埃克西爾能源 (XEL) 2011 Q3 法說會逐字稿

Welcome to Xcel Energy's third-quarter 2011 earnings conference call. During today's presentation all parties will be in a listen-only mode and following the presentation the conference will be open for questions. (Operator Instructions). This conference is being recorded today, October 27, 2011. And I would now like to turn the conference over to Paul Johnson, Vice President of Investor Relations and Financial Management. Please go ahead, sir.

Thank you and welcome to Xcel Energy's third-quarter 2011 earnings release conference call. I'm Paul Johnson; with me today are Ben Fowke, Chairman, President and Chief Executive Officer; Teresa Madden, Senior Vice President and Chief Financial Officer; Dave Sparby, Senior Vice President and Group President; Scott Wilensky, Senior Vice President and General Counsel; and George Tyson, Vice President and Treasurer.

Today we'll discuss our third-quarter results and accomplishments. In addition, we'll provide an update to our 2011 guidance and introduce 2012 guidance. Please note that there are slides that accompany the conference call which are available on our webpage.

In addition, please note that some of our comments may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and our filings with the SEC.

Today's press release refers to both GAAP and ongoing earnings. Third-quarter 2011 ongoing earnings were $0.69 per share compared with $0.62 per share in 2010. Third-quarter 2011 GAAP earnings were also $0.69 per share compared with $0.67 per share in 2010. Last year third-quarter GAAP earnings included a non-recurring benefit of $0.05 per share related to the settlement of a lawsuit.

Management believes ongoing earnings provides a more meaningful comparison of results and are more representative to Xcel Energy's fundamental earnings power. Therefore, we will be discussing ongoing earnings today during our review of third-quarter results. Please see our earnings release for a reconciliation of GAAP ongoing earnings results. I'll now turn the call over to Ben Fowke who became CEO of Xcel Energy in August of this year.

Thank you, Paul, and welcome, everyone. Let me just say that I'm truly honored to be CEO of Xcel Energy. We have a great Company with a strong balance sheet, a sound strategy, a constructive regulatory environment, a visible pipeline of investment opportunities, engaged employees and a history of delivering on expectations while managing risk.

I will build on our great tradition with an emphasis on improving earned returns while continuing to provide our customers with safe, clean, reliable energy at a reasonable cost. So with that let me turn to our results.

This morning we reported third-quarter ongoing earnings of $0.69 per share compared with $0.62 per share in 2010. These results represent a continuation of solid performance this year and give us confidence that we will deliver 2011 earnings in the upper half of our guidance range of $1.65 to $1.75 per share, which is consistent with our 5% to 7% earnings growth objective.

Now I'll brief you on some recent developments beginning with an update on our regulatory proceedings. This has been a busy one for us with several rate requests pending. As most of you are aware, we arrived at constructive settlements in North Dakota and New Mexico.

In North Dakota the Commission recently held hearings on the settlement we reached with [staff] which would result in a rate increase of about $14 million in 2011 and an additional step increase of $2 million in 2012 if approved. This is a black box settlement which was based on a 10.4% ROE. The settlement represents approximately 76% of our requested increase.

We also reached a settlement in our electric rate case in New Mexico. The black box settlement is unopposed, resolves issues and increases rates by $13.5 million effective January 2012. Here again the settlement if approved represents approximately 68% of our requested rate increase.

We expect the North Dakota and New Mexico commissions to rule on these settlements by year end. We're also discussing a potential settlement agreement in the Minnesota rate case.

While we believe our request in Minnesota is reasonable, we think working towards a settlement has the potential to lead to a constructive outcome, especially in light of the delays the case has experienced and considering the overall economic environment. If our efforts are successful we would expect that an agreement could be sent to the Commission by year end.

These settlements are evidence of our ability to effectively manage regulatory risk. Their constructive outcomes if approved position us to continue delivering on our financial objectives in 2011 and beyond. Next I'd like to comment on EPA's recently issued Cross State Air Pollution Rule or CSAPR.

As you're probably aware, CSAPR impacts our operations in Minnesota, Wisconsin and Texas. While we have proactively addressed environmental issues, the late inclusion of Texas and the required compliance by 2012 creates significant issues for SPS. SPS has very limited options to comply with the rules by January 2012. This short time frame does not allow for the installation of additional control equipment at our coal plants.

