威斯康辛能源 (WEC) 2010 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen. Thank you for waiting, and welcome to Wisconsin Energy's quarterly conference call. This conference is being recorded for rebroadcast, and all participants are in a listen-only mode at this time. Before the conference call begins, I will read the forward-looking language. All statements in this presentation, other than historical facts, are forward-looking statements that involve risks and uncertainties which are subject to change at any time. Such statements are based on Management's expectations at the time they are made. In addition to the assumptions and other factors referred to in connection with the statements, factors described in the Company's latest Form 10-K and subsequent reports filed with the Securities and Exchange Commission could cause actual results to differ materially from those contemplated.

During the discussions, reference earnings per share will be based on diluted earnings per share unless otherwise noted. After the presentation, the conference will be open to analysts for questions and answers. In conjunction with this call, Wisconsin Energy has posted on its website a package of detailed financial information at www.WisconsinEnergy.com. A replay of our remarks will be available approximately two hours after the conclusion of this call. And now I would like 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. We appreciate you joining us as we review the Company's 2010 second quarter results. Let me begin, as always, by introducing the members of the Wisconsin Energy Management team who are here with me today. We have Rick Kuester, President and CEO of We Generation, Allen Leverett, our Chief Financial Officer, Jim Fleming, our General Counsel, Jeff West, Treasurer, and Steve Dickson, our Controller. Allen, of course, will review our financial results in detail in just a moment.

As you saw from our news release this morning, we reported earnings from continuing operations of $0.74 per share for the second quarter of 2010. This compares with $0.53 a share for the comparable period last year. Our second quarter 2010 results were helped by a return to more normal weather, continuing cost controls and earnings from our $1.2 billion investment in the first expansion unit at Oak Creek. Overall, we're quite pleased with our second quarter and year-to-date performance.

Now I'd like to spend just a moment on our continuing effort to upgrade the energy infrastructure in Wisconsin. Our Power the Future plan is fundamental to the principal of energy self-sufficiency. The components of our focus on self-sufficiency include investing in two combined cycle gas-fired units at Port Washington, which is north of Milwaukee, the construction of two supercritical pulverized coal units at Oak Creek, which is south of the city, and building a significant amount of renewable generation.

As we've discussed on previous calls, both units at Port Washington are in-service. Construction was completed on time and on budget. The units are among the most efficient in the Midwest market. They're operating well, and our customers are now benefiting from the low price of natural gas that fuels these units. Turning now to the status of the coal-fired units at Oak Creek. As you'll recall, Unit 1 passed all of its performance tests and was placed into commercial service on February 2 of this year. Our general contractor at Oak Creek, Bechtel Power Corporation, is now focusing its efforts on completing the commissioning and testing of Unit 2, and I'm pleased to report the effort is proceeding well.

First fire on coal in the Unit 2 boiler was achieved on July 8. The generator was then synchronized to the grid for the first time on July 16. And since July 16, the unit has operated up to 30% of its rated capacity. Over the coming weeks, Bechtel will gradually increase the output of the unit while conducting a range of tests along the way. After it reaches its full rated capacity, the unit will be shut down for a scheduled two-week outage. Bechtel will use this time to address punch list items and remove start-up equipment. Then the unit will be returned to service for further tuning and a series of rigorous performance tests.

Now, as with any two unit plant, the second unit should benefit from the lessons learned on the first, thus shortening the start-up and commissioning schedule. As a reminder, the guaranteed turnover date for Unit 2 at Oak Creek, a date that was set as part of our settlement agreement with Bechtel is now November 28. We expect Bechtel to meet or beat this completion date. However, our current view is that commercial operation of Unit 2 is indeed likely to be a fourth quarter event.

Turning now to other important developments, on May 18, Wisconsin Act 403 was signed into law by Governor Doyle. This action directs the Wisconsin Public Service Commission to develop a new set of rules that will govern how electric utilities in the state recover their fuel and purchased power costs. In short, the new law provides for a modified escrow accounting mechanism for fuel costs with an annual true up. The next step in the process is for the commission to draft and seek comment on a new rule that will actually implement the law. It's possible that the commission could complete its work on the new rule by September 1. The rule would then move to the state legislature where the standing committees in each house generally have 30 days to take any action. If no action is taken, the rule will automatically go into effect. As it stands today, the new rule could be in place for calendar year 2011.

