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Wisconsin Energy (NYSE:WEC)

Q2 2013 Earnings Call

July 31, 2013 2:00 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 and Executive Vice President

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

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

Analysts

Greg Gordon - ISI Group Inc., Research Division

Jonathan P. Arnold - Deutsche Bank AG, Research Division

James D. von Riesemann - CRT Capital Group LLC, Research Division

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

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Andrew Bischof - Morningstar Inc., Research Division

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

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

Operator

Good afternoon, ladies and gentlemen. Thank you for waiting and welcome to Wisconsin Energy's conference call to review 2013 second quarter 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, referenced 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 a package of detailed financial information on its website 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

Thank you, Colleen. Good afternoon, everyone, and thank you for joining us as we review our 2013 second 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; Pat Keyes, our Chief Financial Officer; Susan Martin, General Counsel; Steve Dickson, our Controller; and Scott Lauber, our newly named Treasurer.

Effective tomorrow, Allen will officially assume the role of President of Wisconsin Energy. Allen, of course, has been a key contributor to our success over the past decade, and this promotion recognizes his leadership skills and the broader operational role that he currently plays in the company. I will continue to serve as Chairman and Chief Executive. Allen, congratulations.

Pat Keyes will be reviewing our financial results in detail in just a moment. But as you saw from our news release this morning, we're reporting earnings from continuing operations of $0.52 a share for the second quarter of 2013. This compares with earnings from continuing operations of $0.51 a share for the second quarter of 2012. Our earnings were boosted by stronger natural gas sales during a cooler and longer-than-normal spring, a slight uptick in earnings at We power and our share repurchase program. However, the cooler temperatures in June significantly reduced consumption of electricity, particularly for air-conditioning.

Turning now to the economy of our region, Wisconsin's unemployment rate declined to 6.8% in June, well below the national average. However, in forecasting our second quarter sales for this year, we did anticipate some continued sluggishness in the regional economy. And that sluggishness was clearly evident in the numbers you saw this morning.

Energy sales to our large commercial and industrial customers, excluding the iron ore mines, were down by 4.1% compared to the second quarter a year ago. As you may recall however, we experienced exceptionally warm weather in last year's second quarter. So when you factor in normal weather, whatever that is, sales to our large commercial and industrial group in the most recent quarter were down by 2.1%. Three of the industrial sectors that we served did show some encouraging growth during the quarter, printing and publishing, plastics and the chemical and air separation industries.

Also we're continuing to see customer growth across our system. New electric service installations are up this year by nearly 3%, and new requests for natural gas service increased by more than 7% compared to the same period last year.

Now as many of you know, we have 1 major construction project underway, our biomass-fueled power plant in Rothschild, Wisconsin. Construction is now nearly 90% complete, and we're on schedule for commercial operation by the end of this year. Since our last call, progress has continued. We achieved a significant milestone in May when the auxiliary natural gas boiler began supplying steam to the Domtar paper mill, which is located immediately adjacent to our new plant.

In addition, we've successfully completed the oil flush of the steam turbine generator, and the chemical cleaning of the boiler is now complete. As of today, 47 of the plant's 80 systems are in the start-up and commissioning stages. In about a month, we expect to fire natural gas in the biomass boiler for the first time.

As I've noted before, the biomass plant will help us diversify our portfolio of renewable energy. The unit will efficiently produce electricity for the grid and steam for the Domtar paper mill, and we'll be able to dispatch the unit, a benefit that's simply not available with solar or wind generation.

Overall, our investment in the biomass plant is expected to total approximately $265 million, excluding allowance for funds used during construction. And as I mentioned, we're targeting commercial operation before the end of 2013.

Switching gears now. You'll recall that in 2011, our board authorized us to buy back up to $300 million of Wisconsin Energy common stock. That authorization runs through the end of this year. During the second quarter, we purchased approximately 1,043,000 shares. Since the program began, we've repurchased 5,974,000 shares at a cost that is just under $206.6 million. That equates to an average purchase price of $34.57 a share.

Moving to our recent dividend announcement. At our July meeting, the board voted to accelerate to the second half of 2013, the dividend action that was planned for the first quarter 2014. As a result, the directors declared a quarterly cash dividend of $0.3825 a share on the company's common stock. This is an increase of $0.0425 a share on the quarterly dividend, and raises the annual rate from $1.36 a share to $1.53 a share. The board also reaffirmed our dividend policy that calls for a payout ratio to rise to 65% to 70% of our earnings in 2017, a level that will be more competitive with our peers across the regulated utility sector.