In addition, SPS doesn't have many viable options to comply with the new rules due to transmission constraints that limit energy imports and the expected lack of a liquid allowance market in the region. Xcel Energy is one of many parties challenging the recently proposed EPA rules. Over 45 petitioners, including 13 states, several utilities and other filed challenges to CSPAR in the US Court of Appeals for the District of Columbia Circuit. 12 separate motions for stay, including our motion, are pending before the court.

Although the outcome of any litigation is difficult to predict, we are confident in the strength of our challenges to the rule. Clearly we're not alone in challenging these new rules and are encouraged that FERC commissioner Moeller has stated that the timing of these rules is too aggressive and could hinder grid reliability.

The EPA itself appears to recognize the potential problems with the rule and has proposed modifications. While we don't believe these adjustments go far enough to alleviate our concerns, we're optimistic that a more reasonable time line may be established.

To address CSAPR ultimately we'll need to increase our capital investments at SPS. We will update you on our plans, including an updated capital expenditure forecast, at our analyst meeting in December.

Now most of our comments on our conference calls tend to focus on financial results. However, operational excellence is a cornerstone at Xcel Energy. Periodically it's helpful to provide an example to emphasize this point.

This summer 80 mile per hour winds and rain damaged 94 miles of infrastructure including transmission lines, turbines, wind collectors and distribution lines in Southwestern Minnesota. I'm pleased to report that we completed the design and reconstruction of 64 miles of transmission infrastructure and energized it with new and stronger structures in less than three months. The remaining wind collector feeders were completed in mid-October.

The successful and timely completion of this project demonstrates the people, alliances, resources and internal processes are in place to achieve outstanding results.

I'd now like to introduce you to Teresa Madden, Senior Vice President and Chief Financial Officer. Many of you met Teresa over the years at various investor conferences. I've worked with her for many years. She has incredible depth of understanding of every aspect of the Company's finances and I have every confidence that she will be an outstanding CFO. Teresa, the floor is yours.

Thanks, Ben, for the kind introduction, and good morning to everyone on the call. Today I will discuss our third-quarter results, our recent financing activity, update you on other pending rate cases, and close with our 2012 earnings guidance. Let's begin with a review of the significant drivers on the income statement.

Strong growth in third-quarter earnings was largely driven by a $139 million increase in electric margin. Significant drivers include a $41 million increase from interim and final rates in multiple states; a $29 million increase in revenue requirements reflecting the acquisition of two natural gas power plants in Colorado, this margin impact is partially offset by higher O&M, depreciation, property taxes and financing costs associated with these facilities; a $19 million increased from higher sales as a result of warmer than normal weather; and an $18 million increase for conservation and DSM revenue incentives.

Natural gas margins increased modestly by $4 million over the quarter. As you're probably aware, natural gas usage is relatively minor in the third quarter. Partially offsetting the improvement in our electric and gas margin were increases in a few expense categories that I will review.

O&M expenses increased $23 million or 4.6% largely driven by increased plant generation, labor and employee benefit costs. In addition, due to warmer than normal summer temperatures, we are spending incremental O&M to ensure continued system reliability and high customer satisfaction. As a result we now project our annual 2011 O&M to increase approximately 4.5% which is modestly above our original guidance of an increase of 4%.

Also offsetting some of the improvement in margin was higher depreciation and amortization expense which increased $21 million or 9.3%. The increase was driven by incremental capital investments including the Nobles wind farm that went into service in 2010 and the new two natural gas plants we acquired from Calpine. Higher property taxes, primarily in Colorado and Minnesota, led to a $7 million or 8.8% increase in taxes other than income.

Finally, during the quarter we announced the redemption of $105 million of preferred stock and incurred a call premium of a little over $3 million which is not tax-deductible. This opportunistic financing streamlines our capital structure and lowers our cost of capital.

Now I will review the results of each of our operating companies. First, earnings in NSP Minnesota increased by $0.05 per share largely due to higher interim electric rates in Minnesota and North Dakota and conservation incentives partially offset by higher O&M expenses, property taxes and depreciation expense.

Second, earnings at PSCo were flat for the quarter. Higher margins, primarily due to weather, were offset by higher O&M, property taxes and depreciation expense.

Third, NSP Wisconsin earnings were also flat for the quarter. The positive impact of new electric rate was offset by higher O&M and depreciation expense.

