威斯康辛能源 (WEC) 2012 Q1 法說會逐字稿

Good afternoon. Ladies and gentlemen. Thank you for waiting and welcome to Wisconsin Energy's conference call to review 2012 first-quarter results. This conference call 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.

After the presentation, the conference will be opened to analysts for questions and answers. In conjunction with this call, Wisconsin Energy has posted on its website a package of detailed financial information at www.WisconsinEnergy.com. A replay of our remarks will be available approximately two hours after the conclusion of this call. And now, it's my pleasure to introduce Mr. Gale Klappa, Chairman of the Board, President, and Chief Executive Officer of Wisconsin Energy Corporation.

Colleen, thank you. Good afternoon everyone and thank you for joining us as we review the Company's 2012 first-quarter results. Let me begin as always by introducing the members of the Wisconsin Energy management team who are here with me today. We have Allen Leverett, President and Chief Executive of We Generation, Rick Kuester, our Chief Financial Officer, Susan Martin, General Counsel, Pat Keyes, our Treasurer, and Steve Dickson, Controller. Susan, of course, was recently promoted to the General Counsel position. She succeeds Jim Fleming who retired just a few weeks ago.

Rick will review our financial results in detail in just a moment. But as you saw from our news release this morning, we reported earnings from Continuing Operations of $0.74 a share for the first quarter of 2012. This compares with earnings of $0.72 a share for the first quarter of 2011. Weather, of course, both regionally and nationally was the big story in the opening quarter of 2012. For Wisconsin Energy, the warmest winter in 122 years drove down residential demand for natural gas by nearly 24% compared to last year's first quarter. As you'll recall, sharply lower demand for natural gas prompted us to revise our first-quarter earnings guidance on March 29. At the same time, we also reaffirmed our full-year forecast.

Now, while the weather was a dominant factor in our first quarter results, there were several bright spots that I'd like to briefly touch on. First, we had a positive swing of $17 million from the recovery of fuel costs in the quarter compared with the first quarter of 2011. We also recorded significantly lower operation and maintenance costs. That's largely because of the one-year holiday on regulatory amortizations approved by the Wisconsin Commission and the order that froze our base rates for 2012. We also had lower interest costs and there was an uptick in electric sales to our largest customers.

Turning now to the economy. Wisconsin's unemployment rate, at 6.8% in March, remains well below the national average. As I mentioned, electric sales to our large, commercial, and industrial customers rose by 3% in the first quarter of 2012. The sectors showing particular strength in the past quarter include iron ore mining, heavy equipment manufacturing, and for the first time since the recession, the producers of rubber and plastic products. We're also seeing a rebound in new customer connections. Compared to the low level of activity during the recession, electric customer connections were up 29%, and connections of new natural gas customers rose by 33% over the 12 months ended March.

On the construction front we have two major projects under way -- the 50-megawatt biomass plant in Northern Wisconsin and the air quality control upgrade at the original Oak Creek units. We're making excellent progress on the biomass plant in Northern Wisconsin. We've already topped out the structural steel for the boiler and the steel structure for the turbine and fuel storage buildings are now 90% complete. Construction of the cooling tower is under way as well as excavation work for the auxiliary boiler. As I've noted before, the biomass plant will help us diversify our portfolio of renewable energy. We'll be able to dispatch the unit and the efficient technology that will produce steam for the operating paper mill at the site will clearly enhance the economics of the project.

Our investment in the biomass plant is expected to total between $245 million and $255 million, excluding allowance for funds used during construction. We're on schedule and on budget to meet a completion date by the end of 2013. Of course, the biomass project and the Glacier Hills Wind Park that we completed late last year are key components that will help us meet Wisconsin's renewable portfolio standard for the year 2015. To refresh your memory, the standard calls for an increase in the amount of electricity delivered from renewable sources from 5% in 2010 to 10% in 2015 at a state-wide level. The standard sets targets for each Wisconsin utility using an historical baseline. Using that baseline, approximately 8.27% of our retail sales of electricity must come from renewable sources in the year 2015.

When we complete the biomass project, we'll be well positioned to meet that 2015 standard. I should pont out, however, that we expect to deplete our bank of renewable credits and as a result we expect to need additional credits or additional renewable generation in the year 2017. Finally, we're in the last stages of completing the air quality control upgrade for the older coal fired units at our Oak Creek site. The four older units at Oak Creek are still among the most efficient base load units in the Midwest. So the economic solution for our customers was to invest approximately $900 million including allowance for funds used during construction for the installation of wet scrubbers and selective catalytic reduction facilities.

This is the second largest construction project in the Company's history. And I'm pleased the to report that the wet scrubber and the selective catalytic reduction equipment for Units 5 and 6 at Oak Creek were placed into commercial service on March 3. This state-of-the-art equipment is performing well. It's performing as we expected. And we're meeting or exceeding all of the applicable emissions standards. For Units 7 and 8 at Oak Creek we're now focused on initial tuning and testing of the new air quality controls. We're targeting an inservice date for the Unit 7 and 8 controls later this summer and we remain on budget for the project.

Now I'd like to spend just a moment on the impact we're seeing from the current conditions in the coal and natural gas markets. As all of you know, natural gas prices are at extremely low levels. At this point, spot prices are about $2.35 per million BTU and forward prices for the summer are in the $2.35 to $2.55 per million BTU range. This is clearly influencing locational marginal prices in the MISO market. But over the years, the key to successfully serving customers at competitive prices has been fuel diversity and fuel diversity was a major focus of our Power the Future plan. You may remember that the plan called for the retirement of nearly 600 megawatts of older, less efficient, coal-fired capacity. At the same time, the new capacity that we added was almost equally balanced between natural gas and coal.

Of the approximately 2200 megawatts that we built in the past decade, 1,090 megawatts was natural-gas-fired combined cycle capacity and 1,056 megawatts was highly efficient pulverized coal capacity. Another important point, about 80% of the coal that we use is Powder River Basin sub-bituminous coal. Although the new Oak Creek expansion units are currently fueled with bituminous coal, we're seeking the flexibility to burn blends of bituminous and sun-bituminous coal there in the future. Overall, we're projecting to burn just under 9 million tons of coal this year, versus 10.7 million tons in 2011. We'll achieve this reduction by carrying out planned burns, maximizing the use of storage, and working with our coal suppliers to defer, buy out, or renegotiate several existing contracts.