And now, I'd like to touch for a few minutes on our growth plan and on the investment opportunities that will unfold during the next several years. You may recall that our capital budget calls for spending $3.2 billion to $3.5 billion over the 5-year period 2013 through 2017. In this 5-year plan, we're shifting, of course, from the large high-profile projects that were part of our Power the Future effort to many smaller-scale projects designed to upgrade our aging distribution infrastructure. Over the next 5 years, we'll place a greater focus on pipes, poles, wires, transformers and substations, the very building blocks of our delivery business. We've already begun rebuilding 2,000 miles of electric distribution lines, replacing 18,500 aging power poles, 20,000 transformers and literally, hundreds of substation components.

On the natural gas distribution side of our business, we've begun the work to replace 1,250 miles of gas mains, 83,000 individual gas distribution lines and approximately 233,000 meter sets. The primary risks associated with these type of projects, developmental, legal, regulatory and 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 major projects we've completed in recent years. Our focus on renewing our distribution network is essential to maintaining our status as the most reliable utility in the Midwest. And of course, we'll continue to update you as these needed infrastructure projects move forward.

Another key investment we're planning is the conversion of our Valley Power Plant to natural gas. The Valley plant is a cogeneration facility, located along the Menomonee River, very near downtown Milwaukee. Valley generates electricity for the grid, produces steam to heat more than 450 buildings in the downtown Milwaukee business center and provides voltage support for our distribution network. We filed for Construction Authority with the Wisconsin Commission on April 26, and the notice of proceeding was issued by the Commission on June 21. If approved, we plan to complete the Valley conversion in late 2015 or early 2016 at an estimated cost of $65 million to $70 million, excluding allowance for funds used during construction. It's important to note that before we begin the conversion, we must upgrade the existing natural gas pipeline that runs near the facility. That upgrade began physically in March of this year, and we estimated that it will cost approximately $26 million.

Converting Valley to natural gas has several very important benefits. First, it will reduce our operating costs and it will enhance the environmental performance of the units. We expect the electric capacity of the plant to remain at 280 megawatts, and we believe our plan will help support a vibrant downtown Milwaukee for many years to come.

Turning now to developments at Oak Creek. We continue to make progress on our fuel flexibility initiative at the Oak Creek expansion units. As you may recall, the units were initially permitted to burn bituminous coal. However, given the current cost differential between bituminous and Powder River Basin sub-bituminous coal, blending the 2 types of coal could save our customers a significant amount of money. Our current estimate, $25 million to $50 million a year, depending upon the mix. So after receiving the necessary approvals, we began testing a blend of bituminous and Powder River Basin coal at our Oak Creek expansion units in May. Testing is expected to continue into 2015 and will help us identify the equipment modifications that would be needed to increase the percentage of Powder River Basin coal in our fuel mix at Oak Creek.

Shifting now to our hydroelectric plants, you may recall that we plan to build a new powerhouse at our Twin Falls hydroelectric site on the border of Wisconsin and Michigan's Upper Peninsula. Twin Falls is 1 of 13 hydroelectric plants in our system. It was built back in 1912, and while the plant is licensed to operate until 2040, the existing powerhouse is really in need of repair. We considered several alternatives, but the most prudent course of action is to build a new powerhouse and add spillway capacity to meet current federal standards. We received a Certificate of Authority for the project from the Wisconsin Commission in May. We're expecting a permit from the Wisconsin Department of Natural Resources and the license amendment from the Federal Energy Regulatory Commission later this year. If we receive the final approvals in a timely manner, we would begin construction by the spring of 2014, with completion planned in 2016. We estimate the cost of the project to be $60 million to $65 million, again, excluding allowance for funds used during construction.

It's important to note that the investments we're planning on the generation side of our business are expected to lower costs for customers. For example, the Valley conversion is projected to save up to $20 million annually in operating costs. And our fuel flexibility effort at Oak Creek could save customers, as I mentioned, up to $50 million a year, depending on the fuel mix.

Now turning to the natural gas distribution side of our business. We filed an application with the Wisconsin Commission in March to build a natural gas lateral in the West Central region of Wisconsin. The 85-mile line would run between Eau Claire County and the city of Tomah in Monroe County. The project will address reliability concerns in the Western part of Wisconsin and meet growing customer demand, driven in part by customers converting from propane to natural gas, and of course, the recent growth of the sand mining industry in the region. In addition, 7 communities have passed resolutions now authorizing us to begin operating natural gas distribution systems within their borders, and these are communities that currently do not have natural gas distribution service. So if our project is approved, construction of the line would begin in early 2015, with an in-service date during the fourth quarter of 2015. The projected cost is $150 million to $170 million, excluding allowance for funds used during construction.

