威斯康辛能源 (WEC) 2013 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. Thank you for waiting and welcome to Wisconsin Energy's conference call to review 2013 third-quarter results. This conference call is being recorded for rebroadcast and all participants are in a listen-only mode at this time.

Before the conference call begins, I will read the forward-looking language. All statements in this presentation other than historical facts are forward-looking statements that involve risks and uncertainties which are subject to change at any time. Such statements are based on management's expectations at the time they are made. In addition to the assumptions and other factors referred to in connection with the statements, factors described in the Company's latest Form 10-K and subsequent reports filed with the Securities and Exchange Commission could cause actual results to differ materially from those contemplated.

During the discussions referenced earnings per share will be based on diluted earnings per share unless otherwise noted.

After the presentation, the conference will be 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 is my pleasure to introduce Mr. Gale Klappa, Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation.

Colleen, thank you very much. Good afternoon, everyone, and thanks for joining us as we review our 2013 third-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 of Wisconsin Energy and President and CEO of We Generation; Pat Keyes, our Chief Financial Officer; Susan Martin, General Counsel; Steve Dickson, Controller; and Scott Lauber, our Treasurer.

Pat of course will review our financial results in detail in just a moment, but as you saw from our news release this morning, we reported earnings of $0.60 a share for the third quarter of 2013. This compares with earnings of $0.67 a share for the third quarter of 2012.

Our latest results reflect a return to normal summer weather compared to the record heat that we experienced last summer. On the positive side of the ledger, our earnings were boosted by a slight uptick in net income at We Power and by our share repurchase program.

For the first three quarters of 2013, our earnings came in at $1.88 a share compared to $1.92 a share for the first nine months a year ago. You will recall that our year-to-date results this year reflect a $0.09 a share reduction for customer bill credits. When our new biomass plant is complete and in commercial operation, we expect to add $0.09 a share to our fourth-quarter earnings.

Turning now to the economy in our region, Wisconsin's unemployment rate declined to 6.7% in August and remains well below the national average. However, we anticipated some continued sluggishness in the regional economy when we projected our third-quarter sales, and that sluggishness is truly reflected in our numbers.

Energy sales to our large commercial and industrial customers, excluding the iron ore mines in Michigan, were down by 3.5% compared with the third quarter a year ago. When you factor in normal weather, sales to our large commercial and industrial customers, again excluding the iron ore mines, were down by 2.7%.

We did see some positive signs, though, in September. Overall, electricity use by our large customer segment was higher than September of a year ago. And about half of the 17 industrial sectors that we track showed some positive growth in September.

Also, we are continuing to see customer growth across our system as well. Compared to the same time last year, new electric service installations are up by 2.7% and new natural gas installations have increased by 13.5%.

Now, as many of you know, we are finishing up a major construction project, our biomass fuel power plant in Rothschild, Wisconsin. Construction is now 97% complete, and we are on schedule for commercial operation before the end of the year.

Since our last call, we recorded several significant milestones at Rothschild. We achieved first fire using natural gas on September 17. A week later on September 24, we synchronized the steam turbine generator for the very first time. Also, we had our first fire using biomass on October 3. And we are continuing to test and fine-tune various systems on the unit in preparation for commercial operation.

As I have noted before, the biomass plant will help us diversify our portfolio of renewable energy. The new unit will produce electricity for the grid and steam for the Domtar paper mill on the site. And we will be able to dispatch the unit on demand, a benefit that is simply not available with solar or wind generation.

Overall, our investment in the biomass plant is expected to total about $269 million, and that is excluding allowance for funds used during construction.

In September, we also started a new construction project at one of our hydroelectric plants. We have officially begun the work of building a new powerhouse at our Twin Falls hydroelectric site on the border of Wisconsin and the Upper Peninsula of Michigan. Twin Falls is one of 13 hydroelectric plants on our system. It was built back in 1912, and while the plant is licensed to operate until the year 2040, the existing powerhouse really needs repair.

We considered several alternatives, but the most prudent course 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.

Since our last update, we have received all the necessary permits, including a license amendment from the Federal Energy Regulatory Commission. We expect to complete the Twin Falls project in 2016, and we are estimating that the cost will be in the range of $60 million to $65 million, again excluding allowance for funds used during construction.

You may recall that we are also planning to convert our Valley power plant from coal to natural gas. The Valley plant is a cogeneration facility located along the Menominee River 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 a Notice of Proceeding was issued by the Commission in late June. 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 is important to note that before we begin the conversion, we must also upgrade the existing natural gas pipeline that runs near the facility. That upgrade began in March of this year at an estimated cost of approximately $26 million.

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

Switching gears now, you will recall that in 2011, our Board authorized us to repurchase up to $300 million of Wisconsin Energy common stock. That authorization runs through the end of this year. During the third quarter, we purchased approximately 1.147 million shares. Since the program began, in total, we have repurchased 7.121 million shares at a cost just under $254.8 million. That equates to an average purchase price of $35.78 a share.

Regarding our dividend policy, at our July Board meeting, the Board voted to accelerate to the second half of 2013 the dividend action that was planned for the first quarter of 2014. As a result, the directors declared a quarterly cash dividend of $0.3825 a share on the Company's common stock. This was an increase of $0.0425 a share in the quarterly dividend, and it raised the annual rate from $1.36 a share to now $1.53 a share.

