埃克西爾能源 (XEL) 2006 Q3 法說會逐字稿

Good morning. My name is Michael and I will be your conference operator today. At this time I would like to welcome everyone to the Xcel Energy third quarter 2006 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question and answer session. [OPERATOR INSTRUCTIONS] Thank you.

I would now like to turn the call over to Mr. Dick Kolkmann. Sir, you may begin.

Thanks, Michael, and welcome to xcel energy's third quarter 2006 earnings release conference call. I'm Dick Kolkmann, managing director of investor relations. And with me is Ben Fowke, Vice president and CFO of Xcel Energy. We also have several others here in the room to help provide answers to your questions. Some of the comments that will be made contain forward looking information, significant factors that could cause results to differ from those anticipated, are described in our earnings release, and xcel energy's filings with the securities and exchange commission.

Now, I will turn the call over to Ben.

Thanks Dick, and welcome everyone. I'm pleased to report that for the third quarter in a row, we've delivered strong earnings results. Today I'll cover the quarter, the outlook for the balance of the year, our regulatory progress and finally some additional detail on our 2007 guidance. So, let's start with the quarter.

Xcel Energy recorded earnings from continues operations of $0.53 per share for the third quarter of 2006. This compares with $0.47 per share for the third quarter of 2005. Earnings from continuing operations equal total earnings for both the third quarter of 2006 and 2005. Our earnings from continuing operations increased by $0.06 per share for the quarter, largely due to higher electric retail margins, which increased earnings by $0.08 per share. Higher gas margins, which increased earnings by $0.02 per share, and other items that together increased earnings by about $0.01 per share. These positive factors were partially offset by higher utility O&M expenses which decreased earnings by $0.02 per share, and higher depreciation expense which decreased earnings by $0.03 per share. That summarizes the third quarter results.

Now, let's look into the details. Our base retail electric utility margins increased by 57 million or $0.08 per share for the quarter, largely driven by rate increases and sales growth. Electric margin grew by 66 million from various rate increases. This includes 35 million from the [inaudible] rate increase in Minnesota, 11 million for the implementation of the [inaudible] and 20 million for electric rate increase in Wisconsin. For the quarter, our weather adjusted electric retail sales growth was a solid 2.3% which increased electric margin by $15 million. On a year to date basis our weather adjusted sales growth was 2%.

While we experienced warmer than normal temperatures during the quarter we had similar weather during the third quarter of 2005. As a result, weather had a minimal impact on our quarterly comparisons. Partially offsetting these positive items was a reclassification of transmission expenses which reduced electric margin by $21 million. The reclassification didn't impact net income, it just moved some transmission expenses from O&M to electric cost of goods sold.

Electric margin for the quarter also declined by 17 million for the Electric Commodity Adjustment Incentive Or the ECA. As we've discussed in the past, the ECA is for a cost recovery and an incentive mechanism in Colorado that provides for an 11.25 million cap on any cost or benefit. In 2005 the ECA was positive while year to date results reflect a cost of 11.25 million. The ECA expires in 2006 and is expected to be replaced with a more traditional cost recovery mechanism. For more information on electric margin, please refer to the margin table in our earnings release.

Turning to operating expenses, our third quarter O&M expenses increased approximately $10 million, or 2.6% driven largely by employee benefit cost. For the full year we expect our O&M expense to increase about 4% over last year. As was the case last year, we benefited from additional margin from warmer than normal summer temperatures. As a result we decided to spend additional O&M to ensure the system stays in good shape and is ready to go in 2007.

Our third quarter depreciation expense increased $19 million or 9.9%, driven by increased capital spending and changes in decommissioning accruals. That wraps up the explanation of the quarterly results. It's been a busy quarter on the regulatory front, so let me update you on our progress.

I'll start in the north and work my way south. In September the Minnesota Commission issued an order granting us electric revenue increase of approximately 131 million based on an authorized ROE of 10.54%. We had requested an electric rate increase of 156 million. While we'd asked for a reconsideration of a few items, overall, we think the decision represents a constructive regulatory outcome.