We're also continuing to follow another possible investment opportunity, the potential sale of the State of Wisconsin's electric and steam generating plants. On June 30, Governor Walker signed into law a new state budget that includes a provision expanding the state's authority to sell or lease certain state-owned properties. This means that the administration now has the authority to sell the state's electric and steam plants. No formal timetable has been announced, but if a sale does take place, we will expect that it would occur in either 2014 or early 2015.

And before closing my remarks, I'd like to briefly touch on one of the recent developments related to our Michigan operations. Under Michigan law, the retail customers may choose an alternative energy supplier to provide power supply service. The law limits customer choice to 10% of Michigan's retail sales, but the law excludes the iron ore mines from this cap. Of course, we continue to provide the distribution and customer service functions regardless of the customer's power supplier. In late July, the 2 iron ore mines we've been serving on uninterruptible tariff asked to switch to an alternative supplier effective September 1. In addition, several smaller customers have chosen an alternative supplier. We do not expect the loss of the mines or the smaller customers to have a material impact on our consolidated financial results or projections for 2013, and we're evaluating our options for mitigating this loss of load for 2014 and beyond.

And now finally, I'd like to address a number of questions we've received recently about potential mergers and acquisitions. Our approach to mergers and acquisitions remains unchanged. As many of you are aware, we use 3 criteria to evaluate any potential opportunity: First, we would have to believe that an acquisition would be accretive to our earnings per share by the end of the first year; secondly, it would need to be substantially credit neutral; and finally, after due diligence, we would have to believe that the long-term growth rate of the acquisition would be at least equal to our stand-alone growth rate. Allen and I have applied these criteria for, gosh, for the 10 years we've been at Wisconsin Energy and the criteria remain firmly in place today.

And now, with more details on our second quarter and our outlook for the remainder of 2013, here's Pat.

James Patrick Keyes

Thank you, Gale. As Gale mentioned, our 2013 second quarter earnings from continuing operations were $0.52 a share, compared with $0.51 a share for the same quarter in 2012. Results were slightly better than last year, primarily because of increased natural gas sales, the positive impact of our share repurchases and increased earnings at We power.

Our consolidated operating income for the second quarter was $229.5 million as compared to $222.6 million in 2012, an increase of $6.9 million. Starting with the Utility Energy segment, you will see that operating income in the second quarter of 2013 totaled $138.9 million, an increase of $5.3 million over the second quarter of 2012.

Our second quarter earnings were helped by $15.4 million due to the pricing increases that went into effect January 1 of this year. We also experienced $5.5 million of favorable fuel recoveries as compared to the second quarter last year. Our earnings were hurt by $6.3 million because of the increased depreciation expense, largely driven by the environmental projects at the older Oak Creek units that were completed last year. Finally, we estimate that weather reduced our operating income by $13 million as compared to the second quarter of last year. Overall, these were the primary factors that netted to a $5.3 million improvement in utility operating income.

I would also like to remind you of one item that is affecting our quarterly earnings. As I mentioned last quarter, we expect to receive a federal tax grant when we complete our new biomass facility later this year. Our customers are currently receiving the benefits of this grant through bill credits. However, accounting rules do not allow us to recognize the grant income until the plant is placed into service. We estimate that our second quarter earnings would have been $0.03 a share higher, and our first half earnings would've been $0.06 a share higher, if we had recorded the grant income to match the bill credits.

Now turning to our Non-Utility segment. Operating income in this segment was up $1.3 million this quarter because of the final approval of our Power the Future plant costs in the last Wisconsin rate case. We expect this increase to continue each quarter through 2013.

Taking the changes for these 2 segments together and a slight improvement at corporate and other, you arrive at the $6.9 million increase in operating income.

Earnings from our investment in the American Transmission Company totaled $17.3 million in the second quarter, which is a $1.1 million improvement over the same period in 2012.

Our other income net declined by $2.8 million, primarily because of lower AFUDC. The AFUDC decreased because we completed the final stages of the air quality control system for the older Oak Creek units last year.

In addition, our net interest expense increased by $1.8 million, primarily because of the completion of the air quality control system for the older Oak Creek units. Once the construction was complete, we stopped capitalizing interest.

