威斯康辛能源 (WEC) 2012 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 2012 third-quarter results. This conference call is being recorded for rebroadcast. 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 discussion, referenced earnings per share will be based on diluted earnings per share unless otherwise noted.

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

Colleen, thank you very much. Good afternoon everyone. Thank you for joining us as we review the Company's 2012 third-quarter results. For all of you dialing in from the East Coast, we hope that you and your family are safe and coping well with the aftermath of Hurricane Sandy.

Let me begin as always by introducing the members of the Wisconsin Energy Management team who are here with me today. We have Allen Leverett, President and Chief Executive of WE Generation; Pat Keyes, our Chief Financial Officer; Susan Martin, General Counsel; Steve Dickson, Controller; and Scott Lauber, our Assistant Treasurer. Pat will review our financial results in detail in just a moment, but as you saw from our news release this morning we reported earnings from continuing operations of $0.67 a share for the third quarter of 2012. This compares with earnings from continuing operations of $0.55 a share for the third quarter of 2011.

The weather of course has been a major story throughout this year. We began 2012 with the warmest winter in 122 years. That was followed by an old fashioned heat wave this summer. The hottest day in Milwaukee this year was on July 5 when the temperature reached 103 degrees. I'm pleased to report to you that our generating fleet performed very well. We were able to meet the strong customer demand for energy thanks to the $3 billion we've invested over the past decade in new efficient generating units through our Power the Future plan.

Turning now to the economy, Wisconsin's unemployment rate at 7.3% as of September remains well below the national average. However, energy sales to our large commercial and industrial customers excluding the iron ore mines dropped by 1.8% in the third quarter of this year. This was slightly better, though, than our expectations. Our plan for the year as you may remember projected a reduction in sales to our large commercial and industrial group, in part because two customers began using their own self generation. Excluding these two customers and the iron ore mines, large commercial and industrial sales actually rose by 0.6%.

Sectors showing particular strength in the quarter included food products, chemical manufacturing, and metal fabrication. We're also seeing an uptick now in new customer connections. New electric service installations are up 9.8% compared to the first nine months of last year, and connections of new natural gas customers, given today's price of natural gas, are up by more than 14% compared to the same period a year ago.

On the construction front, we have one major project under way, the 50-megawatt biomass plant in Northern Wisconsin, and one significant project that was recently completed, the air quality control upgrade at our original Oak Creek units. In fact, on September 4 we closed out this $900 million air quality project, the second largest construction project in our history, on time and better than budget. The wet scrubbers and the selective catalytic reduction equipment are operational now and delivering the emission reductions that we had expected. We're completing punch list items and final tuning and testing as well as demolition of the old chimneys at the site. Demolition of the chimneys and a few remaining project items are expected to be completed in the third quarter of next year.

We're also making excellent progress on our biomass fuel generating plant at the site of the Domtar paper mill in Rothschild. Construction is approximately 50% complete now. We're on schedule and on budget to meet a completion date by the end of 2013. The main boiler erection will continue into the first quarter of next year at the site. The steam turbine and generator have been delivered and placed on their foundations. Piping and electrical work have begun in several areas of the complex including the main boiler, turbine, water treatment, cooling water, pump house, and auxiliary boilers. The transformers, switches and bus bar have also been set in the switch yard and construction of the piping for the mill's steam supply is now under way.

As I've noted before, the biomass plant will help us diversify our portfolio of renewable energy. We'll be able to dispatch the unit and the efficient technology that will produce electricity for the grid and the steam for the operating paper mill will clearly enhance the economics of the project. Our investment in the biomass plant is expected to total between $245 million and $255 million, excluding allowance for funds used during construction.

Of course, the biomass project and the Glacier Hills Wind Park that we completed last year are key components that will help us meet Wisconsin's renewable portfolio standard for the year 2015. To refresh your memory, that standard calls for an increase in the amount of electricity delivered from renewable sources from 5% in 2010 to 10% in 2015 at a state-wide level. The standard sets targets for each Wisconsin utility using an historical baseline. Applying that baseline approximately 8.25% of our retail electricity sales must come from renewable sources in 2015. When we complete the biomass project we'll be well positioned to meet that 2015 standard. Also, we recently signed agreements for renewable energy credits which should allow us to be in compliance through the year 2019. And because of favorable market conditions, we plan to purchase more renewable credits, further extending the time frame that we expect to be in compliance.

Turning now to other items of interest. In past quarters we've discussed with you the impact we were seeing from conditions in the coal and natural gas markets. Natural gas prices have continued to be at relatively low levels, influencing the dispatch order and locational marginal pricing in the Midwest power market. Over the years of course, the key to serving customers at a competitive price has been fuel diversity, and fuel diversity was a core principle of our Power the Future plan. You may remember that our plan called for the addition of 2,200 megawatts of new capacity, capacity that is almost equally balanced between natural gas and coal.

And now, with our efficient new capacity in place, and natural gas prices at low levels, our natural gas burn is expected to nearly double from 28.5 billion cubic feet last year, to 50 billion cubic feet this year. In fact, our natural gas units at Port Washington operated at a 56% capacity factor in the first three quarters of this year. This compares with a 23% capacity factor during the same period of 2011. Our Port Washington units are essentially now being dispatched as base load units.

Of course, as our natural gas burns have gone up, our coal burns have naturally come down. We're projecting to burn approximately 8.1 million tons of coal this year, versus 10.7 million tons in 2011. We'll achieve this reduction by maximizing the use of coal storage facilities and by working with our coal suppliers to amend existing contracts.

In another important development, we're awaiting approval of our filing for a revised air permit that would allow us to blend Western and Eastern coals at our new Oak Creek expansion units. The new units are currently permitted to burn Eastern bituminous coal. However, moving to a blend with Powder River Basin's sub-bituminous coal could substantially lower fuel costs for our customers. We expect to receive approval for our request for a revised air permit by year end. Our plan then calls for us to begin testing the blended coal at our Oak Creek expansion units during the year 2013. Overall, our diverse fleet and our long-term power purchase agreement for nuclear energy position us well as the power markets continue to evolve.