And now I'd like to update you on our progress toward meeting the renewable portfolio standard that the state of Wisconsin has in place for the year 2015. To refresh your memory, the standard calls for an increase in the amount of electricity we supply with renewable resources from 5% in 2010 to 10% in 2015 at a statewide level. The standard sets targets for each of the Wisconsin utilities using an historical baseline. Using that baseline, approximately 8.25% of our retail electricity sales must come from renewable sources in the year 2015. With the completion of our Blue Sky Green Field wind farm in 2008, we took a major step toward meeting Wisconsin's goal to reduce its carbon footprint. Blue Sky Green Field has a total of 88 turbines, each with a capacity of 1.65 megawatts. It was completed under budget and ahead of schedule.

Also in 2008, as you may recall, we purchased a new wind farm development site approximately 45 miles northeast of Madison. This site, which we call the Glacier Hills Wind Park, has a strong wind resource, close proximity to transmission and low population density, making it one of the best locations for a major wind farm in Wisconsin. On January 22 of this year, the Wisconsin Commission approved our request for a Certificate of Public Convenience and Necessity to build up to 90 wind turbines at the Glacier Hills site. After reconfiguring the layout to comply with the Commission's order, we finalized an agreement with Vestas Wind System for a supply of 90 1.8 megawatt turbines to be delivered by mid-2011. With the installation of 90 turbines, Glacier Hills will have a generating capacity of approximately 162 megawatts. We broke ground and began construction at Glacier Hills in the second quarter and we're pleased to be moving forward on what will be Wisconsin's largest wind farm to date.

The first full year of operation for Glacier Hills is projected to be 2012. Our current estimate of the capital costs at Glacier Hills is approximately $367 million. This estimate does not include any allowance for funds used during construction or reimbursable transmission costs.

Now, as you may recall, last fall we also announced our plans to build a 50 megawatt cogeneration plant that would be fueled by biomass at a paper mill site in northern Wisconsin. The paper mill is owned and operated by Domtar Corporation. We're fortunate to be close to significant forest lands that can be harvested in a sustainable matter. These forests have large amounts of wood waste that can be purchased to help fuel the plant. Now, diversification of our renewable energy supply is one of our important goals. As compared to wind for example, the clear benefit from an operational standpoint is that we will be able to dispatch the biomass unit.

The unit will also supply steam to the Domtar mill and of course, co-generating electricity and steam significantly improves the overall efficiency of the unit. Our investment in this project is projected to be approximately $255 million without allowance for funds used during construction. On March 15, we filed an application for approval of this project with the Wisconsin Commission. We expect the Commission to make a decision in this case by year-end or certainly early 2011. Our targeted in-service date for the biomass project is late 2013.

Construction is also underway on a major upgrade of the air quality controls for the existing older coal-fired units at Oak Creek. We plan to invest approximately $950 million, including allowance for funds used during construction for the installation of wet flu gas desulfurization and selective catalytic reduction facilities. We expect these controls to be completed and in-service in 2012. Construction, I'm pleased to report, is progressing very well. The project is now almost 40% complete and we're on time and on budget.

Turning now to our Michigan operations. On December 16 of last year, the Michigan Public Service Commission approved our self-implementation plan to raise electric rates by approximately $12 million, effective with the commercial operation of Unit 1 at Oak Creek. Subsequently, the Michigan Commission authorized an additional increase of $11.5 million dollars that was effective just very recently on July 2. The total rate increase, $23.5 million annually for our Michigan operations, is subject to a 30-day appeal period.

Finally, before I turn the call over to Allen, I'd like to touch briefly on the direction of the economy in our region. The good news is that we continue to see improvement in the economic activity in the second quarter. During our last call, we mentioned the strength we were seeing in three sectors of our service area; iron ore mining, specialty steel and paper production. During the second quarter, these sectors remain strong and we began to see rising electricity use in several additional sectors; most notably in metal fabrication, rubber and plastic products, transportation equipment and health care. Our second quarter electric sales to our largest customers grew by 14%. Now, if you exclude the iron ore mines, sales to our largest customers grew by 7% during the quarter. However, we remain well below 2008 sales levels. And now with more details on our second quarter and our outlook for the remainder of 2010, here's Allen.

Thanks, Gale. Now, as Gale mentioned earlier, our 2010 second quarter earnings from continuing operations were $0.74 a share. I will focus on operating income by segment and then touch on other income statement items. I'll also discuss cash flows in the quarter and the first half of the year. Our consolidated operating income in the second quarter of 2010 was $163 million as compared to $118 million in 2009, an increase of $45 million. The bulk of the increased earnings came from We Power as we benefited from a full quarter's earnings from the first unit at Oak Creek.