When compared to the second quarter of 2012, our pretax income is up by $3.4 million, and our income tax expense is higher by $3.7 million, causing the slight decrease in net income of $300,000. The higher effective tax rate this year is, again, partly driven by lower AFUDC. Our effective tax rate for 2013 is expected to be between 36% and 37%.

Combining all these items brings you to $119 million of net income from continuing operations for the second quarter of 2013 or earnings of $0.52 per share.

During the first 6 months of 2013, our adjusted operating cash flows totaled $684.2 million, which is a $47.9 million increase from the same period in 2012. This increase largely came from the lower working capital needs and cash received this year through customer rates for the recovery of regulatory assets. This was partially offset by a $24.9 million decrease in restricted cash that related to the 2012 refund of the Department of Energy settlement.

Our total capital expenditures decreased by $6.7 million in the first half of 2013 as compared to 2012. This reflects the completion of the air quality control system for the older Oak Creek units.

We paid $155.6 million in common dividends for the first half of 2013, an increase of $17.3 million over the first half of 2012. As Gale mentioned earlier, the board announced its decision to accelerate to the second half of 2013 the dividend action that was originally planned for the first quarter of 2014. This equates to a quarterly dividend of $0.3825 a share, up from our prior $0.34 a share.

Our adjusted debt-to-capital ratio was 52.2% at the end of June. Our calculation to reach half of our hybrid security is common equity, which is consistent with past presentations. The projected year-end debt-to-total capital is expected to be relatively flat with 2012 year end. 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.

As shown in the earnings package on our website, retail sales of electricity decreased by 2.5% in the first half of 2013 as compared to the first half of 2012. Our normalized sales were down by 1.5%. All normalized sales are adjusted for the effects of leap year and weather.

Looking at the individual customer segments, with the cool June weather, we saw actual residential sales, for the first half of the year, down 0.9%. On a normalized basis, the sales were down 0.3%.

Across our small commercial/industrial group, sales for the first 6 months were down by 0.1%. But on a normalized basis, sales to small commercial/industrial customers were up 0.4%.

On a normalized basis, sales for the first half of 2013 in the large commercial/industrial segment, excluding the iron ore mines, were down 1.4%.

On the gas side of the business, total volumes the first half of the year increased by 11.8%, primarily due to colder weather than last year. On a normalized basis, and excluding the volumes used in power generation, gas volumes increased by 2% compared to 2012. This is attributed to an increase in customers, fuel switching to natural gas and the positive impact of additional gas used in the sand mining industry. Overall, these gas volumes were better than our projections. The overall effect of the electric and gas results are in line with our sales expectations.

Turning to other items of interest. In June of 2013, our electric subsidiary issued a $250 million 5-year bond at a coupon of 1.7%. This bond essentially replaced a $300 million bond with a coupon of 4.5% that came due in May.

Finally, looking to our earnings forecast. First, we're tightening our 2013 guidance. Our prior guidance was in a range of $2.38 a share to $2.48 a share. Our new 2013 guidance will be from $2.41 a share to $2.48 a share.

Before I turn things back to Gale, I would also like to provide guidance on our third quarter earnings. As background, we earned $0.67 per share in the third quarter of 2012. However, a hot summer boosted our third quarter earnings last year by $0.06 per share. Also as mentioned earlier, we cannot record the income from the federal tax grant for our biomass plant until the plant is placed into service. The customer bill credits will continue in the third quarter, and this is expected to reduce our third quarter earnings this year by $0.03 per share. Taking these factors into consideration, and assuming normal weather, we estimate our 2013 third quarter earnings to be in the range of $0.52 to $0.56 per share.

And with that, I will turn things back to Gale.

Gale E. Klappa

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] Greg Gordon with ISI Group.

Greg Gordon - ISI Group Inc., Research Division

Quick and simple question. You've obviously tightened your earnings guidance range. You've raised the lower end of the range. That's good, but it seems to me, if my memory is correct, that your sales growth is trailing behind what your beginning of the year budget expectation was. So can you tell us what you've done in terms of a midcourse correction to stay on track to have such a good year?

Gale E. Klappa

I appreciate it, Greg. Well, the first thing is, the bill wasn't too bad at Catch 35. It's a little inside joke, folks. At any rate, if you look at our natural gas sales projections, remember our natural gas distribution business is about 20% of our total business. And then, you look at our electric sales projections. You put it all in one pot and we're about on target with where we thought we would be overall for energy consumption. So there's not been a big deviation up to this point, through the first 6 months of this year, against our sales growth forecast when you put the whole group of companies together.

Greg Gordon - ISI Group Inc., Research Division

Got you. So I was focused on the electric numbers, and -- but the gas numbers are ahead of plan?