Now, I'll briefly review where we stand on the regulatory front in Wisconsin where we're in the final stages of our only active rate case. As you may recall, base rates for our electric customers in Wisconsin are frozen for 2012. We proposed and the Wisconsin Commission accepted a creative approach to delay a base rate increase as the economy here continues to recover. Looking forward to 2013 and 2014, we filed a rate request with the Wisconsin Commission seeking an increase for our electric and steam customers and a decrease for our natural gas customers for 2013. On the electric side of our business, the base rate adjustments we're seeking in the next two years are driven by approximately $1.6 billion of capital investment. These are investments in strengthening reliability, in meeting environmental requirements, and complying with Wisconsin's renewable energy mandate, and their investments that the Commission previously approved.

The projects previously approved by the Commission include the air quality control system for the older Oak Creek units, the Glacier Hills Wind Park, the biomass facility, and the expansion units at Oak Creek. Our proposal includes using a federal energy grant that we expect to receive for our biomass facility. After applying this cash grant, the result would be a net customer bill increase of 3.6% in 2013 and 2014. Fuel cost estimates for 2013 will continue to be refined based on updated information, of course. A final fuel cost recovery rate will also be part of the Commission's order that we expect to receive in December.

On the natural gas front, we proposed as I mentioned a decrease in base rates for 2013. We're seeking a 2.3% decrease for Wisconsin gas customers, and a 0.2% decrease for Wisconsin electric gas customers. Then for 2014, we're proposing the base rates for all of our natural gas customers remain flat. For our steam utility we filed for an increase in 2013 of approximately 6% for our downtown Milwaukee steam customers and 7% for our Milwaukee County steam customers. In 2014 our proposal calls for a 6% increase for downtown customers and for Milwaukee County customers as well.

You may remember that the Wisconsin Commission does not intend to pursue capital structure or return on equity as issues in this proceeding. We expect to receive the orders by the end of 2012. We've asked that new electric and steam rates go into effect at the start of 2013 and 2014, and that new gas rates be effective at the start of 2013 as well.

Switching gears now, you'll recall that our Board has approved a share repurchase plan scheduled to run through the end of 2013 that authorizes us to buy back $300 million of Wisconsin Energy common stock through open market purchases or privately negotiated transactions. During the third quarter of this year we repurchased approximately 400,000 shares at a cost of $14 million. As of September 30, this brings the total number of shares repurchased under the plan to approximately 3.6 million, at a cost of $114 million. That equates to an average purchase price of just $31.45 a share.

And as we've previously announced, our Board has adopted a dividend policy that targets a 60% payout ratio in 2014. This policy should support double-digit growth in the dividend in both 2013 and 2014, as we move toward a payout ratio that is more competitive with our peers across the regulated utility sector.

Finally, I'd like to briefly touch on the investment opportunities that we see in our core business. As we've mentioned, our capital budget calls for spending up to $3.5 billion over the five-year period 2012 through 2016. And with this five-year budget, the nature of our capital investments is shifting away from high-profile projects, such as our Power the Future units, renewable generation, and large air quality controls. Instead, our capital plan is comprised of many smaller projects that will upgrade our aging distribution infrastructure. The building blocks if you will of our delivery business, pipes, poles, wires, transformers, and substations.

The primary risks associated with these projects, developmental, legal, regulatory, construction, are naturally more manageable given the smaller scale and scope of the distribution work. But this work is no less valuable or important than the major mega projects we've just completed. Our focus on renewing our distribution facilities is essential to maintaining our status as the most reliable utility in the Midwest.

Also as you may recall, the future of the Presque Isle Power Plant in the upper peninsula of Michigan is under review because of expected changes in national ambient air quality standards. So we've been working to identify a life extension option for the Presque Isle Plant that is economically beneficial for our customers. We're close now to signing a joint venture agreement with Wolverine Power Cooperative for environmental upgrades at the Presque Isle units and potential joint ownership of the plant. Under this proposed agreement Wolverine would pay for the environmental upgrades and receive an ownership interest in the facility. Preliminary work has continued on this project. We've completed the second phase of engineering and a detailed scope of work has been developed. If the joint venture moves forward, we would not expect our rate base to be reduced. The transaction would of course be subject to customary regulatory approvals.

In August we also announced our plans to convert the fuel source for the Valley Power Plant from coal to natural gas. The Valley Plant is a cogeneration facility located along the Menomonee River in Milwaukee that generates electricity for the grid and produces steam to heat hundreds of downtown Milwaukee buildings. Our analysis shows that converting the fuel source for the plant will actually reduce our operating costs and enhance the environmental performance of the Valley units.

We plan to file an application with the Wisconsin Commission in the second quarter of 2013 for approval to modify the plant to use only natural gas in the future. The electric capacity of the plant is expected to remain at 280 megawatts. If approved, we'll target completion of the conversion for late 2015 or early 2016. The current cost estimate is between $60 million and $65 million. As you may remember, in addition, we will upgrade the existing natural gas pipeline that runs near the facility. The Wisconsin Commission approved this $26 million investment back in June. We really believe that the plan we put in place will secure Valley's role in meeting the energy needs of a vibrant downtown Milwaukee for many, many years to come.

Finally, there's one more development that I'd like to cover with you today. Our latest analysis shows that additional capacity is needed for our natural gas distribution network in the Western part of Wisconsin. We're beginning to evaluate routes to serve the communities between Eau Claire County in the far Western part of the state and the city of Tomah in Monroe County in West Central Wisconsin. This region will need additional capacity for three reasons. To address reliability, to meet growth in demand from customers who are converting from propane, and also, from the extensive growth we're seeing in sand mining in that part of the state.

The fine sand that's used in hydraulic fracking is found in abundance in Western Wisconsin, and mining and processing operations are thriving now in this region. We plan to seek approval from the Public Service Commission of Wisconsin in 2013 to proceed with the necessary system enhancements. Our expected investment in this initial phase of this gas distribution project is approximately $150 million.

Now with more details on our third quarter and our outlook for the remainder of 2012, is our Chief Financial Officer, Pat Keyes. Pat?

Thank you, Gale. As Gale mentioned earlier, our 2012 third-quarter earnings from continuing operations were $0.67 a share, as compared to $0.55 a share in 2011. The results were better than last year because of lower operation and maintenance costs, favorable fuel recoveries, and the positive impact of the Company's share repurchase program.

Taking a closer look at the numbers, I will focus on the earnings drivers at the operating income level by business segment, and then touch on the other income statement items. I will also discuss cash flows for the first nine months of the year. Our consolidated operating income in the third quarter of 2012 was $281 million, that's compared to $224 million in last year's third quarter, an increase of $57 million.

