埃克西爾能源 (XEL) 2009 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Xcel Energy's second quarter 2009 earnings conference call. At this time, all participants are in a listen-only mode. Following the formal presentation, instructions will be given for the question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded today, July 30, 2009.

At this time I would like to turn the conference over it our host, Mr. Paul Johnson, who is the Managing Director of Investor Relations. Sir, you may begin the cost-benefit at this time.

Thank you and welcome to Xcel Energy's second-quarter 2009 earnings release conference call. With me today are Ben Fowke, Executive Vice President and CFO for Xcel Energy, Teresa Madden, Vice President and Controller, Scott Wilensky, VP Regulatory and Resource Planning, Dave Sparby, President and CEO NSP Minnesota, and Jim Altman, Vice President, Deputy General Counsel. Today we plan to cover our second-quarter results and provide a general business update. In addition, we are reaffirming our 2009 earnings guidance.

Please note that there are slides that accompany the conference call which are available on our web page. Let me remind you that some of the comment 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. You will notice that today's press release refers to both GAAP and ongoing earnings. Since there wasn't a material difference between GAAP and ongoing earnings, we refer to GAAP earnings during the morning's discussion.

With that, I'll turn the call over to Ben Fowke.

Well, thanks, Paul, and welcome, everyone. This morning we reported second-quarter 2009 earning of $117 million or $0.25 per share compared with $106 million, $0.24 per share in 2008. In general, higher electric margin, primarily from rate relief, coupled with management actions to control costs, served to offset a steeper than expected decline in retail electric sales, and resulted in a $0.01 per share increase for the quarter. Let's look into the details, starting with the review of our quarterly result at each of our subsidiaries.

Second-quarter earnings at PSCo were down $0.02 per share, largely due to rising costs and relatively flat sales margin. In May, the Colorado commission approved an annual electric rate increase of $112 million and rates went into effect earlier this month. We expect these new rates to help offset rising costs and sluggish sales over the second half of the year.

At NSP Minnesota, second-quarter earnings were flat. We have a pending rate case in Minnesota with interim rates which are subject to refund. Interim rates provided incremental revenue and cost recovery which partially offset declining sales and increased costs. At SPS, earnings increased by $0.02 per share for the quarter. We are seeing improved financial results due to electric rate increases in Texas and New Mexico, and the resolution of fuel cost issues in 2008. At NSP Wisconsin, earnings of $0.01 per share were flat compared with the second quarter of last year. Finally, our investment in WYCO, which owns a new gas pipeline in Colorado that began operating in late 2008, contributed earnings of $0.01 per share.

Now let's take a closer look at our consolidated results. Second-quarter 2009 earnings increased $0.01 per share, which was largely driven by higher electric margin which increased earnings by $0.07 per share. Partially offsetting a positive impact of electric margin were higher O&M expenses which reduced earnings by $0.02 per share, dilution from our 2008 equity issuance direct and benefit plans, which reduced earnings by $0.01 per share, and higher interest expense, lower gas margins, and other items which reduced earnings by a total of $0.03 per share.

Next, I will provide more detail on some of the key drivers for the quarter. Electric margin increased by $52 million during the quarter, driven largely by retail rate increases in several of our jurisdictions. Interim rates in Minnesota, combined with new rates in Texas, New Mexico, and Wisconsin increased retail electric margin by $43 million. Conservation revenue, nonfuel riders and the Merck Ryder all served to increase retail electric margin by a total of $26 million. Finally, while weather was cooler than normal, it was warmer than last year which improved electric margin by $7 million.

A couple of factors partially offset these positive results, including higher capacity costs, which reduced margins by $15 million, and a decline in weather-adjusted electric sales, which reduced margins by $16 million. However, the impact was tempered by changes in sales mix and demand revenue from C&I customers, which mitigated about half the quarterly impact of declining sales. The recession and its impact on sales have been a key factor all year.

In fact, second-quarter weather normalized electric retail sales decreased 3.2%, which was worse than we anticipated. Residential sales declined 0.7% during the quarter, which was comparable to the decline we experienced first quarter. However, the sales trend weakened in the commercial and industrial class, where electric sales declined 4.2% for the second quarter compared with a 1.4% decline in the first quarter.

Overall, the recession impacted each of our service territories. While we continue to add customers at about 1% every year, those increases have been more than offset by declines in electric consumption. We believe the declines are due to the recession, conservation, and a relatively mild summer, particularly in the north, which makes it easier to conserve energy. On a year-to-date basis, our weather-adjusted sales declined 2.2%. We think the recession will continue to dampen C&I sales the rest of the year.