Gale E. Klappa

Exactly.

Operator

Your next question comes from the line of Jonathan Arnold with Deutsche Bank.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

On the state power plants, the timeframe, Gale, I think you laid out was probably a little longer than we might have thought. Maybe we were too optimistic or it there some extra steps that have to go through here? And just could you update on how you see that process playing out?

Gale E. Klappa

Happy to, Jonathan. The truth of the matter is, the state has not announced -- or the Department of Administration, on behalf of the state, has not announced a formal timetable. We know that this is something that they are planning, that they are putting together a process to move forward with. But they've not announced a formal timetable. So the information we gave you in the prepared remarks, it was a sale that would be perhaps a 2014 or early 2015 event, that's our best guess at this stage of the game because they've not announced a timetable. But I don't sense any slippage in their desire to try to put a process together and move forward. It's just we don't have a very good handle, because no one has talked about a specific timetable at this stage of the game. On the other hand, the governor has said publicly how he would like to use the proceeds from the sale if a sale takes place. So there's no lack of attention at the state in terms of trying to put together a process. I hope that helps, Jonathan.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

That's very helpful. And the other thing on timing, it seems like kind of you're now expecting not to start the Twin Falls construction until next year, rather than later this year. Is that just -- but you're still on track for 2016. What's going on there?

Gale E. Klappa

You're correct. We would plan to start next year. Allen?

Allen L. Leverett

That's right, in the spring of 2014. So we need one last permit from the Wisconsin Department of Natural Resources, and then, the final approval from FERC. So we expect to get those well before year end, which will allow us to -- when the construction season starts in Michigan, to do the construction starting in spring of '14.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

You were saying fall of '13, last quarter. I was just wondering, what's taken longer?

Allen L. Leverett

Well, that DNR permit that we need, we have to have that Wisconsin DNR permit before the FERC will act. So it's taken us a bit longer to get that Wisconsin DNR permit than we had hoped. Because part of what's happening with this project, Jonathan, this might be too much detail, but we're literally moving the powerhouse from the Michigan side of the river to the Wisconsin side of the river. And because of that, even though it's the same river, the Wisconsin regulators have to weigh in. So that's taking a little longer than we expected.

Gale E. Klappa

Thank you for the question. We don't, by the way, think anything is off track here. It's just a matter of working through the permitting process, and that's taking just a hair longer.

Operator

Your next question comes from the line of Jim von Riesemann with CRT Capital.

James D. von Riesemann - CRT Capital Group LLC, Research Division

I wanted to move to a strategic line of questioning, if you don't mind.

Gale E. Klappa

We'd be happy to talk strategy.

James D. von Riesemann - CRT Capital Group LLC, Research Division

Okay. So as we know, this back-to-basic strategy emerged in earnest in, call it 2005. It was centered on rate-based growth and cost containment efforts. So with that backdrop, let me look at the cost side of the ledger, if you don't mind. One of the key themes this earnings season has been containing costs, yet with 7 to 8 years of cost-reduction efforts already underway, I'm having a tough time reconciling how much fruit might be left on a proverbial tree, so to speak. So the question to you is, could you shed some light on how Wisconsin balances your -- Wisconsin Energy that is, balances your near-term cost containment efforts without triggering a potentially longer-term negative impact on the business, be it earnings or reliability issues and the like? And importantly, how we should think about where the future cost savings could come from?

Gale E. Klappa

Sure, I'll give it a shot, and we'll be happy to ask Pat and Allen to pitch in as well. Let me start with kind of our approach, because I think that if we talk in some detail about our approach, it might help shed light on the other aspects of your question. Our approach, essentially, can be broken down into 2 pieces. Piece 1 is we are -- and I think you saw this reflected in a lot of what we talked about in terms of the capital projects, particularly on the generation side of the business. Our first approach is to look for and carry out investment opportunities that can actually lower O&M costs and lower cost for customers. So if we can make a capital investment that actually takes our O&M costs down, that gives us an investment opportunity, but it also directly benefits customers. And we have a couple of very specific projects along those lines that we touched on, and I'll ask Allen just to briefly touch again. That would be Valley and our Oak Creek fuel flexibility initiative. Allen?

