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Wisconsin Energy Corporation (NYSE:WEC)

F1Q2011 Earnings Conference Call

February 2, 2011 2:00 PM ET

Executives

Colleen Henderson – Head, IR

Gale Klappa – Chairman, President and CEO

Allen Leverett – CFO

Rick Kuester – President and CEO, We Generation

Analysts

Greg Gordon – Morgan Stanley

Brian Russo – Ladenburg Thalman

Michael Lapides – Goldman Sachs

Jim Von Riesemann – UBS

Edward Heyn – Catapult

Steven Gambuzza – Longbow Capital

Alex Kania – Bank of America

Carl Seligson – Utility Financial

Paul Ridzon – KeyBanc

Travis Miller – Morningstar

Leslie Rich – JP Morgan

Vedula Murti – CDP Capital

Paul Patterson – Glenrock Associates

Reza Hitucki – Decade

Colleen Henderson

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. (Operator Instructions) 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, reference to earnings per share will be based on diluted earnings per share unless otherwise noted, and our earnings per share will reflect the dilutive shares as of 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 Web site 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.

Gale Klappa

Colleen, thank you. We found Colleen under 7 feet of snow this morning but she’s doing fine. Well, 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.

Alan will review our financial results in detail in just a moment but as you saw from our news release last 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 of 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 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 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 turn over 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 technology 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 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 as which the unit converts fuel into electricity. The more efficient the unit obviously the less coal we have to burn and therefore the lower costs for 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 at mercury, the levels actually were a fraction of that allowed in our permit. The guaranteed capacity of each unit is 615 megawatts net – excuse me – and that means that the unit must be capable of delivering 615 megawatts into the transmission networks.

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 year 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 at 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 an 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 far. 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 may do our turbine siting criteria. After modifying a number of the turbine locations and negotiating additional agreements with land donors, 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 forestlands 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. Our first quarterly dividend for this year will be payable on March 1st 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 14th and a payable date of March 1st. I believe the stock split which is the company’s first since 1992 will help maintain a trading arranged 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 the 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 financial performance for 2010 and our outlook for 2011. Alan?

Allen Leverett

Thanks, Gale. Now as Gale mentioned earlier, our annual 2010 earnings from continuing operations were $3.84 a share. And 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 a 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 that our Utility operating and maintenance cost increased by $215 million as compared to 2009. The significant portion of these costs were considered when the new rates were set. The largest items relate to the lease costs for the new coal units, operating costs associated with new units, increased costs to maintain our electric distributions 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 purchased 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 these items together, you come to the $13 million 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 in the 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 systems in our existing Oak Creek plants.

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 and 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 on 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 trusts 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 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 of 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 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 that our pension expense this year will be comparable to 2010 levels. As shown in the earnings package we posted on our Web site 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 0.9% weather normalized increase we had forecast in October. For 2011 we are projecting to see a slight decrease of 0.6% in the 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 plant. We issued $420 million of senior notes in two tranches. The first tranche was the $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 with 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 a 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 $2.04 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 1st stock dividend. The earnings contribution from our Utilities 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 Utility 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 the 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 that 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 at ATC. We expect We Power to add $0.18 per share, and the holding company interests 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 midpoint of the 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 that 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 million in 2012. This is down from the $7 million 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 Utility 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 2.5 months of earnings from Unit 2 at Oak Creek. Last year, Unit 2 was placed into commercial operation in early February and Unit 2 was under construction.

In total, I estimate that We Power 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 a decreased ability to capitalized 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.

Gale Klappa

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

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from the line of Greg Gordon with Morgan Stanley.

Gale Klappa

Afternoon, Greg.

Greg Gordon – Morgan Stanley

Thanks. My first quarter is how many touchdowns is Aaron Rodgers going to throw on Sunday?

Gale Klappa

I think five.

Greg Gordon – Morgan Stanley

Well, I got root for them now that the Jets are sidelined, but...