Natural gas will take up the slack. Our natural gas burn is expected to nearly double from 28.5 Bcf last year to 50 Bcf this year. In fact, our natural gas units at Port Washington operated at about a 60% capacity factor in the first quarter of this year. The Port Washington units are essentially now being dispatched in the MISO market as base load units. So overall, I believe we're well-positioned to adjust as the markets for coal and natural gas continue to evolve. And for calendar year 2012, we expect to fully recover our fuel costs.

Now I'll briefly review where we stand on the regulatory fronts in both Wisconsin and Michigan. As you may recall, our electric customers in Wisconsin are seeing no increase in base rates during 2012. We developed a creative approach to push off for a year an increase in base rates as the economy continues to recover here. Looking ahead, we have filed a rate request with the Wisconsin Commission seeking an increase for electric and steam customers for 2013 and 2014, and a decrease in base rates for our natural gas customers in 2013. The base rate adjustments we're seeking are driven by approximately $1.6 billion of capital investments that the Commission previously approved to strengthen reliability, to meet environmental requirements, and to comply with Wisconsin's renewable energy mandate.

Projects previously approved by the Commission include the air quality control system for the older units at Oak Creek, the Glacier Hills Wind Park, the biomass facility in Northern Wisconsin, and the Oak Creek expansion units. Our proposal in this particular rate case includes using a federal grant that we expect to receive for our biomass facility. After applying this cash grant, the result would be a net customer bill impact of a 3.6% increase in 2013, and another 3.6% in 2014. Our filing also includes an estimate of fuel costs for 2013. But that's simply a place holder at this point because our fuel cost projections will be updated and finalized later this year.

On the natural gas distribution front, we proposed a decrease in base rates for customers of our two gas distribution utilities in the year 2013. We're seeking a 2.3% decrease for Wisconsin gas customers, and a 0.002% decrease for Wisconsin Electric gas customers. For 2014 we're proposing the base rates then remain flat. For our steam utility, we filed for an increase in 2013 of approximately 6% for our downtown Milwaukee customers and approximately 7% for our Milwaukee County customers. In 2014, our proposal calls for an increase of 6% for both of those customer groups. We expect the Wisconsin Commission to hold technical hearings on our requests later this year and to issue orders before the end of 2012. We have requested the new rates go into effect at the start of 2013 and 2014, respectively. We'll keep you updated as developments unfold.

Turning now to our Michigan operations. You'll recall that in July of 2011 we filed a request with the Michigan Public Service Commission for an annual rate increase of $17.5 million. We're seeking to recover from Michigan customers their pro rata share of renewable generation, environmental controls, and costs associated with the second expansion unit at Oak Creek. In late December, the Commission decided or directed, I should say, the Company to self-implement a $5.7 million rate increase that took effect on January 5, 2012. The Commission's directive also authorized the Company to implement a $2.7 million credit of the proceeds we received from a settlement with the Department of Energy. Applying the credit, the net effect of the interim rate increase is $3 million or about 1.7%. We expect the Michigan Commission to rule on our entire request by July 5 of this year. In addition, approximately $2 million of renewable costs were included in our Michigan fuel recovery rate, and that was effective January 1 of this year. So the total self-implementation was $7.7 million annually.

Switching gears now, a quick reminder that our Board has authorized a share repurchase plan scheduled to run through the end of 2013 that calls for us to buy back up to $300 million of Wisconsin Energy common stock through open market purchases or privately negotiated transactions. No purchases were made under the plan in the first quarter of this year. Through today, we have repurchased approximately 3.2 million shares at a cost of $100 million. That equates to an average purchase price of $30.79 a share.

And as we previously announced, our Board has adopted a dividend policy that calls for us to reach a 60% payout ratio in the year 2014. This policy should support double-digit growth in the dividend in both 2013 and 2014, as we work to achieve a payout ratio that is more competitive with our peers across the regulated utility sector. We took another major step forward in January by approving a dividend increase of 15%, bringing our new dividend rate for 2012 to $1.20 a share. Finally, I'd like to briefly discuss the investment opportunities we have in our core business. Our latest capital budget calls for spending $3.5 billion over the five-year period 2012 through 2016.

In our 2012 through 2016 budget, the nature of our capital investments is shifting, shifting away from an emphasis on generation involving high profile projects such as our Power the Future units, renewable generation, and large air quality controls. Instead, our capital plan is primarily comprised of many smaller projects that will upgrade our aging distribution infrastructure, the building blocks of our delivery business, pipes, poles, wires, transformers. The primary risks associated with these projects, developmental, legal, regulatory, construction, are naturally more manageable given the smaller scale and scope of the distribution work. But this work is no less valuable or important than the mega projects we've just completed. Our focus on upgrading and renewing our distribution facilities is essential to maintaining our status as the most reliable utility in the Midwest.

So in summary, as we look back at the first quarter, our customers enjoyed basking in Miami-like weather in January, February, and March, and we continue to make solid progress on our financial and operational goals. Now, before I turn the call over to Rick, I'm pleased to share with you one more piece of good news. For the fifth year in a row, Wisconsin Energy was named one of the 100 Best Corporate Citizens in the United States by Corporate Responsibility Magazine. And on that note, here's our Chief Financial Officer, and a darn fine citizen in his own right, Rick Kuester. Rick?

Thanks, Gale. As Gale mentioned earlier our 2012 first quarter earnings from Continuing Operations were $0.74 a share, compared to $0.72 a share in 2011. You will notice that our net income increased by just over $1 million. However, earnings per share increased by $0.02. This increase reflects the impact of our share repurchase program which began in 2011. We estimate that the share repurchases we completed in 2011 will boost our earnings for the full year 2012 by $0.03 per share.