The Board also reaffirmed the dividend policy that calls for our payout ratio to rise to 65% to 70% of earnings in 2017, a level that we believe will be much more competitive with our peers across the regulated utility sector.

And now, I would like to touch on our growth plan and on the investment opportunities that we see unfolding over the next several years.

You may recall that our capital budget calls for spending $3.2 billion to $3.5 billion over the five-year period 2013 through 2017. In this five-year plan, we are shifting from the large, high-profile projects that were part of Power the Future to many smaller-scale projects designed to upgrade our aging distribution infrastructure.

Over the five-year period, we will place a greater focus on pipes, poles, wires, transformers and substations, the building blocks of our delivery business. We have already begun rebuilding 2000 miles of electric distribution lines, replacing 18,500 power poles, 20,000 transformers and literally hundreds of substation components.

On the natural gas distribution side of our business, we started to replace 1250 miles of gas mains, 83,000 individual gas distribution lines and approximately 233,000 meter sets. The primary risks associated with these 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 megaprojects we have completed in recent years. Our focus on renewing the distribution networks is essential to maintaining our status as the most reliable utility in the Midwest.

Turning now to Oak Creek, we continue to make progress on our fuel flexibility initiative at the Oak Creek expansion units. As you may recall, the units initially were permitted to burn bituminous coal. However, given the current cost differential between bituminous and Powder River Basin sub-bituminous coal, blending the two types of coal could save our customers between $25 million and $50 million a year, depending upon the mix.

After receiving environmental approvals, we began testing a blend of bituminous and Powder River Basin coal at our Oak Creek expansion units in May. Testing has been progressing well and is expected to continue into 2015. These tests will help us identify the equipment modifications that will be needed on a permanent basis to increase the percentage of Powder River Basin coal in our fuel mix at Oak Creek. We expect to submit an application for a Certificate of Authority to the Wisconsin commission in late 2014 or early 2015. Of course, we will need this approval to make the necessary modifications at the plant.

It is important to note that the investments we are planning on the generation side of our business -- converting Valley to natural gas, changing our fuel mix at Oak Creek -- are expected to lower costs for customers. The Valley conversion is projected to save up to $20 million a year in operating costs. And as I mentioned, our fuel flexibility efforts at Oak Creek could save customers up to $50 million a year, again depending on the fuel mix.

On the natural gas distribution side of our business, you may recall that we filed an application with the Wisconsin Commission in March to build a natural gas lateral in west central Wisconsin. In August, we filed a supplement to provide additional information, primarily environmental data.

The 85-mile line would run between Eau Claire County in the far western part of the state and the city of Tomah in Monroe County. The project will address reliability concerns in western Wisconsin and meet growing demand, driven in part by customers continuing to convert from propane to natural gas and by the growth of the sand mining industry in the region.

I might add that over the past few months, eight communities along the proposed route have passed resolutions authorizing us to begin operating natural gas distribution systems within their borders.

If approved by the Wisconsin Commission, we expect an in-service date for the new line during the fourth quarter of 2015. The projected cost is $150 million to $170 million, excluding allowance for funds used during construction.

We are 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, as you may, recall 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, steam and chilled water production and distribution facilities.

The state is moving forward, and in early October, state officials began the process of selecting an outside financial advisor. No formal timetable has been announced, but if a sale does take place, we expect that it would occur in late 2014 or early 2015.

And now, before wrapping things up, I have a quick update for you on American Transmission Company. As you know we are the second largest owner of ATC, with an ownership stake of 26.2%.

ATC recently published its ten-year capital investment plan for the years 2013 through 2022. The plan calls for $3 billion to $3.6 billion of capital spending to bolster reliability and reduce congestion in the region. Now, the previous 10-year plan had called for a higher-level investment, in the range of $3.9 billion to $4.8 billion. However, we do not expect the new plan to have a major impact on our near-term earnings forecast because, similar to the prior plan, much of the investment is back-end loaded.

I should also point out that the new 10-year plan from ATC only covers projects inside the franchise footprint in Wisconsin and the Upper Peninsula of Michigan.

ATC is also pursuing investments outside this footprint through a joint venture with Duke Energy. The joint venture has proposed approximately $4 billion of new transmission in the broader Midwest and in the western part of the country. Any of these projects, if approved, would provide additional investment upside through ATC's 50% share in the joint venture.

Turning to Wisconsin rate matters, at the end of July, we filed our 2014 fuel case. We are asking the Wisconsin Commission for approval to reduce our fuel recovery rate next year by approximately $30 million. The primary driver of the savings is a reduction in the delivered cost of coal.

And finally before closing my remarks, I would like to update you on our Michigan operations. As you recall, under Michigan law, retail customers may choose an alternative supplier to provide power supply service. The law limits customer choice to 10% of Michigan's retail sales. But the law excludes from this cap the iron ore mines in Michigan's Upper Peninsula. Of course, we continue to provide distribution and customer service functions regardless of the power supplier.

As we reported to you on our last call, the two iron ore mines we were serving on an interruptible tariff switched to an alternative supplier on September 1. Several smaller retail customers have switched as well. We do not expect the loss of the mines or the smaller customers to have a material impact on our consolidated financial projections for 2013.