Allen L. Leverett

Yes, and just on that note, Jim, in the case of Valley, that's a fuel-switching project. So there, what we propose to do is switch from coal to natural gas. Of course, when you go away from solid fuel for this kind of plant, much lower level of employment at the plant, the great deal of expenses and capital investments that will just go away because you're no longer handling solid fuel and handling the combustion byproducts that come along with solid fuel. So as Gale mentioned in the prepared remarks, that could be up to a $20 million-a-year savings. On sort of the fuel flexibility front, Gale also mentioned the project at the Oak Creek expansion plan where we're -- want to make investments to be able to burn a blend of bit and sub-bit coal. Depending on what we're able to do in terms of an ultimate level of sub-bituminous coal, we could be looking at $50 million a year in savings. Now, of course, those aren't O&M savings. They're fuel savings. But that still serves, I mean because ultimately, customers don't discriminate between O&M and fuel, they're just looking at their total bill. So that, certainly, is another source of savings. And I know, in other areas, Pat, we're looking at things.

Gale E. Klappa

Yes, that's kind of piece 1, Jim. And as Allen said, and we're going to ask Pat to comment here, on the nongeneration side of our business, we believe there are numerous opportunities to invest in automation and process improvement to take O&M out of the business. And Pat can give you a couple examples of that. And then, I'll come back with a third piece after Pat can give you a couple of examples of how we can automate our processes, use IT technology to cut O&M. Pat?

James Patrick Keyes

Sure, be glad to, Gale. So Jim, I think as Gale alluded to, at the core of this are lots of small initiatives where we identify where our process inefficiencies are, where we have a lot of hand-offs, where we have a lot of people pushing paper and not thinking in effect, and figuring out how we can better automate them. And that's not any one big project. That's a series of several that we will do year-on-year-on-year. So that's kind of the core example. But there's other more tactical examples. And let me use customer service as one of them. There are segments of our customers, generally speaking the younger folks, that don't really like the whole experience of calling into a call center. So the more functionality or more ways of interacting with us that we can make available on the web or on mobile apps, those customers would prefer to shift to that channel of interaction. And that is a win for them, it's also a win for us because that's a lower-cost channel for them to interact with than picking up the phone. So we've got several ideas that we continue to roll out applications in that area. Another area we're looking at is in parts of our service territory. That is, universities where we've got high volumes of people going on and off during move season, would there be an advantage to put remote disconnect technology in those areas so that we don't have to send people out every spring and every fall to disconnect and reconnect the meter? Again, we're still evaluating it. May roll that out over time. But that's another example of a place we still have opportunity for cost take-out. So with that, Gale, I'll turn it back to you.

Gale E. Klappa

Terrific. And you may be getting more detail than you want here, Jim. But there's a third piece and that's what I generally call line losses. And that's been one of our focuses over time, in terms of how do you reduce line losses. And there are all kinds of ways, both from a process standpoint and a technical standpoint on line losses. And we've been pretty successful at actually reducing our line losses over time. We were able to do that in England. We've been able to do that here. So there's just hundreds of little initiatives, all focused on process improvement, automation and investment that can take O&M out of the business over time. I hope that helps, Jim.

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

Yes, it is. So the bottom line is that you replace OpEx with CapEx, you keep your cost structure relatively flat by automating stuff, and that your earnings growth prospectively isn't predicated on job cuts or major cost-reduction initiatives. Is that right, the way I think about it?

Gale E. Klappa

I think you've nailed it.

Operator

Your next question comes from the line of Julien Dumoulin-Smith with UBS.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

So going back to one of the little details there on Michigan, I'd be curious, what caused the switching decision now, of any period? And frankly, you alluded to the mines being an exception. Are all the customers here mines that you're talking about? And perhaps, what are the alternative solutions, if you will, that you're evaluating potentially?

Gale E. Klappa

Okay, sure. Well, the 2 major customers, obviously, are the iron ore mines. We really don't know what motivated them. I mean they have been eligible to switch, I believe since 2002, when that First Choice law was introduced in Michigan. And the last amendment to the law in which they received the -- well, actually, the Choice was introduced in Michigan in 2002. There was a 2008 amendment to the Choice law that specifically exempted the mines from the cap. So they've been eligible to switch for -- well, ever since 2008. What specifically motivated them at this stage of the game, we really don't know for certain. But again, I think there's some internal dynamics up there at the 2 mines, the Empire Mine and the Tilden Mine. Those are the names of the 2 mines. One of the dynamics, certainly, that we expected was that the Empire Mine, based on their public announcements, is going to close for good at the end of 2014. And we're not certain, based on the information they've given us, just how much they intended to produce out of that mine anyway in 2014. So the switch of the Empire Mine may have had something to do with the final stages of its life. Well, I'm speculating though, we just don't know for certain what motivated the particular timing for their switch. The other customers that have switched so far -- I might add, by the way, that we are the last utility that I'm aware of in Michigan to see customer switching. From 2002 up until June of this year, we hadn't lost a single customer in the Upper Peninsula. But the other customers who are switching are, by and large, very small customers. I know of a paint store, I know of a bank branch. Very, very small customers. So I hope that helps.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Absolutely. And just in the remarketing, I mean, if you can give us some sense of a net impact. It's probably fairly modest, but ...