Now, as we take a closer look at the numbers, I will focus on the earnings drivers at the operating income level by business segment, and then touch on other income statement items. I will also discuss cash flows in the quarter. Our consolidated operating income in the first quarter of 2012 was $296 million, which was the same as first quarter 2011. Starting with utility energy segment, you will see that operating income totaled $209 million, a decrease of $4 million versus 2011. The most significant factor in the quarter was the record warmth that we experienced. The quarter ended with slightly cooler temperatures during the last three days, which helped boost us to $0.74 a share.

We estimate that our electric and gas margins were reduced by $49 million as compared to last year, and $34 million as compared to normal weather. Partially offsetting the impact of weather were our collections on fuel which improved by $17 million, as compared to 2011, and a reduction in our O&M cost of $25 million at the utility level. We had favorable first quarter fuel recoveries because our fuel filing request was approved on January 5 of this year. Last year, our fuel filing request was not approved until late April. The reduction in O&M cost is related to the one year amortization holiday of certain regulatory assets.

As you will remember from prior calls, last year we reached an agreement with the Wisconsin Commission that allowed us to freeze base electric rates in 2012. One of the provisions in the agreement was the ability to stop the amortization of approximately $148 million associated with regulatory assets. This action will reduce O&M by $148 million during 2012, which will flow evenly through the year. This agreement was designed to help our customers avoid price increases in this economy and allow shareholders to earn returns on the capital projects that Gale discussed earlier. Operating income in the non-utility energy segment, which consists primarily of the Power the Future units, was up by $4 million. Unit 2 at Oak Creek was placed in service on January 12, 2011 so we realized a full quarter's earnings on the unit in 2012. Last year we only realized a partial quarter's earnings on Unit 2.

In addition, we finalized the depreciable lives of these units which had a slight positive impact on earnings. The increased earnings in the non-utility segment offset the reduced earnings from the utility. Our corporate and other segment were also unchanged from the prior year, which gets us back to level consolidated operating income. During the first quarter of 2012, earnings from our investment in the American Transmission Company increased just slightly over 2011. Our other income increased slightly because of higher AFUDC associated with the air quality control project and the biomass project.

Net interest expense decreased by $4 million. We saw a reduction in our gross interest expense as we retired $450 million in holding company debt in April 2011. Consolidated income tax expense rose by approximately $7 million because of higher pretax earnings and a higher effective tax rate. Our effective tax rate for 2012 is expected to be between 35.5% and 36.5%. Combining all of these items brings you to $172 million of net income from Continuing Operations for the first quarter of 2012, or earnings of $0.74 per share.

During the quarter, we generated $361 million of Funds from Operations, which is a $7 million increase from the same period in 2011. This year's cash flows were helped because no contributions were needed for our qualified benefit plans. Those plans are fully funded. In the first quarter of last year, we contributed $122 million to our qualified plans. This item was offset by several smaller charges including a reduction in regulatory amortizations of $37 million associated with the amortization holiday discussed previously. Our total capital expenditures increased by approximately $7 million in the first quarter of 2012, as compared to the first quarter of 2011. We saw increased expenditures associated with the biomass plant and within our core utility operations. The warm weather did allow us to get a head start for the year on our capital projects.

We also paid $69 million in common dividends in the first quarter of 2012, which was $8 million greater than the same period last year. As Gale mentioned, the first quarter dividends equate to an annual dividend of $1.20 per share which is a 15% increase over the prior year's annual dividend of $1.04 per share. Our adjusted debt-to-capital ratio was 53.3% as of March 31, 2012. Our adjusted calculations treats half of our hybrid securities as common equity which is consistent with past presentation. We are using cash to satisfy any shares required for our 401K plan, options, and other programs. Going forward, we do not expect to issue any additional shares.

As shown in the earning package on our website our actual first quarter 2012 retail sales of electricity decreased by 1%, as compared to the same quarter a year ago. On a weather normalized basis, first quarter 2012 retail electric sales were up 1.1%. Excluding the mines, normalized first quarter sales increased by 0.3%. As you recall, we have two customers that are utilizing their own self-generation in 2012. Adjusting for these customers, and the mines on a normalized basis, we saw retail sales grow by 0.6%. Overall, these results are in line with our 2012 sales forecast.

As we look at our natural gas sales, we saw retail sales decrease almost 24% during the first quarter of 2012, as compared to the first quarter of 2011, due to the warm winter. Excluding the effects of weather, our natural gas sales are in line with our annual forecasts. Our 2012 earnings guidance remains the same as what we provided to you on our February conference call. We expect our earnings for 2012 to be in the range of $2.24 to $2.29 per share. While our first quarter earnings fell below our original guidance because of record warm weather, we have taken actions to control spending and we have seen lower fuel and purchase power cost driven by the low natural gas prices. In addition, our interest costs are projected to be lower than originally forecasted. Before I turn things back over to Gale, I would like to provide quarterly guidance. Factoring in lower sales in April due to weather, we estimate second quarter earnings will be in the $0.40 to $0.43 per share range. With that, I'll turn things back over to Gale.

Rick, 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 question.

(Operator Instructions).

Kit Konolige, Konolige Research.

Good afternoon to all you at Miami on Lake Michigan.

There you go.

All right. Good for golf, right? So I think, Rick, you mentioned no issuance of shares. Can we extrapolate from the first quarter that there's no share repurchases likely at the current stock price?

Well, Kit, I wouldn't start extrapolating. I guess I would back up and just say because of the free cash flow that we have, we've identified a number of uses for that cash. First and foremost is to reinvest in our business. Second, is to increase our dividend and as you're aware we've accelerated our target to get to 60% by a year, so we'll be there in 2014. Then we're looking opportunistically at basically buying shares or reducing debt at the holding company. And we want to make good economic choices. We don't want to sit on a bunch of cash. We've got a program that basically is authorized out through 2013 to buy back shares and we will continue to look at that every quarter and just see what makes the most sense for shareholders.

Okay. Very good. Let me ask one more on sales. Can you give us any further color on -- are you guys able to see whether it's commercial versus residential that's the kind of relative weaknesses and offset to the somewhat improving industrial sales?