Gale Klappa

Yeah. Sorry about the foot fetish thing.

Greg Gordon – Morgan Stanley

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

Gale Klappa

Well 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 and either they or we have been projecting in 2010.

Having said that, one off 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 in 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 that 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 erred on the conservative side, so be it. And I think the basic message that 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?

Allen Leverett

Yeah. I guess 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’re 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, I mean 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 I mean, if you – 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, well 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.

Greg Gordon – Morgan Stanley

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

Gale Klappa

That is correct.

Allen Leverett

Yeah, 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 that we expected and we have under spent our capital budget. So all three of those combined are moving you from that say, roughly seven to that approximately $6.7 billion in 2012.

Greg Gordon – Morgan Stanley

Right. And you’re looking, but you’re looking at the commensurate ability to hypothetically increase the payout ratio, given your stronger cash position, at least that is what you said earlier.

Allen Leverett

You’re actually right.

Gale Klappa

Going from – again, we’ve 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’d probably be at the lower end of that 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.

Greg Gordon – Morgan Stanley

Great. Thank you very much.

Gale Klappa

Take care. Go pack.

Operator

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

Gale Klappa

Hi, Brian. Good afternoon.

Brian Russo – Ladenburg Thalman

Hi, good afternoon. Just you mentioned that you’re expected to be at the high end of the range of your equity ratio in ‘11, how should we kind of view what that equity ratio might look like in your upcoming Wisconsin general rate case filing?

Allen Leverett

Well, typically the filings with the Commission, what we 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, 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’ve got an equity ratio near the middle of that range, and then, you know, you make your own assumptions about what allowed returns look like down the road.

Brian Russo – Ladenburg Thalman

Okay. So when we think back to when you laid out some of those 2012 financial drivers, I guess 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?

Allen Leverett

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

Brian Russo – Ladenburg Thalman

Okay. And then just some of the longer term renewable projects that you guys are considering, a solar 12.5 megawatt plant I believe sometime in ‘13, then the longer term renewables that 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?

Gale Klappa

Well, you’re asking a very good question, Brian, and I think there are kind of three pieces to the answer. The first is that obviously our next major focus as I mentioned in our prepared remarks is the biomass plant that we 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 standard.

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 renewables 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 standard? 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 final approval I hope at the Commission, we could actually deliver the goal for 2015, but that would require using a – 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?

Brian Russo – Ladenburg Thalman

Yes it does. Thank you very much.

Gale Klappa

You’re more than welcome.

Operator

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

Gale Klappa

Rock and roll, Michael.

Michael Lapides – Goldman Sachs

Hey, 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 lake pollution controls primarily scrubbers, can you talk about the time line 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?

Gale Klappa

Michael, this is Gale. I’ll tackle the – 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.

Michael Lapides – Goldman Sachs

Sure.

Gale Klappa

Based on everything we can tell, with the proposed EPA rules coming down the road, it is likely we will have three plants that may require some amount of modification. The 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 smaller – much, much smaller plant that provides steam-chilled water to a huge medical complex on the western side of 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, our best options 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 a couple of hundred million dollars of capital spending to modifications of the plant. Rick, how about add to that?

Rick Kuester

Yeah, 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 makes sense in terms of what to convert, what to put additional controls on. Timelines we would expect by this year we’d be making some decisions on Milwaukee Kennedy (ph) which is subject to the Industrial Boiler MACT rules and probably also for Valley which is not subject to Industrial Boiler MACT rules, they’re subject to the Electric Generating Unit MACT rules. And the dividing line is 25 megawatts: above 25 megawatts, EGU; below 25 megawatts, it’s Industrial Boiler.

I expect on those two plants we’ll be making decision this year, implementation kind of middle of the decade. Presque Isle is going to be just right behind that and so I think the capital that we’ll be spending will be primarily in the ‘12 through ‘14 to ‘15 timeframe.

Gale Klappa

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

Michael Lapides – Goldman Sachs

So 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?

