission approved our request for a Certificate of Public Convenience and Necessity to build up to 90 wind turbines, subject to modifications the Commission made to our turbine sighting criteria. After modifying a number of the turbine locations and negotiating initial agreements with land owners, we were able to maintain 90 turbines at the site. Each turbine will have a capacity of 1.8 megawatts, bringing the total generating capacity at Glacier Hills to 162 megawatts, the largest wind farm in the state.

Construction at Glacier Hills began in May of 2010. Turbines are scheduled to begin arriving this spring with full commercial operation expected by the end of this year. Glacier Hills, as I mentioned, will eclipse our 88 turbine Blue Sky Green Field Energy Center as the largest wind generating facility in Wisconsin. Our current estimate of the capital cost for Glacier Hills is $367 million. That excludes allowance for funds used during construction and reimbursable transmission costs. The project remains on schedule and on budget.

Now, as you may recall, in the fall of 2009, we also announced our plans to build a 50-megawatt biomass fuel generating plant at a paper mill site in northern Wisconsin. The paper mill was owned and operated by Domtar Corporation. We're fortunate to be close to significant forest lands that can be harvested in a sustainable manner. These forests have large amounts of wood waste that can be purchased to fuel the plant. As I've mentioned before, diversification of our renewable energy supply is one of our important goals. As compared to wind, the clear benefit from an operational standpoint is that we will be able to dispatch the biomass unit. Our investment in this project is projected to be approximately $255 million excluding AFUDC, with a targeted in-service date in late 2013. We have received all the local permits necessary to move forward, and the Wisconsin Public Service Commission has indicated that it will make a final decision in the case in the next four to six weeks. Construction could begin later this spring.

Turning now to other major developments in the quarter, last month, our Board of Directors approved an increase in the quarterly dividend that brings the annual dividend from $1.60 to $2.08 a share. Our new dividend policy targets a payout ratio of 50% to 55% of earnings going forward. The first quarterly dividend for this year will be payable on March 1 at a rate of $0.52 a share. And as I'm sure you're aware, the Board of Directors also approved a two-for-one split of our common shares. This is structured as a stock dividend with a record date of February 14 and a payable date of March 1. I believe the stock split, which is the Company's first since 1992, will help maintain a trading range for our stock that is attractive to a wide range of institutional and individual investors. And just a reminder, unless we note otherwise, all of the per share amounts that we are discussing today are before the impact of a stock dividend.

One other important note. Allen will talk in a moment about the cash impacts that we expect bonus depreciation to have on the Company. Given the way our utility rate base is calculated, the bonus depreciation will reduce our rate base somewhat. However, given the additional cash flow that bonus depreciation will provide, we may well be in a position to move to the upper end of the range of our dividend payout ratio as early as 2012. And as a reminder, our policy calls for us to pay out between 50% and 55% of our earnings in dividends.

And now I'll turn the call over to Allen who will give you an update on our financial performance for 2010 and our outlook for 2011. Allen?

Thanks, Gale. As Gale mentioned earlier, our annual 2010 earnings from continuing operations were $3.84 a share. Now, I'll focus on operating income by segment and then touch on other income statement items. I'll also discuss cash flows for the year and cover our earnings guidance for 2011.

Our consolidated operating income in 2010 was $810 million as compared to $660 million in 2009, for an increase of $150 million. Operating income in our utility energy segment totaled $564 million, an increase of $13 million versus 2009. The trends that we saw for the first nine months of the year continued through the fourth quarter. On an annual basis we estimate that our utility operating income was helped by $160 million of pricing increases, the largest of which related to our general rate case in Wisconsin that was implemented in January of 2010. In addition, we estimate that more favorable weather helped our utility business by approximately $49 million, primarily as a result of the hot summer of 2010 as compared to the cool summer of 2009. Finally, our utility depreciation expense was lower by $62 million as we implemented new depreciation rates in conjunction with the new electric rates in January of 2010.

On the other side of the ledger we estimate our utility, operating and maintenance costs increased by $215 million as compared to 2009. A significant portion of these costs were considered when the new rates were set. The largest items relate to the lease cost for the new coal units, operating costs associated with the new units, increased cost to maintain our electric distribution system and higher accrued bad debt expense. In addition, our recovery of fuel expense was $63 million unfavorable as compared to 2009. In 2010, we under collected fuel and purchase power costs by approximately $44 million, and in 2009, we had favorable recoveries of fuel by approximately $19 million. Finally, all other items were $20 million favorable including the impact of higher electric sales associated with improved economic conditions. When you add all of these items together, you come to the $13 million increase in operating income at the utility level.

Operating income in the non-utility energy segment, which primarily includes We Power, was up $132 million. This increase was driven by the earnings on Unit 1 at Oak Creek which was placed into commercial operation in early February of 2010. Corporate and other affiliates had an operating loss of $6 million in 2010 compared to an operating loss of $11 million in 2009. The largest factor in this $5 million change was a $4 million favorable adjustment in 2010 related to corporate benefits expense. During 2010 we were able to settle certain benefit liabilities for amounts below their recorded value. Taking the changes for each of these segments together brings you back to the $150 million increase in operating income for 2010.

During 2010, earnings from our investment in the American Transmission Company totaled $60 million for a slight increase over the $59 million we reported for 2009. Other income increased by $11 million primarily because of increased allowance for funds used during construction on large utility construction projects, including the air quality control system at our existing Oak Creek plant. Net interest expense increased by almost $49 million. As we mentioned in prior calls, the increased interest expense was primarily driven by two factors related to the commercial operation of Unit 1 at Oak Creek. First, while the plant was being constructed, we capitalized interest expense at our overall cost of debt which was approximately 6%. Once the plant was placed into commercial operation, we no longer capitalized interest expense. The second factor relates to interest rates. Once the plant was placed into commercial operation, we issued long term debt to finance a portion of the unit. The proceeds of the long term debt were used to repay short-term debt incurred during construction. So the higher interest rates on the long term debt led to higher interest expense. I would like to remind you though that the long term interest rates were considered when the lease payments on the new unit were set.

Consolidated income tax expense increased approximately $35 million because of higher pre-tax earnings, partially offset by a lower effective tax rate. Our effective tax rate for 2010 was 35.5% compared to 36.5% in 2009. This decline was primarily a result of a greater equity AFUDC and Section 199 production related tax deductions. I expect that our effective tax rate in 2011 will be between 35% and 36%.