On the residential side, we don't anticipate the recent trend will worsen. Remember that residential sales started to decline in the second half of 2008, so the comparative forecast starts from a lower base. In total, we are lowering our annual weather-adjusted electric sales forecast to reflect a decline of 2%. While we clearly don't have a crystal ball, we feel this is a realistic forecast based on current information.

Turning to expenses, second quarter O&M expenses decreased about $16 million or 3.4% largely due to outage timing, higher nuclear-related expenses, and higher employee benefit costs, which included increased pension and medical costs. Those results were partially offset by lower consulting and material cost. We've taken several steps to manage our O&M expenses, including reducing and deferring annual merit expenses, cutting travel expenses and consulting costs. These cost reductions are reflected in our annual O&M guidance and will not affect customer service or reliability.

That explains the significant quarterly deviations. Now I'd like to provide you a brief regulatory update. Let me start with the rate cases that we've recently resolved. In May, the Colorado Commission received $112 million electric rate increase with new rates effective in July. In Texas, the Commission recently approved a $57 million rate increase, interim rates were put in place in February. And in July, the New Mexico Commission approved a $14 million rate increase, with new rates effective in July. And all three cases, we reached constructive settlements with major interveners which helped minimize regulatory lag.

Next let me turn to our pending rate cases. We are nearing the end of the Minnesota electric rate case process, where interim rates of $132 million ,subject to refund, went into effect in January. We're seeking an increase of $136 million, which does not reflect any change in the depreciation life at our Prairie Island Nuclear Plant. We also filed an alternative request for $119 million, based on a three-year depreciation life extension for Prairie Island. This lower revenue request wouldn't affect net income but would affect cash flow.

Interveners have submitted testimony, and hearings have been completed. At the time of the hearings, the Office of Energy Security recommended a revenue increase of $90 million based on a 10.88% ROE. They also recommended a 10-year life extension of Prairie Island, which results in a $40 million decrease in depreciation and decommissioning expense. Again, this recommended life extension wouldn't affect net income, but would reduce our cash flows. With the exception of the differences in depreciation life for Prairie Island, the OES recommendation is close to our revised request. We expect our recommendation from the ALJ in August and a final decision from the Minnesota Commission in October.

In May, we filed a request to increase electric rates in Colorado by $180 million, based on a 2010 forecast test year, an 11.25% ROE, rate base of $4.4 billion, and an equity ratio of 58%. This rate request is driven by capital investment in Colorado, and includes recovery of costs associated with Comanche 3 and Fort St. Vrain, which go into service this year. It also reflects rising pension and medical costs. Intervenor testimony is scheduled to be filed in September. We expect a decision before year end, with new rates effective in January of 2010.

In June, we filed a request to increase Wisconsin retail electric rates by $30 million or 5.7%, and propose no change in our natural gas rates. This request is based on an ROE of 10.75%, an equity ratio of 53%, and electric rate base of $644 million, and a gas rate base of $81 million in a 2010 forecasted test year. We expect a decision by year end with new rates effective in January of 2010. Also in June, we filed a request to increase South Dakota electric rates by about $19 million, based on an ROE of 11.25%, rate base of $282 million, and equity ratio approximately 52%, and a 2008 historic test year with adjustments for known and measurable changes. This is the first rate case we've filed in South Dakota since 1992. We expect a decision by year end with rates in effect in January of 2010.

In closing, while 2009 has proven to be a challenging year, our year-to-date earnings are $0.04 ahead of last year. The recession has resulted in declining sales. However, changes in sales mix and demand revenue from commercial and industrial customers have softened the impact on our financial results. Weather's also been challenging. Year-to-date mild temperatures have reduced earnings by $0.02 compared with normal. In addition, we're also experiencing unseasonably cool weather throughout our service territory this summer, which we expect will reduce earnings by $0.03 to $0.04 per share in July. That being said, we've done a good job of managing these challenges and have taken appropriate steps to offset the impact of declining sales, unfavorable weather, and higher benefit cost.

To summarize, we've received constructive regulatory decisions in Colorado, Texas, and New Mexico. We've effectively managed our O&M expenses by reducing costs in areas with no direct impact to our customers. We've been able to lower our projected interest expense forecast due to improved working capital and lower interest rates, and we are experiencing improved AFUDC equity earnings. We now expect AFUDC equity earnings to increase $5 million to $10 million versus our most recent forecast of zero. As a result, our business plan remains solidly on track, and we are reaffirming our annual guidance of $1.45 to $1.55 per share.