Gale E. Klappa

Well, I think in terms of remarketing, and certainly, we have some opportunities for serving some other customers, but also, we simply have to look at -- as we have been looking at, we simply have to look at the future of the Presque Isle Power Plant up in the Upper Peninsula. Normally, if you lost -- if you were in a normal business and you lost a significant customer load, even though it may or may not have been particularly profitable, you would look at, well, what capacity do I still need? So one of the things we obviously have to reexamine is the future of the Presque Isle Power Plant. It's all very early days and we will work our way through this; having active discussions internally, obviously, and with the Michigan Public Service Commission. And we'll just step-by-step, methodically, logically and productively work our way through this.

Operator

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

Andrew Bischof - Morningstar Inc., Research Division

A quick clarifying question on the share buyback. What was the average purchase price in the quarter? And I apologize, I missed the total shares since program initiation?

Gale E. Klappa

We have that in the script, and we'll go back to the page here in terms of the total number of shares for the program.

James Patrick Keyes

So Andy, this is Pat. For the program, it was 5.974 million shares at around $206 million, so an average share price of $34.57. For the quarter, we purchased just over 1 million shares for just over $43 million.

Andrew Bischof - Morningstar Inc., Research Division

And one other question. You've talked in detail about your growth opportunities, which was much appreciated. In the past, you've highlighted the additional opportunities at ATC, not only within Wisconsin, Michigan, but outside that footprint. Any update on those additional opportunities or is this announcement still pretty out in the future?

Gale E. Klappa

I think all of the information we provided you over time about the 10-year growth forecast for American Transmission Company still applies today. They, as you probably remember, Andy, they do a rolling 10-year forecast that's updated every autumn. And I believe it's October.

Allen L. Leverett

It's done in October, Andy. This is Allen. Yes.

Gale E. Klappa

So nothing different. Still on track and a new update coming in October.

Operator

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

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

What was the fuel cover on an absolute basis? I know it was $5 million relative to last year.

Gale E. Klappa

The famous Steve Dixon is turning to that page right now.

Stephen P. Dickson

Yes, our fuel recovery, we are above the 2% band, so we are deferring everything about the 2% band. And through the 6 months, we're at about $16.6 million, which is where the band is, and we're a little bit above that. We're at $19.7 million, so we deferred the amount above $16 million. Does that make sense?

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

So $3 million?

Stephen P. Dickson

$3 million is what we've deferred.

Gale E. Klappa

What we've deferred. Yes, so in other words, we're allowed to keep for our shareholders anything up to 2% above the target amount or our shareholders have to eat anything below the 2% target amount. And what Steve is saying is, we were just above the 2% target amount. So what you saw in our earnings was the amount up to the 2% target. The remaining over recovery, we've deferred. And if that holds, that will go back to customers.

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

So you ate $2 million last year, is that the right way to think about it, to get to $5 million this year?

Gale E. Klappa

Yes, that is correct.

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

Okay. And just because you mentioned it about line losses, what are you doing with conservation voltage regulation? What's the opportunity there?

Gale E. Klappa

Well, obviously, there's a lot of work going on around the industry related to that. I know EPRI has a project related to that. Some utilities are looking at it. We're looking at it, but nothing definitive yet.

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

Okay. So your work so far has been on the utility side of the meter?

Gale E. Klappa

That is largely correct, yes.

Operator

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

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

Natural gas demand. We've seen in a handful of utilities, I think you guys as well, what is a little bit of a pickup in weather-normalized demand for natural gas from utilities to their customers. Could you just comment on that? What are the trends you're seeing, whether you think it's a short-term blip or whether it's something structural? After all, if you look at like 10, 20, 30-year cycles of natural gas demand served by utilities, it had actually been on a downward slope. So just curious if this is a short-term thing or something else to look out for?