Combining all of these items brings you to $454 million of net income from continuing operations for 2010, or earnings of $3.84 per share. Now, during 2010 we generated $810 million of cash from operations on a GAAP basis which is up $182 million when compared to the same period in 2009. The single largest factor that accounts for this improvement was the $289 million contribution we made to our benefit trust in 2009. We did not make any contributions to our benefit trust in 2010. On an adjusted basis our cash from operations totaled $996 million. The adjusted number includes the $186 million of cash impacts from the Point Beach bill credits. Under GAAP, the cash from the bill credits is reflected as a change in restricted cash which GAAP defines as an investing activity. From a management standpoint, we consider this as a source of cash as it relates directly to the bill credits. I would note that as of the end of 2010, we had provided all of the credits from the sale of Point Beach to our customers.

Total capital expenditures were approximately $798 million in 2010. About $687 million of this was dedicated to our utility businesses and the balance was primarily for the generating units being constructed as part of our Power the Future plan. In 2011 our total capital budget is approximately $953 million. $916 million of this is in our utility operations and the balance is primarily for our Power the Future program. Within the utility, we estimate that approximately $335 million will be spent on the Glacier Hills wind project and $166 million will be spent on environmental related upgrades to our power plants. The remaining amount is expected to be spent on recurring utility projects.

We paid $187 million in common dividends in 2010. Consistent with our dividend announcement last month, we expect to pay $243 million of dividends in 2011. On a GAAP basis, our debt-to-capital ratio was 56.9% as of December 31, 2010, and we were at 54.1% on an adjusted basis. These ratios are somewhat better than our December 31, 2009 levels. The adjusted amount treats half of our $500 million in hybrid securities as common equity which is the approach used by the majority of the rating agencies. Looking to 2011, I expect that our debt-to-capital ratio will increase slightly this year. However, the debt-to-capital ratio should remain below 55% on an adjusted basis. We are using cash to satisfy any shares required for our 401(k) plan, options and other programs.

Going forward, with the exception of the stock dividend to be paid on March 1, we do not expect to issue any additional shares. Consistent with our financial plan we did not make a contribution to our pension trust in 2010. However, our plan this year called for just over a $100 million contribution to our pension trust. We made this contribution on January 7 of this year. This contribution, along with the 11.5% trust investment returns in 2010, put us in a well-funded position. Going forward, we are assuming long term asset returns of 7.25%. I expect our pension expense this year will be comparable to 2010 levels.

As shown in the earnings package we posted on our website yesterday, our actual 2010 retail sales of electricity increased 6% as compared to 2009. On a weather normalized basis, 2010 retail electric sales increased 2.3%. This is somewhat better than the 0.9% weather normalized increase we had forecast in October. For 2011, we are projecting to see a slight decrease of 0.6% in electricity sales versus normalized 2010 sales. This nominal decline is caused by a small forecasted drop in residential sales because of low housing starts and the assumption that there will be continued conservation efforts. In the small commercial and industrial class, we expect to see moderate growth. Our large commercial and industrial class is forecasted to decline by 1.6% because of plant closings such as the Chrysler automotive plant in Kenosha, Wisconsin. In addition, a couple of our customers are in the process of building renewable generation projects. Excluding these customers, we expect our large commercial and industrial group to be relatively flat.

On January 19 we completed the long term debt financing associated with the second coal-fired unit of our Power the Future plan. We issued $420 million of senior notes in two tranches.The first tranche was a $205 million note with a coupon rate of 4.673% and a final maturity of January 19, 2031. The second tranche was a $215 million note with a coupon rate of 5.848% and a final maturity of January 19, 2041. The net proceeds were used to repay short-term debt incurred during construction. On April 1, Wisconsin Energy has a $450 million, 6.5% note which matures. We expect to repay this maturity with internal cash and short-term debt. Later this year, we expect Wisconsin Electric Power Company to issue approximately $300 million of long term debt to help fund its construction program. In December, we entered into new three year bank credit facilities to replace the old facilities that were expiring this spring. The new facilities are sized at $450 million for Wisconsin Energy, $500 million for Wisconsin Electric, and $300 million for Wisconsin Gas.

Our earnings guidance range for 2011 remains the same as what we provided to you in December. We expect our earnings in 2011 to be in the range of $4.10 to $4.20 per share before the stock split, and $2.05 to $2.10 on a post split basis. Now, from this point forward, in my presentation, I will refer to our earnings per share on a basis that includes the new shares that will be issued in connection with the March 1 stock dividend. The earnings contribution from our utility segment, which includes Wisconsin Electric and Wisconsin Gas, was $1.34 per share in 2010. Rate base for the combined utilities was about $5.6 billion in 2010 and we earned approximately 10.2% on equity for our overall retail utility business which excludes our ownership in American Transmission Company. Looking to this year, combined rate base is expected to grow to $6.35 billion. We believe that our earned rate of return on equity will be about 9.7% in 2011, again excluding our American Transmission Company earnings and investment. At this point, I expect our equity level at the utilities will be at or near the top of the 48.5% to 53.5% range set by the Public Service Commission of Wisconsin.

So to summarize we expect the earnings contribution of the utilities segment will increase to $1.39 per share in 2011. We expect the earnings contribution from our investment in the American Transmission Company to grow from $0.15 per share in 2010 to $0.16 per share this year.

Moving now to We Power, which includes the units at Port Washington as well as the units at Oak Creek, we expect the earnings contribution from We Power to increase from $0.48 per share in 2010 to $0.66 per share this year. Note that in order to be consistent with a basis of presentation we have used in the past, this includes an allocation of holding company interest to We Power and does not include any impact of capitalized interest. Also, the estimated earnings for this year included about 11 months of earnings from Unit 2 at Oak Creek. In 2012 of course, we expect a full year of earnings contribution from both of the Oak Creek units.

Finally, moving to the holding company, we expect the earnings reduction from unallocated holding company debt will increase from $0.05 to $0.13 per share. This is primarily because of the reduction in capitalized interest now that the Oak Creek units are complete. So to review, starting from the $1.92 per share that we earned in 2010, pro forma for the shares to be issued in the stock dividend, utility earnings are expected to increase $0.05 a share. Added to this is a projected $0.01 per share increase at ATC. We expect We Power to add $0.18 per share, and the holding company interest to reduce earnings $0.08 per share. Adding these changes together brings you from the actual base of earnings of $1.92 per share in 2010 to $2.08 a share which is the mid point of our guidance range this year. Again, all of these values for 2010 and 2011 include the new shares from the stock dividend.