We have taken and will continue to take multiple steps to mitigate the losses for 2014 and beyond. For example, we filed a request with MISO, the Midcontinent Independent System Operator, to suspend operations of all five of our generating units at our Presque Isle power plant. In October, MISO informed us that all the units are necessary to maintain reliability in northern Michigan. As a result, we are eligible for system support resource payments from MISO to recover our costs for operating the units. We currently are working with MISO to determine the exact amount of these payments, and we expect to become eligible to receive the payments beginning in February of 2014.

Although the long-term impact of the Michigan Choice Law is still uncertain, we expect the successful mitigation efforts and a reasonable regulatory response should make our net financial exposure immaterial.

That said, given the loss of load in Michigan's Upper Peninsula, we need to reevaluate our supply portfolio. Before the departure of the mines, we had a long-term need for at least a portion of the Presque Isle power plant. At this point, we do not have that need. As a result, we are working with Wolverine Power Cooperative to modify the joint venture structure that we developed last year so that it works for both Wolverine and our customers over the long-term.

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

Thank you, Gale. As Gale mentioned, our 2013 third-quarter earnings were $0.60 a share compared to $0.67 a share for the same quarter in 2013. As expected, the results were slightly lower than last year because of a return to normal summer weather and customer bill credits related to our new biomass plant.

Our consolidated operating income for the third quarter was $258 million as compared to $280.6 million in 2012, and that is a decrease of $22.6 million.

Starting with the Utility Energy segment, you will see that operating income in the third quarter of 2013 totaled $166.6 million, a decrease of $24.4 million from the third quarter of 2012. The primary driver was the milder weather, which we estimate reduced our electric margins by $22.9 million. In addition, depreciation expense increased by $5.2 million, primarily because of the major environmental project that went into service last year.

As I have mentioned in previous earnings calls, we expect to receive a Federal Treasury grant related to our new biomass facility, which is scheduled to go into service by the end of the year. Our customers currently benefit from this grant through bill credits. However, accounting rules do not allow us to recognize the grant income until the plant is placed in service. We estimate that our third-quarter earnings would have been $0.03 a share higher and our earnings for the first nine months would have been $0.09 a share higher had we recorded the grant income to match the bill credits. Therefore, we expect to see a $0.09 pickup in the fourth quarter when we recognize the grant income after the biomass plant is placed into service.

Now, turning to our Nonutility segment, operating income was up $1.7 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 in the fourth quarter.

Taking the changes for these two segments together and a slight improvement at corporate and other, you arrive at the $22.6 million decrease in operating income.

Earnings from our investment in the American Transmission Company totaled $17.1 million in the third quarter, and that is level with the same period in 2012.

Our other income net declined by $3.9 million, primarily because of lower AFUDC. 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 $1.1 million, primarily because of lower capitalized interest.

When compared to the third quarter of 2012, our tax expense is down because of lower pre-tax income. We expect our effective tax rate for 2013 will be between 36% and 37%.

Combining all of these items brings you to $137.5 million of net income for the third quarter of 2013, or earnings of $0.60 per share.

During the first nine months of 2013, our adjusted operating cash flows totaled $1.053 billion, which is a $25 million increase from the same period in 2012. The increase largely came from cash received this year through customer rates for recovery of regulatory assets.

In addition, during the first nine months of 2013, we made no contributions to our benefits plans compared to $100 million contribution made in the same timeframe in 2012. This increase was partially offset by a $33 million decrease in restricted cash related to a customer refund in 2012 of a settlement with the Department of Energy.

Our total capital expenditures increased by $20 million in the first nine months of 2013 compared to 2012, primarily because of investments in our distribution infrastructure.

We paid $242.3 million in common dividends in the first nine months of 2013, an increase of $34.9 million, or almost 17% over the first nine months of 2012. Our 2013 dividend includes two increases, the first in March and then again in September. Our current quarterly dividend rate is $0.3825 per share.

Our adjusted debt-to-capital ratio was 52% at the end of September. Our calculation treats half of our hybrid securities as 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, so going forward, we do not expect to issue any additional shares.

As shown in the earnings package on our website, retail sales of electricity, excluding the mines, decreased by 2.9% in the first nine months of 2013 as compared to the first nine months of 2012. Our normalized sales were down by 8/10 of a percent. All normalized sales are adjusted for the effects of leap year and weather.

Looking at the individual customer segments, actual residential sales for the first nine months of the year were down 3.9% because of a return to normal summer weather. On a normalized basis, sales were down 2/10 of a percent.

Across our small commercial and industrial group, sales for the first nine months were down 1.1%. On a normalized basis, sales to small commercial and industrial customers were down 6/10 of a percent. And on a normalized basis, sales for the first nine months of 2013 in the large commercial industrial segment, again excluding the iron ore mines, were down 1.8%.

On the natural gas distribution side of the business, total volumes during the first nine months of the year, excluding the volumes used in power generation, increased by 20.9%, primarily due to colder winter weather. On a normalized basis, gas volumes for the first nine months of the year rose by 2% as compared to 2012. This growth is the result of 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.