Our utility segment also showed increased earnings driven by more favorable weather and some improvement in economic conditions. Operating income in our utility energy segment totaled $98 million, an increase of $9 million versus 2009. Now, as background, effective January 1 of this year, we received a 3.4% increase in our Wisconsin electric retail rates. This rate increase covered many items, including expected increases in utility operating costs associated with Oak Creek and changes in our depreciation expense. When we look at the second quarter, we see $46 million in revenues related to pricing increases, excluding fuel. In addition, the second quarter benefited by $16 million, because of lower utility depreciation expense as a result of the new rates, and $7 million of increased electric and gas margins caused by more favorable weather in 2010.

On the negative side, we experienced $48 million of increased non-fuel O&M costs, primarily associated with the recovery of regulatory amortizations and costs to operate Oak Creek. We also had a $10 million positive MISO item in 2009 that did not occur in 2010. Finally, our recoveries of fuel and purchased power were down $2 million when compared with the second quarter of 2009. These factors led to the $9 million increase in utility operating income in the second quarter. Operating income in the non-utility energy segment, which primarily includes We Power, was up $36 million because of the commercial operation of Unit 1 at Oak Creek on February 2. Taking the changes for these two segments, you arrive at the $45 million increase in operating income for the second quarter of 2010.

During the second quarter of 2010, earnings from our investment in the American Transmission Company totaled $15 million, which was a slight increase over 2009. Other income increased by $2 million because of higher AFUDC on our utility construction projects. Net interest expense increased by $13 million, primarily because of interest expense associated with Unit 1 at Oak Creek. In February, we issued $530 million in long-term debt to replace short-term debt used to finance the construction of Unit 1. In addition, once Unit 1 achieved commercial operation, we stopped capitalizing interest on the construction work in progress.

We also expect increases in interest expense when Unit 2 achieves commercial operation. The interest on the permanent debt for these projects is covered by the lease payments and thus included in customer rates. Consolidated income tax expense increased by approximately $10 million because of higher pre-tax earnings offset by a slightly lower effective tax rate. Our effective tax rate for 2010 is expected to be between 35% and 36%. Combining all of these items brings you to $88 million of net income from continuing operations for the second quarter of 2010, or earnings of $0.74 per share.

During the first six months of 2010, we generated $424 million of cash from operations on a GAAP basis, which is up $193 million from the same period in 2009. As we discussed on prior conference calls, we contributed $289 million to our benefit trust in January of 2009. No contributions are expected this year. On an adjusted basis, our cash from operations totaled $506 million for the first six months of 2010. The adjusted number includes the $82 million of cash impacts from the Point Beach bill credits. Under GAAP, the cash from the bill credits is reflected as a change in restricted cash, which GAAP defines as an investing activity. From a management standpoint, we consider this as a source of cash.

Our total capital expenditures were approximately $379 million in the first six months of 2010. About $300 million of this was dedicated to our utility business and the balance was primarily associated with the generating units being constructed as part of our Power of the Future plan. At the beginning of the year, we projected our total capital budget to be approximately $950 million. Now, as we reforecast the rest of the year, we estimate that our 2010 capital spending will be reduced from $950 million to approximately $820 million. We have also revised our capital spending estimate for the three year period from 2010 to 2012. Our revised forecast is approximately $250 million less than our previous forecast. We also paid $94 million in common dividends in the first half of 2010, which was an 18% increase over the same period last year.

On a GAAP basis, our debt to capital ratio was 57.2% and we were at 54.3% on an adjusted basis. These ratios are slightly better than our June 30, 2009 levels of 58.2% and 55.2%, respectively. The adjusted amount treats half our hybrid securities as common equity. We are using cash to satisfy any shares required for our 401K plan, options and other programs. Going forward, we do not expect to issue any additional shares.

As shown in the earnings package that we posted on our website this morning, our actual second quarter retail sales of electricity increased 7.2% as compared to 2009. On a weather normalized basis, second quarter retail electric sales increased 4%. Excluding the sales to our largest customer, the iron ore mines, on a weather normalized basis, retail sales increased 1.2%, which is ahead of our second quarter projection that called for an increase of 0.1%. Consumption by our residential customers increased in the second quarter by 1.7% and in our small commercial and industrial class by 4.7%, both driven by the warmer weather as compared to last year.

We believe that conservation efforts by residential customers contributed to the decline in weather normalized usage in the residential class as compared with our original projections. However, weather normalized sales to our small commercial and industrial class came in stronger than our projections. When we turn to our largest customers, we see that sales to the large commercial and industrial class increased 14.3% for the second quarter of 2010 over 2009. Excluding sales to the iron ore mines, the large commercial and industrial class increased 7.1%. On a weather normalized basis, large commercial and industrial sales, excluding the mines, increased 4.7%, which was better than our projections. Overall, our retail sales, excluding the mines, are tracking well against forecast. Based on the results to date, we have adjusted the forecast for the mines. The revenue and margin for this increase was reflected in the Michigan rate case results.