Gale Klappa

There wouldn’t be much in 2012. No. Again, most of those dollars if we end up needing to spend them, yeah, would be – exactly. The study dollars in 2012, actual capital spending in ‘13 and ‘14.

Michael Lapides – Goldman Sachs

Got it. Okay.

Allen Leverett

And then, Michael, on ATC, 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-kV 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 increase, 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, I mean 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 of the U.P. of Michigan, at this point, Michael, we wouldn’t have anything that would be in specific enough terms to talk about really.

Michael Lapides – Goldman Sachs

Got it. Okay. Thanks, guys. Much appreciated.

Gale Klappa

More than welcome. Thank you, Michael.

Operator

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

Gale Klappa

How you doing, Jim?

Jim Von Riesemann – UBS

Good afternoon. I’m doing well. Thanks.

Gale Klappa

Good afternoon to you.

Jim Von Riesemann – UBS

Two questions. The first one is, if I’ve 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 as compared to 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?

Gale Klappa

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 sometime late spring and we would expect a pretty modest rate request simply because that’s the position we’re in at this stage in the game. And the drivers clearly will be – Allen?

Allen Leverett

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

Jim Von Riesemann – UBS

Okay.

Gale Klappa

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

Jim Von Riesemann – UBS

Super. And then on the M&A side?

Gale Klappa

On the M&A side, let me first say that, I think, given the size of the company and given the prospects we see certainly there’s no requirement in 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 ten 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 the easier – 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 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 believe that you really need to apply those kinds of criteria for a combination to deliver shareholder value that what 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.

Jim Von Riesemann – UBS

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?

Gale Klappa

Well, 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 many of – compliance with many of those rules, but to give you a really solid, long-term view, I would like to have a much better field for what we’re looking at related to EPA requirements and I think we’ll get that this year.

Jim Von Riesemann – UBS

Okay, and then I guess 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 ROE, call it 10.5 of the payout ratio, better than 50% suggests at least 5.5% long-term growth rate. Is that in the realm of reasonableness?

Gale Klappa

I would say, for us four to six 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 I – at the moment and this is just 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 four to six.

Jim Von Riesemann – UBS

Okay. Thank you.

Gale Klappa

Thank you, Jim.

Operator

Your next question comes from the line of Edward Heyn with Catapult. Please go ahead with your question.

Gale Klappa

Ted, how’s it going?

Edward Heyn – Catapult

Good, Gale. Good afternoon.

Gale Klappa

Are you giving me 3.5 in Green Bay?

Edward Heyn – Catapult

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

Gale Klappa

You’re giving me 3.5?

Edward Heyn – Catapult

Yeah. All right.

Gale Klappa

All right. What are we – what is this friendly wager for?

Edward Heyn – Catapult

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

Gale Klappa

All right. That apple better be big.

Edward Heyn – Catapult

Yeah. A quick question on the – 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 was on $117 a share 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 $0.12 number could be $0.10 lighter but you’re going to try to give that back with cash distributed through dividends.

Allen Leverett

Well, one thing, there’s sort of a 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 13 month average over that period. So, for example, if you had bonus depreciation benefits that occur relatively late in the year, that in affect doesn’t count dollar for dollar against you in that period.

So if I just sort of narrow down, Ted, and look at the bonus depreciation impact on rate base and say look in the 2012 test period, do all 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.

Edward Heyn – Catapult

Okay.

Allen Leverett

But then as you say, that provides additional cash in effective from operations they can be used to faster on the dividend. So hopefully I haven’t overly complicated things, but just keep that in mind. There is this averaging that occurs.

Edward Heyn – Catapult

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

Allen Leverett

Yeah, that’s the right zip code. The other thing you have to take into account though when you’re doing that 50/50, well there’s – 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’d 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 sort of –

Edward Heyn – Catapult

Okay, just the cost of that capital is going to be cheaper?

Allen Leverett

Yeah...

Gale Klappa

And you’re in the right zip code, though, Ted.