Starting with the Utility Energy segment, you will see that the operating income totaled $191 million, an increase of $55 million versus 2011. As Gale mentioned earlier, we experienced record heat in the third quarter of 2012. But we also experienced a hot third quarter in 2011. So the weather was a positive compared to normal but was not the major factor in our relatively strong third-quarter performance. I'll elaborate further on the impact of weather in my sales remarks.

When looking at our Utility operating income in the third quarter of 2012, as compared to the third quarter of 2011, we see positive variances because of lower O&M and more favorable fuel recoveries. Our nonfuel O&M was $53 million lower this quarter, primarily because of the one-year rate amortization holiday that began in January. Our fuel recoveries improved by $19 million because of lower natural gas prices. Partially offsetting these items was increased Utility depreciation expense of $11 million driven by the new Glacier Hills Wind Park, which went into service in December of last year, and the new air quality control project at our older Oak Creek units, the last train of which went into service in early September. Combined, these two projects represent almost $1.3 billion of new investment.

The rate agreement in place for 2012 contemplated these investments. As you'll recall, we agreed to freeze base electric rates and in return, the Wisconsin Commission approved a one-year holiday on the amortization of certain regulatory assets. The reduction in O&M expenses as resolved in the amortization holiday allows us to offset higher depreciation costs from new assets and earn a return on the $1.3 billion of new investment.

Operating income in the Nonutility energy segment which consists primarily of our Power the Future units was up by $2 million. As we mentioned during previous calls, we finalized the depreciable lives of the new Oak Creek units in 2012 which had a slight positive impact on earnings. Taking the changes for these two segments together, you arrive at the $57 million increase in operating income for the third quarter of 2012. Corporate charges and other miscellaneous items were flat year over year.

During the third quarter of 2012, earnings from our investment in the American Transmission Company increased just slightly over 2011. Our other income was reduced by $7 million because of lower AFUDC. In the third quarter last year, we were earning AFUDC on the Glacier Hills Wind Park and the air quality control project at our Oak Creek site. We have stopped accruing AFUDC now that these assets have been placed in service.

Net interest expense increased by $4 million primarily because of lower capitalized interest associated with less construction work. Consolidated income tax expense rose by approximately $21 million because of higher pretax earnings and a higher effective tax rate. Our effective tax rate for 2012 is expected to be between 35.5% and 36.5%. Combining all of these items brings you to $156 million of net income from continuing operations for the third quarter of 2012, or earnings of $0.67 per share.

During the first nine months of 2012, our adjusted operating cash flow totaled $1 billion, which is a $238 million increase over the same period in 2011. Our adjusted operating cash flow includes the impact of changes in restricted cash. The largest favorable factor relates to our benefits plans. In September of this year, we contributed $100 million to our plans, compared to $257 million last year.

Our total capital expenditures decreased by $135 million in the first nine months of 2012, as compared to the corresponding period in 2011. We saw lower capital expenditures as large capital projects were completed. We also paid $207 million in common dividends in the first nine months of 2012, which was $25 million greater than the same period last year. Dividends in the first nine months equate to an annual rate of $1.20 per share, which is a 15% increase over the prior year's annual dividend of $1.04 per share.

As of September 30, 2012, our adjusted debt to capital ratio was 52.1%. Our calculation treats 50% of our hybrid securities as common equity, which is consistent with past presentation. We are using cash to satisfy any shares required for our 401-K plan, options, and other programs. Going forward, we do not expect to issue any additional shares.

As shown in the earnings packet on our website, retail sales of electricity decreased by 0.7% during the first nine months of 2012, as compared to the same period in 2011. Our weather normalized sales were down by 1.7%. In our plan for the year, we took into account an extended outage at our largest customer and we knew that two other customers were moving to self generation. Adjusting for these three customers, normalized retail sales were flat during the first nine months of 2012 as compared to 2011.

Looking now at individual customer segments. We see actual residential sales slightly down in the quarter compared to 2011. Although the quarter overall was warmer than 2011, the weather pattern was different in 2012. This year's third quarter started out with a week of intense heat followed by a cooler period, and then the end of the quarter was slightly warmer than 2011. Conversely, high humidity and warmer than normal temperatures persisted throughout the third quarter in 2011. On a year-to-date basis, residential sales are up 0.6%, and on a normalized basis, residential sales are down 0.7%.

Across our small Commercial and Industrial group, we saw actual quarterly sales up 0.7% and year-to-date sales up 1.1%. On a weather normalized basis, year-to-date sales to small Commercial and Industrial customers are up 0.6%. We continue to see modest growth in our small C&I class. In the large Commercial and Industrial segment, quarterly sales were down by 8.3%. However, if you exclude the iron ore mines, and the two self generation customers, sales were up 0.6%. Year-to-date sales are down 3.3%, and excluding those same customers sales are up by 1.7%. On a normalized basis, year-to-date sales excluding these customers are flat.

Turning now to our earnings guidance. We're increasing our guidance for the year. We now expect our earnings for 2012 to be in the range of $2.31 a share to $2.33 a share. Assuming normal weather, our guidance for the fourth quarter is in a range of $0.39 to $0.41 a share. We will be carrying out a number of maintenance projects in the fourth quarter. In addition, AFUDC will be lower and depreciation expense will be higher, both compared to last year's fourth quarter, because of the $1.3 billion of assets we placed in service. However, we still expect to earn our full allowed return on equity at Wisconsin Electric. With that, I will turn things back to Gale.

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

(Operator Instructions)

Greg Gordon, ISI Group.

There is no power south of 40th street. But I was able to find a bunk someplace with power until they can get that transformer back on on 13th street. Apparently they had a 14-foot storm surge when the highest storm surge they'd seen was 12.5 feet in 1888.

Oh, wow.

Bad luck for ConEd. Hopefully they'll get power back on soon.

Hang in there, Greg.

My first question is on the coal blending. I visited the site of the construction site several times while you were building the new units and I know that you have sort of a state-of-the-art coal blending facility there. What was the initial expected use of the coal blending facility if not to blend coals the way you're now asking to blend them, or was it initially meant mainly to blend [half and half] and other Eastern coals and now you're asking to blend Eastern and Western? Can you explain that?

We'll let Allen Leverett answer that for you Greg.