So with that, let's open it up for questions.

Thank you very much. Ladies and gentlemen, at this time we will begin the question-and-answer session. (Operator Instructions). And our first question comes from (technical issues).

Can you hear me?

Now we can, Abdullah. How you doing?

I'm fine, thank you. Couple of things. One, can you remind us the big driving items behind the current Colorado rate case and, you know, terms of -- in terms of the request and what protections you currently have in terms of having predetermined, et cetera? Secondarily, can you currently talk your latest views on capital spending and relative to cash flows and where various opportunities such as renewables and those types of things stand.

Sure. Let me take the first one which is the 2010 forecasted test year in Colorado, where we're asking for $180 million of rate release. Abdullah, that is driven largely by capital additions. Comanche 3, as you know, that's our coal plant that will come into service later this Fall, commercial operations early 2010. At a very good price point for our customers, and, you know, I think it's going to do a lot for the state. We also have Fort St. Vrain that is coming in well under budget, as well. So those are the big capital drivers. Then as I mentioned in my prepared remarks, we are seeing rising pension and medical costs. That will be a lion's share of the O&M type of relief that we're looking for. I think your second question was related to capital expenditures, particularly on the renewables, was that correct?

Capital expenditures in general, in terms of matching up operating cash flows to -- to CapEx within the current balance sheet, as well as kind of what your current view is as to the level of potential renewables. We've been seeing and hearing anecdotally about some slow-down in terms of commitments and pushing out of various renewable, potential renewable spending.

Well, they're kind of related for us. As you know, we're in the process of gaining final stage approval for the projects, the wind projects, one in North Dakota, one in Minnesota, all at NSP Minnesota, that will increase our CapEx over the next couple of years. Also put us, you know, ahead of the milestones toward meeting those RPF standards. So, you know, that's what -- that will basically be what we're concentrating on for renewables in Minnesota. In Colorado, we have an RFP outstanding, and you might recall that earlier in the year we reduced that overall RFP by 500 megawatts. But we did not reduce the renewable component of that which I believe is 850 megawatts.

So and again that keeps us ahead of meeting our milestones in Colorado for the RPF standards. In regards to overall capital expenditures, you have some flexibility there related to what's happening with sales and the economy and -- and that sort of thing. And that flexibility will be reflected, but I mean by and large, Abdullah most of our capital expenditures are going to be related to long-term resource planning decisions and transmission and infrastructure work that needs to get done. The good news is cash flow's been pretty good for us. It's working capital as I mentioned in my remarks has improved significantly this year over last. So, you know, I think we're in pretty good shape.

Yes. As I recall, I'm trying to remember -- I think the CapEx range is like between 1.8 and 2.3?

Yes. It's-- 1.8 this year and it's 2.3 next.

Okay. Thank you very much.

Welcome.

And our next question comes from the line of Travis Miller with Morningstar. Please go ahead.

Hi, Travis.

Good morning. The $0.03 to $0.04 reduction that you cited in your comments for July from the weather --

Yes --

Is that just from what you've seen in this month, or was that a year-to-date by the end of July number?

No, that's -- unfortunately, that's just what we've seen in July. July has been one of the coolest months on record here in Minnesota, and it hasn't been particularly warm in Colorado, Travis. But, we understand the challenge of weather, and we've obviously understood that weather was going to be a challenge that we faced in the second half of the year. And we think we've taken action since the beginning of the year to mitigate that, and -- and frankly, we think we're near the middle of our guidance range. So even with the weather. So we like it -- we'd like it to be warmer, but it's not. We'll take actions to address it.

Sure. A bit of a followup on that. Those O&M costs that you've been able to cut and contain, are those more one-time items or ongoing? What kind of balance is there?

Well they're not deferrals, so you won't see more pressure on our 2010 O&M forecast as a result of what we're doing in 2009. But they're -- some of it's productivity. Some of it is just, tightening our belts as we think it's appropriate to do with employee expenses, consulting, that sort of thing, deferring merit raises, controlling contract labor, controlling overtime and that's I guess in the productivity side. But Travis, the other thing we're seeing is one of the natural things you see with cooler weather and less sales is less strain on your system. And, we're seeing less severity of summer storms and things like that. So it all adds up to cuts that don't boomerang again, come back to you in 2010.

Okay. Thanks a lot.

Thank you, Travis.

Our next question comes from the line of [William Hedstrom with Capital], please go ahead.