In Colorado, we requested an electric rate increase of 208 million. The request was based on our 11% ROE, an equity ratio of almost 60% and a rate base of 3.4 billion. While the case is based on our 2005 historic test year, the filing is adjusted for known and measurable changes. I'm pleased to report that we reached a definitive settlement agreement with several intervenor in the Colorado rate case, including the Commission staff and the office of consumer council. The settlement reflects a rate increase of $151million, which represents a base rate increase of 107 million and right of recovery of 44 million related to capacity and wind source costs. The settlement is based on an authorized ROE of 10.5% and an equity ratio of 60%.

The settlement is pending approval by the Colorado Commission. While we didn't get everything we asked for the agreement represents another example of constructive regulation in our major jurisdiction. We've asked the Commission to hold hearings to rule on the settlement in November and requested that final rates go into effect in January, 2007.

In Texas we've requested an electric rate increase of $48 million based on an ROE of 11.6%, and in a historic test year with an equity ratio of 51% and a rate base of $943 million. In September we filed corrections to the case which increased the request to 63 million. However, to establish new rates as quickly as possible we did not refile the entire case. As a result, we are limited to the $48 million increase originally requested. Final rates are now expected to be effective in the second quarter of 2007.

That's an update on our regulatory developments. I think you'll agree with me that it's been a productive quarter with positive conclusion in our Minnesota rate case and a pending settlement in our Colorado rate case. Now ride like to discuss earnings guidance for both 2006 and 2007.

We have delivered three solid quarters this year. In addition, we've reached a constructive conclusion in our Minnesota electric case and we've recognized some tax benefits and our sales have increased due to favorable temperatures. As a result, we believe that we are well positioned to achieve annual earnings in the upper half of our 2006 guidance range of 1.25 to $1.35 per share. That said, we do need to monitor regulatory proceedings at SPS. As we discussed in our SEC fillings, we have several complaints at SPS related to cost allocations involving the use of system averaged cost versus incremental fuel cost. While we believe our arguments have strong merits there's always uncertainty in regulatory proceedings. We've accrued approximately $15 million, which we believe is the appropriate reserve for these complaints. However, I want to point out to you that our guidance for both 2006 and 2007 assumes no additional material accruals for exposure at the SPS regulatory proceedings. For more information please review our 2006 key assumptions which are listed in the earnings release.

Turning to next year, we are initiating 2007 earnings guidance of $1.35 to $1.45 per share. Last year at the fall EEI Financial Conference, we increased our earnings growth objectives to 5 to 7% from a base of 2005 actual results. The EPS growth objective was based on our capital investment and regulatory recovery plans. As you look at our guidance for 2006 and 2007 you'll see that our projected results are consistent with our EPS growth objective. Further, as a result of the pending settlement in the Colorado electric rate case, we go into 2007 with more regulatory certainty.

Let me highlight a few key assumptions for our 2007 earnings guidance. We assume normal weather conditions throughout the year. Our guidance assumes reasonable regulatory recovery in our various rate cases and that the Colorado Commission approves or electric rate case settlement. We expect that our electric sales will grow 1.7 to 2.2% on a weather adjusted basis. As I discussed earlier, we don't expect any additional material accruals for regulatory proceedings at SPS, and finally, our guidance assumes that we continue to recognize [indiscernible] tax benefits. So those are the highlights. For more information, please, refer to our earnings release where we detail our assumptions for most lines of the income statement.

Included in the earnings release is our updated capital expenditure forecast. As you know, a key component to our strategy is getting the rules right before we invest the capital. It is clear that the commissions and regulatory staff in our major jurisdictions recognize that there is a need for significant investment and have worked with us to insure the appropriate regulatory treatment. This has validated our business strategy. As a result, we have increased our capital expenditure forecast. These investments will meet customer needs and provide us with sustainable earnings growth into the next decade.

While we've given you a fair amount of detail by year, you should be aware that this CapEx forecast is not written in stone, we'll continue to evaluate the forecast based on our financial results, changing customer needs, potential investment opportunities, regulatory recovery and other conditions. We plan to finance the Capital Expenditure program through a combination of cash from operations, utilization of our net operating tax loss carry forward, the dividend reinvestment program, and the issuance of debt, and potentially a high bred security. As a result of constructive regulatory outcomes, we believe we can fund our capital program and deleverage the balance sheet over time without the need for a public equity issuance beyond our normal dividend reinvestment program.