Finally, as we look ahead to the fourth quarter, we are tightening our annual earnings guidance. Our prior guidance was $2.41 to $2.48 a share. Our new guidance is $2.43 to $2.48 a share. Again, our new guidance for 2013 is $2.43 to $2.48 a share. This reflects our strong performance through the first nine months of the year, assumes normal weather, takes into consideration the effects of the Michigan Choice Law and recognizes the grant income associated with the biomass plant.

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

Pat, thank you very much. Overall, we are on track and focused on delivering value for our customers and our stockholders.

(Operator Instructions). Julien Doumoulin-Smith, UBS.

Hi, Julien, how are you?

Hey, good afternoon. Not too bad, thank you.

Good.

So first question here, just with regards to the Wolverine and Presque Isle and all that, what are you guys trying to get out there? I mean, does this ultimately shut down or is this a sale or something in between?

Well, we will ask Allen to give you some detail, but let me just kind of frame this for you again, because you are asking an important question.

A year ago, we truly believed looking at our demand projections and looking at the demand in the Upper Peninsula that we had a need for a portion -- at least a portion of the Presque Isle five-unit facility. However, that plant is going to need environmental upgrades.

And Allen and his folks worked very hard with Wolverine Power Cooperative to put together what I thought was a very elegant solution, which was Wolverine would fund completely the cost of the environmental upgrades in return for a pro rata ownership of the plant, roughly a third. That really, we thought, fit both Wolverine's need and our need going forward.

But now with the loss of the mines, we simply don't have retail customers to support basically our continued cost of the plant.

So we are looking at each one of the paths. We obviously in the interim are being told we have to run the plant, and now we are eligible for the system support resource payments from MISO. But in the longer-term, really we are looking at all the alternatives, and Allen can give you some detail.

And I would say probably long-term, Julien, and I think from a practical standpoint, there are probably only two likely paths. One path is -- I will call it some renegotiated version of the joint venture agreement. So perhaps instead of having five units at the plant, maybe only have three units. So perhaps you downsize it, perhaps Wolverine maybe and some other entities own the smaller plant. So I mean, that is one potential path.

I would say the other potential path is there is just a dissolution basically of the joint venture agreement we have now. We run the units -- as Gale mentioned, we run the units as long as they are required by MISO and MISO is making those SSR payments. And then once the units are no longer needed, well, they would be retired.

So I think from a practical standpoint, those are really the only two paths. It is hard for me to imagine a path where the joint venture agreement as currently structured that we can continue with that, because as Gale mentioned, we have had such a change in our demand as a Company. So hopefully, that helps some.

Absolutely. Just curious, if you don't mind following up -- on what does this mean for customer rates at the end of the day in the UP?

Well, we can both take a shot at that. I mean, in terms of customer rates in the UP, I mean, backing up, if the plant is going to continue to operate for the longer-term, someone has to cover the cost of the operation. And our view would be that -- I mean, customer rates in the UP probably would continue to go up some, because either way, customer rates in Michigan would have to support -- if the plant were to run for the long-term, customer rates would have to support the environmental upgrades and the ongoing production costs and fixed production costs of the plant.

I think everybody is aware of that. There is a lot of discussion going on. Clearly, the governor's office would very much like in Michigan the plant to stay open. They really believe there is future economic growth there, particularly in terms of the mining industry. So lots of discussions going on right now, and I would guess that the picture would become much clearer certainly over the course of the next few months.

Got you. And then maybe following up on some comments from some of your peers today, just trying to get a sense longer-term how do you see your earnings growth rate trending here? I mean, just given the sort of availability of investment opportunities, I'm curious, as you balance ATC and others, are we seeing a consistent trend here or is there some slowing in your future? Just to throw it out there.

Well, we are in the process now, Julien, of completing our next rolling five-year capital spending plan. But from everything I am seeing, we have said, as you know, that our medium-term growth looks like 4% to 6% off our 2011 base. And right now, I would say that that stands in terms of as good a projection as we can divine by looking into the future.

And remember, we have -- as I mentioned in the prepared remarks, we have a significant amount of investment that needs to be made in our delivery networks, in upgrading our aging infrastructure. So about two thirds of the capital spending that we have identified for 2013 through 2017 is really being devoted to upgrading the reliability of our distribution networks. And that is work that needs to continue.

So I would say the best range we can give you at the moment is 4% to 6% EPS growth.

Very good to hear. Well, thanks again.

You are more than welcome. Thank you.

Kit Konolige, BGC Financial.

Good afternoon.

Kit, have you been on the Obamacare website?

No, I have enough trouble with just my regular website. I may -- if I get on it, I may be responsible for keeping it down a lot longer than anybody thinks.

We're just checking. We want to make sure (multiple speakers) --

Yes, yes, don't worry about that. That's for sure. Not looking for trouble.

Let me, Gale, just follow up on your discussion just now regarding earnings growth. So in order to get earnings growth with -- well, let me ask this. What kind of sales growth do you see feeding into that earnings growth over the next whatever it is -- three to five years?

Well, Kit, as you know, we have been, I think, appropriately conservative in our sales growth projections. I believe when we all were together last year at the EEI conference in November, I think we were the only major company projecting literally no growth in kilowatt hour sales for 2013. As it is turning out, that projection was pretty much on target.