In February, we completed the permanent debt financing for the first new unit at Oak Creek. Net proceeds were used to repay debt incurred to finance the construction of Unit 1. We anticipate that the permanent debt financing for Unit 2 at Oak Creek will occur upon commercial operation of the unit. Now, given the strong cash flows relative to our financial plan, I do not expect that we will need any long-term financing at our utilities this year. However, we do expect to complete long-term financings at the utilities in 2011. On a consolidated basis, we have approximately $1.6 billion of available undrawn credit facilities that expire in March and April of 2011. We anticipate renewing and downsizing our credit facilities later this year before they expire in 2011.

I would now like to discuss our earnings guidance for this year. Our original outlook for the year assumed we would earn about a 10% return on equity in our utility segment as compared to the 10.4% allowed rate of return. This differential was expected to be driven by fuel under recovery, timing of rate recovery in Michigan and the electric sales forecast that the Wisconsin Commission used to set our retail rates. As compared to this original outlook, we are doing somewhat worse on fuel recovery. Now, we expect to under recover fuel costs by $30 million to $35 million for the full year, partly due to the warm weather in July.

Timing of the Michigan case was as we expected and we are doing somewhat better than planned on electric sales. In addition, the hot summer weather has brought about a higher than expected number of severe storms and we expect our storm costs to exceed our original budget. Taking all of this together, I currently expect that we will earn about a 10.3% return on equity in our utility segment. This move from 10% to 10.3% represents approximately $0.07 per share in earnings. However, as Gale mentioned, we now expect Unit 2 at Oak Creek will enter service in the fourth quarter. Our original guidance assumed commercial operation of Unit 2 at the end of August. A November 1 in-service date would reduce the outlook by about $0.04 per share. So, the better than anticipated utility results are expected to be partially offset by the assumption of a November 1 in-service date. Given all these factors, we are tightening our earnings guidance range, but not moving the top end at this time. Our new 2010 earnings guidance range is $3.70 to $3.75 per share.

Now, I would like to give you -- move to our earnings outlook for the third quarter. Let me start by saying that we project our third quarter earnings to be significantly above the $0.50 per share we earned in the third quarter of 2009. We see two key drivers for higher earnings in the third quarter as compared to last year. First, we project another full quarter earnings contribution from Oak Creek Unit number 1. I expect this will add $0.11 per share. I do not expect an earnings contribution in the third quarter from Oak Creek Unit 2. The other driver is expected to be weather. Summer weather in the third quarter of 2009 was quite mild. This year ,we are seeing a significant difference. For the first 20 days of this month, Milwaukee has experienced the hottest July weather in the last 60 years. While we cannot predict the rest of the weather for the quarter, it is safe to say that we expect to benefit from the warmer weather as compared to last summer. If weather in the third quarter was normal overall, we estimate it would add $0.18 per share, as compared to last year. At this point, there is a fair likelihood that weather will be better than normal in the third quarter. However, it is also likely that third quarter earnings will be negatively impacted by storm and higher fuel costs. Taking these drivers together, I would estimate our third quarter earnings this year to be between $0.80 and $0.85 per share.

Before I turn things back over to Gale, I would also like to briefly discuss our outlook for 2011 and 2012. As we have said in the past, we expect 2011 to be a watershed, as it will be the first year that we expect to have 12 months of earnings from all four of our Power the Future units. Our current expectation for earnings in 2011 is $4.10 to $4.20 per share. At the midpoint of this range, or $4.15, I estimate the return on equity in our utility segment would be about 10%.

Moving now to 2012, we are not prepared to give earnings guidance for 2012. However, I did want to give you input on each of the segments. Starting with the utility segment, average total rate base for the combined utilities is expected to grow from approximately $5.7 billion in 2010 to $7 billion in 2012. Total rate base includes net plant in-service as well as construction work in progress, working capital and other capital invested in the business. I would note that the $7 billion figure for 2012 is consistent with the revised three year spending outlook I mentioned earlier.

At We Power, as in 2011, we expect all four of the new plants will be operational for all of 2012. As a result, the total earnings contribution from this segment is projected to be approximately $1.33 per share including allocation of $375 million of holding company debt. The earnings contribution from our investment in American Transmission Company should be about $0.34 per share and unallocated holding company interest expense should amount to a $0.17 per share reduction. We hope this information will help you develop your own estimates of 2012 earnings. So, with that, I'll turn things back over to Gale.

