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Wisconsin Energy (NYSE:WEC)

Q4 2012 Earnings Call

January 30, 2013 2:30 pm ET

Executives

Gale E. Klappa - Chairman, Chief Executive Officer, President, Chairman of Executive Committee, Chairman of Wisconsin Electric Power Company, Chairman of Wisconsin Gas LLC, Chief Executive Officer of Wisconsin Electric Power Company, Chief Executive Officer of Wisconsin Gas LLC, President of Wisconsin Electric Power Company and President of Wisconsin Gas LLC

James Patrick Keyes - Chief Financial Officer, Executive Vice President and Treasurer

Allen L. Leverett - Executive Vice President, Executive Vice President - Wisconsin Electric Power Company, Chief Executive Officer of WE Generation Operations and President of WE Generation Operations

Scott J. Lauber - Assistant Treasurer

Stephen P. Dickson - Principal Accounting Officer, Vice President and Controller

Analysts

James D. von Riesemann - UBS Investment Bank, Research Division

Greg Gordon - ISI Group Inc., Research Division

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Paul Patterson - Glenrock Associates LLC

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Andrew Bischof - Morningstar Inc., Research Division

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Dan Jenkins

Operator

Good afternoon, ladies and gentlemen. Thank you for waiting and welcome to Wisconsin Energy's conference call to review 2012 year-end results. This conference call 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 earnings-per-share will be based on diluted earnings per share unless otherwise noted. After the presentation, the conference will be open to analysts for questions and answers. In conjunction with this call, Wisconsin Energy has posted on its website a package of detailed financial information at www.wisconsinenergy.com. A replay of our remarks will be available approximately 2 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.