Now just as our capital investment program is not set in stone, neither is our financing plan. We will modify our plan based on change to the Capital Expenditure forecast, changes in cash generation, outcomes in various regulatory proceedings, and our desire to improve our credit rating.

In summary, this has been an outstanding quarter. We've reached a constructive resolution in our rate case in Minnesota and a positive settlement with parties in Colorado. Our construction program remains on track. We delivered another strong quarter of earnings results. We've positioned ourselves for a strong 2007. And finally we've expanded our Capital Expenditure program to meet customer needs and provide sustainable earnings growth into the next decade.

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

[OPERATOR INSTRUCTIONS] Our first question from Greg Gordon with Citigroup.

Thanks good morning.

Hi, Greg.

I know this is like a broken record with this question already but, when if at all, are we going to have any visibility on resolution [inaudible] uncertainty on the Coley tax issue?

Greg, you [inaudible] on the holding?

When are we potentially going to get more visibility on the resolution of the uncertainty around the Coley?

Oh, the Coley. Well, we've been told to be trial ready at the beginning of 2007, so if you -- if that implies that a trial will commence in the early part of 2007 and if it does I think it's about a six to eight week process. So hopefully we'll have an answer for you before the first quarter of 2007. We're also still waiting, Greg, to hear on our motion for summary judgment that was heard several weeks ago.

I'm looking at my old Capital Expenditure forecast in my model, and I'm going to concede, it may not be perfectly updated but, this new CapEx budget looks higher.

It is.

I'm just wondering, can you give us an updated sort of projection on what rate base looks like over the next several years? Like you've provided at some of your analysts presentations.

Rate base will continue to grow by about 5% annually. The changes, Greg, from the last capital forecast are primarily in the area of nuclear expenditures. We're planning to upgrade our units to add another 250 megawatts of capacity. You see more transmission investment, primarily around the CapEx 2020 program. That's in the latter half of the decade. Imbedded in the base capital assumptions toward latter part of the decade is some uprating at our Sherco plants in Minnesota.

The nuclear plants that you plan on spending incremental capital on are in which regulated jurisdictions?

Minnesota.

So they wouldn't fall under the MERP? If you increased capital base in those assets, you'd have to file a separate proceeding to get the recovery?

Yes. There's two ways you could get recovery, one through traditional rate cases, which you know in Minnesota are forward test years, but what we're planning to do next year is work with our commission to try to put together an enhanced recovery method, as we've done with other capital expenditure programs.

So when I look at this 160 ramping to 180, ramping to 250, and nuclear capacity life extension, there's going to be some sort of future process to try to get recovery of those expenditures?

That's the plan, Greg.

And then the 2020 program, those recoveries of those Capital Expenditures by revenue requirement would be granted at the Ferk level, is that right?

The CapEx 2020 program is administered by the state and it's a forward looking rider. Method similar to what we have in MERP.

Okay. Thanks guys.

Thank you.

Your next question comes interest Daniele Seitz with Dahlman Rose.

Hi. Just a quick question. When do you anticipate to file in Minnesota again?

On the gas side, Daniele, we'll probably file in November of this year. On the electric side, I don't think we have a date at this point. We'll continue to monitor our results, but at this point there is no set determination on when we would file an the electric case.

So whatever discussions you are going to have with the Minnesota Commission regarding future construction will be separate from a rate case?

You're referring to the upright program I mentioned?

Yes.

Yes, that would be separate.

Thanks.

Your next question comes from Angie Storozynski with HSDC.

Good morning. I have one question about your assumptions. I'm looking at the weather adjusted retail electric sales growth and the natural gas sales growth, and I see that now you're projecting that's going to be between 1.7 and 2.1% for 2007. It seems much higher than, at least what I anticipated, and I just want to know if you see any change in the region, and the regional economy, that drives the sales growth higher? And also for natural gas sales, I see that now we're assuming a decline between 1 and 2%, and as far as I remember, previously we assumed they were going to be almost flat. So, can I get a comment on that?

It's really just the consistent with the patterns that we saw this year in '06 and we're just extending those into '07. This year we'll be on the electric side around 2%. On gas side it'll be slightly declining. We think those trends will continue into '07.

Regarding natural gas sales, do you think it's some sort of conservation measure? And do you think that with the, supposedly lower, natural gas prices you think that this trends might be reversed?