I'm not sure, Greg, what time period you were at the site. We don't actually have a blending facility. What you might be remembering is inside that very large coal storage building there's what's called a stacker reclaimer. We don't actually have the capability right now to be able to blend at the site.

Okay, that was what I was thinking of.

Either on the belt or inside the boiler itself. So what we're looking to do is really explore next year two approaches to doing fuel blending. So one, the so-called "on the belt" where you actually have a blending facility like you're probably thinking of at other sites. And then another approach, where you would actually blend what they call "in the furnace." So we're going to look at those two approaches and then figure out what's really the best long-term approach to really getting some fuel flexibility at the site.

How much Powder River Basin coal would you be buying if you were given approval to do what you're asking for?

Well, I guess I would think of it in terms of potential blend percentages and our long-term goal, Greg, is to be able to burn either 100% bituminous or 100% PRB. We want to be able to burn all blends in between, but I think realistically probably the highest we're going to get on PRB for a while would be 80% PRB, but we'll have to do a lot of testing in order to figure out what's the best approach and what are the hurdles that we'll have to overcome to get to that 80% level. So I think for the next few years, I think that's probably from a practical standpoint the cap on what we could burn in terms of PRB. But longer term, we like the flexibility to go to 100%.

And Greg, this is Gale. Just one other point that might be helpful. We did invest early on, and you may be remembering this as well, early on in the design of these new units we did invest about $24 million to make sure that with an additional investment that Allen's talking about, we could actually have the unit - operate on a blend of coals. So the initial design and the initial work there built in the capability we need, so if we made an additional investment in blending it could actually pay off.

Great. Next question's on capital spending. When we look at the cap spending program in your last analyst update, should we be adding the programs you talked about in terms of I think it was the gas pipeline expansions and repowering of the generation unit, are those additional capital spending on top of what you've already budgeted or do those fall inside stuff that you've already sort of budgeted for?

Good question, Greg. In terms of that 2012 through 2016, $3.5 billion program, these fall inside.

They fall inside. Great. Final question. You had talked about the possibility that the government of Wisconsin might consider selling some of its power generation units that it just simply doesn't have the money to maintain or retrofit with environmental upgrades. Has there been any progress on that front and do you think that that will be an event that you'll be able to consider making an investment in in 2013?

Good question, Greg. If this occurs, meaning if legislation -- this takes a piece of legislation to enable the current administration to sell those units. There are 37, some of them very small, but 37 generating units, some of them provide steam only across the state of Wisconsin. Certainly from everything we can tell, the governor would still like to put the operation of those plants and the environmental upgrades that will cost several hundred million dollars into the private sector and if that occurs, it would occur I think in 2013 with a piece of legislation. So that will be a 2013 event if it does occur. But certainly the logic of why that would be a good thing for the state is firmly in place.

Thanks, guys.

Jim von Riesemann, UBS.

The question's really broad picture. With Dominion's announced shutdown of the Kewaunee facility, can you talk broadly about energy policy in the state of Wisconsin, what it means from both generation needs and maybe transmission needs, especially in light of the fracking sand too?

Sure, be happy to. I think there's one important conclusion that comes out of the -- comes out naturally out of the decision by Dominion to close the Kewaunee reactor. And that is there's no doubt in my mind it makes more valuable to our customers the Port Washington natural gas units and the Oak Creek coal units that we've completed as part of Power the Future. If you think about it, it's taking over 500 megawatts of base load capacity out of the picture in the State of Wisconsin. So regardless of growth or regardless of anything else that happens, because we have these brand-new very efficient units in place, it is bound to make those units more valuable for our customers. I think that's piece one.

Piece two, you asked about Transmission and I do know that American Transmission Company is taking another hard look at one particular transmission line that it had proposed. It actually had proposed the transmission line to help move energy out of the Point Beach Plant that's been operated. If you remember, NextEra I think added about 17% to the capacity of the Point Beach units. American Transmission Company had proposed to help alleviate some transmission constraints in that area by building a new transmission line.

They've now withdrawn that proposal. They still think something will be needed. Remember, Kewaunee and the Point Beach units are very near each other, so taking Kewaunee out of service probably alleviates some of the transmission constraints. So there may be some modestly less investment in one particular transmission line by ATC as a result of this. However, we really don't see any major impact on our ATC earnings growth in the near term as a result of this. We think the prospects for ATC earnings growth certainly over the next three to five years remain as we have them in our plan. Does that help, Jim?

That does, thank you.

Kit Konolige, BGC Financial.

I'm in midtown. The lights are on but the steam is not, so no hot water. Oh, well. There are worse problems.

If you come to downtown Milwaukee, we'll get you a shower.

That sounds very attractive. We have this big crane hanging over here. You may have seen the pictures. So that's an engineering project you should send some guys to work on.

We've got a bunch of crews out there helping out, but not on the crane.

There you go. Follow-up on your discussion on the buyback. So this is the first in a while, I believe. Can you discuss with us what let's say "trip wire" there was that led to the decision to go ahead and buy back and what we should look for then on the remaining amount of authorization over the next five quarters now?

Sure. Be happy to. And really, the trip wire was very simple. And it consisted of two factors that Pat and I took into account. The first was that we continue to do very well on cash generation this year. And as you know, we don't think building up and just holding cash on our balance sheet makes a whole lot of sense. So we were continuing to do well against our plan on cash generation for a number of reasons.

And then secondly, as you know, the market choked a little bit over the last few months, particularly after Utilities hit a high in early August, and we thought as the stock price retreated some, we thought it was a good opportunity to spend a very modest amount of money. It was only $14 million. And so those were the factors that led to our decision to go ahead and repurchase $14 million. As I mentioned, we're now at about $114 million total of our share repurchases since the start of 2011. And we've been able to do that at $31.45 a share for the average repurchase price which we think is a very, very good price.

I don't think you can read anything into what that might mean for the next few quarters. We can be very patient here. But again, I think fundamentally a build-up of cash on the balance sheet it's better even where the stock is trading to buy back stock than to build up a lot of cash on the balance sheet. But we also are balancing all of that against investment opportunities as we see them. So our preference obviously would be to invest the capital and our cash flow in additional Utility-like projects that do not change our risk profile. One of which of course would be the one we just talked about if it came to pass which would be the state owned power plants.

Very good. Speaking of the investment opportunities, then, can you give us a few more details on the gas pipeline expansion opportunity even looking a little longer term out in Western Wisconsin?

