Gale E. Klappa - Chairman, Chief Executive Officer, Chairman of Executive Committee, Chief Executive Officer of Wisconsin Electric Power Company, Chief Executive Officer of Wisconsin Gas LLC, President of Wisconsin Electric Power Company, President of Wisconsin Gas LLC, Chairman of Wisconsin Electric Power Company, Chairman of Wisconsin Gas LLC James Patrick Keyes - Chief Financial Officer and Executive Vice President Allen L. Leverett - President, Executive Vice President of Wisconsin Electric Power Company, Chief Executive Officer of We Generation Operations and President of We Generation Operations

Julien Dumoulin-Smith - UBS Investment Bank, Research Division Kit Konolige - BGC Partners, Inc., Research Division Brian J. Russo - Ladenburg Thalmann & Co. Inc., 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 Jonathan P. Arnold - Deutsche Bank AG, Research Division Paul Patterson - Glenrock Associates LLC

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. [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 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 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 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 3 quarters of 2013, our earnings came in at $1.88 a share, compared to $1.92 a share for the first 9 months a year ago. You'll recall that our year-to-date results this year reflect a $0.09 a share reduction for our 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…

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's a decrease of $22.6 million. Starting with the utility energy segment. You'll 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've 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 9 months would have been $0.09 a share higher have we recorded the grant income to match the bill credits. Therefore, we expect to see a $0.09 pick up 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…

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

[Operator Instructions] Julien Dumoulin-Smith with UBS.

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, is this ultimately shut down or is this a sale or something in between?

Well, we'll ask Allen to give you some detail, but let me just kind of frame this for you again, because you're 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 the portion of the Presque Isle 5 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 1/3. 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're looking at each one of the paths. We obviously, in the interim, are being told we have to run the plant and now we're eligible for the system support resource payments from MISO. But in the longer-term, really, we're looking at all the alternatives and Allen can give you some detail.

Yes, and I would say probably long term, Julien, I think from a practical standpoint, there are probably only 2 likely paths. One path is I'll call it some renegotiated version of the joint venture agreement. So perhaps instead of having 5 units at the plant, maybe only have 3 units. So perhaps you downsize it, perhaps Wolverine maybe and some other entity own those -- the smaller plant. So, I mean that's one potential path. I would say the other potential path is, there's just the dissolution basically of the joint venture agreement we have now. We run the unit. 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'd be retired. So I think from a practical standpoint, that those are really the only 2 paths. It's 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've had such a change in our demand as a company. So hopefully that helps some.

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

Well, we can both take a shot at that. In terms of the customer rates and 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, our customers 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 everyone is aware of that. There's a lot of discussion going on. Clear, the governor's office would very much like, in Michigan, the plant to stay open. They really believe there is future economic growth there and 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 their future, just to throw it out there.

Well, we're in the process now, Julien, of completing our next rolling 5-year capital spending plan. But from everything I'm seeing, I mean 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 2/3 of the capital spending that we've 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 can give you at the moment is 4% to 6% EPS growth.

Kit Konolige with BGC Financial please state your question.

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, 3 to 5 years?

Well, Kit, as you know, we've been, I think, appropriately conservative in our sales growth projections. I believe, when we are all 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. I mean, as it's 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're putting our rolling 5-year plan together and updating it, I think you're going to see sales growth projections on the electric side in the 0.3% to 0.5% growth range. That's currently what we're focusing on and we're 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'll refine all of that, but I think right now, you can expect in our new 5-year plan, to see about 0.3% to 0.5% annual weather normal increase in electric sales.

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

Well, certainly some rate release, but I think 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're 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're 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 would be another lever that you will see us employ over the course of the next 5 to 7 years.

All right. Great. And then a 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'm 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're not going overpromise and underdeliver. And so we've 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, I mean, maybe just picking up on that. Gale, certainly in the script, addressed the first 5 years. What I mean by that is the impact of the revised ATC outlook on the first 5 years of our financial projections, and as he said, really no impact on that first 5 years. So let me maybe address kind of the period beyond the first 5 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 sort of 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, if ATC can do better than that low-range case outside the footprint, it's already, reasonably speaking, a low bar, we'd 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.

Brian Russo with Ladenburg Thalmann. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Just curious, do you have a depreciated book value for the Presque Isle Plant?

Yes. Right at about $219 million. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: 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 2 or possibly 3 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's kind of the first area, if you will, that was causing a difference. The second thing that was causing a difference, as I'm sure you're aware, the Kewaunee Nuclear Plant here in Wisconsin is now shut down. So it's shut down. They 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 of the Kewaunee Plant is not going to operate over the long-term. And then finally, there were 2 345 kV projects. One, that's sort of a -- 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're 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 3 major drivers, if you will, of the change in their outlook. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. My last question, I'm 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? Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: 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 weather normal basis, we were projecting weather normal but we did a little bit better, I believe, particularly in September on energy sales than we had projected.

Andy Bischof with Morningstar, please state your question.

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

Well, I would hope we'll 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've 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's 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.

Paul Ridzon with KeyBanc Capital Markets, please state your question.

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're 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, $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 material handling, not so much capital?

Well, it could be capital, Paul. And we really need to get through the testing phase with the 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're 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're 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're just not really going to know where we are on that continuum of solutions until we finished the testing.