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

And now, ladies and gentlemen, we would like to take your questions. (Operator Instructions) We will take our first question from Scott Senchak with Decade Capital.

Hello, Scott. How are you today?

Hello, guys. It's actually [Reza].

Oh, Reza. What have you done with Scott?

Well, he's is in the background and he's listening also.

Okay. How you doing, Reza?

Pretty good. A lot of new information. What are we as -- are you expecting to earn in 2011 at the utility?

In our $4.10 to $4.20 earnings projection?

As I mentioned in the script, $4.10 to $4.20 range. If we were right at the middle of that range, or $4.15, that would be about a 10% return on equity.

10%. And then you mentioned a CapEx reduction $250 million, that's a total reduction over three years, correct?

Correct.

That's correct. And what we will do when we file the Q later, or in a few days, we'll have a new three year summary in the 10-Q. So, by segment for each of the three years. So, we'll put that in the 10-Q so that you have the details.

And I'm sorry if I missed this, but what were the drivers that took that $4 to $4.15-ish?

Well, one of the things that when I talked beginning last September about the outlook for 2011, we talked about $4, and included in that $4 was the assumption that the utility would earn, I believe, approximately $2.61 a share. And I said at the time, that the utility, I expected, would earn at least $2.61 a share. And I think as we've gotten further along and we sharpened up our plan, we're more comfortable now increasing our return expectation at the utility. But that's really the key difference, Reza, that moved the outlook that I talked about last September from the $4 to the range of $4.10 to $4.20 now.

Yes. Allen's right. All the other basic assumptions on the segments that we cover with you, like American Transmission Company and Power the Future assets, those are all the same.

And just lastly, does the higher earnings in 2011 at the utility imply that you brought forward some of the 2012 earnings in a way?

No.

So, that means there's a -- how should we think about that from 2011 to 2012?

The way I'd suggest, Reza, you think about it is if you look at, on the replay you can hear again very specifically, the elements of our 2012 plan that Allen laid out for you, the retail rate base from our franchise businesses, the expected contribution from Power the Future earnings, the American Transmission Company contribution. That's how you should look at it. Take a look at what you think we will earn in the utility and then add all the other elements together and you can come up with your own best estimate. But it is not -- our new 2011 estimate is not moving something forward at all from 2012.

Okay. Okay. Great. Thank you.

Thanks for the questions, Reza.

And moving on to Michael Lapides with Goldman Sachs.

Hi, Michael. How are you?

I'm fine, Gale. Congrats on a good quarter and good first half of the year.

Hey, Michael, tell me about the sandwiches for your conference. They going to be any better than last time?

I've had sandwiches and water conversations about it. Remind me one day to tell you a fun water story. And you know what? In the next five or ten years we may all have covering this industry a lot of fun water stories. I want to -- can you rehash a little bit some of the utility components of the information you gave out for 2012, specifically the rate bases? And can you break that down between WEPCO, Wisconsin Gas, and just how we think about electric and gas components of that?

Well, the $7 billion figure, of course, is a combined number. I don't have anything today that would specifically break that out between electric and gas. But if it will be helpful to you, Michael, if you broke it between -- maybe in three categories, fixed asset rate base, CWIP and then all other capital, it's about $5.7 billion of fixed asset rate base, about $400 million CWIP, and then the balance is all of the other capital that we have invested in the business. And going forward, really the reason I talk about it now on that basis, I think it's highly likely that we'll be merging at the beginning of 2011, we'll be legally merging Wisconsin Electric Power Company and Wisconsin Gas. So, hopefully that's helpful for today.

Michael, the reason -- we haven't talked a lot about it, it's really we're trying to basically manage our gas operations as one operation. But we have gas operations in the Wisconsin Electric Corporation. We also have a separate large gas operation under Wisconsin Gas. And we're in the process now of getting Commission approval, essentially, to put the Wisconsin Gas operational rate base into Wisconsin Electric's total rate base.

Got it.

So, no change but we're just trying to continue to look for any efficiencies we can.

How should we think about -- there's always differences for you and many of your peers in terms of the GAAP equity layer at the utility subsidiaries versus the regulated equity layer at the subsidiaries. I'm just trying to think about some back of the envelope rate base math for 2012.