Well, we mentioned in the prepared remarks that the first phase of this project we thought if approved would be approximately $150 million. There is as we look at potential demand and as we look at reliability issues in the Western part of the state, there could be beyond this first phase a second phase that might be $50 million to $60 million of additional capital as well. But that would be a little further out into the five-year period.

Let me just say this about the Western gas expansion project that we're going to prepare an application for to the Commission. The Western part of Wisconsin is quite rural and our distribution network out there in the Western part of the state has not been incredibly robust. But we're seeing other things going on in addition to the explosion of frac sand mining there. The frac sand is not the only reason why we think this is an investment we need to make for reliability. We have two hubs out in the Western part of the state where our reserve margins even with very modest growth will go below acceptable levels over the next couple of years. So just looking at system reliability on our gas distribution network, we believe we need to make this investment.

Then we're also seeing, and you can see it in the numbers I mentioned earlier, we're also seeing a pretty significant uptick in customers moving to natural gas, particularly from propane in rural areas. I think I mentioned to you our new customer connections over our entire system for the first nine months of this year on the natural gas side are up 14% compared to a year ago. So we're seeing customer growth. We're seeing just general demand requiring us to make some enhancements, and then we're seeing a very, very strong expansion of frac sand mining in the Western part of the state. I believe, for example, just talking with our folks yesterday that we're in conversations with 12 or more frac sand mining operations in the Western part of the state who have asked us to take a hard look at providing them service.

Very good. Thank you.

Michael Lapides, Goldman Sachs.

Congrats on a good quarter. O&M related question. Want to make sure I'm following the numbers correctly here. Year to date how much was the dropoff tied to the regulatory amortization, and then what explains the rest of the year-over-year decline in O&M?

Okay. Well, essentially on the rate order that we have in place freezing base rates, it has as part of that order $37 million per quarter in essence cessation of amortization of regulatory assets. So if you look at this quarter, for example, of the O&M reduction, $37 million was tied to the rate order and the cessation of amortization of regulatory assets. The remainder is what I would say -- I'm really proud of our Managers across the business. The remainder is dozens of very solid O&M cost control initiatives that have really been bearing fruit.

And how do we think about what the year-to-date decline in O&M is outside of the amortization, and how do we compare that to the O&M requested in your general rate cases?

Okay. Well, we've got some numbers here. We're turning to the right page. First of all, if you take the amount associated with the holiday, the amortization holiday and the rate freeze, Steve, it's $37 million times 3, right?

That's right. $111 million for the year, and at the Utility the O&M reduction is about $107 million. So you've got $4 million of increased costs and that's across the board, benefit cost, medical costs are higher. So basically at the Utility the story is the freeze on the amortization.

Now, to your question, Michael, about how does that compare with our O&M request in the rate case.

Yes.

Really kind of apples to oranges, because a big part -- well, the biggest part of our rate case is the recovery of and on a $1.3 billion of capital investment on projects the Commission has already approved. So we do have an O&M component that's adding to our rate request because we need people to operate for example the air quality controls at the older Oak Creek units that are now in service. So in essence, what I think you could -- the conclusion you could properly draw is that for basic ongoing O&M we've tried to stay pretty flat from '12 to '13, but there's a component of O&M that we need to add because we're adding people to operate the new assets coming into service.

Understood. Understood. One final question. There's been some news flow about an ATC proposed line and I believe one of your neighbors. There's been some conflicts that have gone to FERC regarding which Utility whether it was ATC or whether it was I think one of the Xcel subsidiaries would actually be the builder of the line and I saw in the last 24 or 48 hours some news about potentially withdrawing the application. Could you just provide some color on that?

I'm going to ask Allen Leverett to answer that. But to frame it for you, I don't think the dispute is about who's going to build the line, it's who will eventually own what chunk of the line. Will there be a sharing of the capacity in ownership, but mostly it's an issue about ownership. Allen?

I think maybe, Michael, you're alluding to two separate facilities. The first one is the one where ATC is having the dispute with Xcel and that's the Badger Coulee line and that's about a $350 million facility. It could very well be that ATC and Xcel end up sharing 50/50 the ownership of that facility. But all that's on appeal at the FERC at this point.

I would say longer term, Michael, as you have order 1,000 kick in, the FERC order around planning, I think in the future we shouldn't have uncertainty about ownership in these types of situations. But the Badger Coulee facility is certainly an open issue.

The other facility that you may have been thinking about is the one that's connected with the Kewaunee closure. Originally, ATC had proposed to build a facility called Barnhart to Branch River and they're putting that on hold, given that Kewaunee is going to be closing. So that's the second facility I think that you're referring to.

But from a high level, I'd just reiterate what Gale was saying earlier. We wouldn't see -- regardless of what happens with the ownership of Badger Coulee, regardless of what happened with Barnhart-Branch River, we don't see an impact to ATC's earnings over the next three years, meaning '13 to '15. Does that help, Michael?

Very helpful, Allen. Very helpful, Gale. Thanks guys, much appreciated.

Paul Ridzon, KeyBanc.

What was the absolute fuel recovery through the quarter?

I think it was $19 million.

$19 million, yes.

Last year it was breakeven?

That's correct.

And what's the risk of --

Wait a second. Sorry, Paul. We misunderstood. The benefit to the quarter on a year to year basis was $19 million. In the third quarter, we have higher costs because the plants are running and so last year we underrecovered by $34 million, and this year it's about $15 million. So the change was about $19 million.

Got it.

We were underrecovered for the quarter but the positive swing was $19 million.

Not as underrecovered. Okay. What's the potential for more self generation?

The two particular customers that we mentioned that have moved to self generation were in my opinion fairly unique circumstances. One is a paper mill. They're moving more to use of biomass to fuel their paper operations. And the other is a sewage district where they've got the ability to use some methane gas on and off. Those circumstances, again, I think are pretty unique to those two particular customers. I would not view this as a trend.

Where did you outperform relative to third-quarter guidance?

Well, relative to third-quarter guidance, I think there are a couple of places where we did better than we thought when we gave our third-quarter guidance. And the first is when we were on the call at the end of the second quarter, we knew we had some warm weather, but overall, from -- overall, we came in better than we thought on -- just on revenues because of the intense heat in early July and then it got warmer again toward the end of the quarter. So particularly the warmth we saw at the end of the quarter. We had a sense because when we were on the call we knew about the early July, but the warmth at the end of the quarter was quite helpful in terms of additional sales. And then I believe we actually did a little better on fuel recovery than we thought we were going to do.