In December of 2010, the President signed several income tax changes into law. These included an extension of the bonus depreciation rules to projects acquired and placed in service in 2011 and 2012. As a result of this change in law, we anticipate that certain projects will benefit from the increased bonus depreciation in 2011 and 2012, such as our Glacier Hills and South Oak Creek air quality projects. Given our interpretation of the bonus depreciation rules, it does not appear that Oak Creek Unit 2 will benefit from bonus depreciation. Also, the rules appear to require 50% as opposed to 100% bonus depreciation for Glacier Hills and the South Oak Creek air quality control system. At this point, we estimate $100 million in cash benefits from bonus depreciation this year and another $200 million in 2012. I expect there will be a small amount of additional benefits post 2012.

Now, as Gale mentioned, the bonus depreciation will also have an impact on our utility rate base because of the additional build up of deferred tax liability caused by the increased tax depreciation. At this point I estimate that our total utility rate base will be approximately $6.7 billion in 2012. This is down from the $7 billion projection we made last year because of bonus depreciation, as well as favorable working capital balances and better than budget capital spending. However, just to reiterate what Gale said earlier, we believe the additional cash positions us to move faster on the dividend. Just for example, a move from a 50% to a 55% payout ratio would translate into a 10% increase in the dividend before factoring in expected earnings growth.

I would also like to provide you with some input on our expectations for earnings in the first quarter. Overall, we expect our first quarter 2011 earnings to be higher than our first quarter 2010 earnings. As a starting point, when you take into consideration the additional shares from the March 1 stock dividend, our first quarter 2010 earnings from continuing operations were $0.55 per share. We expect to see higher earnings in the utilities segment because last year we were hurt by warm winter weather and a significant under recovery of fuel and purchase power costs. Overall I would expect utility earnings to be up $0.08 to $0.12 per share in the first quarter of 2011. The contribution from ATC should be roughly level compared to last year.

Then, if you turn to the non-utility energy segment, during the first quarter of 2011, we expect to see three months of earnings from Unit 1 at Oak Creek as well as two-and-a-half months of earnings from Unit 2 at Oak Creek. Last year Unit 1 was placed into commercial operation in early February and Unit 2 was under construction. In total, I estimate that We Power's earnings contribution will be up about $0.05 per share. The earnings contribution at the holding company is expected to be down about $0.03 per share primarily because of the decreased ability to capitalize interest.

So, to review, starting from the $0.55 per share in the first quarter of 2010, add $0.08 to $0.12 per share at the utilities, $0.05 per share for We Power and subtract $0.03 per share for the holding company, which brings you to a range of $0.65 to $0.69 per share for the first quarter of 2011.

So with that I'll turn things back over to Gale.

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

Now, we would like to take your questions. (Operator Instructions)Your first question comes from the line of Greg Gordon with Morgan Stanley.

Thanks. My first question is how many touchdown is Aaron Rodgers going to throw on Sunday?

I think five.

I've got to root for them, now that the Jets are sidelined.

Sorry about that foot fettish thing.

Sorry about a lot of things including that. So the first question goes to your sales forecast for 2011. You guys came into 2010 with an extremely conservative outlook and we wound up, we had the benefit of weather, of course, but we wound up having pretty significant recovery in industrial demand, wind up making your forecast look unduly conservative. So I know you guys like to under promise and over deliver. What areas of your sales forecast could you be erring on the side of caution?

I can give you my view on that and I'm sure Allen will have a view, as well. Let me first say that one of the ways, Greg, we put together our sales forecast is with one on one discussions with about 200 of our largest commercial and industrial customers. So if there's conservatism built into the forecast, it's really coming straight from our customers. So that's one piece of information that might be helpful.

But you are absolutely correct, we did see a stronger return in terms of demand from our large commercial and industrial customers than either they or we had been projecting in 2010. And having said that, one of the factors, and Allen mentioned this, that is affecting the 2011 forecast is the fact that the automotive, it was actually the engine assembly plant for Chrysler in Kenosha, has closed its doors, and we have factored that into our forecast. The other thing that I think is influencing the forecast, Greg, is that two of our very largest customers, the iron ore mines and the Upper Peninsula of Michigan, and a major specialty steel company here in Wisconsin, both are running at very high levels of capacity. And those two customers were very much responsible for a lot of the uptick we saw in terms of our industrial demand last year and we think further increases from here won't be as strong as what we've seen. So that just gives you a sense, but if we've aired on the conservative side, so be it. And I think the basic message I would leave with you is, unlike lots of other companies, we are not counting on any material increase at all in customer demand to achieve our earnings targets for 2011. Allen?

Maybe just to add two things, Greg. On the residential class, if you look normal to normal, so you take 2011 forecast assuming normal weather and normalized 2010, we were expecting about a 0.4 of 1% reduction in residential. And I think as I mentioned in the script, part of our reason for that forecast is the assumption that there will be continued conservation efforts. Honestly, that's somewhat speculative. We don't yet know how people are going to behave as it relates to conservation efforts. So, to use Gale's words, we could be overly conservative from that standpoint. And then the only other thing, just to give you a feel for just the sensitivity of our earnings to sales growth, let's just say if instead of a 0.6% decline overall in sales, let's say there was a 1% excursion up, so instead of a 0.6 reduction, say we had a 0.4% increase in sales normal to normal, that would mean about $16 million of pre-tax margin for us. Which on the new base of shares is about $0.04 a share. So that gives you a feel for how sensitive things would be if we are being overly conservative.

And my second question, just to clarify, looking at your last published investor presentation, you were targeting average rate base, you said this in your presentation of $7 billion. Now with the impact of bonus depreciation, in 2012, you're looking at more like $6.7 billion, correct?

That is correct.

The bottom line number, that's right. $6.7 billion. But really that decline is because of three things, Greg. One is bonus depreciation, certainly. But we've done better on working capital than we expected and we've underspent our capital budget. So all three of those combined are moving it from that, say, roughly $7 billion to that approximately $6.7 billion in 2012.

But you're looking at the commensurate ability to hypothetically increase that payout ratio given your stronger cash position? At least that's what you said.

That's right.Going from, again, we said 50% to 55% payout ratio is our target. That's the policy the Board has adopted. But as you recall, when the Board adopted that policy in December, and we didn't know at that time about the bonus depreciation, we also said we would probably be at the lower end of the payout range for a while. Now we think the bonus depreciation and what we see coming in terms of cash flow positions us to move potentially very quickly up to that 55% level.

Great. Thank you very much.