I think you can make your own assumptions and we, of course, will have a rate case in 2011. And the Commission will have an opportunity to look again at allowed rates of return and capital structure. But I think a starting point would be roughly 50% of rate base as equity. So, this rate base figure, of course, doesn't include any goodwill or anything. So, if you're looking to estimate the earnings power of the company, make a direct assumption about the regulatory equity ratio, apply that ratio to rate base and then apply an allowed return, and should get you to a pretty reasonable estimate.

That's about as good a short-cut advice I think as we can give you, Michael.

Okay. And last thing, I'm thinking a little bit out further beyond 2012 a little bit. How much of the renewable projects south Oak Creek-- really, the wind, biomass and south Oak Creek drag on past 2012?

Well, actually, very little. If you think -- in terms of our current plan, now obviously there at some point there will need to be future renewable construction and/or purchased power agreements. But if you think about what is clearly in the pipeline approved and underway, in terms of construction, the very significant expenditures for the environmental controls, the upgrade of the environmental controls at the older Oak Creek units, that we expect to have in-service before the end of 2012 and as I mentioned in the script, we're about 40% complete with construction now. So, that should be completely finished and in-service by the end of 2012. Then if you look at our Glacier Hills Wind Park, which we, as I mentioned, we broke ground on in the second quarter, Rick is projecting that to be in-service before the end of 2012. And so, we have a fair amount of the projected spending already underway out in the field. And then for the biomass plant, which we are hoping to receive approval from for late this year or early next, the projected in-service date would be late 2013. That's the one very significant project that would be a 2013 in-service. Rick, anything to add on that?

No. You hit it right on the head.

Although, just keep in mind though, that $7 billion number includes construction work in progress. So, to the extent you expend dollars on the Domtar biomass project, 2011 and 2012, and we do, that gets into the construction work in progress balance, and therefore into the $7 billion figure that I talked about.

Right.

Got it. Okay, thank you, guys. Much appreciated.

See you in a couple weeks, Michael.

Thanks.

Jay Dobson with Wunderlich Securities has the next question.

Hello, Jay. How are you today?

Very well, Gale. How are you?

Yes. Hanging in there. We're doing fine.

Outstanding. Allen, the entire $7 billion, just for clarity, would actually be earning?

Yes.

Earning a return? So, that is, to the earlier question, something we could be doing back of the envelope on and will be through the regulatory process in the 2011 case?

Yes, one way or another. Now, of course, what you typically see with CWIP balances, at least rate making Wisconsin, typically they'll have the half the CWIP and rate base and you'll get some AFUDC treatment on the other CWIP. But in answer to your question, if you're looking at book earnings, yes. Earning one way or another, just understand there may be a piece of CWIP that's still getting AFUDC treatment in 2012.

Okay. That's great. And then, on the 2011 guidance at $4.10 to $4.20. How did the changes, or at least legislatively-driven changes, in fuel help that? I mean, I think in the $4 number there was still a bit of a drag you had to assume. Has that evaporated and how did that impact the new guidance?

Jay, when we look at year ahead guidance, our essential planning assumption is basically fully recovered on fuel. So, that really doesn't change from plan to plan.

Got you. So, really none of the $4 to $4.10 to $4.20 was impact by the potential new fuel recovery rate?

You are correct.

Brilliant. And then Gale, remind us, I'm turning to the renewables versus the, what I'll call modified benchmark of 8.25% of sales by 2015. If we, remind us, if we added Blue Sky and Glacier Hills and the Domtar facility together, where would we be versus that benchmark?

Well, maybe we can start you with where we are today. With Blue Sky in-service and with some of the other purchased power agreements that we have and some of the other renewables that we're getting credit for under the law, we're at about 4.25% today. Then, adding 50 megawatts of biomass, and if later in the plan, one possibility is that we've been talking about with the environmental groups, is adding, in essence, another 12 megawatts of solar, or actually 12.5 megawatts of solar that we would start feathering in 2013. That plus some purchased power agreements, we basically need about, to get to the 2015 requirements, we probably need another 500 megawatts of stuff.

And that assumes, Jay, you do Glacier Hills, you build that into the base, you do the 50 megawatt biomass, the 12.5 megawatt solar, and then longer-term you'd have to do some more wind projects.

Yes. Because we will be -- Jay, this is Rick Kuester. We will be overcomplying in the few years leading up to 2015. We can bank those credits, so that allows us to comply in maybe 2015 and 2016. But then our bank is basically expended and we'll be short of the 8.27% requirement.

Okay. Got you.

And because of the way -- Rick makes an important point. Because of the way the banking works, we simply can't wait until 2014 or 2015 to begin planning the next round of what we're going to do to meet the mandate for renewables because the bank exhausts itself under our current plan and there you are. You're short by 2016-ish.