Edward Heyn – Catapult

Okay. That’s great. And then just on the – Allen, could you give us – I think typically you give breakdowns for CapEx for the next couple of years, is this appropriate time for that refresh?

Allen Leverett

Well, there’ll 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’d mentioned $935 million for 2011, I expect will be at about somewhere between $656 and $681 in 2012, and then I would say in 2013, probably around $540 million.

Edward Heyn – Catapult

$540 million in ‘13? Okay.

Allen Leverett

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 says, okay just to assume for conservatism at this point we’re not doing any additional renewable in this period past Glacier Hills, Domtar, you get to those numbers that I talked about. And then like I said, there’ll be some additional disclosure in some more detail in the 10-K later this month.

Edward Heyn – Catapult

Got you. Okay, that’s helpful. Thanks a lot, guys.

Gale Klappa

You’re more than welcome.

Operator

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

Gale Klappa

How are you, Steve?

Steven Gambuzza – Longbow Capital

Good, thanks. I think you mentioned in the prepared remarks that the Point Beach credits ended at the end of 2010? Is that right?

Gale Klappa

That is correct.

Steven Gambuzza – Longbow Capital

Just curious what the impact will be this year then for – because this was not a rate case year, so there were no change in base rates in 2011, so is it the only really change should be the phase out of those credits?

Gale Klappa

In terms of customer bills?

Steven Gambuzza – Longbow Capital

Yes.

Gale Klappa

Yes. Well there will be two changes. One, the phase out of the credits. And then the second is that we have a fuel case pending with a very modest increase in fuel costs and I expect that’ll 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 the very modest 1%-ish type fuel increase.

Steven Gambuzza – Longbow Capital

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

Gale Klappa

About 5%.

Steven Gambuzza – Longbow Capital

Five percent. Okay. Thank you very much.

Gale Klappa

You’re welcome, Steve.

Operator

Alex Kania with Bank of America. Please state your question.

Gale Klappa

Greetings, Alex. How are you?

Alex Kania – Bank of America

Hey. Good afternoon. Hope the snow hasn’t been too horrible for you guys today.

Gale Klappa

We’ve shoveled out of about eight foot snowdrifts, but we’re here.

Alex Kania – Bank of America

Well (indiscernible). Yes, thank you for coming out with the earnings release. I have two questions for you. I think the first one is if Allen could give just a little more elaboration on the bonus depreciation standard of the 50% versus the 100%? Just 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.

Allen Leverett

Yeah, 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, 2010 to January 1, 2012. The window for 50% extends from January 1, 2008 to December 31, 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. 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.

Alex Kania – Bank of America

Right.

Allen Leverett

And what that means is that you have to have at least 90% of your project expenditures within the window. So, for example, 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, 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 depreciation.

Alex Kania – Bank of America

You get 100%.

Allen Leverett

If you fail the 100%, then you can go back and test to see if you apply, 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 of the major projects, well, Oak Creek 1 and 2, well, they fail both of these because you didn’t spend 90% of the money for those projects in either of those windows.

Gale Klappa

During the window.

Allen Leverett

So you had expenditures that – 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%.

Alex Kania – Bank of America

Got it.

Allen Leverett

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 but...

Gale Klappa

Oh, I know Alex understands.

Alex Kania – Bank of America

Of course. I’m just sitting through for the benefit of everybody else, right?

Gale Klappa

That’s right.

Allen Leverett

So for us this bonus means about an additional $1 billion of tax depreciation that gets moved off 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. Then in addition, there’s an interaction with the Section 199.

Alex Kania – Bank of America

Manufacturing credit? Yeah.

Gale Klappa

Manufacturing credit.

Allen Leverett

Well, 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 but that’s...

Alex Kania – Bank of America

No. That’s perfect. That’s great actually. I’ve never heard kind of as clear an explanation to be honest. So it’s helpful and thanks for the rules.

Gale Klappa

Alex, in time it all turns around.