Finally, earnings at SPS increased $0.02 per share largely due to an electric rate increase in Texas and higher sales driven again by hot weather. Similar to our other opcos, these gains were partially offset by higher O&M expenses, property taxes and depreciation expense.

Now turning to the balance sheet, we were very active on the financing front during the third quarter issuing $700 million of debt at very attractive interest rates. At PSCo we issue $250 million of 30-year first mortgage bonds with a 4.75% coupon. At SPS we issued $200 million of 30-year first mortgage bonds at 4.5% which temporarily tied the record for the lowest 30-year coupon across all corporate sectors.

In addition, at the holding company, we took advantage of historically low rates and issued $250 million of 30-year senior notes at 4.8%. This represents the lowest 30-year coupon ever for a utility holding company bond.

Earlier Ben provided an update on several of the rate cases in which we've either agreed on or are working towards a settlement. We do have a few other rate cases pending that are expected to be wrapped up by year-end or in early 2012.

In South Dakota we filed a request to increase electric rates by $14.6 million based on a 2010 historic test year adjusted for known and measurable changes, an 11% ROE, an equity ratio of 52.5%, and an electric rate base of $323 million. There have been delays in the South Dakota rate case process and we don't anticipate a decision until the first quarter of 2012. As a result we are planning to request interim rates to be effective in January of 2012.

At NSP Wisconsin we filed a request with the Public Service Commission of Wisconsin to increase electric rates by $29 million and gas rates by $8 million. The filing is based on a 2012 forecast test year, 10.75% ROE, an equity ratio of 52.5%, an electric rate base of $718 million, and a natural gas rate base of $84 million.

Earlier this month staff filed testimony and recommended an electric rate increase of approximately $18 million and a natural gas rate increase of about $3 million, both based on an ROE of 10.3%. The staff recommendation reflects a lower ROE and adjustments to nuclear cost, employee compensation and benefits, as well as a recovery of future MGP costs. We filed our rebuttal testimony last week and expect the Commission to rule on the case by year end. We anticipate new rates to be effective in January 2012.

Looking ahead, we plan to file an electric rate case in Colorado during the fourth quarter. As you recall, we are required to file an electric rate case in Colorado prior to April 2012. A few noteworthy items -- we plan on requesting interim rates to be effective in the first quarter of 2012 and we are also discussing the possibility of a multi-year rate plan with key stakeholders to determine whether this approach can be implemented through this case.

Constructive outcomes in these cases combined with the anticipated approval of the settlements in New Mexico and North Dakota, as well as the constructive outcome in Minnesota are key components of our 2012 earnings guidance which we are introducing today.

For 2012 we expect earnings to be in a range of $1.75 to $1.85 per share, which is consistent with our 5% to 7% earnings growth objectives. Using 2009 as the base year, the low end of the 2012 guidance range represents 5% compounded earnings growth with the upper end representing compound earnings growth of 7%.

Some of the key drivers for 2012 include -- very modest electric and gas sales growth including the impact of an additional day of sales due to the leap year; step-in rates in Minnesota; new rates in Wisconsin, South Dakota and New Mexico; increased rates from the planned 2012 Colorado electric case; incremental revenue from various capital riders; and finally increased AFUDC equity earnings associated with our capital investment program.

These drivers will be offset by higher O&M, depreciation and property taxes. For more information see our earnings release for a listing of our preliminary assumptions. We plan to provide additional information related to our 2012 forecast, including an updated five-year capital expenditure plan, at our analyst meeting on December 1 in New York.

In closing, we're pleased to report another strong quarter. As we enter the last two months of 2011, Xcel Energy is well positioned for continued success. We're on track to deliver 2011 earnings in the upper half of our guidance range; we financed our growth at historically low interest rates; we're continuing to demonstrate our ability to manage regulatory risk across several jurisdictions; and finally, we've established 2012 guidance that is consistent with our earnings objective of 5% to 7% growth.

That concludes my prepared remarks. Operator, we will now take questions.

(Operator Instructions). Kit Konolige, Ticonderoga.

Good morning and, Ben and Teresa, welcome to your new positions.

Thank you, Kit, good to hear from you.

Thank you.