Okay. And Gale, is it true for Halloween you're going to be a CEO of a large Charlotte-based utility?

(laughter) I don't know. They didn't deliver the Jim Rogers mask, so --

(laughter) Thank you very much.

Michael Lapides, Goldman Sachs.

Hey, Pat. I just want to make sure I understood some of your comments about the fourth quarter. Can you talk a little about some of the puts and takes from fourth quarter '11 to fourth quarter '12, just trying to think about the bridge year over year.

Sure, Michael. The biggest -- I'll just kind of resummarize some of my remarks. I think the biggest difference is -- we talked about $0.39 to $0.41 as our guidance in the fourth quarter this year. One thing is, as Gale mentioned, we had very hot summer. We've got a lot of stress on the network. So we've got a number of maintenance projects that we've added to our fourth-quarter plans, which is additional spend than we had originally.

And as we talked -- we also talked about the rate settlement. That $37 million flat a quarter was kind of a simplified way to do it. If you think about how the depreciation expense for an example falls, it picks up in the fourth quarter because everything's online. So we've got additional depreciation vis-a-vis that amortization order. That's probably the two biggest.

I think Pat's kind of nailed it. But as we said during the prepared remarks, we fully expect to earn our allowed, authorized return on equity at Wisconsin Electric.

Okay. I just want to make sure on the depreciation side. If the regulatory amort is rolling off, the primary impact to that is actually felt in O&M, what's driving -- you're bringing South Oak Creek, the enviro controls into service and therefore you experience that depreciation for the first time beginning in fourth quarter 2012, or is there some other driver?

Correct on the 78 train, yes.

We completed the last segment of the air quality control upgrade at the older Oak Creek units on September 4. So when that happens obviously we stop accruing allowance for funds used during construction. We start depreciating the new asset. So all of those -- those two things, the cessation of AFUDC and the depreciation of the asset are on a basically almost $900 million project, it's a pretty big swing for Q4.

Got it. Okay. Thanks, guys. Much appreciated.

Operator. Leslie Rich, JPMorgan.

I'll tell you what we can do. We will be happy to call Leslie later after the call since she obviously is having some difficulty with either her phone or with the power in New York.

Operator. Paul Patterson, Glenrock Associates.

Just a few quick ones here. The 9.8% increase I think you said for electrical connects for the last nine months, did I hear that correct, and how does that relate to customer growth?

You are correct. I think we said 9.8% uptick for the nine-month period this year compared with the first nine months of last year in electric new customer connections. And on the natural gas side it's actually above 14% growth. We are coming off, though, a very low period of growth in terms of new customers. So these are nice upticks but we're still only seeing about a 0.3% to 0.4% growth in the total customer base of both the electric -- actually, probably 0.4% growth on the natural gas side so far this year, a little less than that on the electric side. But encouraging, encouraging.

So what, there are a lot of people that -- a lot of customers are disconnecting, is that what it is, so the net number isn't that much? Is that how we should think about it?

No, I think what you're seeing is just very flattish growth. We haven't seen a lot of disconnects.

The 9.8%, why isn't that -- I'm sorry to be so slow -- why is that only leading to 0.4% of customer growth if you're getting 9.8% in new customers and you're not losing that many?

Because if you look at -- let's assume for a minute -- let's take a 1 -- for ease of discussion, we have about 1 million natural gas customers.

Okay.

So if you have 0.4% growth in one year or 0.3% growth in one year and then 0.4%, 0.5% growth in the next comparable period, you're not going to drive the raw numbers that much higher. It's the percentage growth compared to --

Okay. I think I understand. In other words, it's a question of how much new -- I think I'm just -- I misunderstood it from what base that was.

The iron ore mine, what was the actual impact of the iron ore mine? It sounds like you guys had really hot weather but you had no new peak. If you had the iron ore mine operating would you have had a new peak? Could you just tell us what the iron ore mine itself would have done?

I'm looking at Scott and Steve specifically on the iron ore mine. They were at 50% load on those really hot days. And they probably would have added another 100 megawatts. 50 to 100 additional megawatts.

There's one other point that's important here and that is this was July 5 and July 6. And as you know, during the first week of July, a lot of manufacturing customers are shut down for some or all of that week because it's a holiday week. So not only did we have the mines because of their planned outage at 50% load, if you will, we had a lot of manufacturing customers that weren't operating. So there's no doubt in my mind that had it been a normal week, assume for a minute those hot temperatures that occurred on July 5 and July 6 had occurred on July 15, no doubt in my mind we would have set a new peak.

Okay. Now, you guys did benefit from weather, though, I mean you guys mentioned how it was dispersed differently. If I'm looking at your financials you guys do actually seem to suggest if I'm reading them correctly that the quarter did improve over last quarter by $2 million. Am I understanding that correctly? Is that taking all the stuff into account? Do you follow what I'm saying?

Steve, I think the $2 million is pretty accurate. What's your --

Yes. Basically, last year weather was favorable by about $21 million. This year it's favorable by about $23 million compared to normal. That's how you have the $2 million impact as compared to last year. But compared to normal it's about $23 million better compared to normal this year.

Okay. And then when we look at slide 11 and you mentioned a couple things. I just want to make sure I understand this. Excluding the iron mine I guess or just excluding all of mining, your retail sales growth is down for the last nine months 0.6% and that includes leap year, is that right, the benefit that you got from leap year or --?

It does include that. But it also includes the two customers that we talked about that moved to self generation.

Right. But they're not -- they're not going to probably move back from self generation, right?

No, that is correct.

And I guess what I'm also wondering is we are hearing a lot of interest out there in terms of the promotion of combined heat and power, and I know you mentioned that you don't see this as a trend, the self generation effort and I just was -- just wanted to sort of highlight that. You don't see any trends or people being interested in combined heat and power, is that basically because wholesale electric prices are low or how should we think of that?

Really, I don't see us having a lot of -- we haven't had a lot of inquiries, there are not very many discussions going on with customers about combined heat and power investments. Our industrial rates I believe are low enough. Of course, we have for new and expanding customers a real-time pricing rate that is very attractive. I think when you look at our combination of the tools we have to be able to offer to expanding customers and new customers and be very competitive, I think we stack up very, very well.