Gale E. Klappa

Elaine, thank you very much. Good afternoon, everyone, and thank you for joining us as we review the company's 2012 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 Allen Leverett, President and Chief Executive of We Generation; Pat Keyes, our Chief Financial Officer; Susan Martin, General Counsel; Steve Dickson, Controller; and Scott Lauber our Assistant Treasurer. Pat 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 $2.35 a share for 2012. This compares with earnings from continuing operations of $2.18 a share for 2011. And I'm pleased to report that by virtually every meaningful measure, 2012 was an exceptional year for Wisconsin Energy. From an operations standpoint, we achieved milestones in customer satisfaction, employee safety and network reliability. In fact, we attained our highest customer satisfaction ratings in the past decade, and likely, the best ever. We also achieved the best safety record in the history of the company, and we were named the most reliable utility in the Midwest for the eighth time in the past 11 years. I'm also pleased that we were able to dispatch only 1/3 of our employee and contract crews to the New York City area to help restore power in the aftermath of Superstorm Sandy. We were honored to receive an Edison Electric Institute Emergency Assistance Award in recognition of our response. From a financial standpoint, we delivered solid earnings growth, generated strong cash flow and made significant progress toward a dividend payout that is more competitive with our peers. A number of factors contributed to our record financial performance in 2012. The weather, of course, had a major influence on our results. We began 2012 with the warmest winter in 122 years that was followed by an old-fashioned Midwest summer heatwave. In fact, 2012 was the warmest year on record in our region, breaking a mark that stood since 1931. In addition to the weather, the $1.3 billion we invested on state-of-the-art air-quality controls at our older Oak Creek units and in the new Glacier Hills Wind Park also contributed significantly to our 2012 earnings. Turning now to the economy, Wisconsin's unemployment rate at 6.6% as of December remains well below the national average. And although energy sales to our large commercial and industrial customers, excluding the iron ore mines, dropped by 0.7% in 2012, this was actually slightly better than our expectations. Our plan for the year projected a decline in sales in our large commercial and industrial group because 2 customers began using their own self-generation. Excluding these 2 customers and the iron ore mines, large commercial and industrial sales actually rose by 1.1% for the year. We continued, during 2012, to see strength in several industry sectors including food products, chemical manufacturing, metal fabrication and plastics. An encouraging uptick in new customer connections also continued through the year. New electric service installations were up 8.7% compared to 2011, and connections of new natural gas customers increased by more than 13.2% over the prior year. Now as many of you may know, we have one major construction project well underway. That's our biomass fuel power plant in Rothschild, Wisconsin. At this point, construction is 65% complete. We're on schedule and on budget for commercial operation by the end of 2013. We expect the main boiler erection to be completed in the first quarter of this year. Steam turbine and generator have been anchored and grounded in place. Piping and electrical installation continues throughout the site. The switch areas have been energized and connected to the distribution network. The natural gas metering station is now complete and gas is available on the site. And construction of the truck dumpers and the fuel handling systems are well underway. As I've noted before, the biomass plant will help us diversify our portfolio of renewable assets. We'll be able to dispatch this unit and the efficient technology that will produce electricity for the grid and steam for the operating paper mill on 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. Of course, the biomass project and the Glacier Hills Wind Park that we brought into service a year ago 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 20% in 2015 at a statewide level. The standard sets targets for each Wisconsin utility using a historical baseline. Applying that baseline, approximately 8.25% of our retail electricity sales must come from renewable sources in 2015. We will be well positioned to meet that 2015 standard when we complete the biomass facility. Also, we recently signed agreements for some additional renewable energy credits. Those agreements should allow us to be in compliance with the standard through 2019. And because of favorable market conditions, we plan to purchase more renewable credits, further extending the timeframe that we expect to be in compliance. One final note on renewables, in early December, the Wisconsin Commission approved our purchase of the Mumford wind farm, the transaction we announced last August when we agreed with NextEra Energy Resources to purchase the 30-megawatt wind farm for $27 million. We previously had a power purchase agreement for 85% of the energy from this site, so the transaction did not change our renewable portfolio but it did increase our asset base. The remaining 15% of the output from this wind farm is under a power purchase agreement with another utility that runs through 2021. Turning now to other items of interest. In past quarters, we've discussed the impact on our operations of the coal and natural gas markets. Natural gas prices, of course, have remained at very low levels, influencing the dispatch order and locational marginal pricing in the Midwest power market. Over the years, the key to serving customers at a competitive price has been fuel diversity. And fuel diversity was a core principle of our Power the Future plan. You may remember that our plan called for the addition of 2,200 megawatts of new capacity, capacity that is almost equally balanced between coal and natural gas. So now, with our efficient new capacity in place and natural gas prices at low levels, our natural gas burn in 2012 nearly doubled from 23.9 billion cubic feet in 2011 to 46.5 billion cubic feet in 2012. In fact, our natural gas units at Port Washington operated at a 46% capacity factor for the year 2012. This compares with a 23% capacity factor in 2011. All 4 of the combustion turbines at Port Washington were fired for more than 5,200 hours in 2012, and that, of course, supported a record amount of generation from this site for the year. At times, our Port Washington units were essentially being dispatched as baseload units in MISO. Of course, as our natural gas burns have gone up, our coal burns have naturally come down. We burned approximately 8.3 million tons of coal in 2012 versus 10.7 million tons in 2011. We achieved this reduction by purchasing less coal, maximizing the use of coal storage and working with our coal suppliers to amend existing contracts. In another development, we're seeking a revised air permit that would allow us to blend western and eastern coals at our new Oak Creek expansion units. These units initially were permitted to burn eastern bituminous coal. However, moving to a blend with Powder River Basin sub-bituminous coal could significantly, in our estimates, lower fuel cost for our customers. Overall, our diverse fleet and our long-term power purchase agreement for nuclear energy position us, we believe, very well as the power markets continue to evolve. Now, I'll briefly turn to