Actually, Kit, because of the unusual weather in Q1, way more than two standard deviations off norm, we all are a little bit skeptical of how effective the weather normalization techniques that the industry uses really are when you get that far off norm. So I wouldn't put a lot of stock in the precision of the weather normalized first quarter numbers. But directionally, they are correct and every one of the categories is up on a weather-normalized basis. The one that seems to be at least for the first quarter lagging a little bit would be small commercial, but that was not the case last year. So my sense is when you look at the pick-up in industrial demand and when you look at the pick-up in customer connections that I mentioned, we are seeing some stronger economic activity. Rick, anything to add?

I think you hit it, Gale.

Great. Thank you, guys.

Thanks, Kit.

Thanks, Kit.

Paul Patterson, Glenrock Associates.

Just to sort of follow up on that, I realize it's more of an art than a science here, but just to make sure I understood this, it's 0.3% was what the weather normalized sales growth was; is that correct?

That's excluding the mines.

Excluding the mines. With the mines it's about 0.6%?

I believe that's correct.

Does that include leap year?

Yes, it does include leap year. Yes.

Okay. So it would actually be negative if we take out the effects of leap year; right?

You could probably come to that conclusion. I wouldn't necessarily think that's a firm conclusion. Again, thinking about the deficiency of the technique, the weather normalization technique when you have this kind of disparity in the weather, my own sense is we're seeing a little bit stronger pick-up, particularly on the industrial side, and my guess is we're going to see a bit of a rebound if weather ever comes back to normal here on the commercial side. Because we did last year. Commercial was stronger than we expected last year.

Okay. And then the Prairieville, I think it is -- I'm probably messing this up -- to Zion line.

Pleasant Prairie to Zion.

Pleasant Prairie to Zion. Could you give us any flavor as to what you think that might do with respect to congestion and with respect to imports or exports into Illinois.

Sure. We'll ask Allen Leverett to give you his views since he represents us on the Board of American Transmission Company. But let me just, for everybody's sake, kind of clarify what Paul's talking about. The Pleasant Prairie to Zion line is an important link to strengthen the transmission network and relieve some congestion between the very far southern chunk of the state of Wisconsin and Illinois. It's only about a five mile line but an important additional interconnect. Allen?

Paul, it's a 345 kV segment, if you will. I would expect at this point that they would bring it in service in 2014. And effectively what it will allow us to do, often we get in a situation right now where we have generation that you sort of think of it as being shut in where you can't -- if you had no transmission constraint you'd be able to export much more to the south. So it will open that up a bit and should result in some savings for our customers. It's hard to say, Paul, because you don't know precisely what the situation will be on the transmission system but I could easily see savings to our customers in say a $15 million to $20 million a year range.

Okay.

From a fuel standpoint. No earnings -- certainly no earnings impact for us but some nice savings we hope for our customers.

And they would expect to complete -- both the Illinois and Wisconsin Commissions have now approved the construction of the line -- and they would expect to complete it before the end of 2013.

So good for customers and perhaps a little bit depressing to the power markets in Illinois, all things being equal.

They're depressed already.

(Laughter) Yes, they are. Thank you very much.

Thank you.

Jim von Riesemann, UBS.

Two questions, actually. The first one is when you think about your story prospectively are you a growth story or a yield story?

I think we're both. When you think about our risk-adjusted growth profile going forward of 4% to 6% as we've said, we think the risk-adjusted returns off that growth are very solid and then certainly we have for the next several years what I would think would be one of if not the best dividend growth story in the industry.

So let's just -- doing the math here, if you're growing dividends at 10% a year and it's now 2014 which is where you want to be at a 60% payout ratio, you're talking numbers in the $2.40 to $2.45 range. How do you get to that 4% to 6% growth going forward?

Well, I think if you look at the $3.5 billion capital program that we've laid out for the period 2012 through 2016, you sprinkle in some opportunistic share buybacks under our share buyback authorization, and you assume that we earn close to our allowed rates of return, that's how you get there.

Okay. Second question, I'll follow-up more offline with you on that. Second question is on the current state of the political affairs in Wisconsin. Can you give us an update on the Governor Walker recall campaign as well as the Senate recall campaigns?

Sure, be happy to, Jim. Well, first of all, I think the good news is the endless election cycle is about to come to an end for a while. The dates for the recall election process have been set. And the first date is next week, actually, when there will be a primary to determine the Democratic candidate who will run against Governor Walker in the recall election. Two candidates -- well, two principal candidates -- there are a number of candidates but the two leading candidates on the Democratic side on the polls would be Milwaukee mayor, Tom Barrett, and former Dane COunty executive, Kathleen Falk. So they probably will be the two largest vote-getters on the Democratic side. Don't know which will win but we'll find out very soon.

So one of those two candidates likely to face governor Walker in the recall election and the date for that election has been set for June 5. So June 5 would be the recall election date. In that recall election, there will be a recall election for the governor's office. There will be a recall election for the lieutenant governor's office and there will be a recall election for four state senators. I think one interesting side note, really the state legislature has adjourned for the year. So there's no planned meetings between now and the next election, which would be in November. So there's really no activity unless there's some kind of special session that would fall out of the Senate recall elections, if I'm making any sense.

You are. The Senate recall election, if memory serves me correctly, if it's a successful one, the balance of the power shifts from the Republicans to the Democrats, right?

It's actually 16, 16 now, Jim.

Someone resigned. It's tied now. If the Republicans lost any seats in the Senate recall elections, the balance of power would shift but from a practical standpoint, unless there's a special session there is no power to -- behind the shift.

Assembly is still solidly Republican.

Assembly is still solidly Republican. And then there will be a normal election for state Senate seats in November.

Okay. How do you think under various circumstances the energy policy in the state of Wisconsin moves around? I mean, what's the prospects for extending or killing renewables, doing a state-owned generation sale, et cetera?