Your next question comes from the line of Brian Russo with Ladenburg Thalmann.Please state your question.

Good afternoon. You mentioned you're expected to be at the high end of the range of your equity ratio in '11. How should we view what that equity ratio might look like in your upcoming Wisconsin general rate case filing?

Typically the filings, what we've filed, and the Commission has ultimately approved, is an equity range of 48.5% to 53.5%. And then what they do, Brian, is when they set your revenue requirements, if you will, for rate making, they assume a number right down the middle of that range. So, in other words, 51%. So I would suggest, and this is just a forecast, but if you're looking at longer term numbers, probably a reasonable assumption to make is that you got an equity ratio near the middle of that range, and then you make your own assumptions about what allowed returns look like down the road.

Okay. So when we think back to when you laid out some of those 2012 financial drivers, the only thing that has changed is the rate base going from $7 billion down to $6.7 billion, but all of the other drivers that laid out are relatively intact?

Other than the very significant driver that we talked about which was cash. And we're in a much better cash position now, given bonus depreciation and where we were on those other factors that I mentioned. But that's cash and a little bit of a decline in the projected rate base. Those are the two major differences, Brian.

Okay. And then just from the longer term renewable projects you guys are considering, a solar 12.5-megawatt plant, I believe sometime in '13. And then the longer term renewables I think previously you outlined possibly 500 megawatts necessary to meet the '15 requirement. Has any of that changed or is any of that influenced by the shift in the political landscape in Wisconsin?

You're asking a very good question, Brian, and I think there are three pieces to the answer. The first is that obviously, our next major focus, as I mentioned in the prepared remarks, is the biomass plant that we've proposed for northern Wisconsin, about a $255 million project. We think it's a very solid project and we expect a decision from the Commission in the next four to six weeks. Now, if you step back and say, okay, with the two major wind farms that we will have in place by the end of this year, and assuming we get approval on the biomass project, and with the way the formula works that allows banking for early compliance, with all of those things, we could meet the 2015 standard for one year. So without any further renewable construction, if you will. But just given Glacier Hills, given Blue Sky Green Field, given the biomass project, and the banking of credits from early compliance, for one year in 2015 we could meet the standards. And I think what we need to do now, other than continuing to push forward with the biomass plan, if approved, is really take a pause and see what the Walker Administration wants to do related to renewable spending in the state going forward after 2015. I don't believe that will be one of the first two or three things on his agenda, but by the end of 2011, I do expect there will be some attention paid by the legislature and the Walker Administration to what that looks like, what the renewable goals look like with this new administration.

A couple of the things that have been beginning to be discussed, and there's nothing set in concrete in terms of a change in policy at this stage of the game, but a couple of the things that are beginning to be discussed are things like should the definition of renewables be changed? Or should the utilities be given an extra five years, say to 2020, to meet the compliance standards. Those are all things that are in the discussion stage and the thought stage at this point in time. So we're actually in a very good position in that with the work we've done so far and with the biomass project that we have teed up for final approval I hope with the Commission, we could actually deliver the goal for 2015. But that would require using the bank of credits and therefore the question becomes what after 2015. And we'll get clarity on that, I believe, this year. Does that help?

Yes, it does. Thank you very much.

Your next question comes from the line of Michael Lapides with Goldman Sachs. Please state your question.

Hi guys. Two questions. One, can you just provide an update on growth opportunities, if any, for American Transmission Company? And two, for your remaining coal plants that lack pollution controls, primarily scrubbers, can you talk about the timeline for when you're likely to have to make decisions about whether it's retirement, whether it's repowering, whether it's adding the controls, whatever option you choose.

Michael, it's Gale. I'll tackle and Rick is here with us so he can add in any of his thoughts but we'll tackle, if you don't mind, the question about the coal plants first. Based on everything we can tell with the proposed EPA rules coming down the road, it is likely that we will have three plants that may require some amount of modification. Those three plants are the Valley Plant which is an older coal-fired unit just south of the downtown area of Milwaukee. The second is called the Milwaukee County Grounds Plant. That is a much much smaller plant that provides steam-chilled water to a huge medical complex on the western side of the city. And then the third plant is the Presque Isle plant which is an older coal-fired facility in the Upper Peninsula of Michigan. All three of the plants have reliability must run characteristics.

The Valley plant, for example,, is the only remaining operating power plant inside the city of Milwaukee and provides not only steam to all of the major downtown buildings, but also provides voltage support for the load pocket. So that's a must run facility. And Rick has a team studying what our options are, best options are there, should we need to make modifications. And then we have a similar study underway for the Milwaukee County Grounds and also we're now beginning to take a very hard look at what might need to be done in the Upper Peninsula with the Presque Isle Plant. I think the next milestone will be probably February 22 when the EPA is expected to come out with its new industrial boiler MACT -- maximum available control technology rules. But we are thinking that we will have to devote at least $200 million of capital spending to modifications of the plants. Rick, how about add to that?

Yes, those modifications could be in the form of additional controls or it could be conversion to gas. As Gale said, these plants have must run characteristics either because of steam or because of where they sit on the grid. So we're taking a hard look at what does it make sense in terms of what to convert, what to put additional controls on. Time lines we would expect by this year we would be making some decisions on Milwaukee County which is subject to the industrial boiler MACT rules. And probably also for Valley which is not subject to the industrial boiler MACT rules, they are subject to the electric generating unit MACT rules. The dividing line is 25 megawatts -about-twenty-five megawatts, below 25 megawatts is industrial boiler MACT. I expect on those two plants we'll be making decisions this year, implementation middle of the decade. Presque Isle is going to be just right behind that, so I think the capital that we'll be spending will be primarily in the '12 through '14, '15 time frame.

And what we're seeing, and Rick is really relating to this, is that some of the proposed rules have 2015 compliance dates, and that's why Rick is thinking '12, '13, and '14 for much of that capital we my need to spend on those three plants.

When I think about your rate base numbers for 2012, I assume that doesn't exclude the several hundred million dollars of potential spend on the existing coal units?

There wouldn't be much in 2012. Again, most of those dollars, if we end up needing to spend them, it would be -- the study dollars in 2012, the actual capital spending in '13 and '14.

Got it, okay.