the final results of our Wisconsin rate case. If you remember that in the spring of last year, we filed a request with the Wisconsin Commission for electric natural gas and steam rates for the years 2013 and 2014. Our request was driven primarily by the investment of approximately $1.6 billion in previously approved capital projects, such as the air quality control system at our older Oak Creek units, the addition of the Glacier Hills Wind Park and the construction of our biomass plant in Northern Wisconsin. The commission completed its assessment in late November and issued a final order on December 20 for rates that went into effect on January 1 of this year. Here are the final results. The commission granted an overall 4.8% increase in base electric rates for 2013 and a 1% increase for 2014. After applying a renewable energy tax grant, and we'll talk more a little bit later about that renewable energy tax grant, but after applying that grant, that we expect to receive after our biomass plant is complete, our customers will see a net bill increase of 2.6% in both 2013 and 2014. In the rate order, the commission also determined that 100% of the construction costs for our Oak Creek expansion units were prudently incurred, and the commission approved the recovery in rates of more than 99.5% of the final cost at Oak Creek. Finally, the commission approved recovery of a 1.6% increase in fuel costs that we expect to see during 2013. For our natural gas distribution business, the commission granted our request for a decrease in natural gas rates for 2013, averaging 1.9% for gas customers of Wisconsin Electric and 5.5% for gas customers of Wisconsin Gas. Those rates will then remain unchanged in 2014. For steam customers, the commission authorized a 6% increase in 2013 and '14 for the Milwaukee downtown utility, and increases of 7% in 2013 and 6% in 2014 for our Wauwatosa steam utility. The commission also maintained our approved capital structures and return on equity. Switching gears now, you'll recall that in 2011, our Board of Directors authorized a share repurchase plan that calls for us to buy back up to $300 million of Wisconsin Energy common stock through open market purchases or privately negotiated transactions. The authorization runs through the end of 2013. During the fourth quarter of 2012, we repurchased approximately 1,028,000 shares at a cost of $37.8 million. Since the program began, we've repurchased approximately 4,650,000 shares at a cost of $151.8 million. That equates to an average purchase price for the program so far of $32.63 a share. And as we look at our dividend policy, earlier this month, our board affirmed our policy that targets a 60% payout ratio in 2014. The board also adopted a follow-on policy targeting a dividend payout ratio that trends to 65% to 70% of earnings in 2017. This policy marks an important step toward making our dividend payout more competitive with our peers across the utility industry. It should also support double-digit growth in the dividend in 2014, and 7% to 8% dividend growth in the years 2015 through 2017. And as we reported to you in mid-January, the board declared a quarterly dividend of $0.34 a share for the first quarter of this year, which equates to an annual dividend of $1.36 a share. This represents a 13.3% increase over the prior year and is consistent with the dividend policy I've just described. Finally, I'd like to discuss the investment opportunities we see going forward in our core business. Our capital budget, and these are new numbers, our capital budget calls for spending between $3.2 billion and $3.5 billion over the 5-year period ending 2017. In this new 5-year budget, the nature of our capital investments continue to shift away from high-profile projects, such as our Power the Future units, renewable generation and large air quality controls. Instead, our capital plan is comprised of many smaller projects that will upgrade our aging distribution infrastructure, the building blocks of our delivery business, pipes, poles, wires, transformers and substations. The primary risks, of course, 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 megaprojects we've completed over the past decade. Our focus on renewing our distribution network is essential to maintaining our status as the most reliable utility in the Midwest. Over the past few quarters, we've also been updating you on our goal to identify a life extension option for the Presque Isle Power Plant in Marquette, Michigan, an option that would be economically beneficial for our customers. In late November, we signed a definitive agreement with Wolverine Power Cooperative that calls for Wolverine to acquire a minority interest in the plan by funding new state-of-the-art emission controls for the facility. The new controls are necessary to meet expected changes in air quality rules, while maintaining system reliability in Michigan's Upper Peninsula. The joint venture, I should point out, will not reduce our rate base. We expect that it will reduce our operating costs. We plan to file for approvals from the Michigan and Wisconsin Commission in February, and hopefully, begin construction work in 2014. And as you'll also recall, we announced plans late last summer to convert the fuel source for our Valley Power Plant from coal to natural gas. The Valley Plant is a co-generation facility located along the Menomonee River in Milwaukee that generates electricity for the grid and produces steam to heat hundreds of downtown Milwaukee buildings. Our analysis shows that converting the fuel source for this plant will reduce our operating cost and enhance the environmental performance of the Valley units. We plan to file an application with the Wisconsin Commission in the second quarter of this year for approval to modify the plant to use natural gas in the future. The electric capacity of the plant is expected to remain at 280 megawatts. If approved, we'll target completion of the project by late 2015 or early 2016. The current cost estimate, $60 million to $65 million. In addition, we're upgrading the existing natural gas pipeline that runs near the facility. The Wisconsin Commission approved this $26 million investment last June, and we expect to begin construction of the modern pipeline in the first quarter of this year. We believe the plan we put in place will secure Valley's role in meeting the energy needs of a vibrant downtown Milwaukee for many years to come. On another important topic, we're continuing to investigate the need for additional capacity for our natural gas distribution network in the Western part of Wisconsin. Now, for you cheesehead aficionados, we're evaluating routes to serve the communities between the town of Wilson in Eau Claire County and the City of Tomah in Monroe County. This region will need additional capacity to address reliability and to meet growing demand for natural gas. We plan to seek approval from the Wisconsin Commission on this project this spring. Our projected investment in the initial phase of the gas distribution project for West Central Wisconsin is approximately $150 million. So in summary, ladies and gentlemen, we enter 2013 in excellent condition, financially and operationally. The company is performing at a high level. All of our Power the Future investments are providing tangible benefits for our customers and stockholders, and we have much more to do to renew and upgrade our distribution network as we focus on delivering the future. Now, with more details on our full year performance for 2012, and importantly, our outlook for 2013, here's our Chief Financial Officer, Pat Keyes. Pat?