Just a couple of quick questions. I was -- first of all, I was hoping you could give us a little sense of what the other key stakeholders in Colorado, who they would be and some kind of read on how likely you think it is that a multi-year plan would be a possibility? And secondly, I'd be interested in what your 12 guidance or outlook assumes about equity issuance?

Well, I'll take at least the first part of that question, Kit. I think our stakeholders in Colorado are just who you think they would be -- the Commission itself, the staff, the consumer advocate groups and of course larger C&I type customers. So we're working with all those stakeholders now as we try to put together a plan that they can buy into and that's been a significant portion of our outreach efforts over the last year. In terms of equity, I'll let Teresa handle that.

In terms of equity, we're currently not planning to issue any equity outside of our DRIP programs for 2012. However, we will be opportunistic and if conditions warrant we potentially could maybe enter into a forward equity sale. But currently no plans for any equity issuances outside just our normal DRIP.

Thank you.

Greg Gordon, ISI Group.

Your Analyst Day is going to be in early December and the final NESHAP rules posting date has been delayed now until mid-December. So are we still going to get a reasonably good read on what you think the potential environmental spend is going to look like? Or is that something that we're going to have to wait for until after we see the final rule?

Greg, I didn't hear which you rule you're referring to (multiple speakers).

The Mercury Rule, the Mercury Rule.

Yes. Yes, I think we can give you a pretty good -- the biggest variable for us is going to be the CSAPR Rule and that's been -- that, as you know, as I mentioned in my remarks, we're litigated. We'll probably get some kind of response first quarter I think is what we're anticipating next year. So that will be a little bit later most likely than when we're at the analyst meeting.

But we have run various scenarios on how we would respond and how we can respond to CSAPR and we're going to share that with you in December. Greg, keep in mind that last year when we issued the CapEx forecast we had a placeholder for all of these EPA rules. And if I recall correctly at SPS it was about $400 million during the five-year timeframe.

So we'll update that. Obviously timing and some other things might change, but I think we're anticipating at some point having to do these things; we just weren't anticipating having to do it by January of this year -- coming year.

Okay, great. Thank you.

Paul Ridzon, KeyBanc.

Couple things. Can you put book ends around what the impact of trading and fuel swings were in the quarter? It looks like that might have driven part of the earnings.

In terms of trading was very small. And when you say fuel, in terms of you referring to the deferred fuel adjustment?

Yes.

That deferred fuel adjustment was actually in the third quarter of last year and it was around $20 million. So actually this year we're not -- we don't have any adjustments like that. So that's the primary driver.

Okay, thank you. And with the expedition of the process for the Hampton LaCrosse line, how do you view that impact? Do you think it will accelerate or does it make you feel comfortable with the current schedule?

It makes us feel comfortable with the current schedule, Paul.

Okay, thank you very much.

Paul Fremont, Jefferies & Company.

A quick question just on understanding the upcoming Colorado filing. Should we assume that just to stay even with where you are right now you're going to need to file at least for the $121 million of non-fuel expense that's currently in the rider?

Go ahead.

This is Scott. We would need to incorporate the transfer of what's currently in the PCCA rider for the Calpine assets into our base rate request. And you're right, that's about $120 million. We'd also anticipate that we'd have a rate request that's incremental to that.

So in other words the comparator then should be anything over and above; $120 million would be essentially an increase over what you're currently collecting in that state?

That's right. And when we actually notice the filing there's a legal notice that would require that we indicate that $120 million as part of the request. But as we try to share this with our customers we'll indicate that the level of the increase is the true increase to customers' bills, not the transfer of the Calpine assets from the rider to base.

And just as a point of clarification, I'm assuming that the premium paid for the preferred stock is a nonrecurring expense item, even though it's included in your ongoing EPS calculation?

It is nonrecurring, that's correct.

Thank you very much.

Carl Seligson, Utility Financial Experts.

I'm somewhat concerned, although it's been beaten back at other places, about what's going on in Boulder and the effect that that might have on other Colorado communities as far as municipalization. Could you give us a few words on that?

The votes by ballot are due November 1, so I'll be able to tell you how it all turned out here pretty shortly. You know, Carl, Boulder has had a history wanting to municipalize, so I really wouldn't -- I really don't think it's indicative of other cities and municipalities in Colorado.