And then, Michael, on ITC, as you may or may not know, every October, American Transmission Company will publish a new 10 year spending plan. And when they did their update this October, their spending plan over the next 10 years would call for $3.4 billion of spending. Their previous 10 year plan called for about $2.5 billion of spending, so there is really an increase of $900 million between the two plans. The driver for the increase was almost exclusively for really two lines, two new 345 KB lines. One, which is a new east/west interconnection from the Madison area over to Minnesota, and then a north/south line, if you will, going down to Iowa. So that was most of the driver for the increase from the $2.5 billion to the $3.4 billion. So if those projects are done, transmission projects have an even longer gestation than generating plants, so that spending, that additional spending would be five years out, but there's quite a bit of additional spending that would be in their plan. In terms of outside the footprint for ATC, meaning outside of Wisconsin, outside the UP of Michigan, at this point, Michael, we wouldn't have anything that would be in specific enough terms to talk about really.

Got it. Okay, thanks guys. Much appreciated.

Your next question comes from the line of Jim von Riesemann with UBS. Please state your question.

Good afternoon. Two questions. The first one is, if I missed it I apologize, but could you provide an update with respect to the timing of the rate case and what some of the key parameters might be? And then the second question revolves around M&A chatter, so this is for you, Gale. In that regard, could you talk broadly about what makes sense, what doesn't make sense for Wisconsin Energy? And if I remember correctly Wisconsin has a Holding Company Act, which can be prohibitive or impede a lot of M&A both intra as well as interstate. Could you just refresh our memories as to what those hurdles are?

Sure, I'll be happy to, Jim. First, in terms of the rate case, and we can let Allen quantify the drivers for you, but I would expect in terms of the timing of the filing, it would be some time late Spring. And we would expect a pretty modest rate request simply because that's the position we're in at this stage of the game. And the drivers clearly will be, Allen?

Far and away, we have two projects, Jim, that have been accruing really 100% of the plant, of the balances, they've been accruing AFUDC, as opposed to some sort of CWIP in rate base concept. So, one of those is South Oak Creek air quality and the other is Glacier Hills. So far and away, there's over $1 billion worth of capital that's not in rates that will have to be put in rates related, again, to South Oak Creek AQCS and Glacier Hills, so that will be a very significant driver in the case.

Really, we're seeing reasonably flat O&M projections. The O&M component that would be going up in association with the rate case is largely driven by the O&M that we're going to have to operate the new air quality controls at South Oak Creek. So again, I think this will be a pretty modest rate request and you could expect it late spring, and the drivers are the capital expenditures that Allen mentioned.

Super. And then on the M&A side?

On the M&A side, let me first say that, given the size of the Company, and given the prospects we see, certainly there's no requirement in my mind whatsoever for us to acquire another utility. So first of all, I think we are just fine with our growth prospects, with the economies of scale that we have, and I would just say to you it's not one of the top 10 things that I'm overly concerned about at the moment. If the stars and moon align then it would certainly be something we would look at.

Related to the Holding Company Act in Wisconsin, I don't believe it would be a huge impediment for a merger or acquisition or combination inside the state. But there clearly needs to be demonstrated customer benefit. And I think, obviously, the easier demonstration of customer benefit would be for combinations inside the state. But I don't see the Holding Company Act in Wisconsin being a tremendous impediment if there was a friendly merger or combination that was on the horizon. For us, we would apply the same type of criteria we have mentioned in the past to any type of potential acquisition, and that would be we would want it to be accretive certainly by the end of year one. We would want it to be, at a minimum, credit neutral. And we would want it to be at least neutral to positive to our long term earnings per share growth rate. I'm a firm believer that you really need to apply those kinds of criteria for a combination to deliver shareholder value that our job really is to do. So we would be pretty strict about applying those type of criteria to any potential acquisition that we might look at. And I hope that answers your question, Jim.

It does but it raises one other one, thank you. The question is long term growth rates, and you've been pretty silent on eliciting a longer term growth rate these days. Care to comment?

I think the longer term growth rates really are a function of economic growth, a function of customer growth and a function of some of the environmental rules potentially that we need to be facing. As we mentioned to you, there's an entire host of new environmental rules that the Environmental Protection Agency is proposing. We're ahead of the curve on compliance with many of those rules. But to give you a really solid long term view, I would like to have a much better feel for what we're looking at related to EPA requirements and I think we'll get that this year.

My follow-up to that is, if you think about it mathematically and everything we all learned in business school, if you take the ROE times the payout ratio and your ROE, call it 10.5% with a payout ratio better than 50%, suggests at 5.5% long term growth rate. Is that in the realm of reasonableness?

I would say for us, 4% to 6% might be a reasonable long term growth rate. But we can give you a much better feel once we have a very good sense of the EPA requirements. But at the moment, this is again sheer speculation on my part, if I were going to try to chunk in a long term growth rate into the model I would do 4% to 6%.

Okay, thank you.

Your next question comes from the line of Edward Heyn with Catapult.

Gale, good afternoon.

Are you giving me 3.5 in Green Bay?

That seems like a decent spread. You have a good chance I think.

You're giving me 3.5?

Yes.

All right, what is this friendly wager for?

I guess a New York apple versus a Wisconsin block of cheese or something.

That apple better be big.

Yes. A quick question just on the rate base. I know that you have benefited the bonus depreciation. Thinking about $300 million of rate base, if I just take 10% ROE and a 50% equity ratio, that's about $15 million in net income. And on your old share count, on 117 of shares, that seems like $0.12 of earnings pressure. Is that the right way to think about, relative to how you were thinking about things before the bonus depreciation, that your '12 number could be $0.10 lighter but you're going to try to give that back with cash distributed through dividends?

One thing, there's a sort of complication about the way these rate base calculations are done, Ted. There's this averaging process that occurs. So when they look at your rate base in a given test period, they look at a 13 month average over that period. So for example, if you have bonus depreciation benefits that occur relatively late in the year, that, in effect , doesn't count dollar for dollar against you in that period. So if I just narrow down, Ted, and look at the bonus depreciation impact on rate base, and say look in the 2012 test period, do all of the averaging that's done, the bonus depreciation only has about $100 million impact in 2012. So you can go through the same math that you were going through, but effectively the bonus depreciation impact on rate base is only about $100 million in 2012, and then I would say the bonus depreciation impact is about $300 million in 2013. But then, as you say, that provides additional cash in effect from operations that can be used to go faster on the dividends. So hopefully I haven't overly complicated things but keep that in mind. There is this averaging that

So it seems like the $300 million of rate base is not just bonus D&A. It's also under spending on capital. Whether it's bonus D&A or just lower spend, is it right to think, is that $0.10 number right of earnings power relative to how you were thinking about it before when you gave a $7 billion rate base number?