James Patrick Keyes

Thank you, Gale. As Gale mentioned, for 2012, our earnings from continuing operations rose to $2.35 a share. This compared with $2.18 a share for 2011. Consistent with past practice, I will discuss operating income for our 2 business segments and then discuss other income, interest expense and income taxes. Our consolidated operating income for the full year 2012 was right at $1 billion and is compared to $887 million in 2011. That's an increase of $113 million. The largest increase was in our utility segment. But we also saw an increase in our nonutility segment, which consists primarily of our Power the Future units. As we look at our utility operating income in 2012 as compared to 2011, you will see that operating income totaled $648 million for 2012, an increase of $103 million from 2011. As we discussed in our quarterly calls, the biggest driver in utility operating income was the impact of a 2011 rate agreement with our Wisconsin regulators. As background, going into 2012, we knew we needed a return on $1.3 billion of new plant that was being place into service with the Glacier Hills Wind Park and the air quality control system at our older Oak Creek units. Our agreement with the Wisconsin Commission froze base electric rates for customers in 2012, and it allowed us to recover depreciation expense and earn a return on the $1.3 billion of investment by suspending $148 million of regulatory amortizations that were part of our O&M expense. Our 2012 utility operating income, therefore, was favorably impacted by this $148 million amortization holiday. In addition, we estimate that the hot 2012 weather boosted our electric margins by approximately $19 million. Other factors, including lower fuel expense and lower O&M expense in our gas distribution business, accounted for the other $9 million of improvement. Partially offsetting these items was higher depreciation expense of $39 million, which primarily related to the $1.3 billion of new investments we discussed earlier. We also saw $34 million of lower gas margins primarily because of unseasonally warm winter weather in the first quarter of 2012. Now, turning to the non-utility energy segment, we saw operating income increase by $10 million in 2012 as compared to the prior year. As we mentioned during previous calls, we finalized the depreciable lives of the Oak Creek expansion units in 2012, which had a slight positive impact on earnings. We also had a full-year of earnings at the second Oak Creek expansion unit in 2012, which contributed to the increase in operating income. Taking the changes for these 2 segments together, we arrived at the $113 million increase in operating income for 2012. Corporate expenses and other miscellaneous items were flat year-over-year growth. During 2012, earnings from our investment in the American Transmission Company pooled nearly $66 million, up almost $3 million from 2011. Other income decreased by $28 million primarily because of lower AFUDC. AFUDC allows us to accrue a return on approved utility projects during construction. In 2012, our AFUDC was down by almost $24 million because, as expected, we stopped accruing a return for the Oak Creek air quality control system and Glacier Hills when those facilities were placed into service. Net interest expense increased by $12 million primarily because of lower capitalized interest. We, of course, stopped capitalizing interest when the 2 large construction projects were placed into service. Consolidated income tax expense rose by approximately $43 million because of higher pretax earnings and a higher effective tax rate. The higher effective tax rate was driven primarily by lower equity AFUDC, which is a permanent difference for income tax purposes. Our effective tax rate for 2012 was 35.9% compared to 34% in 2011. We estimate that our effective tax rate in 2013 will be 37% to 38%. Combining all of these items brings you to $546 million of net income for continuing operations for the full year 2012 or earnings of $2.35 per share. During 2012, we generated $1.2 billion of cash from operations on an adjusted basis, which includes changes in restricted cash. This is up over $261 million over 2011. Our cash from operations was helped by $20 million of higher net income, $35 million of higher depreciation expense, $184 million of lower net working capital and lower contributions to our pension and other benefit trust. In 2012, we contributed $100 million to our pension and other benefit trust compared to $277 million in 2011. Partially offsetting all these items was $148 million reduction in noncash amortizations compared to 2011. This change was driven by the terms of the 1-year rate increase. Our capital expenditures totaled $707 million in 2012, $124 million decrease as compared to 2011. We saw lower capital expenditures as our large construction projects were completed. We also paid $276 million in common dividends in 2012, which was $34 million greater than 2011. Dividends for the year equated to an annual rate of $1.20 per share, which was a 15% increase over the prior year's annual dividend of $1.04 per share. And, as Gale mentioned, the board, just 2 weeks ago, declared an increase in the quarterly dividend equivalent to $1.36 per share on an annual basis or a 13.3% increase for 2013. As of the end of 2012, our adjusted debt-to-capital ratio was 53.2%. Our calculation treats half of our hybrid securities as common equity, which is consistent with past presentation. We expect 2013 ratios to be in line with 2012. We are using cash to satisfy any shares required for our 401(k) plan, options and other programs. Going forward, we do not expect to issue any additional shares. Turning now to our sales results. As shown in the earnings package on our website, retail sales of electricity decreased by 0.6% during 2012 as compared to the full year 2011. Our weather normalized sales were down by 1.5%. In our plan for 2012, we took into account an extended outage at our largest customer, and we knew that 2 other customers were moving to self-generation. Adjusting for these items, normalized retail sales declined by 0.2% for 2012 as compared to 2011. Looking at the individual customer segments, we saw actual residential sales increase by 0.5% in 2012. On a normalized basis, residential sales declined by 1%. However, we believe the extreme weather conditions in 2012, including the warmest winter on record, and a hot dry summer compared to 2011, did impact the accuracy of our normalized results. Across our small commercial and industrial group, actual yearly sales rose by 0.7%. On a weather normalized basis, full-year sales to this group were up 0.3%. We continue to see modest growth in our small commercial and industrial class. Large commercial and industrial segment sales for the full year 2012 were down 2.8%. However, if you exclude the iron ore mines and the 2 self-generation customers, sales increased by 1.1%. Overall in 2013, we are projecting a decrease in weather-normalized sales of 0.7%, but that number does not tell the whole story. If we exclude the forecasted sales to the mines, we're projecting a slight increase of 0.2% for the year. We expect residential sales to remain relatively flat, impacted by modest growth in housing starts, offset by conservation. In the small commercial and industrial segment, we are projecting a slight increase of 0.3%. In the large commercial and industrial group, we are projecting a decrease of 2.4%. When you exclude the mines, we're projecting a slight increase in the large commercial and industrial group of 0.2%. Turning now to other items of interest. In December of 2012, our electric subsidiary issued a $250 million, 30-year bond at a coupon of 3.65%. This is the lowest 30-year coupon in our debt portfolio and one of the lowest on record. On a separate topic, as you know, the recent budget agreement in Washington extended bonus depreciation through 2013. Taken in isolation, you would expect to see a nearly $100 million reduction in rate base in 2015, which will carry through to 2016 as a result of this extension. However, as our new 5-year capital spending plan evolved, we saw the need to invest approximately $100 million more than our earlier internal projections. We took this impact into account when we finalized our capital budget of $3.2 billion to $3.5 billion over the 5-year period of 2013 to 2017. Finally, I'd like to announce our earnings guidance. We expect our earnings for 2013 to be in the range of $2.38 a share to $2.48 a share. Our 2013 earnings projection assumes normal weather and reflects the new rates authorized by the Wisconsin Commission. Again, our guidance for 2013 is $2.38 a share to $2.48 a share. Now, before I talk specifically about our first quarter earnings guidance, I would like to touch on the accounting impact of the renewable tax grant associated with our new biomass plant. As Gale previously mentioned, our rates that went into effect January 1, 2013, reflect a bill credit for the expected benefit of the renewable grant. However, the accounting rules will not allow us to record the grant income until the plant is placed into service, which is expected in the fourth quarter this year. As a result, our revenues will be lower each quarter of 2013 until the plant is completed. When the plant is completed, we expect to record the grant income equal to the amount of the bill credits that were granted to date. We therefore expect this grant accounting treatment to reduce earnings in the first 3 quarters with a catch-up in the fourth quarter when the plant is scheduled to go online. Once the plan is commercial, you're allowed to match the grant income with the bill credits through December of 2014. With that as a backdrop, we expect our first quarter 2013 earnings to be in the range of $0.67 to $0.71 per share. The timing of this renewable grant is expected to reduce the first quarter earnings by approximately $0.03 per share. In addition, relative to 2012, our first quarter earnings are expected to be lower by approximately $0.04 per share due to lower AFUDC. With that, I will turn things to Gale.

Gale E. Klappa

Pat, 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] Your first question comes from the line of Jim von Riesemann with UBS.

James D. von Riesemann - UBS Investment Bank, Research Division

A question for you, actually 2 questions. One is a minutia question and one's a big picture. First, on the minutia. Did you say you expect to complete the buyback program this year? And then the second is really the big picture one. And so in light of the board's second approved dividend policy in less than a year, I mean a major revision, the question is how do you think about the balance between earnings growth and dividend growth over the longer term? So I guess said differently, how do you view your value proposition and differentiate yourself prospectively?

Gale E. Klappa

Okay, very good questions, Jim. On the minutia question, the answer is no, I did not say we would complete the buyback program in 2013. I did say the board had authorized the program to run through 2013. But as you know, we're being opportunistic.