Okay.

Let me if I can give you -- I hope this won't confuse you. Let me give you two other energy sales statistics that were helpful to me. Because when we start talking about weather adjusted and all these ins and outs, sometimes I think we can get lost in that. Actually, when you have weather as extreme as we've experienced both in the summer of 2011 and the summer of 2012, you get two standard deviations away from norm and our weather normalization techniques that are available to the industry aren't that good, frankly, at the tail end of these standard deviations.

What I asked our folks to do is go back and tell me for the spring/summer period, so the six-month period ended September 30, April, May, June, July, August, and September, just give me actual results for residential sales for this period this year and that second and third quarter period last year. And this helped me kind of sort through the trend. Our residential sales, it was warm both years, in both quarters of both years. Our residential sales for the six months ended September 30 are up 2.9% actual. Our small Commercial and Industrial is up 2.7%.

And that makes a lot more sense to me. It was warm both periods. Different patterns in terms of the intensity of the weather. But I think that may shed some light on the fact that I don't see us in a huge declining trend here.

Okay. I guess the reason why I'm asking about it, Gale, quite frankly is you're not the only guys who are seeing very weak growth or negative growth and we're seeing it all around the country. So I just was wondering, is there anything else that you're seeing perhaps because I just -- it's remarkable. Over the last 18 months it seems to be pretty widespread. But it also just looking at some -- there's some utilities that have had negative weather adjusted electric sales growth for almost three years. Is there anything customer usage or anything that you're seeing, outside of -- do you follow what I'm asking?

I follow. I appreciate that. I do think -- well, first of all, many of the utilities that you're properly saying are seeing negative trends here in sales growth, many of those were in the faster growth regions of the country where the boom and bust has been much more dramatic than it has been in the Midwest. We have -- we simply are just more stable and have been through this recession than many, many other regions. There's not a flash of growth here but it is steady and it is stable and we're beginning to see some commercial activity that we've not seen in five or six years, announcement of new shopping centers, announcement of a potential brand-new skyscraper in downtown Milwaukee.

The one trend I am seeing I think is that we are beginning to see some commercial growth on the horizon that we've not seen over the last five or six years. On the residential side, the other thing we are seeing is a continuation of what I've mentioned in past calls, where we have a -- what we call in the industry a shoulder month, take a May or an October, where it's easy for a customer not to turn on the heat or to turn off the air conditioning. We're seeing more conservation in the shoulder months where it is easier to conserve. I don't think there's any question about that.

So those would be the two trends that I would point out to you. Shoulder month conservation to a stronger degree than we have seen in the past, and I think here, for this region, some commercial growth that's on the horizon that may give our Commercial and Industrial sales a bit of a lift.

Okay. Thanks a lot. Happy Halloween.

Jay Dobson, Wunderlich Securities.

I wanted to revisit the O&M item. I think I'm still just getting a little confused sort of what happened in the third quarter. So -- and I'm specifically speaking about the slug excluding the $37 million regulatory asset amortization holiday. So that was down about $16 million, $53 million net of $37 million. Can you give me just a flavor of what that was? Because as I look at it, it almost looks like some O&M was shifted to the fourth quarter because the weather was fairly similar, in fact, actually probably somewhat more conducive to regular maintenance this year than last year. I'm sort of confused what's so stressed about this third quarter that's forcing a lot of maintenance in the fourth quarter that wouldn't have been similar to a year ago. Trying to get my head around this.

We'll ask Steve to take a shot. I'll also give you my view on it.

Yes. You are right, it's about $53 million decline, $37 million relates to the amortization. There's a lot of small things in there. One of the things is the gas distribution expenses were down because it was a mild winter so we didn't need to perform as much work. There was a slight benefit in our miscellaneous benefits expense because of a share performance on one of the benefit plans. So that was a benefit to the comp near reduction in expense and again, that's tied to the stock price compared to other companies. But that was relatively minor.

There's a lot of small things. But maintenance on the delivery, and yes, the other thing that helped us on the electric side, even though it was very hot in the third quarter, we did not experience major storms, and so the storm expense was low compared to last year.

And overall, as I mentioned in addition, and Steve is very accurate on the things he cited, we just have a lot of cost consciousness and a lot of cost control going on across the organization. It's little things here and there but they all add up.

Right. No, no, no, absolutely. Maybe thinking about it differently. Would the major maintenance that you're doing in the fourth quarter that's dragging fourth-quarter earnings relative to a year ago not have occurred last year at all in the second half?

No. But we will have more of it in Q4 of this year than in Q4 of last year.

More than in the second half of last year. I understand in the fourth quarter, definitely. I'm trying to get at the second half of --

The answer is yes, more in the second half this year than in the second half last year.

Okay. Great. Thanks very much.

Dan Jenkins, State of Wisconsin.

Dan, I was hoping to hear from you today. Before we get into this I want to make sure that you're prepared for Halloween tonight. Do you have your bail money in small denominations, small bills. Because I'm not going to bail you out again, Dan.

I have big bills, so --

(laughter) There you go. Just forget my cell phone number, okay?

Okay. First question I have is kind of related to the rate proceeding. You said you expect the decision by the end of -- by December. I'm just wondering if you could update us a little bit on kind of what discussions or what kind of testimony or feedback or whatever you've gotten from the Commission staff.

Sure. I'd be happy to, Dan. In essence, let me back up because I want to frame the case a little bit. I think that will help understand the briefs that have been filed in the case by all the parties. The predominant driver of our rate filing, remember it's a 3.6% base rate increase that we're seeking, the overwhelmingly predominant driver is the capital we've spent, about $1.3 billion on the Glacier Hills Wind Park, on the air quality controls that we just completed at the older Oak Creek units. Those are projects that were approved by the Commission; we brought them in on time and on budget. And in the case of the air quality control upgrade, actually better than budget.

So the rate case is in essence about seeking recovery in rates for those investments that were previously approved. The lion's share of the case is about capital that's already been spent. A very small amount of the case is about our O&M projections on how much O&M we need to spend in 2013 and 2014. If you'll recall, in Wisconsin we have a two-year forward-looking test year. So we project our expenses and our investment levels for 2013 and 2014 as part of the rate case.