Good morning. With supervision and guidance for electric retail sales, can k you provide a geographic breakdown on your growth assumptions and how your northern jurisdictions are faring as compared to Colorado or SPS?

Yes, I can. I mean, it's more pronounced in the north. The second quarter, would you prefer quarter or year to date?

Year to date.

Year to date in NSP Minnesota, we're down 3.2%, these are all weather normalized. PSCo it's less at 2%, SPS is negative 1% and NSP Wisconsin is negative 1.2%. By and large, residential is -- isn't being too impacted with the exception of NSP Minnesota, where we're feeling it a little bit more. I think in part that may be because this is really the second year in a row where we've had a pretty mild summer, and when you combine that with the recessionary impact, I think people are basically not using air conditioning as much and they can do so because it's quite comfortable up here right now. On the C&I side, quarter we saw basically there were reductions across the board, year to date. More pronounced at NSP Minnesota than in any of our other jurisdictions.

Okay, thanks a lot.

Thank you.

And our next question comes from the line of Ashar Khan with Incremental Capital. Please go ahead at this time.

Hey, Ashar.

Hey, how are you do, Ben? I guess you kind of answered the question. So you said you're on track to meet the mid-point of the guidance at this point as you look at things.

Yes, you got that right. I think even with the weather, we're near the mid-point of our guidance, and, you know, as you know, that -- as you read the press release, we -- we included in our O&M estimates still the full amount of our annual incentive which, unfortunately, last year we cut completely. So I think we're in good shape to certainly meet guidance and I think at this point we're near the middle of that guidance range.

Okay. Thank you very much.

Thank you.

And our next question comes from the line of Greg Gordon with Morgan Stanley. Please go ahead at this time.

Hey, guys. I'm back.

I know.

So if I go to note 6 and I just look at all the puts and takes and use sort of the mid-point of what's changed since Q1, would it be fair to say that your top line revenue is expected to be about $50 million lower, and you've found about $50 million of cost cutting and a little bit of AFUDC to offset that?

Yes -- let me -- I think $50 million might be a bit high to tell you the truth. Perhaps if you add weather on top of that.

Okay.

Since the beginning of the year, Greg, we've basically -- through O&M, AFUDC, interest expense, a number of items, we've reduce the -- we had improvements of $0.07 or $0.08. And I think that basically offsets the weather and the sales decline that we've seen.

Got it. When I look at -- at least what we've seen so far, the limited number of companies that have reported, in the southeast and in the midwest, we're seeing sales declines on the commercial and industrial segment of 15% to 17%. And even on a weather normalized basis, they're in the double digits. You guys have seen a much, much more muted reduction in commercial and industrial sales on both the normal and weather adjusted basis. So I don't know if you're in a position to compare and contrast your territory to others, but what's driving the more muted decline?

Well, I think a couple things. I mean, one while we're suffering from a recession, I think if you look at the unemployment numbers, et cetera, , our jurisdictions typically are about a full 2% points better than the national average. But I think probably the biggest driver, Greg, is the fact that we don't have a large manufacturing base. And it's -- you start as move east and across our northern jurisdictions, you see more manufacturing. We have a large commercial base, but not as much on the I side of that. And where we do have an industrial load it tends to be energy and mining related, and while we've seen slowdowns there, it's certainly not been as severe as some of the other manufacturing sectors of

Great. Thanks.

Welcome. Welcome back.

And our next question comes from the line of Dan Jenkins with the State of Wisconsin Investment Board upon please go ahead.

Hey, Dan.

Hi, good afternoon -- good morning, I mean. On your page 6 where -- of your release where you break down the revenues, I was wondering if the first line there, the retail rate increases, if you could break that down further. The six-month number by the states. In the Minnesota/Texas/Wisconsin --

Yes. I can. Let me --

Hey, Dan. Why don't you give me a call after the call, and we can -- we can walk through that. I mean, if you look at the rate increases and like for example Minnesota is $132 million interim rate, you can take about half that, and then if you want I'll walk you through the rest of them after the call.

Okay. Another question I have was you talk about the higher nuclear plant operating costs and related to some changes in regulation. I was wondering at what point does that not become a year-over-year increase -- does at some point the comparison year over year kind of go away because -- because of that change?

There's two components that you should think about, Dan. One is the outage cost which, as you remember, we had an accounting change last year. So we still are on track to see that overall even though for the year to date it's -- it's flat. In fact, minus $1 million. It will be at that $35 million level by the end of the year. I think your question, though, is pointed to the other line item on nuclear plant operating costs which are up $8 million quarter to quarter and $16 million year to date S. that correct?