There is no definite timeframe where the board has said we must finish the program for 2013. We will take a look each opportunity we have and go from there. And on the larger question, actually, I think there are 3 pieces to the answer. And the first piece, basically, I heard you asked how do we expect to differentiate ourselves as a quality investment going forward. And I really think it starts with the fact that we have today, we're in a fortunate position that we have greater financial flexibility today than certainly any time in the recent history of this company. And I think we have greater financial flexibility than virtually any other company in the industry. You'll see when we release our new investor deck tomorrow that we're projecting to have over $500 million of free cash flow in the period through 2017. We have, I think, so, number one, terrific financial flexibility. The second piece is even post Power the Future, we have significant growth. The growth is different, as I pointed out in the script, but we have significant growth that is needed in terms of the upgrade and the renewal of our distribution networks. So we're projecting 4% to 6% annual earnings-per-share growth, and given the financial flexibility we have, we think we have best-in-class dividend growth story. So when you put that altogether, I can see us delivering and believe we can deliver 8% to 10% total shareholder returns. And when your risk-adjust that for the type of projects that we have in front of us and the demonstrated ability of the management to deliver projects on time and on budget, I personally think that, that equates to a superior return story.

James D. von Riesemann - UBS Investment Bank, Research Division

Can I just follow up with one question or two?

Gale E. Klappa

Sure.

James D. von Riesemann - UBS Investment Bank, Research Division

On the dividend policy, when the board talks about dividend policy and upping the payout ratio, how do you balance what that rate payout policy is supposed to be? So if we're entering an environment where utility growth is slower prospectively because in a 5% to 6% rate base growth environment, and underlying demand of 0% to 1%, it's going to be pretty tough to match that going forward. How do you think about modulating between dividends and the other considerations?

Gale E. Klappa

Well, I think essentially -- again, a very good question, Jim. Essentially, what we do, and I think many do this, we step back and say what is legitimate capital spending need this business has. And we've identified that, for example, going forward in our new 5-year plan at $3.2 billion to $3.5 billion, okay? So how do we finance the $3.2 billion to $3.5 billion? In our case, that can be done with internally generated cash and also keeping our debt to total capital where it needs to be. So then, once you've identified that, what does your dividend policy evolve to from that situation, because in our case, we don't believe we need to issue additional equity. So in essence, we piece the puzzle together, starting with what is our growth opportunity, what is the investment need in the business, how do we finance that and then what can we do to stay at the efficient frontier for a company like ours on dividend policy.

James D. von Riesemann - UBS Investment Bank, Research Division

Okay. And then I have one last one and I'll let it -- turn it over. But on going back to my final minutia question, your earnings guidance for 2013, does that assume some level of buyback for the balance of the year?

Gale E. Klappa

It does assume some level of buyback for the balance of the year, that is correct.

Operator

Your next question comes from the line of Greg Gordon with ISI Group.

Greg Gordon - ISI Group Inc., Research Division

So can you give us an update on where the debate in the Statehouse stands on the government potentially deciding to divest its state-owned power plants given their inability to find the funds to upgrade the emissions controls, and whether or not you might be in a position to help the government meet its emission controls and generation needs?

Gale E. Klappa

Well, we're not from the government, but we are here to help you, Greg. The truth of the matter is I think we will know a great deal more by July. The legislature now in Wisconsin is just back into session and the governor will be presenting his new biannual budget to the legislature sometime in the next few weeks. So there are a couple of different opportunities if a bill to authorize the sale of state power plants and other state assets, if that -- a bill like that is to move forward, there are a number of opportunities certainly in the first half of this year. So I believe we'll have much a clearer view of whether a sale of the state-owned power plants is imminent by the time the budget passes in July.

Greg Gordon - ISI Group Inc., Research Division

But the capital budget that you just laid out for us, since it's not at this point clear that there'll be an opportunity for you there, that would be accretive to that budget if that came about?

Gale E. Klappa

You are correct, that would be accretive to that budget.

Operator

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

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

You mentioned sales growth in your '13 guidance, and I was just curious if you could just comment on O&M expense trends?

Gale E. Klappa

Sure, I'd be happy to. Now, one of the things that you will see and that may confuse some folks, as you look at our O&M reports over the next 4 quarters, just remember, we had an amortization holiday under our previous rate order that, in essence, put up on our balance sheet or kept on our balance sheet a $148 million of regulatory assets that did not amortize through O&M in 2012. That stopped as of January 1 of this year. So you're going to see $148 million increase in essence in O&M over the course of 2013 compared to 2012, but that's because of the regulatory amortization holiday ending. Essentially, there will be a very modest other increase in normal O&M. There'll be some increase related to some of the capital projects that we have on the distribution side of the business, are 80% capital, 20% O&M under the rate formulas. So you may see some very modest increase in overall O&M, but day-to-day O&M other than that associated with supporting capital projects will be flat.

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Okay, great. And then also, I think in the previous calls, you mentioned some gas infrastructure growth in some of the regions where there's attractive sand for frac-ing.

Gale E. Klappa

That is correct.

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Is that associated with the gas distribution investment of over $100 million you referenced earlier?

Gale E. Klappa

Yes. The $150 million project that we said, roughly $150 million capital project for western Wisconsin that I mentioned earlier in the call is directly associated with a major project for that part of the state. And it's related to 2 things. One, yes, we're seeing substantial increase in frac sand mining, but we also have customer growth there as customers convert from propane. So our projections are showing a dwindling amount of reserve capacity in the western part of the state. So we think there's a very solid and important case to make to the Public Service Commission for construction authority for that project, and we'll be making that case this year.

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Okay. And lastly, on the potential state divestitures, can you remind us? I know there are small -- there are several small units. I'm just curious if -- I'd like to kind of gauge what type of investment size this could potentially lead to.