Well, I think there are probably two pivot points here. One is certainly on the issue you raised which is renewables. Both of the Democratic candidates for Governor have mentioned in their stump speeches that they would want to re-emphasize construction of renewable generation, particularly wind in Wisconsin. So in my judgment, we probably would see a movement back toward construction of additional renewables to a greater degree under a Democratic administration than under the current administration. On the other hand, I don't believe any of the Democratic candidates for Governor are supportive of privatizing the state-owned power plants.

Okay. That's helpful. Thanks.

Okay. Thank you, Jim. Good questions.

Thank you.

Greg Gordon, ISI Group.

Just to circle back a little bit to the beginning of JVR's question, and it dovetails with the list of potential incremental rate-based growth projects on Page 20 of your handout. As we look at your plan, you lay out some very clear building blocks that look like, all things equal, they get you to, at a minimum, at a bare minimum the low end of your earnings growth aspiration. Is it fair to presume that if you were able to bring any of these six different options to the finish line in lieu of incremental buybacks, that that's what kind of pushes you to the high end of the growth rate?

As Rick said, priority one is investing in the core business. So if we find -- but these have to be real projects with real value to customers and shareholders, and if we find those projects, that's where we will focus our investment opportunity.

But they're not in your base case. These are things that are -- that could be incremental if they're deemed to be in the best interest of customers but they're not currently in the base case?

Well, for example, the first one on Page 20, investing in fuel blending at the new Oak Creek coal units, I believe that's not a big investment but it certainly is in our base case.

Okay.

Renewable energy beyond 2016 is not. Additional investment beyond what we have identified in the aging gas and electric distribution infrastructure is not. Future EPA rules beyond the ones we're aware of is not and certainly divestiture of the energy assets by the state of Wisconsin is not. The majority of them, Greg, are not.

Okay. Just wanted to be clear what you guys are counting on versus not counting on in the plan. Thank you.

Does that help?

Yes, very much so.

Thank you, Greg.

Michael Lapides, Goldman Sachs.

Couple questions and this may be an Allen question. Thinking about the ATC CapEx forecast for the next few years, just curious, why the downward trajectory?

Allen's looking at a page right now in front of him.

This doesn't have the capital, but in terms of the capital projection, I think that they finished a number of pretty large projects, Michael, and as you know, the transmission investments are pretty lumpy. So they finished those big projects and now the next big projects that are on the horizon, probably heard them talk about, or heard us talk about, Madison La Crosse, that's a big 345 kV east-west. So that's really the next big project that's out there. And then you have to go to 2015, 2016 to see another really big round of projects. At this point, strictly because of the lumpiness of the investments.

So is it pretty safe to assume that kind of the $38 million to $40 million a year rate-base growth. So you get a little bit of earnings growth contribution out of ATC longer term. Is ATC up year-over-year, like when I think about your 2012 guidance, is ATC's contribution higher in '12 than '11. It was relatively flat in the first quarter. Just want to check through that.

Up slightly. Up slightly in 2012 over 2011. But I think to Allen's point, Michael, maybe there's a couple of time differentiators that we can do for you here. Because clearly ATC has announced about a $4 billion capital plan over the next 10 years. That's materially larger than their last 10. As Allen pointed out, they're coming off completing very significant investments. They have a bit of a -- from that standpoint, a bit of a lower capital spend on the next four or five years and then it ramps up materially again because of the lumpiness and the time it takes to site and construct.

Okay. Two last --

One last thing on the ATC earnings, Michael, they are in line over the next five years, they are in line with our 4% to 6% growth rate. So they support that growth rate. And then they actually tick up after that because of the back end loading of the capital budget.

Got it. So ATC growth is similar to core utility growth.

For the next several years.

And then goes higher.

And then goes higher.

One or two other items. Balance sheet plans for this year, when you think about what's embedded in guidance for total debt issuances versus retirements in 2012 relative to where you ended 2011, can you just kind of give us some insight there of what's embedded in your guidance level?

We'll be happy to and then Pat or Rick can certainly add to anything that I've got to offer here. But we don't have any real maturities coming due in 2012. That's for starters. We did in our capital plan assume a bond offering at Wisconsin Electric for in the neighborhood of $250 million for at some point this year which we have not yet finally determined the date.

That's right.

Basically, that's about it.

That's right, Gale. Michael, this is Pat. I can just add that net-net, at the end of 2012 we'll be up slightly in the total debt that we were over 2011 and that's just to fund all the things that Rick has just walked through.

And that assumes no early retirements of hold co debt?

That is correct.

That is correct.

Last item. You're benefiting from -- I'd love if you could just kind of repeat a little bit, you talked about this prior -- from significant cash in-flows related to deferred taxes. You got a big cash in-flow I think earlier in the first quarter. Can you talk about that in terms of what's embedded in that kind of a cash flow statement item in 2012 in your guidance level for 2012, and then how should we think about what happens longer term?

Let me first, Michael, talk about the longer term and I think probably the best way to capsulize it is that based on our projections, we expect to have approximately $600 million of free cash flow over the period 2012 through 2016 and our definition of free cash flow would be after capital spending and after dividends. So after capital spending, after dividends, about $600 million of free cash between now and 2016. Frankly, the year-to-year breakdown is kind of immaterial here because it depends upon the level of capital spending and the timing of capital spending in any given year. So I think probably our best explanation to you is just that. The 2012 through 2016, approximately $600 million.

Okay. Can you all talk about the deferred tax benefit in 2012? Because I know there -- I thought there was a big cash in-flow expected in the first quarter related to some of the new Oak Creek units. I just want to make sure I'm kind of following the cash flows this year correctly.

Certainly I know what you're talking about. We'll let Steve Dickson mention this to you. But the influx of cash I don't believe is a first quarter event here.

No, it's tied to our timing of the periodic payments. Basically, as we've disclosed in the 10-K, is we do not expect to pay federal income taxes this year because of the benefits that we got in depreciation in prior years. So there's no slug of cash coming in. It's more of not having to make estimated payments.