Right.

Is your question what's driving that?

No, since you described what's driving that I was curious. You said it was driven by an increase in security costs and regulatory fees resulting from new NRC requirements. At some point does the year over year affect zero out, you know what I'm saying? So you've had this change in security costs, when did that go into effect? Was that like start at the beginning of '09 so in 2010 it will -- won't be a year-over-year --

Yes. I --

Delta, you know what I'm saying?

Yes, I know what you're saying. I think that trend line will probably continue unfortunately because I mean we're seeing -- it's not just this year, it's been over several years now a lot of increased security requirements, worker fatigue requirements, increased NRC fees and they're not going away. They just keep coming. And, historically we've run a pretty lean labor force at our plants. So as those are new requirements for worker fatigue and security have come on, we've had to hire the personnel to address it. That's what you need to do, and that's what we're doing.

Okay. Sure, that's -- that's a trend that you don't expect to change then --

I don't think it really levellizes out, not this year, any way. Teresa, Scott, do you see anything different?

No.

No.

Okay. Then kind of the next thing on the nuclear. I was wondering do you know what your year-to-date I was wondering do you know what your year-to-date capacity factors are?

Yes. They've been in the upper 80s, low 90s.

Okay. And then I noticed, you had put out what the 2008 ROEs were. And I noticed it was 799 for Minnesota Gas.

Yes.

Are you considering filing a rate case for the Minnesota gas?

I think that's under consideration. But why don't we have Scott address that.

We're looking at that right now. We noticed the same thing. We're looking a look at our budget, and if it warrants an increase, we are prepared to file.

Okay that's all I had. Thank you.

Thanks, Dan.

Our next question comes from the line of Danielle Seitz with Dudak Research Group. Go ahead.

Hi. I was wondering if you could give us a bit of color on the -- what you anticipate in terms of the economy next year. Do you see a relatively early recovery, or actually not? Just give us the color of what you see in your territories.

Yes. Danielle, I don't know if I can really provide any more insight than what we all read in the paper. I don't think we're -- I'm hopeful that we're at the bottom, but my sources are probably the same as your sources. We were a bit surprised at the second-quarter impact. We don't believe it will get worse, but I don't see any signs, frankly, that it's going to get better any time soon. Hence, our forecast for the sales this year. Wish I could provide more insight, but I'd be -- I'm guessing.

No, I mean obviously as far any insight is good. From where we stand. It's always easier when you can tell us what you hear from the different C&I customers and so on.

Yes. Just gives -- Yes. And I think as we talked about earlier, a lot of our C&I is more on the C side. I think in general those things are harder to get your arms around. But they'll tend to I assume move up as the economy generally improves.

And my other question, is do you see an increase in AFUDC, can you tell us where it comes from given that you're down incrementally and all that. I was wondering what was the impetus for the upside in AFC.

Well, we've changed it twice. We changed it on the first quarter and first quarter, I believe, was primarily driven by the rate settlement we entered into in Colorado with Comanche 3 where we chose to recognize AFUDC versus quit recovery in the rates. The most recent revision to the forecast is more a series of cats and dogs and, you know, just more of the budgeting forecasting process as we've gotten into the year and can't point to anything specific.

Okay. Thanks.

You're welcome.

And our next question comes from the line of Paul Ridzon with KeyBanc. Please go ahead at this point.

How are you, Ben?

Pretty good.

Actually Danielle just asked my AFUDC question so I'm all set.

Good.

Thank you.

(Operator Instructions). The next question comes from the line of Paul Patterson with Glenrock Associates. Please go ahead at this time.

Good morning, guys.

Good morning, Paul.

I'm sorry I missed this. I got distracted right when you guys were discussing it. The O&M outlook this year versus 2010, you were discussing that. Could you just review that? I'm sorry to ask you to review that again.

I don't think we've talked about the O&M outlook for 2010. I think what you probably came in the middle of is the fact that the reductions that we're making in 2009 are not going to be reductions that then bounce right back into our 2010 forecast, Paul.

So they're sustainable?

Yes.

Okay. And then also some O&M items seem to be unusual. If I understood correctly it seems that there was some O&M increases that from reading the release that may not be showing up next year. Is that right?

You have something specific? I mean --

I was thinking on the nuclear side.