And just to reiterate, we want to continue to serve Boulder. I think -- well, you might be aware, Carl, we had a major snowstorm in Colorado and it impacted Boulder and I think it's just another example of the service we provide. We had -- we were prepared, we called crews up from SPS and out from Grand Junction and we had them ready and available the night before the snowstorm.

So we do a pretty good job of serving, we do a good job of providing reliable energy and clean energy. And I sure hope the citizens see it that way too. If not, we'll work with them and, it will take a while, but we'll figure out a fair price so that our other customers in Colorado aren't disadvantaged. But I don't think the short answer to your question is that it's a trend that you're going to see across our jurisdiction.

Great, thank you.

Justin McCann, S&P Capital.

It's S&P Capital IQ. Good morning. Regarding the economic outlook in your service territories, in which states do you have the greatest concern?

Greatest concern?

Yes.

I would say that the states that we're seeing that flattest sales would be Minnesota and in Colorado, which happen to be our two largest states. We're seeing very robust -- well, much greater sales in Texas and we're seeing an uptick in Wisconsin as well.

You've got to keep in mind though that when the recession hit the hardest a few years ago, we were much less impacted than other parts of the country. So we're not seeing the rebound, we continue to see sluggish and flat sales, but we weren't hurt as bad as others to begin with. And there are signs that the larger C&I customers are starting to pick up -- they always have in Texas, but in other regions as well.

Okay, thank you.

Ali Agha, SunTrust.

Ben or Teresa, are we -- going back to your plans for equity issuance, I know in the past you've said no earlier than 2012, which would imply you know say '12 or '13 just given the CapEx program. Is that still a fair way to think about it? I mean if it's not '12 it's likely '13, but you made the opportunistic in '12? Is that the way we should be thinking about it really?

Well, as I said before, we're not planning any in 2012, but if we saw an opportunistic option we may potentially sell an equity forward.

And Ali, I don't think that there's anything more we'd comment on related to equity. And as a point too, we've always said no equity in '11; we haven't really talked about '12 before.

Okay, that's right. Maybe I was getting my years mixed up.

Yes, I think what we've done, Ali, is just give the amount of equity we need over a multi-year time frame. And we look at market conditions and all the other things that you would think and we make the -- we pick when the best time is.

Okay. And then a second question, just looking at the results as they've come through say maybe on an LTM basis, and I don't know if you weather adjust or not. But can you just remind us what kind of lag is still in the system in terms of what the earned ROEs are versus authorized across the portfolio?

Sure, Ali. In terms of our earned authorized -- or our earned ROE at the utilities, there tends to be around an average of up to about 100 basis points. But we do pick up from leverage in the holding company probably around 50 basis points. So hopefully that helps.

Ali, I think you always -- you raise this question, I think it's a great one. We certainly are going to address regulatory lag. We have the riders, we have the forward test years, but things like an expanded CapEx program, sluggish sales, they've kind of kept us spinning our wheels on regulatory lag. Multi-year rate cases, etc., will help tremendously to close that lag. We're under earning now, so I think if we can close that gap that would be a nice pickup for us.

Yes, Ben, and so just to get a flavor, given the flurry of rate cases going on and so on, I was just curious. There's always that lag, but where would you say you are in the cycle? Is it historically narrower than normal, wider -- just to get some flavor of how it's looking?

A little hard to -- we're enjoying some good weather this year, Ali, so it's a little bit -- I would just say normal, unless anybody else has a different take on it.

No, I think that's correct.

And final question, looking at your remainder of PPAs with other IPPs, are you seeing more opportunity today to do that Calpine type acquisition of assets or are the conditions or the PPA terms not ripe today to replicate something like that?

Well, that's a great question. We're always looking, we're filing resource plans in our two major jurisdictions here over the next -- I guess it would be the next month. And you'll see what kind of resource we're needing; you kind of have to start there. That will work backwards with the opportunities to work with IPPs and PPA's.

Always looking, Ali, if it makes sense, then we will do it, but I don't think there's -- again, I don't see anything -- it's kind of neutral I guess is what I would say at this point.

Okay, thank you.

Leslie Rich, JPMorgan.

Hi, I wondered if I could go back to Texas for a minute for SPS and CSAPR. Assuming that you can't install a scrubber in 15 minutes and that you are forced to comply by 2012, would the -- I assume you would be purchasing emissions allowances. Is that recoverable from customers in terms of a pass-through, or would that be absorbed by shareholders?