Gale E. Klappa

Good question, Michael, and I'll give you my theory, for what it's worth. First of all, I think you're right. Here and across the country, we've seen a little change in terms of the historic past 20 years where usage per customer was going down at a slow, but reasonably steady rate. And clearly -- well, let's start with demand. Most of the demand for natural gas in a state like Wisconsin is coming from residential and small commercial customers. In fact, about 2/3 of the natural gas historically consumed in the state of Wisconsin is consumed by residential and small commercial customers. So there, very weather-dependent, obviously, year to year, but when you try to weather normalize, the big change has been the efficiency of furnaces. So if, for example, you replaced a 20-year-old gas-fueled furnace with a brand new one, you would get a significant percentage pickup in efficiency. And I think -- and it's that way with virtually every natural gas appliance in your home. The new appliances are simply much, much more efficient. So I believe that was the big factor driving this kind of slow but steady decline year after year in usage, natural gas usage per customer. Now the last couple of years as natural gas prices have really been low and have stayed low, we have seen a break in that pattern. And you can see it in the numbers we reported today. Couple of things going on. First of all, you know when it costs you less per term and your wife is cold, you know you're going to turn it up. So I think that's piece 1. The second piece is -- so I think there's not as much price disincentive to being more comfortable and to using more natural gas. So that may be one structural change. I think the second is we're seeing an uptick again in conversions. If you look at the price spread in most parts of the country between propane and natural gas, there's still a very significant price spread that incentivizes customers to switch from the use of propane to the use of natural gas. In fact, I think I mentioned during my prepared remarks that we've gotten authorizations and requests now from 7 smaller communities in the western part of Wisconsin, asking us to begin providing natural gas distribution service so that their residents have the opportunity to switch from either oil, propane baseload heat to natural gas. So I think that the pricing of natural gas today is causing a changed behavior in the marketplace, driving more customer connections, driving a move away from propane. And that is mitigating, I think, the increased efficiency that customers are seeing when they upgrade their equipment. So I hope that helps.

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

It helped. How do you think about what -- you've talked at length about what's kind of in guidance or in your views about weather-normalized electricity demand. What's in your views for weather-normalized gas demand?

Gale E. Klappa

Well, until we see -- I'll be honest with you. Until we see more of a pattern here, I'm not sure we're ready to declare it a structural change. But we're obviously taking a very hard look at it, and if we see enough evidence that there's a structural change, it will change our long-term forecast. For now, candidly, the weather has been so abnormal, either abnormally warm or abnormally cold in the last 2 or 3 winters, and you know, I've talked about the limitations of the weather normalization techniques. I think we need to see a little more data and hopefully, more normal weather so that we can really understand whether the weather is driving some of this change, and our weather normalization techniques are limited, which they are, or whether there's true structural change. So I don't mean to give you a vague answer at all, but I think in another 24 months, I hope we would have a better answer for you because we'll have more data.

Operator

Your next question is a follow-up question from the line of Jim von Riesemann with CRT Capital.

James D. von Riesemann - CRT Capital Group LLC, Research Division

Going back strategically, under what conditions do you think the board or what conditions would be ripe for the board to raise your payout ratio above 70%?

Gale E. Klappa

Well, I can tell you about how Allen and I both look at it. And our board would certainly have a view, but they tend to follow our logic very well in terms of the financial structure. If you step back and you say, "All right, there are several components of the business that we want to make sure all fit together." All right? So the first thing we look at is what is our cash need? And that's driven by what is our investment opportunity. And as we said, for the next several years, 2013 through 2017, we expect an investment opportunity ranging from $3.2 billion to $3.5 billion. So that's Step 1. We identify our investment opportunities and our cash needs. Step 2 is we know that we want to maintain a strong A-category credit rating. So we know what debt-to-total capital and equity-to-total capital, we know what that needs to look like on a percentage basis. And then, thirdly, we don't really want to be forced -- unless there's an incredible opportunity that we didn't see, we don't want to be forced into issuing equity. And so you put all that together and out falls a sustainable medium-term dividend payout ratio. We really look at it systematically, block by block, in terms of the components of the business. And so I think logically, to directly answer your question: What would motivate the board to materially increase the payout ratio? It would be if we thought there was just simply a derth of investment opportunities where you simply -- you didn't have a productive use for that cash. Allen, anything you'd like to add?

Allen L. Leverett

No, I don't think so, Gale. But you always go through those 3 parts, Jim, that Gale enumerated.

Gale E. Klappa

All right. Well, ladies and gentlemen, we appreciate you taking part in the call today. That concludes our conference call for this afternoon. Again, thank you so much for participating. If you have any other questions, the famous Colleen Henderson will be available in our Investor Relations office, and her direct line (414)221-2592. Thanks again, everybody. Take care.

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