It's certainly something we'll look at. But gas prices are still relatively high if you look at it on a historic basis, and customers are more aware of their gas bills, more energy efficient appliances are being installed. That's the trend we see. It's the reason when we file rate cases is that we're looking for more fixed recovery, so we don't have as much exposure to either weather or declining sales usage.

And just one more question. How about the higher operating and maintenance expense? I understand that this quarter you guys basically invested more to insure reliability of the service. However, when I look at the nine month numbers, we're up almost 4%. And I see the guidance that's between 3 and 4% growth in O&M expenses. Why do we see this growth? What drives the higher costs?

There's a couple things. There's nuclear outages, two nuclear outages this year contributed to the expenses. We're seeing higher employee benefit costs, in general, some increases in expenses. Next year our guidance is set for O&M to increase 2 to 3% from our '06 levels. So you'll see it tail off a bit from what we experienced this year. Bottom line is, we are making sure that our operating system is given adequate O&M so that we can have reliable service and we've been pretty successful at that.

Okay. Thank you.

Your next question comes from Gregg Orrill with Lehman Brothers.

Hi Gregg.

Hi. How you doing?

Good.

Two topics, the first I wanted to follow up on the accruals for the SPS case. I was just wondering if you could provide any detail on the items in the $15 million that you've accrued for? And then, the other topic is just to confirm the size of the drip and potential timing of a hybrid issuance?

Let me, let me issue the drip, the drip typically adds about $40 million a year, so about 2 million shares or something like that. The timing of the hybrid security-- I mean it will depend, but we're probably looking at late 2007, 2008 time frame for that. Was your first question related to the SPS situation?

Yes.

Specifically, what did you want to know, Gregg?

More detail on the accruals. Just what they related to.

Just by examining the complaints and the merits of the complaints, we've established the $15 million reserve. There's several different complaints, all of the same average versus incremental fuel cost theme. That's what we think covers it.

Okay. Thanks.

Your next question comes from Paul Ridzon with Keybanc.

Hi, Paul.

Good morning. How are you?

Good.

You upped your wholesale outlook for the year. Just kind of wondering what drove that? And then secondly, you had on the tax line looks like $0.025 to $0.03 reserve reversal. Was wondering when you put that reserve on, whether that was in '06 or from prior periods?

To answer you last question first, the tax reserve has just been over a period of time and we haven't filed a rate case in Minnesota for I think it's been 12 years. So it was over a long period of time. And we were able to release that as we went through the rate case and resolve some open issues. I forgot you first question.

What drove the higher -- you upped your wholesale outlook.

Well, basically it's just based upon results year to date. We had some positive items in the proprietary side of our trading business. Can't count on that going forward, but given year to date levels it positioned us to be on the higher end of the guidance on that.

And then the stepdown next year is just an expected -- you won't have such positive results next year?

Well, there's two big factors. The biggest one is the fact that is, under the Colorado settlement and the Minnesota order, we agreed to share much more of a percentage of our trading margins coming off of our generation stack than we had in the past. That combined with growing retail load is the reason why you see a decline in trading margining.

Thank you very much.

Your next question comes from Nathan Judge with Atlantic Equities.

Good morning. I wanted to follow up on the accrual also. Was that $15 million, did that fall into this quarter?

I think it's been over two quarters. Teresa is that right? Okay. About half and half Nathan.

Okay, great. Also in the O&M, you recorded [dots] your higher employee benefit costs was primarily performance based. It was a negative $21 million impact. Could you quantify how much that was performance based?

The majority of it was, and it's a number of different programs. The biggest driver was the short term annual incentive. As we look to be on the upper end of our earnings guidance range, that means some incentive costs go up. There was also some increases, Nathan, on some longer term incentive related to the good performance that our stock had seen.

I see. Okay. So looking forward, in your expectations for 2007, would you expect that kind of level to continue or is this a more of a one time item?

I don't think you'd have the same level. I'd like to see it continue 'cause that would mean that we're doing very well, but it would be based around performance.

I understand. Based on 2007 levels, would we, if you were to achieve similar type of appreciation, your stock in [fees] and similar types of earnings performance, would we see a similar type of impact for performance pay?