Oh, yes. That's the -- that's real what he we're seeing this year is related to that change in the amortization accounting that was approved by the Commission last year. So that -- we're still on track as per our guidance to have outage accounting be an increase of $35 million this year. And then I believe in -- correct me if I'm wrong, Teresa, it starts to levellize out in 2010? She's nodding yes.

Okay. Okay. Thanks a lot.

Thank you.

And our next question comes from the line of Nathan Judge with Atlantic Equities. Please go ahead at this time.

Hey, Nathan, how are you doing?

I'm well, thank you. Good morning. Wanted to ask just generally as you look at growth and your long-term growth rate, I know you've received the question about how sustainable your growth rate is, and in a recessionary environment. Just near term, if we have a perhaps beleaguered growth in the economic environment, will Xcel grow in line with what it's grown historically?

I mean, will we grow in line with our long-term outlook of 5% to 7%?

Yes.

Yes, I think we will. I think -- I think the reality, though, is in a recessionary time it's probably going to be closer to the five. But I don't think it pushes you below that.

Thank you. And also just on with regard to the CapEx 20/20 plan, can you just give us an update on that and I know there's been some opposition, it seems like Minnesota has agreed with your point of view, but could you just give us more of a perhaps a definitive timeline and investment on that --

Yes. And I'll ask Dave or Scott if they want to chime in. But I think, remember the big thing with the certificate of need that we received earlier in the year, and the next steps as we talked about of the routing and permitting for the specific routes. And, we've seen opposition, but that's kind of I think natural. But Dave or Scott, do you want to add anything to that?

I don't think there's anything unusual in the level of opposition on that project. I think actually it's got a significant level of support that we don't typically see around some transmission projects that moved through the PUC process as well as the largest CON granted by that commission for transmission. You know there's going to be some natural noise around it, but again, I think it's moving fairly smoothly.

Takes a long time to get those -- those from planning to construction.

And you've done a great job of getting them along so far. So best of luck.

Thank you.

And our next question comes from the line of Sara Akers with Wells Fargo. Please go ahead.

Hey, good morning.

Good morning.

Can you elaborate on the D&A expense item? It looks like there's about a $30 million improvement since Q1. Is there any drivers besides what you kind of mentioned about the AFUDC with the clarity on the budgeting? Anything else you can point to that's driving the declines there?

Yes. I would say that most of those reductions, too, Sara, are not going to be earnings impacted because they really reflect commission orders that have been basically swept into, the rate relief that we're now getting. And they relate to a number of things, but I think typically our nuclear plant have been the big drivers.

Okay. That's helpful.

That's already incorporated into the rate relief.

That's very helpful, thank you.

You're welcome.

And our next question comes from the line of Matthew Yates with Merrill Lynch. Please go ahead at this time.

Hi, thanks for taking the question. I just wanted to follow up on the CapEx outlook and some of the comments you've made about very uncertain macro backdrop and equally you have seen a lot of uncertainty on the federal regulations side in term of the energy bill. Can you say to what extent this impacts any of your CapEx decisions in the near term? Thanks a lot.

I don't think it -- I don't think it really does. When you think about what's happening with federal climate change and that legislation, I mean, it's -- I think it validates the fact that we've been on the right path for a number of years now. And that the things that we're doing, adding wind contractually and building our own, uprating our nuclear plants to not only be at a great price point for our customers but provide carbon-free energy, I mean, though are all the things that you want to do. And we've been preparing for what we thought was eventually going to happen, which would be climate change. So-- and these are long-term decisions. So you -- you need to -- you obviously need to be sensitive to the economic times. But I think if you keep your regulatory compact solid and you keep your been sheet strong you can continue to execute on your long-term strategy even if these recessionary times.

If I can follow up on something. If you look at the trend right now in terms of solar module costs or wind turbine prices, can you talk about some of the discussions you're having with some of your energy providers about where PPA prices might be moving?

I'll be able to talk a lot more about that as we get through the RFP process in Colorado. And, you know, I guess just in general there has been I guess some improvement in pricing. And certainly that's related to the economy, I would say, with wind. But in solar it's more technology and breakthroughs and, frankly, commodity prices that the silicons that go into the panel that's are driving the price down there.

Thanks a lot.

You're welcome.

Gentlemen, at this time there are no further questions in the queue. Please continue with any closing comments that you may have.

I appreciate everybody joining the call. And as always, if you have any followup questions, please feel free to call Paul Johnson and the rest of the IR team. And thanks again.

Thank you very much. Ladies and gentlemen, this does conclude our conference call for today. We do thank you for your participation on today's call. You may now disconnect your lines at this time.