What you may be thinking about, Michael, in the first quarter we announced that we received a Private Letter Ruling from the IRS in December of last year that basically confirmed that accelerated depreciation could be applied to the expansion units, the coal expansion units at Oak Creek site. And there was a $285 million cash -- it's basically a timing benefit by the end of 2014 associated with that PLR.

And so that's different than the bonus depreciation or that's all tied together?

No, that's -- well, it is a form of bonus depreciation.

Right.

But the difference is this particular Private Letter Ruling that Rick just mentioned applies to We Power and not to the utility so it does not in essence reduce rate-base growth.

We had previously announced bonus depreciation benefits that went to reduce rate base on our large air quality control projects and renewable projects as a result of the law that was passed and signed by the President, I think in December, 2010. So kind of two announcements. One dealt with regulated business and then we got the PLR that dealt with the nonregulated business and we announced that in the first quarter.

Michael, I know you know this but just so that we don't get descended upon by protesters saying we don't pay federal taxes, this is a timing benefit and the Company will owe hundreds of millions of dollars of taxes in future years.

Understood. Understood. Thank you guys. Much appreciated. I may follow up offline afterwards.

Very good. Thank you, Michael.

Jay Dobson, Wunderlich Securities.

Couple of questions, starting if I can with Rick. You mentioned the share repurchase would have an impact of $0.03 in fiscal year '12. I just wondered if there's an underlying assumption in that or is that simply the impact of what's been completed to date?

It's what's been completed to date which was back in last year.

Perfect.

That's the effect of that.

$100 million purchase at an average price of $30.79.

That's great. Gale, just revisiting an earlier question they took you through slide 20 of your recent slide deck, and what's not in CapEx currently that you identified, were you to go forward with that would reduce the share repurchase, right? So we shouldn't really double count here. If your CapEx does rise that will limit your ability to repurchase shares holding all things constant.

You're exactly right. Jay, that's a very good point and you are correct.

That's perfect. If we could then switch to the Wisconsin rate case. I know a lot of your peers there in the state are filing rate cases. In fact, all to my recollection.

We've got a lot of company, Jay.

Exactly. Sometimes that's good, sometimes that bad. In the context of that, I wanted to see, is there an opportunity to settle the current case? Yours is a little more complex than some your peers. But just wanted to have your early read on the ability to settle it if you could.

Good question, Jay. I think first of all, the history in Wisconsin is not one of settlement. I don't think actually there's been a settled rate case in the nine years our team has been here for any of the Wisconsin utilities that I'm aware of. I think there may be one other utility that thinks they can come close to zero this year that might be able to do a settlement. I wouldn't say there's a high probability of a settlement in the rate case.

However, there is a lot of work going on by the commission staff, by all of the utilities, and by the intervener groups to try to narrow the issues that will be contested in the case. And from that standpoint, I think our case is very straightforward. I mentioned earlier, the case is really driven by about $1.6 billion of capital investment that was previously approved by the Commission, that has come in to service, that is now serving customers, is used and useful, and we brought those projects in essentially on time and on budget. So that actually simplifies the case a tremendous amount. So I would say in our case, there won't be but about three or four, maximum five contested issues and the parties will nail down those issues in a pre-hearing conference starting on May 21.

That is great. Thank you. And then last question, I guess for Rick, but anyone can chime in. So regarding the guidance and sort of indicated that the weather and first quarter's weighing against you, things like O&M and fuel recoveries, as well as lower interest cost will help you over the balance of the year. Want to talk about two of those items. O&M, first. Just what are our incremental opportunities from here as you continue to squeeze costs out? Is it sort of it's always there and we can just squeeze more? Is it in fact a finite opportunity?

I'll start. Rick, Pat, Allen, can certainly chime in. The big driver in the O&M reduction this year, just to refresh everyone's memory, is embedded in our rate order that froze electric rates for customers for 2012. Basically, we asked for and received permission to stop amortizing $148 million of regulatory assets over the course of 2012. And that order allows us to stop the amortization in equal quarterly increments.

So for example, I think the number this quarter was $37 million, if I'm -- and people are nodding their head yes. So you can expect a comparable number when we report, in terms of O&M reduction, from that item when we report in Q2, Q3, and Q4. So that's the big driver this year. We've also asked our -- all of our major business functions to operate at no O&M increase and in some cases an O&M decrease for 2012. We're on target with those initiatives. Rick?

Yes, I would also say, Jay, that last year we had a hot summer and we released some projects at the end of the year. For example, there was a major turbine rebuild that needed to be done. Some of those projects that are episodic in nature won't be flowing through at the end of this year. You'll see probably a more positive benefit from O&M in the second half of the year than you would in the first half of the year.

Very good point.

That's great. Very helpful. Last question, just on the lower fuel recoveries, I assume you have baked into that your concept of plan to burn. Wouldn't mind if you expanded on that. Just how you -- there's a couple different definitions floating around of economic and planned burn when you're talking of some of these coal burns. If you would talk about that. I would assume that's baked in here. Obviously, as fuel costs change that may impact that so if you could just give us a little clarity on that.

Sure, Jay. Very good question. Let me just frame it and then we'll let Allen provide you the details. What is baked into our guidance now for the remainder of the year is an assumption that we will fully recover our fuel costs, that there won't be any reduction of earnings from a lack of recovery of fuel costs. And as we mentioned in the prepared remarks, related to our coal deliveries and our coal costs, we have a variety of initiatives under way, ranging from planned burns to turn back of coal to some buyouts. Allen, I know we have ongoing discussions with the coal companies.

Right. Jay, we talked or Gale talked about in the script that we're going to probably bring the burn from about 10.7 million tons last year to just under 9 this year. And then Gale talked about the range of things we would do to try to achieve that. We'll certainly try to pick the mix of those things that are best from an economic standpoint for our customers. My view right now is that we would be more heavily weighted to doing the deferred buyout renegotiate route for existing contracts as opposed to the planned burn route or storage route. But we'll just have to see where the numbers take us.