So, you have to be in long-term compliance is what we're saying.

No. Perfect. That's helpful. But just for clarity then, back to, not sure who asked it -- the earlier question around CapEx beyond that 2012, 2013 time frame, we should be thinking about that 500 megawatt even if some of it's going to be purchased power, your construction of some portion of that 500 megawatt requirement as being the source of some of your capital spending.

That is correct. And again that would be because we need to be in continuous compliance of the mandate after -- from 2015 going forward.

Okay. Perfect. And then last question, Allen, with adding the Oak Creek units, it's always a little hard to get transparency into the O&M numbers of which you guys have historically done a great job managing. Could you just give us an idea of the underlying O&M not driven by the newer assets. What's going on there and do we continue to see some trend lower, or is that something that we hit bottom now and we should see that trend be with inflation or with some other exogenous factor?

Well, I think if you look at quarterly O&M variance, the number I recall for the new Oak Creek plants is about $16 million worth of additional O&M spending second quarter this year versus second quarter of last year. So, I think, Rick, we pretty much established now the run rate -- we have the folks hired, we pretty much established the run rate for Oak Creek and that was about increasing the run rate about $16 million this quarter versus the second quarter of last year. So, that's pretty much in the base now, Jay, if I'm understanding your question, and then we'll have to expend O&M going forward for renewables.

We've got some people though still working on Unit 2 that are being charged to capital projects. So, the base hasn't quite been set yet.

Okay, got you. But again, that underlying O&M, my question is really understanding you're adding that Oak Creek and so, looking at an O&M comparison is absolutely going to be up because you're adding costs you weren't incurring 12 months ago. But then, if we were to exclude that, the underlying same-store sales, however you want to think of it, the O&M this year that would be, in fact, fully comparable with the O&M last year, what are the trends of those numbers?

Oh. You're saying excluding the additional assets and people that we're bringing on to run those assets?

Yes, sir.

For the remainder of the year, I would say flat.

Brilliant. And where in the future do you think that starts trending higher? Obviously, I knew you had instituted some austerity and some ability to cut costs as a matter of the environment we all saw in 2009. At what point does that start trending higher just necessarily because you run out of some of these cost management efforts or other elements?

We continually look at how to control costs and how to become more efficient. But again, for example, next year we would have union wage increases that are mandated under the contract, so I would think you would have some modest uptick in O&M next year.

That is great. Thank you so much. Gale and Allen, really appreciate it.

Jay? Jay?

Yes?

Got a question for you.

Yes?

That exogenous, do they teach that word in analyst school?

Absolutely. It's a requirement. You have to know the definition.

Take care, Jay.

Thank you.

And moving on to Paul Ridzon with KeyBanc.

Hello, Paul. How are you today?

I'm fine. Yourself?

We're doing well.

2010 CapEx down $130 million, what's not getting spent?

Well, about $67 million of that $130 million difference is timing associated with the south Oak Creek AQCS project. So, that's the biggest single thing. The other variances, the renewables are -- really no change in the renewable budget. And then there's about $30 million which we had in the original budget for SCRs. Our piece of the SCR expense capital at Edgewater 5 and now it's pretty clear that we're going to sell that unit and the new owner will expend those dollars. So, that gives you $97 million of the variance. So, $67 million AQCS, $30 million was the Edgewater 5 SCR. And then the rest is sprinkled throughout the business. Is that helpful?

Yes. Thank you. And the fuel legislation, this just eliminates the dead band where you either retain for a period of time? You basically have a fuel clause at this point, correct?

It really won't, believe it or not, it really won't eliminate the dead band entirely. The legislation says there has to be a symmetrical, if there's going to be any kind of bandwidth, it has to be symmetrical on the upside and on the downside. And right now, it appears that the Commission would like to have somewhere between a 1% and 2% bandwidth. The difference being -- there are two major differences in how the fuel clause going forward is likely to work compared to how it's been working. One is that the Commission would ask each utility to, if it expected to change in fuel costs in the new year, to come in the fall of the prior year and essentially present a fuel case in a one day hearing, and then assuming the Commission agreed that it was reasonable, the new fuel rate would go into effect January 1. That in and of itself will help would help considerably in reducing any kind of lag in recovery. And the second is, you wouldn't have to go in in the next calendar year unless something extraordinary happened because either above the 2% bandwidth or below the 2% bandwidth there would be escrow accounting. So, that's essentially the developments in this new fuel rule as it seems to be taking shape. I think it would be a significant help in terms of more current recovery and lesser lag of our fuel cost recovery.