Allen Leverett

Yeah. It does.

Alex Kania – Bank of America

Yeah. It will, of course.

Allen Leverett

It all turns around.

Alex Kania – Bank of America

Okay. Great. And then my second question is just making sure that doing more of these rate base masks kind of things. Looking from ‘11 to ‘12, and you’ve give a few of the pieces. $6.7 billion in – I’m sorry, where are we in 2000? We’re about $6.35 billion in ‘12, up to $6.7 billion – $6.35 billion in ‘11, $6.7 billion in ‘12. And then in ‘11 you’re thinking that your equity layer is going to be toward the high end of the allowed range which is about 53.5%.

Allen Leverett

That’s right.

Alex Kania – Bank of America

So that’s kind of 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.

Alex Kania – Bank of America

Okay. So verily so if I just assumed going into 2012 that presumably that you’re not going to reduce that equity layer, I mean, I guess you could theoretically but if I – even if the net was flat and you just dividend it out all of the kind of all of your retained earnings and kept that ugly layer flat that you’d be looking in 2012 at like a 51% equity layer? Is that fair to think about?

Allen Leverett

Yeah. I think I had an earlier question about that.

Alex Kania – Bank of America

Yes.

Allen Leverett

I think sitting here today it’s reasonable to assume you’d be at the mid-point of the equity range.

Alex Kania – Bank of America

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

Gale Klappa

Thanks, Alex.

Alex Kania – Bank of America

Take care. Bye.

Gale Klappa

Take care.

Operator

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

Gale Klappa

Welcome, Carl. How are you?

Carl Seligson – Utility Financial

Thank you, Gale. Doing well. You guys are so good at explaining things I wondered if you’d tell me what depreciation is. I’m teasing. What’s going on with Mark Meyer? Is he going to get re-appointed? And if not, what’s the likelihood that you’ll get someone who’s less favorably disposed?

Gale Klappa

Well, Mark’s term expires on March 1.

Carl Seligson – Utility Financial

Right.

Gale Klappa

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 on 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 re-appointed 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 is 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.

Carl Seligson – Utility Financial

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

Gale Klappa

Yes. The appointment to the commission must be confirmed by the state senate. But, of course, in Wisconsin in the last election, the Republicans gained control of both the assembly and the state senate.

Carl Seligson – Utility Financial

Right.

Gale Klappa

So I wouldn’t foresee any quality candidate having any difficulty being confirmed by the state senate.

Carl Seligson – Utility Financial

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

Gale Klappa

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

Carl Seligson – Utility Financial

‘15

Gale Klappa

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.

Carl Seligson – Utility Financial

I guess there is the possibility of a significant turnaround as a result of the election, so you could have two Republicans in term in time.

Gale Klappa

Yes and I expect in time we will have.

Carl Seligson – Utility Financial

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

Gale Klappa

Yeah, they’re not real good at shoveling though.

Carl Seligson – Utility Financial

Imagine that. You got to teach them, you had it early.

Gale Klappa

Amen.

Carl Seligson – Utility Financial

Okay.

Gale Klappa

Thanks, Carl.

Carl Seligson – Utility Financial

Thanks. Bye-bye.

Operator

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

Gale Klappa

Hey, Paul. How you doing?

Paul Ridzon – KeyBanc

Fine. How are you?

Gale Klappa

Doing great. What can we do for you today, Paul.

Paul Ridzon – KeyBanc

I’m not a Packers fan, but I hate the Steelers though. Good luck.

Gale Klappa

All right. Rock and roll.

Paul Ridzon – KeyBanc

Update on fuel legislation. 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 wide spread of potential environmental CapEx. Would you like to put bookends on it?

Gale Klappa

Let me, well let’s see that’s about eight questions, Paul, let’s try to tackle them one at a time. You had asked about fuel rules?

Paul Ridzon – KeyBanc

Yes.

Gale Klappa

In the waning days of the past legislature at the end of December, new fuel rules were finalized. And 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 will 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. And Allen?