No, that's -- all of what we would do is recoverable. Leslie, I'm not sure that there's much of an emission allowance market and that's the problem. So when we think about what we would do if we had to comply in 2012, we'd obviously wait to see if that emissions market developed. But in the absence of that we would try to basically a lot of ways turn our system upside down and run gas plants more like baseload plants and not run our coal plants nearly as often.

So the cost of that would be fuel. And that fuel is -- that's passed through to our customers. Obviously we don't think that's a good plan from a cost perspective and clearly it's not a good plan from a reliability perspective hence the suit that we filed. And again, I think -- I just think there has to be a more reasonable outcome than a 2012 compliance plan.

So if compliance was pushed off say one year, would that yield the same strategy?

I think one year would be pretty tough too, Leslie. I think it takes time to put -- I think the plan would probably be SCRs and NCRs and scrubbers and/or DSI type technology and that takes time. We would be looking for a longer time frame than that.

Okay, but importantly, the environmental CapEx, the incremental fuel costs from coal/gas switching and any emissions allowance costs are all recoverable?

That's our assumption. That would be the past practice.

Great, thank you.

Sarah Akers, Wells Fargo.

As a follow-up to that question, as you see CapEx ramping in SPS, can you remind us what kind of recovery mechanisms you have in place? If you're going to be spending a lot on environmental, do you have a rider? And if you don't would you pursue a rider in Texas?

Well, the recovery platform at SPS has improved and we continue to make sure that we can continue to improve it. So at this point we don't have a rider to cover these sorts of things. But I think we have the opportunity and just like we have in Colorado.

We are working with our stakeholders down there and I think we have a lot of stakeholder support to do the right thing for the system and to get the kind of recovery we would need too. So we're not there yet, but it's my anticipation that we would have a good regulatory plan to go along with this. Dave or Scott, I don't know if you want to add anything. Do you want to add --?

The only thing I would just add is we do have about 50% of our load in the wholesale market there and that's on a formula rate. And that would be picked up immediately even without rider relief at the states.

Okay, great. And then do you have -- since the last quarter do you have any update or progress on potentially adding wind in South Dakota?

Are you talking about North Dakota?

Yes, I apologize. Where [AmeriCorps] was canceled and then there might have been a follow on there.

We continue to look for opportunities there and we don't have anything to announce, but I can tell you that we continue to look for the opportunities and be in a position hopefully to take care of production tax credits. But obviously the math has to work for our customers as well.

Great, thanks a lot.

Scott Senchak, Decade.

Can you give us a sense of any increase or decrease in pension expense you expect to see from '12 -- in '12 from '11 if all bookmarks were made today with the returns and discount rates and everything?

We are expecting to see some increase between '11 and '12. And I would just say in general it's probably in the $30 million to $40 million range. That -- and we do have that included in terms of our assumptions. We have based that on a somewhat lower discount rate than we currently have in our 2011 at a 5.5% discount rate. So we have taken that into consideration. We do expect to see some increase, but we have factored that into our guidance.

I just might add to your question that coming into the year our plans were some of the better funded plans in the industry and we took a conservative approach with our plans. So while lower discount rates and asset performance in general hasn't been stellar this year, as we all know, I think we're in a lot better shape and will be in a lot better shape by the end of the year. So it's an expense for us, but we're better positioned, I believe, than most.

Okay, thanks. And then also just can you give us any color on why you guys kind of like the forward sale equity mechanism -- versus any of the other options?

Scott, I think the reason we like the forward is there is the ability to avoid the dilution impact. There is a cost to using a forward and so you want -- if you're going to use it you don't want to have something like that -- at least we don't want to have it outstanding for a year. But if you like the price of equity and you want to delay the dilution for four to six months it's not a bad way to go.

I think if you have a large capital expenditure it's not a bad risk management tool either. But it's just one tool that we have at our disposal.

Okay, thanks.

Paul Patterson, Glenrock Associates.

I just wanted to touch base with you on the wind contract that you guys have with FPL. Did you guys already discuss this? I apologize because I've been distracted a little bit here and there.

Are you talking about the Limon 2 project?

Yes, the one that decreased rates. It seems that you guys had made an announcement about -- and I'm just wondering if you could elaborate a little bit about what drove that and how things look in terms of the wind story out there.