You'd see some, but I think what you're seeing this year when you add the 21 million is an incentive program all in that will probably be pushing close to 40, 35 to 40 million and that's not what we would -- when we go into next year, the number would roughly be, say $10 million lower. If the performance was on the upper end you might see some movement there, but, Nathan, that all depends on what the-- there's a lot of mechanics that go into that. Sure. Okay. I appreciate that.

Just finally, on the capacity payments for your 2007 projections and assumptions, you note that you expect a $35 million increase there for capacity cost. Could you just go into a bit more detail there?

Sure. As our load grows, we need to make sure that we have the capacity, whether owned or purchased, to serve is load, and the good news is that under the Colorado settlement we were able to achieve a capacity rider, so the capacity cost flow through automatically, that's very [indiscernible] supported by the way. And I think that's one of the, I think, benefits out of the Colorado settlement. However, we don't have those mechanisms in Minnesota or Texas. As we need to add capacity for growing sales to support sales growth, we do it.

Is it higher capacity cost or is it actual more volume? Or a combination of both?

It's more volume driven than actual increases in the capacity costs that we already have.

Right. I appreciate that. Thank you.

Your next question comes from Karen Choi with AllianceBernstein.

I just had another question about the hybrid security. Would the hybrid be issued at the operating level or at the holding company? And, if it was issued at the operating level company, what type of regulatory treatment would it get?

I think the current plans would contemplate it being issued at the holding company level.

Thank you.

You're welcome.

Your next question is a follow-up from Greg Gordon with Citigroup.

Thanks. Just to hit you on this capacity question again. I'm a little bit confused. When we plug this $35 million of incremental capacity costs into your jurisdictional costs profile in Minnesota and SPS, isn't that going to be a drag on your authorized returns, and shouldn't we assume that you ultimately file for relief for those costs?

It is a drag. There's no doubt about it. Just like O&M, those are drags on your costs, Greg, but that's what you have sales growth for in other items.

So you don't think that when we bottle these down to the ROE that it causes you to under-earn your authorized returns in those jurisdictions?

I don't think it would cause us to significantly under-earn. Some of that will all depend on actual sales growth. I should point out the that we do have a major customer in our Minnesota jurisdiction coming back online next year as a retail customer, so some of those capacity costs support increased sales growth there and margin growth there, so I think all in all it's just a function of meeting increased revenues coming from our sales growth.

I understand. So in its totally it's really top line revenue growth net of these costs?

Yes.

Think of those things together not separate?

Yes.

Okay. And then just going back to your CapEx forecast, the-- which expenditures on this forecast are ones that you don't already sort of have recovery of from some sort of mechanism, or aren't captured in sort of a next in rate case, where we should assume that there's going to be some sort of discussion with the regulator around cost recovery going forward. Is it is the 180 million a year on the nuclear line? Or is it less than that? Are there other CapEx numbers here that aren't already wrapped into a regulatory discussion?

Yes, I think if you-- we're going to get more detail on this, Greg, at the EEI Conference, but if you go through our Capital Expenditures, the break out, you have your base Capital Expenditure programs, most of that is going to be covered through your traditional regulatory cost recovery methods, either historic or forward test year, depending on the jurisdiction, as you know, MERP is a forward looking rider recovery in Minnesota. Comanche III, we have the ability to bring in forward looking quip as we file rate cases. Minnesota Wind Transmission and CapEx 2020, are all covered through forward rider mechanisms, and as I mentioned the nuclear capacity increases and life extension, the-- right now the method would be filing a rate case. We are going work with the commission and staff next year to try to get an alternative recovery mechanism in place.

So the 160 you spent this year, and the future CapEx you have forecast, those are not rolled into a recovery mechanism as of yet?

Correct.

Thanks guys.

Okay.

Your next question is a follow-up from Daniele Seitz with Dahlman Rose.

Hi. I just was wondering, how much capacity will you add to your plans and by what year?

What we add to our-- whether the capacity that we bring--

If your going to be an upgrade, I'm sorry.

You're talking about the capacity increases for our nuclear plants?

Yes.

That will add 250 megawatts of increased capacity. That won't come online until, gee, I believe the actual upgrades will be past the 2010 time frame.

Okay. Great.

This is the work that gets-- the expenditures that get you there.

Yes, thanks.

Your next question from Dan Jenkins with the State of Wisconsin.