You were the only ones right.

Yes, sometimes we get lucky. But long story short, as we are putting our rolling five-year plan together and updating it, I think you're going to see sales growth projections on the electric side in the 3/10 to 5/10 of a percent growth range. That is currently what we are focusing on.

And we are now completing, as we do every year, interviews with our 120 largest industrial customers to get their input on the demand that they see over the next year. So we will refine all of that. But I think right now, you can expect in our new five-year plan to see about a 3/10 to 1/2 a percent annual weather-normal increase in electric sales.

So that relatively low level of load growth would suggest that you will need some -- and a relatively high level of capital spending would imply that you would need some significant rate relief over that period.

Well, certainly some rate relief, but more in the lines of historic inflation over time. And let me explain why. Yes, the sales growth projections are moderate to low, I think appropriate, but moderate to low. But we are also making significant amount of investments on the capital you referred to that will help us take out operation and maintenance costs.

And we mentioned a couple of them in the prepared remarks. For example, our proposal to convert our Valley power plant from coal to natural gas. We expect that will take out roughly $20 million a year in operating costs.

The concept of fuel flexibility that we are testing out at our new Oak Creek units, that $25 million to $50 million of fuel cost savings. Pat -- our IT group also reports up through Pat, and we have a whole list of very significant IT capital projects designed to take out operation and maintenance costs and make our processes more efficient.

So we think we can modify and reduce what otherwise would be a larger rate increase request, simply by wisely spending capital that makes us more efficient and takes out O&M. And I think that will be another lever that you will see us employ over the course of the next five to seven years.

Great. And then separate area. On the ATC and the Duke joint ventures, is the Duke JV in particular -- what do you realistically see as the likelihood of some of those $4 billion in proposed projects coming to fruition?

Let me say first -- I am going to ask Allen, because he sits on the board of ATC, to give you a specific answer. But to frame that answer for you, Kit, we have always been, as you know, reasonably conservative in terms of what we put into our financial model. We are not going to overpromise and under-deliver. And so we have been quite conservative in terms of taking the ATC plan and shaping it to what we think is a conservative estimate of what may happen.

And many of those projects, as you know, just because of the nature of large transmission projects, are back-end loaded in the financial model. Allen?

Yes, and Kit, maybe just picking up on that, Gale certainly in the script addressed the first five years. What I mean by that is the impact of the revised ATC outlook on the first five years of our financial projections. And as he said, really no impact on that first five years.

So let me maybe address kind of the period beyond the first five years. When we develop longer-term projections, and we look at the outlook from ATC for inside the footprint, we really use what I would call a midrange case. I mean, we don't take the most conservative nor do we take the highest case. We try to take kind of a midrange case for inside the footprint.

However, outside the footprint, we use a low-range case, meaning a much more conservative outlook on what ATC might be able to invest.

So as we look at it, if ATC can do better than that low-range case outside the footprint, and it is already, reasonably speaking, a low bar, we would be optimistic that on a net basis we could be right back to kind of the 10-year outlook that they had before, and possibly even have a little upside above that. And certainly with the outlook, it would still be supportive of the 4% to 6% EPS growth target that Gale mentioned earlier to Julien's question.

So hopefully, that helps a little bit, Kit.

Yes, absolutely. Much appreciated. Thank you.

Brian Russo, Ladenburg Thalmann.

Hi, Brian, how are you today?

Good. Just curious, do you have a depreciated book value for the Presque Isle plant?

Yes, right at about $219 million.

Okay. And what were the primary drivers of the lower revised CapEx at ATC? What was driving that?

Allen?

Yes, and then I would sort of put it in two or possibly three categories. Far and away the biggest driver, ATC had put forward a plan for addressing transmission issues in the Upper Peninsula of Michigan. And in the new plan, the size of those investments is less than in the old plan. So that is kind of the first area, if you will, that was causing a difference.

The second thing that was causing a difference, as I am sure you are aware, the Kewaunee Nuclear Plant here in Wisconsin is now shut down. So it is shut down. There were going to be some transmission improvements that would've been required if it had continued to operate. Those are no longer going to be required, or at least the level that are going to be required are now much less, because the Kewaunee Plant is not going to operate over the long-term.

And then finally, there were two 345-kV projects, one that's sort of more of an east-west line that went from Wisconsin over to Minnesota; another line more north-south that went from Wisconsin down into Iowa. In the previous outlook, ATC had projected that they would be able to invest the capital for the entire length of both of those lines. And as it turned out, they were only able to invest roughly half of the investment required in each of the lines. So Xcel will get half of that east-west line that I mentioned, and ITC will get half of that north-south line that I mentioned.

But at a high level, those are the three major drivers, if you will, of the change in their outlook.

Okay. And my last question. I am just curious -- you reported $0.60, and that was above the quarterly guidance of $0.52 to $0.56 you conveyed in August. So I was just curious what enabled you to beat your budget.

What allowed us to beat the budget?

Yes.

Well, I think a couple of things. First of all, really good, solid operation and maintenance cost control from our folks.

And then on a weather-normal basis -- and we were projecting weather-normal -- but we did a little bit better, I believe, particularly in September on energy sales than we had projected.