Gale E. Klappa

Well, we'd be happy to do that. First of all, there are -- and we're not certain if the state would put all of these plants up for bid or just some of them. All of that is yet to be determined. But if all of them were put up for sale, there are 37 of them, 3 or 4 are reasonable size. 3 or 4 are actually power plants that produce electricity for the grid and steam for a particular type of state customer. The remainder other than those 3 or 4, which are of reasonable size, the remainder are smaller steam plants that produce steam heat for specific state facilities. For example, the University of Wisconsin Milwaukee has a relatively new steam heat plant. It doesn't produce electricity for the grid but does produce district heat for a particular part of that campus. In terms of investment opportunity, we have a placeholder. We have not been allowed, no one has been because this hasn't been finally decided by the state. No one has been able to really do any due diligence on a particular project for these 37 different facilities. There's a state --as just a placeholder, we're thinking $200 million to $250 million.

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Okay. And just reasonable size, what is that, 25 to 50 megawatts per unit?

Gale E. Klappa

Some of them are even smaller.

Operator

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

Paul Patterson - Glenrock Associates LLC

You guys went through, and I apologize for being slow on the projected sales growth, I think for 2013, with or without the mines and stuff, could you -- I apologize. Could you redo those for me?

Gale E. Klappa

We will be happy to ask Pat to redo those for you.

James Patrick Keyes

Sure, I'll be glad to. So we projected overall, a decrease in weather normalized sales of 0.7%. However, if you exclude the mines, it's really an increase of 0.2%.

Paul Patterson - Glenrock Associates LLC

Okay. And this is retail, right?

James Patrick Keyes

Yes. And then if you flip quickly through the segments. Residential is basically flat. Small C&I, a slight increase of 0.3% and then large C&I, we projected a decrease of 2.4%. But if you exclude the mines, again, the large C&I is actually going to be an increase of 0.2%.

Gale E. Klappa

Other way to look at that is weather normalized, basically, we're expecting to hit the earnings targets we've given you with essentially no sales growth. 0.2%, weather-normalized, excluding the mines.

Paul Patterson - Glenrock Associates LLC

Does this take into account leap year?

Gale E. Klappa

Leap year, yes.

James Patrick Keyes

Yes, it does. Oh, yes.

Paul Patterson - Glenrock Associates LLC

Okay. So leap year, obviously -- okay. So that basically is -- that's been normalized for that, correct?

Gale E. Klappa

It's been normalized for leap year. Were you in our forecast meeting?

Paul Patterson - Glenrock Associates LLC

No, I'm afraid not. I hope you benefited from my absence. But I guess I wanted to get your thoughts. I mean 2/10 of -- this is not exactly blockbuster growth. Just your thoughts about going forward, just policies for energy efficiency, renewables, what have you. I mean just sort of trying to get a sense as to how -- is there -- what do you think longer-term here or things that are driving this and how, as you guys are obviously very forward thinking, what have you, how do you position yourselves in terms of dealing with what appears to be, let's face it, not exactly superb growth? I mean, is that just an abnormality for this year or how do you look going forward longer-term?

Gale E. Klappa

Well, very good question. And I think, as you know, this is a question that is really beginning to be asked all over the industry. The first thing I would say is lots of companies will give you earnings growth projections and then when you dig deeper and say, well, what's behind that in terms of sales growth, 1%, 2% or 3%, we have never based our earnings growth projections on what we think are anything but appropriately conservative and rational sales ACs, but input from our customers. So let me take it segment by segment because I think there's a different story to answer your question in each one of the 3 segments.

First, the large industrial, strictly tied to the economy. We -- if you normalize our 2012 numbers, I think we were up 1.1% in industrial, nothing to write home about but -- I mean just intuitively to me, given what we're seeing in the economy in Wisconsin, that felt about right.

Commercial, we are up weather-normalized. It seems to me like we're seeing modest but continuing, predictable growth in the commercial segment of our customer group. The real puzzling one is residential. And there, I have a theory and I could be wrong. But it does not make a lot of sense to me when I see our weather-normalized residential sales. And I was talking with Scott Lauber the other day and he was saying, we had to weather-normalize 4% of our sales, closer to 5% of our sales, just because of the abnormal weather in 2011 and 2012. That's a huge number of megawatt hours. And we were 4, 5 standard -- well, 3 or 4 standard deviations away from norm in terms of the weather over the last couple of years. So my view is that we really need another year to update on residential before we really understand what's happening in terms of residential customer demand. I just am not seeing, and I don't think any of us are seeing, a major change in lifestyle in terms of our residential customers. We are seeing a change in the appliances and tools that are available to our customers to live their lifestyles. They're getting more efficient support from appliances, from TVs and everything else. But I still think our residential growth is underlying stronger than the numbers are showing because at this kind of deviation from norm, the weather normalization techniques just are not that accurate. So we really -- we're cautious. We're not going to promise you sales growth that we can't deliver. And I think the key going forward, if we don't see a rebound in growth, particularly in residential, the key going forward is going to be cost discipline. We have to continue to drive cost and productivity in our business. I hope that helps, Paul.

Paul Patterson - Glenrock Associates LLC

It does. But then, I guess it's too early for any rate design or any thoughts about sort of a different construct with regulators or what have you, or it's just too early to say? Is that how we should think about it?

Gale E. Klappa

Well, actually, I mean we have a construct with our regulators in Wisconsin that I think is quite beneficial to everyone, and that is the commission has asked each of the Wisconsin utilities to file a case every 2 years with a 2-year forward-looking test period. So to me, the 2-year forward-looking test period, taking into account reasonable assumptions of sales demand -- sales and demand growth really is among the best protection you can get anywhere.

Paul Patterson - Glenrock Associates LLC

I got you. So decoupling, it doesn't -- I mean, since you're coming in so frequently and since you have the forward-look, it sort of negates the potential need for decoupling or something like that?

Gale E. Klappa

That would certainly be my view.

Operator

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

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

I wanted to make sure, first of all, capital spending. Do you see -- if I remember correctly, '13 was higher outlook than '14. Do you still see that or do you see capital spending more kind of like levelized if I just took $3.2 billion, $3.3 billion and divide it by the 5 years? That's the first question. The second is free cash flow. Can you repeat the comment you made about how much total free cash flow after dividends you expect over the next few years?