Yes, that's the right zip code. The other thing that you have to take into account, though, when you're doing that 50/50, say you take $100 million, just to make the numbers work easy, one of the things you have to add back is the fact that, all other things being equal, there would be $50 million less debt at the holding Company and less interest at the holding company. So there's a little bit of an add back for that, Ted, that you have to --

Okay, it's just the cost of that capital will be cheaper?

Yes.

You're in the right zip code, though, Ted.

That's great. And Allen, could you give us, I think typically you give breakdowns of CapEx for the next couple years. Is this the appropriate time for that refresh?

There will certainly be very fulsome disclosure in the 10-K that we'll come out with later this month. But my current estimates, Ted, I think I mentioned the $935 million for 2011. I expect we'll be at about somewhere between $656 million and $681 million in 2012. And then I would say in 2013, probably around $540 million. Now, the assumption, just to be clear on what's behind that, I have not assumed any additional renewable projects past Glacier Hills or Domtar in those numbers. So that's says, okay, just assume for conservatism at this point we aren't doing any additional renewables in this period past Glacier Hills and Domtar, you get to those numbers that I talked about. And then, like I said, there will be additional disclosure with some more detail in the 10-K later this month.

Got you, that's helpful. Thanks a lot guys.

Your next question comes from the line of Steve Gambuzza with Longbow Capital. Please go ahead with your question.

Two things. I think you mentioned in the prepared remarks the Point Beach credits ended at the end of '10, is that right?

That is correct.

Just curious what the impact will be this year then, because this was not a rate case year so there was no change in rates in 2011. So the only real change should be the phase out of those credits?

In terms of customer bills?

Yes.

There will be two changes. One, the phase out of the credits. And then the second is we have a fuel case pending with a very modest increase in fuel costs, and I expect that will be decided by the Commission in the next month. So the only changes we would see for customer impact or customer bills in 2011 are those two, basically the expiration of the Point Beach credits and a very modest 1% type fuel increase.

On a percentage basis roughly what is the impact of the Point Beach credit for an average customer bill?

About 5%.

Okay, thank you very much.

Alex Kania with Bank of America, please state your question.

Good afternoon. I hope the snow hasn't been too horrible for you guys today.

We've shoveled out of about eight foot snow drifts but we're here.

Thank you for coming out with the earnings release. I have two questions for you. I think the first one is if Allen could just give a little more elaboration on the bonus depreciation standard of the 50% versus the 100% because we were trying to figure out, for you guys and certainly other utilities. How much would actually be able to be taken in terms of accelerated depreciation and what your understanding of that rule is?

Yes, let me start with that. And Alex, basically what the new law provides for are two windows on bonus depreciation, if you will. One window for 100% and another window for 50%. So the window for 100% extends from September 8 of 2010 to January 1 of 2012. The window for 50% extends from January 1 of 2008 to December 31 of 2012. So you have those two windows, and obviously the window for 50% is much broader in time than the 100%. Then what you do is, to determine whether you qualify for a window, you apply a two part test. The first part of that test is placed in service, so that's pretty straightforward. You have a piece of property that goes commercial in that window, you can put a check mark by that test.

The second test is the so-called acquired in test. And what that means is that you have to have at least 90% of your project expenditures within the window. So for example, if you have a project where you spend at least 90% of the project within that window, so say 100% from September 10 to January 1 of 2012, if you spend 90% of that window and it's placed in service in that window, you're a winner. You get 100% bonus appreciation. If you fail the 100% then you can go back and test to see if you qualify for the 50% window. So then for us, Alex, and I'm probably telling you more than you want to know, but for us, if you go through all the major projects, Oak Creek 1 and 2, they fail both of these because you didn't spend 90% of the money for those projects in either of those windows. You had significant expenditures before 2008. South Oak Creek AQCS, it's good for 50% but not for 100%, and then Glacier Hills good for 50%, not for 100%. The other thing, Alex, to keep in mind, and I've seen some folks that maybe don't understand this nuance, I'm sure you do--

Oh, I know Alex understands it.

Of course, this is for the benefit of everybody else, right?

Right. So for us, this bonus means about an additional $1 billion of tax depreciation that gets moved up in time. So when you're figuring out what the theoretical cash tax benefit of that is, you can't just apply some 40% combined tax rate because what happens, at least in the states we do business, the states don't pay any attention to bonus depreciation. So immediately you go to a federal rate rather than a combined state and federal rate. And then in addition, there's an interaction with the Section 199.-

Manufacturing credit?

It's actually a deduction, not a credit. But anyway, that's another 20 minute discussion. So it takes you from a combined rate of 40% down to something more like 32% once you put in the 199 leakage. So for us, it's about $1 billion of tax depreciation, $320 million worth of cash tax benefit and then in time you take the benefit along the lines of what I described in the script. So $100 million in 2011, $200 million in 2012, and then the rest. So you're probably sorry you asked now.

No, that's great actually. I never heard as clear an explanation.

It all turns around.

Okay, great. And then my second question is just making sure, doing more of these rate base kind of things, looking from '11 to '12, and you've given a few of the pieces, we're about $6.35 billion in '11, $6.7 billion in '12. And then in '11, you're thinking that your equity layer will be toward the high end of the allowed range which is about 53.5%. That's right. So that's saying that you guys have, I don't know what that is, about $3.4 billion or so of equity that you've got locked at the utilities for 2011, for the most part, on average, right?

Allen Leverett That's right.

So at the very least, if I just assume going into 2012 that presumably you're not going to reduce that equity layer, I guess you could theoretically, but if I even assumed that was flat and you just dividended out all of your retained earnings and kept that other layer flat, you'd be looking in 2012 at a 51% equity layer. Is that fair to think about?

Yes, I think I had an earlier question about that. Sitting here today it's reasonable to assume you'd be at the mid point of the equity range.

Got it. That's perfect. I was just making sure I was thinking about that right. Great, thanks very much guys, and good luck on Sunday.

Your next question comes from the line of Carl Seligson with Utility Financial.

You guys are so good at explaining things I wonder if you'd tell me what depreciation is. Just teasing. What's going on with Mark Meyer? Is he going to get reappointed, and if not what's the likelihood you'll get someone who's less favorably disposed?