Allen Leverett

Yeah, and I’m not sure that I totally understood where you were going with the interest benefit. The only interest benefit that I recall talking about were some interest benefits of the holding company.

Gale Klappa

Right.

Allen Leverett

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.

Paul Ridzon – KeyBanc

Okay. I understand. Thanks.

Allen Leverett

Okay.

Gale Klappa

All right. And we may have lost your other questions. Can you – is there anything else you’d like us to address Paul?

Allen Leverett

I thought you had one more question. I wasn’t sure.

Gale Klappa

Well, we can’t remember and obviously you can’t either, but we appreciate you asking, Paul.

Operator

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

Gale Klappa

Hi, Travis. Good afternoon.

Travis Miller – Morningstar

Good afternoon to you. A real quick question, given the amount of cash that you guys have coming in, in projective the next couple of years, any projections or plans for additional pension contributions?

Gale Klappa

Well 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 in the pension trust 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?

Allen Leverett

Yeah. I mean if you look out and say, okay we’ve made the contribution that Gail mentioned for this year. And say all right look out from 2012 to 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.

Travis Miller – Morningstar

Okay, great. That’s very helpful. Thank you.

Gale Klappa

You are more than welcome.

Operator

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

Gale Klappa

Hi, Leslie. How are you today?

Leslie Rich – JP Morgan

Great, Gale. How are you?

Gale Klappa

Doing well.

Leslie Rich – JP Morgan

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

Gale Klappa

Well I think we’re looking at really in two ways. First at the utilities and I would think our 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 in the utilities. And again, as Allen mentioned, the range that the Wisconsin Commission has historically provided would be about a 48.5% to a 53.5% equity ratio at the utilities.

And then in terms of the entire enterprise, well, we said that we want – we at least want to get to – we at least want to again maintain solid investment grade credit rating and have a total debt-to-capital that basically supports those credit ratings. So everything in terms of our look at a 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 that we would want to keep it in that 54 to 55% range over the longer term. Allen?

Allen Leverett

Yeah and it’s the only thing, Leslie, it’s – I agree with all that Gale just said. The additional thing that I would say, though, is 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’d have $200 million worth of unsecured debt that secures 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’d also have opportunities to pay them down.

Gale Klappa

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

Leslie Rich – JP Morgan

Okay. Thank you.

Gale Klappa

You’re welcome, Leslie.

Operator

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

Gale Klappa

Hi, Vedula.

Vedula Murti – CDP Capital

Hi, couple of things. One, you went through the sales forecast that 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 kind of 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?

Allen Leverett

Yeah. I guess if you look at, Vedula, the 2010 normalized Electric sales and compare 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, very consistent with what is 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 of 2011 would be would actually be about 0.6% below the forecast that they had for 2010. And it varied by class. I’m talking all in terms at a total company level. Some classes may be more or less than the test year.

Vedula Murti – CDP Capital

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

Allen Leverett

Well, I think 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 an additional $16 million of margin which I think back in the envelope is probably about 28 basis points on the return, if that helps.

Vedula Murti – CDP Capital

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

Gale Klappa

Oh. Sure I’d 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 slipstream 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 is – it really performed very well for the first time out of a 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 are will it operate as designed in terms of carbon capture as it gets scaled up to a full utility-sized plant.

Vedula Murti – CDP Capital

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

Allen Leverett

The restricted cash was related to the Point Beach field credits.

Vedula Murti – CDP Capital

Oh. Okay. Got it. Okay. Thank you.

Gale Klappa

You’re welcome.

Operator

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

Gale Klappa

Greetings, Paul.

Paul Patterson – Glenrock Associates

Hi. How are you?

Gale Klappa

Doing great. How about you?

Paul Patterson – Glenrock Associates

Okay. I wanted to ask you about the performance at Oak Creek and if it’s beating, I guess, some of the benchmarks that you guys had laid down.