Gale E. Klappa

Well, first of all, and you will see this on our investor deck that we're going to release tomorrow, the new breakdown of the 5-year capital spend, I will give you 5 numbers. For 2013, we're estimating $656 million of capital; for 2014, $589 million; and for 2015, $741 million.

James Patrick Keyes

And that's at the utility, Michael.

Gale E. Klappa

Yes, that's at the utility, exactly. That's coming off of by comparison $697 million of the utility for 2012. And we have that further broken down of the slide in the investor deck, the generation, electric delivery, gas delivery, renewables, et cetera. So you'll see a pretty granular breakdown tomorrow. But those are the essential numbers going forward. And then your other question about cash flow. What we're showing in our projections is a little better than $500 million of free cash for the 5-year period 2013 through 2017 after capital spending and after our dividend policy that we've announced is implemented.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

And does that include or exclude the buyback program you've authorized?

Gale E. Klappa

Well, that would include.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. So it's not incremental for the buyback? It is...

James Patrick Keyes

Michael, this is Pat. Let me clarify. The $500 million over the 5 years is before we start the buyback. So in other words, we would use the $500 million as cash to help fund the buyback.

Gale E. Klappa

Exactly, yes.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. Okay. It just strikes me as given some of the stuff you put out in the public domain regarding various tax-related items, that your free cash flow would actually even be a little bit above that level. Am I -- I may be overstating something, but it just -- the $500 million at first glance over the next 5 years strikes me as a little bit on the shy side. Not that, that's a problem. Most other companies don't have that problem.

James Patrick Keyes

Michael, we appreciate it. I guess the only thing I could say is you know how that cash was generated, certainly from operations, also from bonus depreciation. That bonus depreciation kind of falls off over time. If you're running like next year's model and you're saying, boy, you're sure generating a lot of that cash next year, that wouldn't surprise me if that's what your model said. Certainly, we expect more of the cash flow over the 5 years to be in the upfront years than in the back-end.

Gale E. Klappa

It's more front-end loaded.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. And are there things, whether it's working capital, whether it's pension contributions or something else, that are significant cash outflows that may not show up -- that aren't necessarily net income D&A, CapEx, dividends, kind of the big 4?

Gale E. Klappa

No. In fact -- the short answer is no. But we've had very good control of our working capital over the course of the last several years. In addition to that, from a pension fund standpoint, we're almost 100% funded, which many companies cannot say. So we don't see anything else like that lurking that would show a deviation in the numbers.

Operator

Your next question comes from the line of Andy Bischof with MorningStar.

Andrew Bischof - Morningstar Inc., Research Division

I was wondering if you could just provide a little clarity on the timing for decision regarding air permit application for the western, eastern coal blend in Oak Creek? And then clarify question, you said you were 100% funded for the pension funds?

Gale E. Klappa

99-point-something.

James Patrick Keyes

Yes, we're over 99, Andy.

Gale E. Klappa

And we'll ask Allen Leverett to comment on the timing for the air permit for the fuel blending at Oak Creek.

Allen L. Leverett

Yes, we expect to have that resolved in the first quarter of the year. So I certainly see it as being in the first part of this year. But we'll have to work with not only the U.S. EPA, but we're also working with the Wisconsin DNR. So we have to work with both agencies, get their concurrence and then the DNR is the one that will actually issue the permit. So we hope to have all of that wrapped up in the first quarter so that we can begin the testing, say, in the second quarter of this year.

Operator

Your next question comes from the line of Paul Ridzon with KeyBanc.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Just your O&M commentary, so we should take 12, add 148 for the holiday and then gross that up by 1% or 2%? Is that fair?

Gale E. Klappa

I would -- actually, I don't think I'd even add 1% to 2%. I'd keep it flat.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

And can you just review the language around the grant and how that's impacting timing?

Gale E. Klappa

We sure can. I'll frame it and will let Pat fill in the detail. Essentially, in the Wisconsin Commission rate order, for rates that went into effect here in January of '13, we agreed -- in fact we proposed and the commission agreed that we would prefund, if you will, the grant. So customers are receiving, starting with their January bills, a portion of the federal tax grant that we expect to receive upon completion of the biomass plant. So in essence, because we're giving customer credits in advance of receiving the cash, our revenues are going to go down and they will have a slight impact each quarter for the first 3 quarters on earnings. And then we do a big catch-up according to the accounting rules in Q4. Pat?

James Patrick Keyes

Exactly, Gale. So I would look at it this way. If first quarter was a $0.03, you can expect to see something similar, same zip code, second quarter and third quarter, and then a $0.09 pickup in Q4 so it all comes clean.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Is there a cost of money issue?

Gale E. Klappa

Oh, a minor one, yes. But, I mean, it's factored into the rate case.

Operator

Your next question comes from the line of Dan Jenkins with State of Wisconsin Investment Board.

Dan Jenkins

I was wondering, you mentioned -- update us a little bit on the CapEx program and apparently, there'll be more details tomorrow.

Gale E. Klappa

Correct.

Dan Jenkins

Do you have -- could you give us an update for what you're planning for financing needs in 2013?

Gale E. Klappa

Sure. Pat and Scott have that right in front of them.

James Patrick Keyes

Yes, glad to, Dan. We have got debt retiring, I believe it's in May at Wisconsin Electric of about $300 million. So you can expect us to be out for a bond over roughly that amount, roughly Q2, Q3. And then at Wisconsin Gas, we have got $45 million of debt retiring in Q4. I would expect we'll be doing a new issue of Q3, Q4 at Wisconsin Gas in the $100 million, $150 million neighborhood.