Okay, great. Thank you very much.

You are welcome.

Andy Bischof, Morningstar.

Hi, good afternoon.

Hi, Andy.

A real quick question for you guys this afternoon. In Michigan, you mentioned you would be eligible for system support payments in February. When would you expect to know the details of that support?

Well, I would hope we will know the details of that support by the end of the year, certainly by early January. Because the process that MISO goes through -- and first of all, now that they have determined that we are eligible for the payments, the next step is we and they sit down with a detailed analysis of the operating costs, of the potential capital costs over the course of the next few years, and then we and they agree on a level of payment.

That whole agreement then is subject to approval by the Federal Energy Regulatory Commission. And once submitted, Allen, I believe the FERC has 60 days to respond.

That is right.

So we would hope to have all those discussions wrapped up with MISO by the end of the year and a filing to FERC very early in the new year.

Thank you. I look forward to seeing you all at EEI.

Thank you. We will look forward to seeing you in Florida.

Paul Ridzon, KeyBanc Capital Markets.

Hot in Cleveland, Paul.

Oh, yes. So with Dan Jenkins no longer joining us, is Kit kind of filling his shoes?

Well, I haven't given up on Dan. I understand he is going to be in Florida, so we will have a little chat with him then. He still may be over at Freakfest, which I think is starting in about an hour in Madison.

I think it started a few years ago.

(Laughter) Well, you never know.

What can we do for you, Paul?

Your former coworkers went into extra innings, so I missed if you gave them the potential capital opportunities at Oak Valley and Valley -- Oak Creek and Valley.

We talked about fuel flexibility at Oak Creek. At Valley, we did talk about the potential capital opportunity, $65 million to $70 million. We are in the approval process right now with the Wisconsin Commission. That process is moving along as expected.

And then in addition, if you remember, we said to convert Valley from coal to natural gas is a $65 million to $70 million capital investment. But in addition to that, we need to complete an upgrade of the natural gas pipeline that runs near the facility. That work has been approved and is actually underway, began in March, and our expected total cost of that would be about $26 million in addition to the $65 million to $70 million related to the Valley conversion.

So Oak Creek is really just materials handling, not so much capital?

Well, it could be capital, Paul. And we really need to get through the testing phase with burning the blends of sub-bituminous and bituminous coal. And depending on the results of that, you could get, reasonably speaking, a wide range of potential capital investment opportunities.

I mean, if you had to do -- if you are able to do what the engineers call in-furnace blending, that might be something on the order of $20 million to $25 million of capital. If you are not able to do that reliably, you might have to do -- you might have to actually have a blending facility, and that could be upwards of $100 million.

But we are just really not going to know where we are on that continuum of solutions until we've finished the testing.

And we did say that we would -- assuming the testing continues to give us positive results, that we would file for construction authority with the Wisconsin Commission late 2014 or early 2015.

Correct.

And then how would SSR payments compare to the return you are currently earning -- or not earning?

That is a good question. We really need to work through all of this with MISO, but let me just kind of break this into a couple of categories for you.

If you think about the costs we incur to operate the plant, well, they are fuel costs. Well, those fuel costs are by and large recovered through the hourly energy market. So the fuel costs, we should be getting full recovery for.

There is what we call variable O&M, the additional cost for producing the incremental kilowatt hour. The variable O&M also should be recovered through the hourly energy market.

Then we have fixed production costs, so the fixed cost of operating the facility -- the staffing, the normal O&M, the maintenance, et cetera, et cetera. And our guesstimate there is -- not only guesstimate -- but that is part of what SSR payments are supposed to cover.

So to put it all into perspective, if nothing -- if we did nothing, the margin hit pre-tax would be -- Allen -- $50 million to $54 million?

Right.

However, in our discussions with MISO, we are in a range now of $35 million to $82 million, depending upon how much of the capital that we might spend over the next several years to keep the unit reliable, how much of that capital MISO is willing to cover.

But I think by definition, the MISO SSR payments are designed to, at a minimum, compensate you for the fixed production costs.

Did Michigan energy legislation contemplate what would happen in the event of a stranded asset?

Well, I think originally it did. However, if you recall, the 2008 amendment to the Michigan Choice Law, many believe that stranded costs were not recoverable after the amendment to that law. And I believe that basically the law said that anyone who is getting -- any utility getting stranded costs, that the Commission had to make sure those stranded costs were recovered and completely recovered through billing by October of this year. I think the position of the Michigan Commission is that under that law, future stranded costs are not recoverable.

Better start sending out some pretty big bills before tomorrow.

And then just lastly, any forward look on the impact of discount rates on your pension?

Well, I will ask Pat to give you a more specific answer. But right now, I mean, going into this year and through where we stand today, we are virtually fully funded on our pension plan. We have not made any cash contribution to the pension plan this year; it simply hasn't been needed.

I think -- we're, I think, one of the few companies in our industry that is in really very good shape related to pension funding and funding up our obligations under the plan. Pat?

Yes, Gale, I am not sure I have too much more to add to that. We are certainly running the models with our actuaries. And we are, as Gale mentioned, about 100% funded now. Given where we are in returns, where we anticipate the discount rate will end up, we are going to end up about 100% funded by the end of the year is our -- more or less, without having any material contribution.