What was the under recovery in the second quarter of 2010?

Second quarter of 2010? Well, I know for the six months we're down about $30 million.

Yes. For the second quarter, I believe it was $6.5 million itself. Within the quarter itself. And it was about $4.4 million in the same quarter of 2009.

And then for the full six months, right about $30 million under recovery.

Right.

And then back to the back of the envelope regulatory math, we can take $7 billion of rate base but about a 50% cap structure and assume an ROE somewhere within spitting distance of 2010? Or is that just an extreme simplification?

No I wouldn't view that as an extreme simplification. But you'll have to put your own numbers around that because, as I said before, we have to go through a rate case and the Commission gets to re-look at all those parameters. But, I don't think what you've done is an extreme oversimplification.

I agree. And we're simply trying to be helpful to all of you who've got so many questions about 2012. And we thought showing you the basic elements of how we look at the business might be useful.

Okay. Thank you. I better get off and leave some time for Dan.

There you go. Thank you.

We will move on to Steve Fleishman with Bank of America Merrill Lynch.

Hi, Steve, how you doing?

Hi, Gale. Just a question on the $7 billion of rate base. I'm wondering if maybe Allen has the numbers for, comparable to that for 2010 or 2011? Because when we add it up, that's a little higher than we're getting.

The 2010 number, while I have it looking, is $5.7 billion.

Okay. And if we were just doing the simple math of CapEx, less depreciation and deferred taxes, is there anything that is moving these numbers differently than you would normally calculate between 2010 and 2012?

No. And maybe I'll just go ahead and give you the 2011 number, the rate base there would be about $6.4 billion.

Okay.

So, the trajectory we're on, Steve, as Gale mentioned, the $5.7 billion this year, $6.4 billion in 2011 and then trending to the $7 billion in 2012.

Okay.

That's the trajectory and there's nothing new or different about the way that's calculated.

No. It's all as you would expect, Steve.

Okay. Great. And just in terms of the -- when you look at Capex in 2012, you're still not including anything for the next potential wave of environmental issues on the EPA, on Valley or some of the other older coal plants?

Steve, you're exactly right. Nothing would be in there for any future environmental projects that might be required by the new EPA rules.

And Steve, one thing. Maybe, I don't know if this might be a difference in the modeling you've been doing on rate base in the past, but remember, the Commission did change our depreciation rates in the last rate case and that's a fairly significant number. That reduced annual depreciation $16 million a quarter, something like that. So, you want to make sure -- that might have been different in your model. Don't know.

That was based, obviously, on a brand-new depreciation study that was done as part of last rate case.

Okay. Anything strange with your deferred taxes over this period, or pretty consistent?

If you're looking at the 2010 to 2012, pretty consistent.

Okay. Okay, thanks.

You're welcome, Steve.

And our next question will come from Bill Appicelli with Morgan Stanley.

Hi. Good afternoon.

How you doing?

Good. I think most of my questions have been asked and answered. But on the rate base of $7 billion, that's a year-end number, is that correct?

No, that's an average.

An average.

That's an average. Okay.

That's an average for 2012.

Okay. And then on the dividend policy, is there is any change there? The 40% to 45% in 2011 and then targeting 45% to 50% for 2012 and beyond?

No. At the moment, our Board has set that dividend policy. Obviously, we re-look our dividend policy every year, but that policy is set for, certainly for this year. And we will again, re-look our dividend policy, as we always do as a matter of course each year. But at the moment, no change.

Okay. Thank you.

You're welcome.

And we'll now hear from Andrew Levi with Tudor Pickering Investment Bank.

Hello, guys. I'm all set. I'm all set.

Okay. Thanks, Andy.

Yes.

I think we are ready for another call if there is one. Operator are you still with us?

I hope I didn't scare her off.

I think you may have scared her off. Are you in New York, Andy?

Yes. Yes, at times. Sometimes in Houston.

Okay, very good. Well, I'm not sure exactly what's going on with our Operator or with the phone lines. But we appreciate your hanging on there. Andy, I'm not sure you need to hang on if you want to go on to another call or other work, feel free.

Maybe that will get you going.

That might get us going.

Thanks, Andy.

Thanks, Andy. You take care.

Okay. I'll try.

All right. Bye-bye. Well, absent any other calls and absent our operator, I think we're having, must be having some technical problems. We certainly appreciate you taking part in the conference call today. If you have any other questions, Colleen Henderson will be available in our investor relations office. Her direct line 414-221-2592. Again, that's 414-221-2592. Have a good afternoon, everybody. Bye-bye.