Mark's term expires on March 1. And for those listening who are not familiar with the name, Mark is one of the three appointed commissioners at the Wisconsin Public Service Commission. The commissioners are appointed for six year terms and Mark's term runs out March 1. He has indicated a number of months ago that he wished to pursue other opportunities, and regardless of the outcome of the election he did not wish to be reappointed as a commissioner. So the Walker Administration is right now in the final throes of selecting a nominee who will become actually the Chairman of the Commission. In Wisconsin, the Governor has the automatic right, once there's a vacancy on the Commission, to appoint the Chairman. So the person that will be appointed by the Walker administration will become the new Chairman probably sometime in March. And we obviously don't know yet who that person will be but I'm confident that they are working hard to select a person with financial acumen and a person with a very good balance and business expertise.

Is that subject to any kind of confirmation process in the legislature?

Yes, the appointment to the Commission must be confirmed by the State Senate. But, course, Wisconsin in the last election, the Republicans gained control of both the Assembly and the State Senate. So I wouldn't foresee any quality candidate having any difficulty being confirmed by the State Senate.

Is there a possibility that Chairman Callisto would bag it on the basis of not being Chairman anymore?

His term, he has I believe until 2014 for his term to run.

'15 I think.

I believe it's '14, Carl. But at any rate, I don't know. I think at the moment Eric would be inclined to stay at the Commission, although certainly it would not be unusual, given a change of Administration, for a commissioner to look for another opportunity. But at the moment I don't see any other immediate change.

Okay. There is the possibility of a significant turnaround as a result of the election. You could have two Republicans in time.

Yes, and I expect in time we will have.

Thanks very much. And aren't you glad to have three guys there from Atlanta there in all this snow?

Yes, they aren't real good at shoveling though.

I imagine that. You have to teach them. You had it early.

Amen. Thanks, Carl.

Your next question comes from the line of Paul Ridzon with KeyBanc. Please go ahead with your question.

I'm not a Packers fan but I hate the Steelers, so good luck. Update on fuel legislation. And Allen you talked about part of the lower rate base would be offset by reduced debt cost but wouldn't that just go to rate payers? What was weather versus normal in 2010? What have you seen so far and is that in your first quarter guidance? And then lastly, your former employer had a pretty widespread of potential environmental CapEx. Would you like to put book ends on it?

That's about eight questions, Paul. Let's try to tackle them one at a time. You asked about fuel rules?

Yes.

In the waning days of the past legislature at the end of December, new fuel rules were finalized. So we have going into 2011 a new set of rules that are a modest improvement, I think, from the prior rules, in that each utility will be asked to come in, in the fall of the year, and present their projected fuel costs for the next year. And then there'll be a brief one day hearing and the Commission will set a new fuel rate, if required, that would take effect in January 1 of a given year, and apply for the next year. So that should be somewhat helpful in terms of reducing the volatility. And then secondly, the 2% bandwidth that has applied in the past, in other words a fuel rate is set and unless your costs deviate plus or minus 2%, or more than 2% from the rate that's been set, you have the upside potential and the downside risk, and that stays in place. But a new fuel rule is now in place in the state of Wisconsin. Allen?

Yes, I'm not sure that I totally understood where you're going with the interest benefit. The only interest benefit that I recall talking about were some interest benefits at the holding company. And so, of course, if you had a reduction in interest expense at the holding company, that doesn't in any way get wrapped into retail regulation.

I understand, thanks.

And we may have lost your other questions. Is there anything else you'd like us to address, Paul?

I thought you had one more question, Paul. I wasn't sure.

We can't remember and obviously you can't either but we appreciate you asking, Paul.

Your next question comes from the line of Travis Miller with Morningstar.

Good afternoon. Real quick question. Given the amount of cash that you guys have coming in and projected over the next couple years, any projections or plans for additional pension contributions?

We basically, as Allen mentioned in the prepared remarks, we have just made another pension contribution in January per our plan. It was the expected amount. Given the returns we've seen in the past year on the pension trusts, and given the contribution we've made, we're quite well funded, but we do have budgeted modest amounts for pension contributions over the next several years. Allen?

Yes, if you look out and say, okay, we've made the contribution that Gale mentioned for this year, and then if you say, look out from 2012to 2015, so the back four years of our five year plan, my expectation right now is that we'll have average annual contributions to our benefit trust in total of about $50 million to $55 million a year. So relatively modest. And I hope we're assuming a return that we can certainly hit year in, year out which is the 7.25%. But I think pretty modest contributions from 2012 forward.

Okay, great. That's very helpful, thank you.

Your next question comes from the line of Leslie Rich with JPMorgan Asset Management. Please go ahead with your question.

Now that your capital spending program is coming down, how are you thinking about your targeted capital structure?

I think we're looking at it, really, in two ways. First at the utilities. And I would think, in essence, because our goal would be to maintain a solid single A credit rating at the utilities, I don't see going forward any material change in the capital structure at the utilities. And again, as Allen mentioned, the range that the Wisconsin Commission has historically provided would be about a 48.5% to 53.5% equity ratio at the utilities. And then in terms of the entire enterprise, we've said that we at least want to get to, we at least want to again maintain solid investment grade credit ratings and have a debt to total capital that basically supports those credit ratings. So everything in terms of our look at capital structure is driven by where we want to be on a credit rating standpoint. But clearly, we've now taken a lot of risk out of the business in terms of the successful execution of the construction program. Our debt to total capital on an adjusted basis is now down around 54%. But I would think we would want to keep it in that 54% to 55% range over the longer term. Allen?

Yes, the only thing, Leslie, I agree with all that Gale just said. The additional thing I would just say, though, if you look at long term obligations that we would have at the holding company level, we mentioned the $450 million obligation that matures in April of this year, April 1 I think is the exact date. So we're going to, in effect, pay that off over the next couple years. And then the only other long term obligations we would have, we have $200 million worth of unsecured debt that matures in 2033, and then the $500 million of hybrids which has the step up in May of 2017. So we certainly will have the opportunity over the next few years to either leave those out, if we wanted to, and use the cash for other investments within our business, or if we wanted to have opportunities to pay those down, we would also have opportunities to pay them down

Basically I think what you're hearing Allen say is we've got some real flexibility now that we haven't had in a very long time.

Okay, thank you.

Your next question comes from the line of Vedula Murti with CDP Capital.

Hi. A couple things. One, you went through the sales forecast you're assuming for '11. And with '11 not being a rate case year, can you help me, how do you stand with regards to what you're seeing as a sales forecast versus what was assumed in the last case? Are you caught up on it or are you still, is there still a gap there versus what had been assumed in the last case that you'll need to fill in somehow?