So you could be in a position to have pension earnings next year?

I don't think we are really projecting any pension earnings next year.

Thank you.

All right. You are welcome.

Michael Lapides, Goldman Sachs.

Michael, how are you doing?

I am all right, Gale.

Have you had any more of them blue martinis?

I have not had a blue -- that is a darn good idea. And after five or six earnings calls today, that is exactly what I could use right now.

All right.

Easy question for you. Next year is a rate case year.

Yes.

How are you thinking about relative to maybe some of your prior rate cases how material this one is for Wisconsin Energy, how material this one is for your rate payers, what are going to be some of the more important issues that when you file this in the spring investors should monitor?

Well, very good question, Michael. Let me talk with you about kind of maybe three elements. And first of all, we are -- I mean, I believe, and if our projections continue to hold, I think we will have some good news on fuel. So we should be able to -- I mean, as I mentioned in our script, this would not be for 2015, but for 2014, we filed for approval to reduce our fuel recovery rate by $30 million. And if fuel prices stay low, we should get -- we should be neutral to maybe positive, I hope, in terms of fuel cost recovery. So that should be helpful on the rate case front for 2015 and beyond.

The second piece clearly will be we need to recover capital projects that have basically already been approved. Remember, we talk about the capital investments we are making in Deliver the Future. The basic upgrades that we are making to our distribution networks. That capital that we've spent with blessing from the Commission and the prior rate case will need to be recovered in rates starting in 2015. So that will be one of the big drivers.

So I think fuel will be a help. One of the big drivers will clearly be the Deliver the Future capital. And then there will be a couple of other factors that will swing one way or another. But we are hoping that this will be a moderate rate case, and we don't see any sticker shock coming down the road here.

Meaning you see something that is in the low- to mid-single-digit increase level, and not a dramatically bigger number than that?

That is certainly our goal and that is what we believe we will be filing for, yes.

Got it. Okay, last item. Presque Isle, I want to make sure I follow this correctly. If it is $219 million in book, and if it were still included in rate base, kind of -- I am going to do back-of-the envelope math -- 50-50 Capital structure, 10% ROE -- you are talking $10 million to $15 million -- $10 million to $12 million of authorized net income in book.

Is there any scenario where the MISO payments actually give you a greater bottom line contribution than what you would get under just traditional regulatory ratemaking?

Michael, the MISO payments are not designed to give you any kind of a greater return. I would point out that I think it is just important to keep in the back of your mind, the book value of the Presque Isle plant is still included in rate base.

Got it. So in other words, any SSR from the MISO is basically serving as a substitute for what regulated rates otherwise would have already included, had you not made the decision -- had your retirement decision -- or had you retired the unit?

Well, not exactly. But I would look at it this way. Instead of the mines, the SSR payments from MISO -- in essence, instead of the mines being a customer, MISO is being a customer, but MISO is not necessarily going to pay you the return. MISO will keep you whole on the operating costs and perhaps some capital.

Got it. Okay, thank you, Gale. Much appreciate it.

You're welcome.

Jon Arnold, Deutsche Bank.

Jonathan.

Good afternoon, Gale.

Good afternoon. How are you doing?

Good, thank you.

Are you coming to Florida, Jonathan?

Oh yes. We are looking forward to seeing you there.

Sounds good. We will be over at the It's a Small World After All exhibit.

So quickly on the buyback, did I hear you right, that you have done $255-odd million?

Yes, $254.8 million, to put a fine point on it.

Okay. So if you do more or less the same in the fourth quarter that you did in the third, you will basically consume the $300 million through end of 2013. What is the timeframe for potentially re-upping that?

Well, we have our normal meeting with our Board of Directors in December, where we go through our five-year plan, our five-year capital spending plan, our five-year projections on kilowatt hour sales growth, our five-year projections on our capital structure. And it will be at that time, as we walk them through and get approval for our five-year plan, it will be at that time when we will ask them for any changes, if any are warranted, in the share buyback authorization.

Okay. So if you were to tell -- that would be a sort of fourth-quarter earnings timing, if there was a change.

That is correct.

Thank you very much.

You are welcome. Take care.

Paul Patterson, Glenrock Associates.

Good afternoon, Paul.

Hey, how are you doing?

Great. How about you?

I'm managing. I just wanted to touch base on a few quick things.

One was Kit was asking about sales growth, and I think you guys mentioned that you guys saw 2013 as being flat. And to date, it has been about negative 0.8%, or close to negative 1%.

Yes, negative 0.8%.

0.8%. Do you guys see a big increase? Is there some timing issue or something that is going to happen in the fourth quarter to bring it up, or could you just elaborate a little bit on that?

No, we are actually running a little bit lower than our projections on the electric sales side of the business. Now, I will say, last fourth quarter, meaning the fourth quarter of 2012, the weather was mild. So on a weather-normal basis, you might see some small bit of an uptick on the electric side.

On the other side of the ledger, though, we are seeing a little stronger natural gas sales -- and I mentioned this in the prepared remarks -- than we had anticipated. If you just look at actuals, we are up almost 20% in terms of natural gas deliveries over the first nine months of a year ago, but we had a cold winter in the first quarter, kind of going on into April and May. So on a weather-normal basis, we are up about 2%, and we had not projected that kind of growth on the natural gas side.