Gale Klappa

Right.

Paul Patterson – Glenrock Associates

Was there any particular reason for that? I mean was there some new practice or technology or something that you guys did? Or is this just you guys beating your goals because, I don’t know, being conservative goals perhaps? I don’t know. I was just wondering if you could just elaborate a little bit on that.

Gale Klappa

I’ll ask Rick to give his view as well but first of all, they weren’t conservative goals. I mean if you think about the guarantees that we were able to elicit from Bechtel in the contract, the heat rate guarantee, the emissions guarantees, I mean they were not weak goals. I think that the extra capacity that we’re 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?

Rick Kuester

Yeah. 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 ensure that we had adequate margins in there and we showed up on the back end with those margins. There’ll be a lot of value to that for customers over the life of this project, too.

Paul Patterson – Glenrock Associates

Right. So the – and the efficiency’s the same thing, pretty much.

Gale Klappa

Yes.

Rick Kuester

Yep.

Paul Patterson – Glenrock Associates

Okay. And so – and this all goes to ratepayers and there’s no kicker or something for shareholders in this. Is that correct?

Gale Klappa

No. That’ll all go to ratepayers and just to put a number on it for you. I think the guaranteed heat rate in the contract was $88.50 and then we’re beating that by 6% and when you look at kind of the tables that are produced around the industry, a 6% improvement on an $88.50 heat rate is pretty phenomenal.

Paul Patterson – Glenrock Associates

$88.50 being the nameplate of the heat rate?

Gale Klappa

While being the guaranteed heat rate.

Paul Patterson – Glenrock Associates

Being the guaranteed heat rate. Okay. Thanks a lot.

Gale Klappa

You’re more than welcome.

Operator

Your last question comes from the line of Reza Hitucki with Decade. Please state your question.

Gale Klappa

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

Reza Hitucki – Decade

I know. This is quite the call. Allen, I just wanted to clarify a couple of things. There’re 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 sort of already embedded in the, I guess, the negative $0.17 parent drag items for 2012?

Allen Leverett

Yeah. And then year-over-year or 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 there is a $0.03 benefit because you pay off a portion of the 450 senior note and then you replace a portion of it with commercial paper. So you add $0.11 increase drag because of less capitalized interest offset $0.03 with an interest benefit for a net $0.08 swing if I’m making sense.

Reza Hitucki – Decade

Well, although the apparent drag in ‘11 is $0.27 improving to $0.17 in ‘12, right?

Allen Leverett

Yes. So I thought your question was about ‘10 versus ‘11. I’m sorry.

Reza Hitucki – Decade

Oh, no. Sorry. The ‘11 versus ‘12 you mentioned all this extra cash. Is that – so that’s paying down some parent debt is already embedded in the negative $0.27 in ‘11 as well as the negative $0.17 in ‘12.

Allen Leverett

Well, 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 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.

Reza Hitucki – Decade

Oh, okay. I’m sorry I thought like I said there is so many numbers I thought you reiterated the segment guidance for ‘12, like the PTF and ATC and the parent, but...

Gale Klappa

He was really reiterating for ‘11.

Reza Hitucki – Decade

Oh, okay. I’m sorry. And then just to clarify on the rate base, you said ‘12 is $6.7 million, before it was $7 billion, but then you mentioned that the deferred tax impact is only causing $100 million decrement in ‘12 from that $7 billion, I guess, 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 of the 300 is hitting in ‘12. I got a little confused there.

Allen Leverett

Yeah. And let me just sort of take you through. So original forecast, $7 million of worth of rate base for 2012. There’s $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 million to $6.7 million. So bonus depreciation, working capital and CapEx. And then, Reza, as you throw forward to 2013, you’re exactly right. On the margin there’d be another $200 million reduction in rate base because of the buildup in deferred taxes moving to 2013.

Reza Hitucki – Decade

Okay. Okay. Thank you for the clarity.

Allen Leverett

Okay.

Gale Klappa

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

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