I think if you look at, Vedula, the 2010 normalized electric sales and compare that to, in effect, the forecast for 2010 approved by the Wisconsin Commission when they set rates, those two lay almost exactly on top of each other. So really the run rate in 2010 on a normalized basis is very consistent with what was in the test year. And so then, in effect, there really isn't a notion of a 2011 test period per se. So they didn't have an approved forecast for 2011. But what our forecast for 2011 would be, would actually be about 0.6% below the forecast they had for 2010. And it varied by class. I'm talking all in terms of a total Company level. Some classes may be more or less than the test year.

Do you have an estimate of a gross margin type of number that either through efficiencies or if you get fortunate with some weather or that type of thing that basically could get filled in, at least on that, in order to get to the ROE?

I think I talked, I might have talked earlier on this call. If you have a 1% change in sales, so let's say just a 1% across all three classes up, that would add an additional $16 million worth of margin, which I think, back of the envelope, is probably about 28 basis points on the return, if that helps.

Okay. Secondarily, Gale, can you talk a little bit about the carbon sequestration, research projects you guys have been working on, at one of your coal plants, and what's been going on with that?

Sure, would be happy to. We've concluded the experiment. And for those listening who may not be quite familiar with it, we were the first in the country to really test a new technology for carbon capture that uses chilled ammonia to attract the carbon. And we did it on a slip stream of our Pleasant Prairie power plant which is just north of the Illinois border. That experiment, which lasted about 18 months, was actually very successful. It achieved its operating goals for capture rate and is now -- so the technology, the next step now, the technology is being scaled up from where we had it by a factor of 10 at the Mountaineer power plant, which is operated by American Electric Power in West Virginia. So actually that technology really performed very well for the first time out of the laboratory setting and the first time in the field. So, we feel like we've helped to demonstrate a promising new technology. And again, the questions now are will it operate as designed in terms of carbon capture as it gets scaled up to a full utility size plant.

One last item. When I was looking at the cash flow and the balance sheet, Allen, can you remind me what the restricted cash is related to?

Restricted cash was related to the Point Beach credits.

Okay got it. Thank you.

Your next question comes from the line of Paul Patterson with Glenrock Associates.

Hi, how are you? I wanted to ask about the performance at Oak Creek and it beating the benchmarks that you guys had laid out. Was there any particular reason for that? Was there some new practice or technology or something that you guys did or is this just you guys beating your goals because, being conservative goals perhaps? I was wondering if you could elaborate on that.

I'll ask Rick to give his view, as well, but, first of all, they weren't conservative goals. If you think about the guarantees we were able to elicit from Bechtel in the contract, the heat rate guarantee, the emissions guarantees, they were not weak goals. I think the extra capacity that we are seeing is really a function of what was built in in terms of making sure that Bechtel hit the targets. The extra capacity that was built in basically to the steam turbine and the boiler. Rick, I think that had a lot to do with the extra capacity we're getting, don't you think?

Yes. I think basically it was conservatism in the design margin. When you have a contract and you have liquidated damages on the back end, you don't want to miss that because it can be very expensive. So I think Bechtel did a good job of being conservative in terms of station load and working with the boiler and turbine vendor to insure that we had adequate margins in there. And we showed up on the back end with -- there will be a lot of value to that for customers over the life of this project too.

And the efficiencies the same thing pretty much?

Yes.

And so this all goes to rate payers? There's no kicker or something for shareholders in this, is that correct?

That will all go to rate payers. And just to put a number on it for you, I think the guaranteed heat rate in the contract was 8850 and we're beating that by 6%. And when you look at the tables that are produced around the industry, a 6% improvement on an 8850 heat rate is pretty phenomenal.

8850 being the nameplate heat rate?

Being the guaranteed heat rate.

Thanks a lot.

Your last question comes from the line of Reza Hatefi with Decade.

Man, I've never known you to be last before.

I know, this is quite the call. Allen, I just wanted to clarify a couple things. There was a lot of numbers being thrown around earlier. When you mentioned that some of this extra cash will help maybe pay down some parent, or reduce some parent interest drag, is that already embedded in the negative $0.17 parent drag guidance for 2012?

Yes, and then year-over-year what's happening is there's an $0.08 increase in the drag at the holding company. There's $0.11 of drag because of a reduced ability to capitalize interest. And then going the other way, Reza, is a $0.03 benefit because you pay off a portion of the $450 million senior note and then you replace a portion of it with commercial paper. So you had $0.11 increased drag because of less capitalized interest offset $0.03 with an interest benefit for a net $0.08 swing, if I'm making sense.

Although the parent drag in '11 is $0.27 improving to $0.17 in '12, right?

Yes. I thought your question was about '10 versus '11, I'm sorry. Oh, no, sorry. '11 versus '12. You mentioned all of this extra cash. So that paying down some parent debt is already embedded in the negative $0.27 in '11 as well as the negative $0.17 in '12? I haven't given any numbers for '12 on this call. I've only talked about '11. So for '11, to the extent that we have some cash benefits, yes, it's in there. For '12, we haven't given an updated set of numbers for '12 so there would be presumably some benefit at the holding company level in 2012 that's not yet reflected in the numbers that you're looking at, because those numbers would have been from late last year before we had this bonus.

Okay I'm sorry. I thought, like I said there's so many numbers, I thought you reiterated the segment guidance for '12, like the PTF and ATC and the parent.

He was really reiterating for '11.

Okay, I'm sorry. And then just to clarify on the rate base, you said '12 was $6.7 billion, before it was $7 billion, but then you mentioned the deferred tax impact is only causing $100 million decrement in '12 from that $7 billion. What is the other $200 million from? And then how should we think of this deferred tax effect on '13 rate base? Should we be reducing our '13 rate bases by $200 million since only $100 million of the $300 million is hitting in '12? I got a little confused there.

Let me just take you through it. So original forecast $7 billion worth of rate base for 2012. There is $100 million decrease for this additional bonus depreciation and then $200 million because we did better on capital spending. For example, we spent below the budget levels on South Oak Creek and we've done better on working capital. So those three things take you from $7 billion to $6.7 billion. So bonus depreciation, working capital and CapEx. And then, as you go forward to 2013, you're exactly right. On the margin, there would be another $200 million reduction in rate base because of the build up in deferred taxes moving to 2013.

Okay. Thank you for the clarity.

That concludes the world's longest conference call but we do appreciate your participating. If you have any other questions, Colleen Henderson will be available in our Investor Relations office. Her direct line 414-221-2592. Thanks again, everybody. Talk to you soon. Bye-bye.