In terms -- when we say planned burn, though, Jay, what we mean by that is you basically would target a number of tons that you would want to burn and then given where we are right now or at least where we're forecast to be with locational marginal prices, we would actually discount our offer in the market. So we would discount the offer that we would put in for that unit when we put it into MISO into the day ahead market so that we get enough run time to burn that much coal. So you'd actually be discounting, if you will, your offer price in order to achieve a certain level of burn if I'm making sense.

That makes a lot of sense. And I appreciate that. Just on the points you offered, Allen, if you were to work on renegotiating the contract, assuming economic principles prevail, that would essentially just be pushing out the impact into future years.

Not necessarily.

Not necessarily, no.

In some cases it could be a pushout of deliveries. In other cases it might just be well, you just pay liquidated damages and you just turn back the deliveries completely and you're not committed to taking that delivery in a future period. It could be a mix of those two.

That's great. Thanks so much for the clarity. I really appreciate it.

You're welcome. Good questions.

Andrew Bischof, Morningstar.

One remaining question. You kind of highlighted your distribution investments. If you could maybe provide some clarity on your discussions with state regulators and any insight on your ability to get preapproval for those projects.

Oh, certainly. Let me first say there is what we call a CA process, a construction authority process, that has been practiced by the Wisconsin Commission going back decades and decades. If you have a distribution project that, I believe guys, the number is $10 million now. They just raised it.

On electric.

On the electric side. Let's just take electric as an example here. If you have a distribution project, capital project to improve or upgrade or rehab a part of the network, that costs $10 million or more, you must seek authority and preapproval from the Wisconsin Commission staff. So we will have literally over the course of the next five years hundreds of these applications that will go to the Wisconsin Commission staff. And hundreds may be stretching it because they may not all individually come to $10 million, but we will have a significant number of these preapproval requests.

The requests are very thoroughly done. They document the rationale for why the upgrade is needed and in our case all of these relate to maintaining the reliability of the network and replacing aging infrastructure. And let me give you just a couple of examples. Between now and 2016, we would plan to rebuild 2,500 miles of electric distribution lines that today are more than 50 years old. We would plan to replace about 28,000 power poles, about 28,000 transformers that are beyond their design life, and literally hundreds of substation components and that's on the electric side of the business.

On the natural gas side of the business, again, between now and 2016, we would plan to replace 1,250 miles of fiberglass, plastic, and steel gas mains. We would plan to replace about 83,000 individual gas distribution lines and almost 250,000 meter sets on the natural gas distribution side of the business. So that just gives you some flavor of the kinds of projects. Anything under $10 million we would not necessarily seek preapproval for. $10 million or above on the electric side we would and I might add that in the history of this Commission, if they preapprove a project and you bring it in on time and on budget they have never denied cost recovery.

A lot of those projects may not get preapproval, they will be in our rate case that we file with our two-year forward-looking window.

Exactly.

I appreciate that. And I'm assuming they share your need of the distribution investments going forward?

They share our concern?

Yes.

Any time that you demonstrate a need to maintain reliability is generally well-received. The Commission certainly understands the importance of a reliable network.

Appreciate the question.

You're welcome.

Paul Ridzon, KeyBanc.

First of all, what was the absolute fuel recovery as opposed to the year-over-year?

Absolute fuel recovery I believe was --

17.5.

17.5, yes.

Last year, was just about flat, neutral?

Yes.

I'm sorry?

Last year you just about broke even.

First quarter was about level, about even.

Second question is I think it's Presque Isle has some transmission constraints that could be an opportunity.

Yes, the entire -- an I'll let Allen give you the details -- but there is a northern plan that American Transmission Company has proposed. The northern third of Wisconsin and the upper peninsula of Michigan have historically had weak transmission infrastructure. There's been some investment already but clearly when we look at the future, there is no question that there has to be additional transmission, particularly for, again, the northern chunk of Wisconsin and the upper peninsula of Michigan to maintain reliability. Allen?

I think Paul, Gale may have mentioned earlier that ATC's 10-year plan, would call, within their footprint which includes the UP of Michigan as well as Wisconsin, calls for $4 billion worth of capital spending. Roughly a quarter of that $4 billion is to address these issues that you and Gale were alluding to in the UP of Michigan.

What's the sense of urgency? Is that something that could be ticking up earlier?

Certainly stepping back, we have an issue right now even with the Presque Isle facility there. So there's certainly a set of improvements that I think are quite urgent and should be pursued now and ATC is seeking to get out-of-cycle review with MISO on those projects. I would say, Paul, roughly that's probably $250 million worth of projects. It's that kind of zip code. But then the rest of them would be over a period of time. Now, there are as you would expect, there are competing proposals if you will, so I'm sure that ATC would like to build some facilities up from the lower peninsula to the upper peninsula. There are competing proposals out there but there's some of this that really needs to be done in the short term, even with the Presque Isle plant there.

What defines the short term?

Well, if we get out-of-cycle review, I would say at latest they would get reviewed by the end of this year on those early-stage projects. And then I would say if they got approval, Paul, those projects would probably be in place in the 2017 time frame.

Okay. And switching gears, you talked about $148 million amortization holiday, $37 million per quarter but O&M only improved $25 million. Is that $12 million delta what we can expect for the balance of the year kind of on a quarterly basis?

No. Again, as Rick pointed out to you, when you're comparing quarter to quarter this year versus last year we're going to see from the initiatives we have in place and from some of the projects that were one-time only projects in the fourth quarter of last year, you're going to see an improvement in that direction in the second half of the year. Rick?

Yes. One thing that caused O&M to tick up a little bit is we, because of the warm weather we got ahead on a number of our inspections, required inspections in our regulated business side. And, as I said earlier, because of projects that we released at the end of last year we're going to see an improvement year-over-year in the second half of the year from an O&M standpoint.

Any update on the ash pond spill.

In terms of the -- talking about the Oak Creek bluff?

Yes.

Okay. Yes. Really, the response was very efficient, very quick, and if you had gone to the site, this happened on Halloween, October 31 of 2011. If you had gone to the site one month later you would never have known that anything occurred. So we are -- the response, again, was great. 95% of the coal ash and dirt that fell down the bluff stayed on our property. There was no harm to the aquatic environment, no harm to the lake. And so we're wrapping that up right now, in discussions with the Department of Natural Resources and we would expect a full resolution certainly within the next few months.