So there have been some compensating -- there have been some compensating offsets here.

Okay. But on the electric side, it might be a little bit down, I guess, for 2013 versus last year? (multiple speakers).

On a weather-normal basis, I would expect a little bit down for the calendar year. You are correct.

Okay. And then for the 3% to 5% that you mentioned, that was for several years out, is that correct?

0.3% to 0.5%.

That is what I meant. Sorry. Boy, that would be a big difference, wouldn't it?

Allen just had a heart attack.

What is the period of time we are talking about over -- sorry if I missed that. How much -- what is that -- how many years is that over?

That would be a rolling five years, so 2014 to 2018.

Okay. And then in terms of the rate case year and the impact on customers, you mentioned that there was a fuel decrease. And is that what was -- is that fuel decrease factored into what you expect to be that sort of mid-single-digit that I think you guys were discussing?

No, and I apologize if I confused someone. The fuel decrease, the $30 million fuel decrease, we have just filed for that, and would expect the Commission to approve a fuel decrease in 2014.

And what I was really saying is if fuel prices stay low and delivered cost of coal stays low and goes down a hair, we might get some help for that -- we might get some help from that in our 2015 -- in our filing for 2015 rates.

Okay. And then just back to electric sales growth and what you are seeing there. What kind of GDP forecast are you guys looking at for those five years, when you are coming up with that sort of 0.3% to 0.5%?

I am looking at Scott Lauber, our Treasurer, here. The way we -- and Scott is going like, well, why are you looking at me?

What we do -- in essence, we kind of back into a GDP. We really do this bottoms up. We really look at customer segment by customer segment. We look at the growth in that segment or lack thereof. So we don't start with an overarching GDP forecast.

But if I had to guess, seeing what we have seen so far, where we are kind of honing in on a 0.3% to 0.5% annual kilowatt hour sales growth, if I had to guess, that would be -- and I am guessing -- about a1.5% to 2% GDP growth.

Okay. And then just finally, given the power price -- the wholesale power price situation in MISO, and given the transmission projects that we have seen being discussed and potentially may come about, with respect to cross-border PGM versus MISO can get congestion relief -- the seams issue, if you follow me.

Yes.

Do you guys see more opportunities to sell into higher-priced markets, given sort of the dynamics that you guys have there? I mean, I know it doesn't make a big bottom-line impact to you guys, but I do know that you are also sort of looking to provide relief to -- trying to help out customers as much as possible in terms of all system sales. I am just wondering -- any thoughts sort of directionally about that?

I will be happy to give you my thought. Allen, who is very familiar with these issues as well, I will be happy to have Allen pitch in his thoughts.

I don't think near-term -- certainly in the next 12 months, I wouldn't see any kind of major swing or major impact. However, if you look -- having said that -- and again, I should remind everyone -- energy sales into the MISO market, over and above what our customers need, the revenue above cost from those sales go back to -- as you pointed out, go back to reduce fuel costs for our customers.

So that margin, the difference between our revenue that we would get in the hourly energy market and our cost of producing that, that goes back to help customers.

Now, if you look at one of our line items on our statements, you will see a big increase so far in the first nine months of this year in our off-system sales. That is because already we are seeing our Oak Creek units, our brand-new Oak Creek units, dispatched more often by MISO because of their fundamental efficiency. And we have had great availability at our Oak Creek units, our new Oak Creek units this year.

So even without any change in the seams agreements, even without any additional congestion relief between MISO and PJM, we are starting to see the benefits for our customers of the higher off-system sales into the MISO market, given the fundamental efficiency of those Oak Creek units. Allen?

Yes, I guess the only thing I would add -- and maybe just picking up on the fundamental efficiency point that Gale was making. I mean, when you look at the collection of units that we have from a thermal efficiency standpoint, in the case of the new Oak Creek units, one of the most efficient units in the country. The last data set I saw, Paul, it was in the top 10 for steam units in the United States.

And if you certainly look within MISO at our other units and how competitive those are, we believe those are if not in the top decile, in the next to the top decile in terms of efficiency.

So I would say, particularly if you got a higher natural gas price environment, we would be very well-positioned to bring some margin back for our customers -- not for the owners, but certainly for our customers, and that would be a wonderful thing.

So, Paul, maybe we can get 5% energy sales growth after all.

Well, I mean, I just was wondering -- do you see any congestion relief between MISO and PJM, or is that just something that is too far in the future for you guys at all?

Or I mean, like you said, it isn't a bottom-line impact. I was just wondering since you guys are significant in the market. And we are also talking about wind increasing in MISO as well -- just sort of --

Right. Well, at this point, I don't see a lot of congestion relief between the two ISOs, between PJM and MISO. But we are seeing some diminution in the congestion sort of going south through our system, which I guess ultimately, you don't have to go too far south to get to PJM. So hopefully, we will see some --

Okay. I appreciate it, guys.

Good questions, Paul. Thank you very much.

Ladies and gentlemen, that concludes our conference call for today. Thank you again for participating. If you have any other questions, the famous Colleen Henderson will be available in our Investor Relations office, and her direct line is 414-221-2592.

Thank you very much, everybody.