Good morning. First of all I just want clarification on that transmission fee re-classification, and it looks like it's coming out of O&M, but what has it being going into?

First of all, Dan, there's no net income impact from the re-class. It's basically, as we looked at the MISO rules we applied those to contracts that were expiring and as we renegotiated those just put them where the components were better classified.

Where's the offset then for the-- ?

You see a $21 million reduction in O&M offset by a 21 million reduction from our operating margins.

So it's out of revenue, essentially?

It's increasing cost of goods sold, it's lowering O&M. No net income impact.

Okay. Then I was wondering, on your nuclear outages, what kind of assumptions you have for that for '07? I didn't see that listed in your assumptions.

That's a good question. We only have one outage next year verses two this year, which helps to keep the O&M at the lower level that we're assuming.

Which unit is that?

Monticello.

Is that one of the units that will be uprated?

Ultimately we're looking to operate all three units.

I assume the uprate will process will take place during outages is that right?

Not at this outage that we're talking about in '07.

Okay, so it's later than after '07 that you'll start to see is uprates of those various units?

Yes. It's uprates and life extension. So we're going to start doing some of the work to get the life extended. Things like steam generators, and the other things that are necessary to get the plants, the life extended, along with the capacity expansions that will be-- the expenditures will happen further along in the decade.

Okay. Have you already filed with the NRC to get the licenses extended as well?

Yes.

Okay. And you've gotten all those approvals?

Yes, within the state as well. We expect approval in-- actually, it's November of this year, we'll expect to get some of the approvals we've also filed with the Minnesota Public Utilities Commission and those filings are going pretty well.

Okay. And then I was just curious, on your capital structure, I know you mentioned that you intend to continue to deleverage going forward. Do you have kind of a target [debt] or equity ratio that you're looking to get to?

We don't have a target per se, but we like to see the balance sheet continue to be strengthened. And, again, we'll give you some more details at the EEI Conference, but, basically strong cash flow from operations and growth in earnings will help contribute to the deleveraging, along with the fact that we currently have about $300 million of convertible notes at the holding company that are classified as debt. They're going to roll off beginning next year and into '08, and that'll add 200 basis points to our equity ratio.

Okay. Thank you.

Okay.

Your next question comes from Elizabeth Parrella with Merrill Lynch.

Hi, Ben. Thanks, very much. A question, just to follow-up on the capacity cost increases. Based on the projects or contracts that you've got in place today in those two jurisdictions, can you give us kind of an order of magnitude what the increase would look like in '08, assuming that you don't get any regulatory relief for this, either through new base rates or a tracker mechanism?

For our capacity costs that we--?

In Minnesota and Texas where you don't get recovery. I know you're saying 35 million in '07. Based on the contracts that are signed up that, maybe come on in '80, how much of on increase, sort of order of magnitude might we see in '08 for this?

Elizabeth, I don't have a-- I don't know if anybody else in the room has an answer to that. I know it will be greater at SPS but, we'll have so follow up on that, Elizabeth.

Okay. And just two other quick questions. One is, what's the timing on the SPS wholesale case in terms of that getting resolved?

With the various regulatory complaints that we have?

[inaudible] accrued 15 million as a regulatory--

There's no set timetable. We expect a New Mexico hearing, or order, coming out any day, but there is no firm timetable and there's no firm timetable for Ferk to look at this. It's whenever they look at it.

The other question would be, two quick related questions is, you mentioned things that could cause you to consider having to do equity. I'm wondering whether losing Coley and having to make a substantial payment to the IRS, which obviously you fund out of liquidity, at least initially, does that cause your thinking on equity issuance to change at all?

Yes, I think, Elizabeth, that's exactly the kind of thing that will keep our financing plan flexible for it. We obviously don't anticipate losing Coley, but if that happened it would require -- the way it would be funded is about half of it would be in cash, half of it would be an acceleration of those forward looking NRL tax benefits that we talk about, so you're looking at -- so and then we'd file, as you mentioned, funded off out of credit lines, but then ultimately I think you'd have to issue some equity to make sure that our credit matrix stay strong. You don't have to do that immediately, and we'd obviously work with regulators etc. There wouldn't be any-- while you're appealing it, there wouldn't be any cash outlay per se, but I think your point is spot on. That's the kind of credit-- adverse credit event that we would adopt to.