Dan Jenkins

Okay. Then I was also wondering, I'm trying to get a better idea of what's going on in the large commercial, industrial. You had fairly large decline mostly related to the mines and those 2 self-generation customers in 2012.

Gale E. Klappa

Correct.

Dan Jenkins

But then you mentioned in the release that the mine return to normal operation in September, but yet you expect a big decline again in 2013, mostly related to the mine. So, I guess, is the mine just becoming a lot smaller and smaller operation or what's going on?

Gale E. Klappa

No, I don't think the mine is becoming a much smaller and smaller operation, but they are -- they're very good about informing us of their plan in terms of when they see demand and how they expect to run their mine operations throughout the course of the year. And clearly, what we did when we put together our industrial forecast for 2014 was take the input from the mines on when they might, in essence, have a slowdown in their operations in 2013. So what you're seeing is basically the mines having more variable operation than perhaps the past couple of years.

Dan Jenkins

Right. It sounds like -- so how much of the 2.8% decline in '12 was related to the mine? Do you know that?

Gale E. Klappa

Looking at Scott. I would say the lion's share of it -- now, we did have 2 customers, but they were smaller in 2012 go to self-generation. But the lion's share of it, Scott, would be the mines.

Scott J. Lauber

Right. If you exclude the mines, they're relatively flat.

Gale E. Klappa

Yes, exactly. Just exclude the mines, relatively flat.

Dan Jenkins

Okay. So they're going to be even lower than they were though in '12 again? And so that's what I would...

Gale E. Klappa

No, no. I don't believe so.

Scott J. Lauber

Just a little bit lower in '12. They announced that they're going to idle the plant in the second and third quarter a little bit.

Gale E. Klappa

Yes, they're bringing their operations down some of the second and third quarters.

Scott J. Lauber

Extended summer outage.

Dan Jenkins

Okay. And then you mentioned that you're nearly fully funded on the pension. Will you need to make any more contributions in 2013 or will that...

Gale E. Klappa

None planned in 2013.

Dan Jenkins

Okay. And then if you could just expand a little bit on the fairly sizable benefit of '12 over '11 and the working capital. Is a lot of that related to the deferral?

Gale E. Klappa

Actually, no. The deferral -- it would not relate to deferral. Steve Dickson has the details in front of him. Steve?

Stephen P. Dickson

Yes, and I assume you're referring to the earnings package, and I'm looking at Page 11 and we've separately broken out the regulatory amortization. So you can see the $148 million change year-to-year. In the working capital and other, it declined. It was a negative $230 million last year, this year, it's a negative $56 million. So actually, that's a favorable improvement of about $174 million. The biggest item in there relates to income taxes that we got back, and it relates to the bonus depreciation that we talked and we were able to generate a net operating loss carry back. So we went back to where we've paid taxes in prior years. So there's $128 million and then the difference was $20 million in inventory, working capital. Gas prices are lower so we benefited from that. Does that make sense?

Dan Jenkins

Yes, yes.

Operator

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

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

And this may be one for Mr. Leverett. Just curious. You've given out for ATC, a 10-year capital spending projection. I think it was like $3.9 billion and above roughly. Can you just talk about the scope and scale, meaning is that very front-end loaded, is that very back-end loaded? I think if I remember correctly, ATC's CapEx had been around in the $250 million range or so for the last few years. Where is that heading in the next couple of years?

Allen L. Leverett

It's somewhat back-end loaded, Michael. And we sound like a broken record talking about this package that's coming out tomorrow, but in the package that comes out tomorrow, you'll see kind of a 3-year path for the capital spending at ATC. So in 2013, we expect the spending to be roughly $291 million and then $255 million in '14 and then it jumps. It's projected to jump to $362 million in 2015. So it's somewhat back-end loaded, and in fact, some of the really large projects that are in their forecast during the -- are out, say, in year 7, 8, 9 because those are projects that are associated with transmission fixes for the Upper Peninsula of Michigan. So those are pretty far out in the forecast. So in general, pretty back-end loaded, and the package tomorrow will show you the year-by-year detail, at least for the next 3 years at ATC.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it, Allen. And just refresh, how does that compare to 2012 CapEx at ATC?

Allen L. Leverett

I want to say that the 2012 CapEx -- I thought it was around the $250 million number that you mentioned, actually, Michael, but let me get, Pat, maybe if you could check that number.

James Patrick Keyes

Well, it was $310 million. So a little over $300 million.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Okay. And your owner -- and am I right, your ownership percentage, mid-20 like 26%, 28%?

James Patrick Keyes

26.2%.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

And the same ROE and authorized equity layer metrics, no changes there?

Allen L. Leverett

Nothing has changed in their tariff. So it's still 12 to ROE, roughly 50% equity deemed capital structure.

Operator

Your next question comes from the line of Paul Ridzon with KeyBanc.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Just on the mining customers, is that a material earnings impact? I mean, isn't a lot of their -- a lot of that demand charges or how does that work?

Gale E. Klappa

They are on an interruptible rate by and large because it's not a very significant movement in terms of just looking at, say, 2013 versus 2012. No significant difference in earnings impact.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Who are the big customers?

Gale E. Klappa

Who are the -- theirs or -- who are the mines?

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Yes.

Gale E. Klappa

They are owned by Cleveland-Cliffs.

Allen L. Leverett

So they're 2 major mines, Paul. There's the Empire Mine and the Tilden Mine. And the one that's been doing the extended shutdowns, I believe, is the Empire Mine.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Empire and what was the other one?

Allen L. Leverett

Tilden.

Gale E. Klappa

Tilden. All right. Well, ladies and gentlemen, I believe that concludes our conference call for today. Thank you so much for participating. If you have any other questions, Colleen Henderson will be available in our Investor Relations office and her direct line, (414) 221-2592. Thanks again. Have a good afternoon, everybody.

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