And we did say that we would -- assuming the testing continues to give us positive results, that we would file a -- for construction authority with the Wisconsin Commission late '14 or early '15.

Correct.

And then how would SSR payments compare to the return you're currently earning? Or not earning?

That's a good question. Well, 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 cost we incurred to operate the plant, well, there are fuel costs. Well, those fuel costs are, by and large, recovered through the hourly energy market. So the fuel cost we should be getting full recovery for. There's what we call variable O&M, the additional costs reproducing 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's 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 pretax would be, Allen, $50 million to $54 million?

Right.

However, in our discussions with MISO, we're in the 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.

Does -- did Michigan energy legislation contemplate what would happen if [indiscernible] 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. Right? The position of the Michigan commission is that under that law, future stranded costs are not recoverable.

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

Well, I'll 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, 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'm not sure I have too much more to add to that. We're certainly running the miles 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're 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 at a position to have pension earnings next year?

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

Michael Lapides with Goldman Sachs, please state your question.

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

Yes.

How are you thinking about relative to maybe some of you priority rate cases? How material this one is for Wisconsin Energy? How much material this one is for your ratepayers? 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 3 elements. I mean, first of all, where I believe, and if our projections continue to hold, I think we'll 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 recoveries. So that should be helpful on the rate case front for 2015 and beyond. The second piece clearly will be, we need to recover projects, capital projects that have basically already been approved. Remember, we talked about the capital investments we're making in deliver the future. The basic upgrades that we're making to our distribution networks, that capital that we spent, with blessing from the commission in 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 be -- will clearly be the deliver the future capital. And then there'd be a couple of other factors that will swing one way or another but we're 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's in the low- to mid-single-digit-increase level and not a dramatically bigger number than that?

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

Got it. Last item, Presque Isle, I want to make sure I follow this correctly. If it's $219 million in book and if it were still included in rate base kind of -- I'm going to do back-of-the-envelope math, 50/50 GAAP structure, 10% ROE, you're 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 rate, regulatory rate making?

Michael, they're not -- the MISO payments are not designed to give you any kind of a greater return. I would point out that I think it's just important 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 rate, any SSR from the MISO is basically serving as a substitute for what regulated rates otherwise would've already included had you not made the decision -- had your retirement decision kind of -- 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 cost and, perhaps, some capital.

Jon Arnold with Deutsche Bank, please state your question.

So quickly on the buyback. Did I hear you right that you've 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 the end of 2013. What's the time frame for potentially re-upping that?

Well, we have our normal meeting with our Board of Directors in December where we go through our 5-year plan, our 5-year capital spending plan, our 5-year projections on kilowatt hour sales growth, our 5-year projections on our capital structure. And it will be at that time, as we walk them through and get approval for our 5-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.

Paul Patterson with Glenrock Associates, please state your question.

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's been about negative 0.8% or close to negative 1%. What...

Yes, negative 0.8%.

0.8%. Do you guys see a big increase this -- is there some timing issue? What's going to end up going to happen in the fourth quarter to bring it up? Or could you just elaborate a little bit on that?

No. We're 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 bit of a 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're up almost 20% in terms of natural gas deliveries over the first 9 months of the 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're up about 2% and we had not projected that kind of growth on the natural gas side. So 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?

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

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's what I meant. Sorry. Boy, that would be a big difference, wouldn't it? What's the period of time we're talking about over -- sorry, if I missed. What's that over that -- how many years is that over?

That would a rolling 5 years, so '14 to '18.

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 apologized 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 that 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 in our filing for 2015 rates.

Okay. And then just back to electric sales growth and what you're seeing there. What kind of GDP forecast are you guys looking at for those 5 years when you're coming up with that sort of 0.3% to 0.5%?

I'm looking at Scott Lauber, our Treasurer, here. But the way we -- what we do in essence, we kind of back in to 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've seen so far, we're kind honing in on a 0.3% to 0.5% annual kilowatt hour sales growth. If I had to guess, that would be, and I'm guessing, about 1.5%, 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've seen being discussed and potentially may come about with respect to cross-border PJM versus MISO, 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're also sort of looking to provide relief to try to help out customers as much as possible in terms of off-systems sales. Just wondering any thoughts sort of directionally about that or...

Well, I will be happy to give you my thought. Allen, who is very familiar with these issues as well, I'd be happy to have Allen pitching 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 for our -- 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 reduced 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 to producing that, that goes back to help customers. Now if you look at one of our line items on our statements, you'll see a big increase so far in the first 9 months of this year in our off-system sales. That's because, already, we're seeing our Oak Creek units, our brand-new Oak Creek units, dispatched more often by MISO because of their fundamental efficiency. And we've 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're starting to see the benefits for our customers of the higher off-systems sales into the MISO market point given the fundamental efficiency of those Oak Creek units. Allen?

Yes. I guess, the only thing I would add, and maybe just picking 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 will 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's too far into the future for you guys at all. I mean, it's like you said, it isn't a bottom line impact. I was just wondering since you guys are significant in the market, and we're also talking about wind increasing in MISO as well, just sort of...

Yes.

Right. Well, at this point, I don't see a lot of congestion relief between the 2 ISOs, between PJM and MISO. But what 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'll will see some.

Well, 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.