And last question, can you give us the operating cash flow number for the quarter and the year to date?

I can give it to you year to date. Operating cash flow year to date was 1.6billion. That's in total. I think from continuing operations to about 100 to $150 million less than that.

Okay. Thank you.

Actually, Elizabeth, we've seen-- with falling fuel prices the efforts we've made to improve our collection process, we've seen some pretty substantial increases in working capita,l so it's been a pretty good cash year for us.

Yes, that's apparent. Thanks Ben.

Your next come question Shelby Tucker with Banc of America.

Quick question on-- sort of remind me, your long term dividend policy?

Long term dividend policy is 2 to 4%.

Okay. But in terms more like a payout ratio?

Yes. It's also looking at our overall capital expenditure program, and everything else that goes into meeting, growing earnings, investing significant capital, keeping your credit rating strong, your balance strong. We've stated previously that the payout ratio target range is 60 to 75%.

I guess if your look at my spread sheet, high gained down to about 5% payout ratio by the end of this year or early next.

What pay out ratio?

[inaudible] And if that's the case, at what point would you consider increasing that growth rate?

I think you're better off, Shelby, assuming the 2 to 4% range. Clearly, that's a board decision. Again, that's going to be balanced against the things I talked about. Wanting to keep a strong balance sheet, wanting to invest as we've talked about. So, nothing is ever set in stone, but I think that's the assumption I'd be working off of.

Okay. Thank you.

Your next question is a follow-up from Paul Ridzon with Keybanc.

Can you just refresh our memories. Have you altered your depreciation schedule for the nuclear plants or are your waiting for some sort of approval?

We did have an order this year that changed the decommissioning accruals. Other than that, no.

So when you get this order is that potential up side to your D&A guidance?

No.

You don't plan on changing your appreciation lines?

The area that -- hang on a second. Paul, why don't you answer the question.

Paul, there's no change in the depreciation life for [Prairie Alan] or Monticello. It's been ordered by the Commission. Obviously, as we spend more money investing the plants and looking at some form of rider recovery, we'll also address the depreciation life for those plants.

Do you anticipate the nuclear depreciation flatline or how do you see it going directionally?

Certainly, if we extended the life, depreciation will go down. But, again, keep in mind of the additional capital investment. So we'll sit down with the Commission and look at what's the incremental capital that's been invested. What's the change to depreciation life and come up to some kind of regulatory treatment to reflect that.

So, the instant you get the NRC order, it still needs to be resolved at the State level?

That is correct. There's no wind fall that's built into our guidance range.

Thank you.

Thanks, Paul.

Your next question comes from Ashar Khan with SAC Capital.

My questions have been answered. Just a follow-up. What makes tax-- effective tax rate, Ben, to be between 28 -- I'm just trying to understand the range. What makes it go lower? What makes it go higher?

What makes it go lower is when we're able to take tax benefits that we typically don't enjoy on a continuous basis. For example, this year we were able to release a reserve that we had on some capital losses, because we were able to put in a strategy that allowed us to achieve capital gains. The reason why you see the effective tax rate higher next year is because we don't anticipate that sort of benefit. The other thing you need to look at, Ashar, is the level of base pretax income, which will affect things as well. Remember the Coley benefit is going to be there period. So as earnings grow your-- if-- as earnings grow, your ETR rate will grow naturally. But the big driver is, by far, the ability-- the amount of tax benefits that we have that are, for a lack of a better word, one time in nature.

Okay. Thank you.

You're welcome.

There are no further questions at this time. Gentlemen are there any closing remarks?

Yes. I have just a couple. First, I wanted to thank everybody for participating on our earnings call this morning. I also want to take just a moment to thank somebody that's been an incredible resource to me, in my role as CFO, and that's Dick Kolkmann. Dick is going to retire at the end of this year after 34 years of outstanding service. I'm going to miss him, the Company is going miss him, but we wish him well in his retirement. And if, I think many of you will be at EEI, where we'll be, please, take a moment to wish Dick well on his retirement. He's a class act all the way. So, with that, thank you, and we look forward to seeing you at EEI. Thanks.

This concludes today's Xcel Energy's third quarter 2006 earnings conference call. You may now disconnect.