Just one clarification. We don't have any wet ash ponds, Paul. This was ash that was stored or landfilled in a ravine back in the '50s and '60s when it was entirely okay to do that. It was one pocket of ash that basically let loose and as Gale said we were able to clean it up with 95% of it being taken to a landfill.

Thanks for the clarification.

Thank you.

Dan Jenkins, State of Wisconsin.

Dan, I assume that you're following your normal pattern, voting early and often.

I am originally from Illinois, so --

(Laughter) Yes, well be careful. You ruined your fingernails doing those license plates, I understand.

I had a couple questions. First, you talked a little bit about the increase in customer connections and I was wondering how that compared to, say, pre-recession levels and also is there -- do you have any sense of whether any of that was pulled forward because of the good weather in the first quarter as far as household formation and that kind of thing?

Good questions, Dan. First of all, how does this uptick that we're talking about compare to pre-recession levels. Still well below pre-recession levels. Probably less than half of pre-recession levels at this stage of the game. But encouraging. And in your second question about did the warm spring weather pull forward these connections, perhaps to some degree on the electric side. However, the biggest percentage increase was actually in natural gas connections.

And there I think what we're benefiting from is the comparison of heating your home or your business today with natural gas compared, for example, to propane or oil. The cost differential has become very significant for customers. So I don't think on the natural gays side with the 33% increase in natural gas connections over the past 12 months compared to the 12 months ended Q1 2011, I don't think that's weather. I think that's customers responding rationally to pricing. On the electric side, maybe some, but again, we're just beginning to see a little more stirring of economic activity. Not robust, not back to where it was pre-recession, but encouraging.

How does what you saw compare to what you assumed in your plan for 2012? What was your assumption for customer connections?

We don't have that number in the room with us but it's -- we assumed I think exactly the same level as last year.

Residential sales were flat.

Rick's right, we assumed flat residential sales. We didn't have much of anything in terms of an uptick in new customer connections compared to last year in our forecast.

Okay. And then you mentioned on industrial side that you saw some gains in rubber and plastic area that were kind of first time you've seen that in a while. Wonder if you could give a little more color on what's driving that and if you expect it to continue going forward.

Someone asked me this morning whether that was automotive related and we don't have much of any automotive related rubber and plastic business in our region. I don't think it's being driven by automotive. More color than that. I think it's a lot of individual companies all across the sector producing rubber and plastic products that have gone up.

Things like packaging.

Yes. We have a couple of large packaging manufacturers in our region and I know one of them had a pretty significant uptick in Q1.

Okay. And then the last thing I was wondering about is looking at the cash flow statement, there was a fairly big drop from the working capital and I was wondering what's driving that difference between this year and last year and do you expect that to reverse then going forward?

we'll ask Steve Dickson, our Controller, to answer that for you.

I assume you're looking at the consolidated condensed statement of cashflow on the line item, working capital and other.

Right.

That declined about $139 million. Quarter to quarter. And as Rick mentioned on the call, there's a lot of really small items in there. One item if you remember last year in the first quarter we received a settlement from the DOE and that increased the regulatory liabilities so that flowed through as an increase in cash from operations. Ironically because we then restricted it; it was reduction in investing activities. That was the largest item. It was about $40 million. Accrued interest was higher last year and that related to the debt that we repaid and there are a bunch of small items but there's nothing really big other than those two items. Does that make sense?

Sure. How about the reverse, do you expect it to -- so were those kind of one time things then in '11 that more that affected it than --

the big item as I said related to the restricted cash that we received on the DOE refund. That actually turns this year and it's a reduction of operating cash flows this year. So that item ought to reverse significantly in the first quarter. So I think last year there were items which helped us.

Okay. That's all I had. Thank you.

Thanks, Dan.

Vedula Murti, CDP Capital.

Pretty much hit everything. But when we're talking about ATC and we're talking about lumpiness, particularly in the back end when there will be a lot more spending called out in '16, '17 or whatever. If I recall properly I'm just wondering whether the conglomeration of cooperatives, municipals, and all the parties that make up ATC, whether some of them may not t be able to make their capital calls whereby then you may be able to step in on the margin, be able to incrementally participate more in some of those opportunities in the back end. Do you foresee anything liking that or does everybody look really solid such that if these things happen pretty much the current proportionality of your ownership versus all the other participants basically stays the same?

Allen can give you some more color as well. I think certainly the way the ATC formula works, when there is a capital call, the owner certainly has a right to either meet that capital call or to decline to meet the capital call. And then if they decline to meet the capital call as you're indicating if the other parties then step in basically the pro rata ownership percentages change. Now, one thing to keep in mind, and it's certainly possible that a co-op or a municipality or a very tiny owner of ATC might or might not stand up to a capital call down the road but they have by and large, very small percentages. Allen?

I guess maybe just looking at it in the limit, Vedula. If you look at all, say the not-for-profit entities and look at their total ownership, it's less than 10% of ATC. So it's certainly not a huge part of ATC. Based on the way they have all behaved in the past, they have certainly made their capital calls in all but some very, very isolated incidents. I think probably a bigger question on their participation going forward is not so much their participation in the inside the footprint.

Yes.

So that $4 billion worth of stuff that we talked about, it's not so much a question about whether they participate in those, in my mind. It's more of a question are they going to want to participate in some of these outside of the footprint types of projects that ATC is trying to pursue with Duke. They're certainly entitled to if they want to help fund those and invest but I think there's probably a bigger question as to if they're going to want to do that.

The other dynamic that may change is ATC basically right now is largely self-funding. And as the capital investment steps up, we might see a change there but that's, again, that's in the second 5-year half of our 10-year period.

Okay. Thank you very much.

You're welcome, Vedula. I believe that concludes our conference call for today. Thank you so much for participating. If you have any additional questions, our famous Colleen Henderson will be available in the Investor Relations office at 414-221-2592. Thank you very much. Have a good day, everybody.