The staff is suggesting that we should spend less O&M than we have proposed for the 2013 and 2014 period, but it appears that they are comfortable with and we would expect they would have been comfortable with the capital investments and the fact that they were brought in previously approved on time and on budget. So the final rounds of briefs and discussions among the parties and with the Commissioners as they're briefed is really about what's the -- is really about now down to what is the O&M that's the appropriate O&M for us for 2013 and 2014.

And as I mentioned to you for all of the Wisconsin utilities this year, the Commission has decided that the current allowed return on equity and the current capital structure will stay in place. Does that help, Dan?

So what's the ROE that's --?

For our Electric, Wisconsin Electric operation, it's 10.4% and for our Wisconsin Gas operation it's 10.5%.

Okay. And so the 3.6%, is that like a one time or is that -- is there like one in 2013 and one in 2014 for the electric rate?

For the -- it varies across the different operations but for electric it's 3.6% and 3.6%. 3.6% in 2013, 3.6% in 2014. Then we're actually -- be helpful to remember this. We're actually filing for a decrease in our gas operations for Wisconsin Electric and in Wisconsin Gas operations as well.

Is that just a one-time decrease on the gas side then or how's that work?

No, we're actually asking for a decrease and then for that decrease to remain in place for 2014.

Okay. So that's -- rather than two phases, that's just a one-time and then it would stay the same for gas?

That is exactly right, Dan.

And then I had a question, you mentioned how --

Plus we need to heat that jail cell a little more for you.

Right. Yes. I appreciate that. (laughter) One thing you mentioned that you would be interested in if the state were to sell off some of their generating facilities, but that you would need some sort of legislation related to that. Given the current makeup of the legislature, do you see that as something that's likely to happen? I know that maybe the governor has that on his agenda, but what kind of feedback are you getting from the legislature?

Well, clearly the appetite for moving that forward will somewhat depend upon the outcome of the election in early November. However, my sense is that there are some Democratic legislators, depending upon the use of the proceeds from the sale, that could be very supportive of the sale. So I'm not sure this is really a hugely partisan issue going forward, and some of the support for the concept of selling the state-owned power plants may well lie in what would the governor intend to do with these one-time proceeds.

Okay. And then just to go back a little bit on what you're seeing particularly from the manufacturing side, first I just want to clarify on the ones that are doing self generation. When do you expect that you won't be seeing the year-over-year impact on that? When did those kind of go off system?

I think we've seen the impact -- I'm looking at Scott Lauber and he's agreeing. I believe we've seen about the impact that we expect to see and we'll see it in this year's numbers. Comparisons next year should be -- should not have any further impact from the two customers.

So --

Or if so, modest, very modest.

Starting first quarter.

Yes, starting first quarter.

And then just one thing, I don't know how closely you look at this but I noticed today the Milwaukee purchasing managers index was down quite a bit, and I was wondering how much, if you know that has much correlation to what you see from the people you provide service to as far as a way to kind of get a sense on what's going on in the large manufacturers.

I wouldn't necessarily place a ton of weight on that in terms of its influence on our large manufacturing customer base. What we look at and we do this every week, we see a report that shows what is happening with our large Industrial customers every single week. And we look at it from the standpoint of latest 4 weeks compared to the prior 4 weeks, latest 13 weeks compared to the 13 weeks of a year ago and then week to week. We have a very good reporting system that keeps us very much in tune with what's happening with our largest Industrial customers, and right now I think the bottom line of what we're seeing is flat overall.

Okay. Then the last thing, I was just wondering, you mentioned that one of the big differences in the cash from operations had to do with the pension funding. I was wondering if you could give us a little color on what you expect on the pension funding going forward.

We'll let Pat give you the answer on that one.

Sure, Dan. Few thoughts on the pension funding. First of all, we had a contribution planned in 2013 and we just pulled it forward. So that's one of the explanations I guess.

Second, we're anticipating that our discount rate at the end of the year is going to be lower than it is right now. So in round numbers, we're just over 5% now and based on all the latest actuarial assumptions I've seen we'll probably end up under 4%. So that drove up the size of our liability and drove the contribution.

I guess the third point would be we kind of chose the $100 million based on all of the best knowledge we've got now. That projects us out to be 100% funded at the end of the year.

Dan, to Pat's last point, I think you'll find we were one of the few large companies around that will be fully funded on their pension liabilities.

Okay. Thank you.

Andy Bischoff, Morningstar.

Just real quick question, most of mine have been answered but if you could kind of opine on your ability to manage O&M costs in 2013, 2014 outside of those additional O&M related to your additional capital investments that have been put in place?

On our ability to manage our O&M costs?

Correct.

We've proven to be very effective, very strong, very capable at managing our O&M costs and I don't think that will change in any way, shape or form.

Okay. In 2013, '14 you'd expect to be able to keep O&M relatively flat outside of those additional capital investments.

Meaning outside of the O&M we need to have for the additional people to run those additional -- the additional assets?

Correct.

The answer is yes.

Okay. Thank you very much.

Vedula Murti, CDP Capital.

Basically a follow-up on Paul Patterson's line of questioning. I think almost everything was asked. But when you get to the next rate cycle, can you discuss a little bit about how much right now of your return in rates are on the fixed tariff as opposed to volumetric at this point. Do you want to transition over, maybe a little higher percentage to get away from volumetric risk? Or do you think if you can tell us where you're at there and whether it's a good mix right now in terms of balancing the opportunity benefit from sales growth and that type of thing versus protection, that type of thing.

Good question Vedula. I don't believe we have in the room with us the exact percentages of the breakdown of rates, how much is in fixed charges, how much is volumetric. We can certainly get that for you and call you back after the call. But in our current rate case we are asking I believe for some adjustment upward in the fixed charges. And again, the specific percentage breakdown we don't have in the room with us but it's a matter of public record and we can certainly get that to you later this afternoon.

But basically the point is though that's something that you're working towards in terms of moving away or diminishing the volumetric component?

Well, clearly with the -- with what we've asked for in terms of modest adjustments in our rate structures in the rate case, we think it would be helpful to move in that direction, meaning a bit away from volumetric and more towards the fixed charge. So the answer is yes.

Okay. Thank you very much.

Ladies and gentlemen, that concludes our conference call for today. We appreciate very much you participating. If you have any other questions, Colleen Henderson will be available in the Investor Relations office. Her direct line, 414-221-2592. Thanks, everybody. See you in Scottsdale.