Yes, Paul, I think what drove our decision to pursue that is that we think the economics, much less the environmental benefits, speak for themselves. The pricing was so attractive that one of the things that I think we probably need to do a better job of is talk about the economics of our wind portfolio, which average over years.

And the prices are lower today about $40 a megawatt hour, which on an energy basis is not a bad hedge against natural gas. And this is the same kind of thought process which drove us to say this is a pretty good deal, let's offer it to our customers. So from an approval -- I don't know if you're interested in the approval process, but --.

Well, I would think you'd get it. I mean this seems very -- it seemed like a remarkable I guess benefit for customers particularly. But I mean was that something particularly unusual about that project? Or is that just what you're seeing because of what you're seeing out there just with the fundamentals of the market? I'm just wondering if you could add a little bit to it. I could talk to you guys off-line about it; I was just wondering if there was any -- it does seem kind of a remarkably beneficial story. No?

I think it's a product of a lot of things. If you look at wind, it tends to have some correlation to the price of natural gas. There's a lot of uncertainty around production tax credits expiring in 2012, so I think developers are interested in moving where they can.

And I think this is a great site with very good capacity and some new turbine technology. So all of those things came together to make for a compelling economic deal. And I mean I think there's other opportunities like that as well. But everything has to come together, this one did.

Okay. And I didn't mean to cut you off on the regulatory process. Is there anything that we should be thinking about as being an issue there? Or I mean, it just seemed like it was such a -- -- I don't know, maybe I'm missing, but it just (multiple speakers) slam-dunk.

No, I think from my perspective I think the issue is whether or not we put this in our wind source programs or whether or not we just sync it up to normal system load. I think the deal, you're right, is the economics are pretty compelling. It's just a matter of how we want to introduce it into our portfolio.

Okay, great. Thanks a lot.

(Operator Instructions). Dan Jenkins, State of Wisconsin Investment Board.

I was wondering, I noticed in your discussion on the Minnesota rate case you mentioned that there's a decision to delay the Monticello power up-rates. I was wondering if you could talk a little bit about why -- what went into that decision and how we should think about that plan going forward.

Yes, sure, Dan. It's really two drivers -- one, we had some delays in equipment and we also are seeing some delays in the NRC license. And so all those things together just said let's just push it off to a scheduled refueling in the spring of 2013. It was just as simple as that really.

Okay so it just fell outside of the rate period so it will just be done at that -- in a couple of years as opposed to (multiple speakers)?

Yes, it will be picked up in the next rate case that we would file.

Is the amount of the up-rate still expected to be the same and so forth?

Yes.

Still economic, yes.

It's still economic and it's still about the same.

Okay. I also noticed you mentioned in your financing plans that you plan to refinance the two issues that are mature in 2012. Do you expect any need for debt financing beyond just the refinancing of those two issues in 2012?

Yes, we would expect -- we've got $450 million maturing in NSP Minnesota, $600 million at PSCo and we would expect incremental debt issuance beyond that, Dan.

Do you have a size potential -- a range of (inaudible)?

We're still working through the numbers. I mean it's probably -- I would say between the two of them you'll see a couple hundred million dollars more of debt. We'll also look at NSP Wisconsin and SPS; there could be some small issuances there.

Okay. And then somewhat related to that is the -- since you have 2012 guidance, is the CapEx plan for 2012 still pretty much in line with what you've reported before or do you have any additional color you can give us on 2012 CapEx?

We'll update our CapEx forecast on December 1 at our Analyst Day, Dan. So we'll give you a new '12 through '16 forecast. I mean the CapEx forecast will go up a bit.

Okay, thank you. That's all I had.

Ashar Khan, Visium.

My questions have been answered. Thank you.

Thank you. There are no further questions in queue. I'd like to turn the call back over to Teresa for closing remarks.

Thank you for participating in our third-quarter earnings call. I look forward to meeting with many of you at the EEI financial conference in November and at our analyst meeting in New York at the New York Stock Exchange on December 1. If any of you have any follow-up questions, please contact Paul or the IR team. And thanks a lot.

Thank you. Ladies and gentlemen, that does conclude our conference for today. We'd like to thank you for your participation. Also, if you'd like to listen to a replay of today's call, please dial 303-590-3030 or 800-406-7325 and enter the access code 447-5769. Again, thank you for your participation and you may now disconnect.