Xcel Energy Inc. 6.25% Junior Subordinated Notes, Series due 2085 (XELLL) Q3 2006 Earnings Report, Transcript and Summary

Good morning, my name is Michael and I would be your conference operator today. At this time, I would like to welcome everyone to the Xcel Energy Q3 2006 Earnings Conference Call. [Operator Instructions]. Thank you, I will now like to turn the call over to Mr. Richard Kolkmann. Sir, you may begin.

Thanks Michael, and welcome to Xcel Energy's Q3 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. Benjamin Fowke - Chief Financial Officer and VP: Thanks Dick and welcome everyone. I’m pleased to report that for the Q3 in a row we delivered strong earnings results. Today, I will 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 continuing operations of $0.53 per share for Q3 of 2006. This compares with $0.47 per share for Q3 of 2005. Earnings from continuing operations equal total earnings for both Q3 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 Q3 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 interim rate increase in Minnesota, $11 million for the implementation of the MERP rider and $20 million for the electric rate increase in Wisconsin. For the quarter our weather adjusted electric retail sales growth was a solid 2.3% which increased the 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 Q3 2005, as a result weather had a minimal impact on our quarterly comparison. Partially offsetting these positive items was a reclassification of transmission expenses, which reduce the 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 good sold. Electric margin for the quarter also declined by $17 million for the electric commodity adjustment incentive or the ECA. As we discussed in the past the ECA is both a cost recovery and an incentive mechanism in Colorado that provides for $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 Q3 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 Q3 depreciation expense increased $19 million or 9.9%, driven by increased capital spending and changes in decommissioning accruals. That raps up the explanation of the quarterly results. It’s been a busy quarter on a regulatory front so let me update you on our progress. I will 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 had asked for reconsideration of few items overall, we think the decision represent a constructive regulatory outcome. In Colorado, we request an electric rate increase of $208 million. The request was based on an 11% ROE and equity ratio of almost 60% and a rate base of $3.4 billion. While the case is based on 2005 historic test year the filing is adjusted for known and measurable changes. I am pleased to report that we reached a definitive settlement agreement with several interveners in the Colorado rate case including the commission staff and the office of Consumer Council. The settlement reflects a rate increase of $151 million, which represents a base rate increase of $107 million and rider recovery of $44 million related to capacity and wind source cost. 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 jurisdictions. We have asked the commission to hold hearings to rule on this settlement in November and requested that final rates go into effect in January 2007. In taxes, we have requested an electric rate increase of $48 million. Based on an ROE of 11.6% and an 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 didn’t re-file 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 Q2 2007. Well, 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 on our Colorado rate case. Now I like to discuss earnings guidance to 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 recognize some tax benefits and our sales have increased due to favorable temperatures. As a result we believe we are well positioned to achieve annual earnings in the upper half of our 2006 guidance range of $25 to $35 per share. That said, we do need to monitor regulatory proceedings at SPS. As we discussed in our SEC filings we have several complaints at SPS related to cost allocations involving the use of system average cost versus incremental fuel cost. But we believe our arguments have strong merits, there is always uncertainty in regulatory proceedings. We have 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 proceeding. 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 a $35 to $45 per share. Last year at the fall EEI financial conference we increased our earnings growth objective 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 will 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. On the highlight of 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 our electric rate case settlement. We expect 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 fully tax benefits. Well, those were 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 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 had worked with us to ensure 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. Well, we have given you a fair amount of detail by year you should be aware that this CapEx forecast is not written in stone, we will 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 to a combination of cash from operations, utilization of our net operating tax laws, carry forward the dividend reinvestment program and the assurance of debt and potentially a hybrid security. As a result of constructive regulatory outcomes, we believe we can fund our capital program and elaborate 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 changes to the capital expenditure forecast, changes in cash generation, outcomes in various regulatory proceedings, and our desire to improve our credit ratings. In summary, this has been an outstanding quarter. We have 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 positioned ourselves for a strong 2007 and finally we have 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 comes from Greg Gordon with Citigroup.

Thanks good morning.

Hi, Greg.

I know this is like a broken record this question already but -- when if that all are we going to have any visibility on resolution also the extent uncertainty on the Coley tax issue?

Greg, on the holding?

Yeah, when do we potentially going to get more visibility on the resolution of the uncertainty around the Coley?

Oh, the Coley, well we have been told to be trial ready in the beginning of 2007, so if you make -- if that implies our trial will commence in the early part of 2007 and if it does, I think it’s about six day, week process. So, hopefully we will have an answer for you before Q1 of 2007, we are also still waiting Greg to here on our motion for some re-judgment that was heard several weeks ago.

Okay, now I’m looking at my old capital expenditure forecast in my model and I’m going to concede I may not be perfectly updated but this new CapEx budget looks higher. 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 provide in some of your analyst percentages.

Well, rate bases -- continue to grow about by 5% annually that the changes Greg from the last capital forecast to primarily in the area of nuclear expenditures. We are planning to upgrade our units to add another 250 megawatts of capacity. You’ll see more transmission investment primarily around the CapEx 2020 program that’s in the latter half of the decade. And all embedded in the base capital assumptions towards the latter part of the decade is some upgrading at our share goal plans in Minnesota.

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

Minnesota

Minnesota, so they wouldn’t fall under the MERP if you increase the capital base in those assets you would have to file a separate proceeding to get the recovery.

Yeah, there is two ways we get recovery, one through jurisdictional rate cases, which in Minnesota are forward test years, but what we are planning to do next year is work with our commission to try to put together an enhanced recovery method as we have done in with other capital expenditure programs.

Okay, so when I look at this 160 ramping to 180, ramping to 250 and nuclear capacity life extension there is 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, recoveries of those capital expenditures, that revenue requirement will be granted at the first level, is that right?

Now, that’s 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.

Okay, thank you.

Your next question comes from Daniele Seitz with Dahlman Rose.

Hi, just a quick question, when do you anticipate to file in Minnesota again?

Yeah, on the GAAP side, Daniele we will probably file in November of the this year, on the electric side I don’t think we have a data this point, I mean we will continue to monitor, of the -- our results but at this point there is no set determination of when we would file another electric case.

So what of the discussions you are going to have with the Minnesota Commission regarding future complexion (inaudible) any case.

You are referring to the upgrade program I mentioned, yes that would be separate.

Okay, thank you.

Your next question comes from Angie Storozynski with HSBC.

Good morning, I have one question about your assumptions. I am looking at the weather adjusted retail of electric sales gross and the natural gas sales gross and I see it that now you are projecting that’s going to be between 1.7% and 2.1% for 2007, it seems much higher than at least what I anticipated, then the -- I just want to know if you see any change in the region and the regional economy that drives the sales grow higher and also for a natural gas sales, I see that now we are assuming of the climb between 1% and 2% and as far as I remember previously we assumed that they are going to be almost flats. So can I get a comment on that?

Yeah, it’s really adjusted consistent with the pattern that we saw in this year in ‘06 and we are just extending those into ’07. This year will be on the electric side around 2%, on the GAAP side it will be slightly declining. We think those trends will continue in to ‘07.

Regarding natural gas sales, do you thing its some sort of conservation measures and do you think that, with supposedly lower natural gas prices do you think that this trends might be reversed.

It’s certainly something we will look at, but gas prices are still relatively high. If you look at it on historic basis and customers are more aware of their gas bills, more energy efficient appliances are being installed so, I mean that’s the trend we see. It’s the reason when we file rate cases that we are looking for more fixed recovery. Also we don’t have as much exposure to either weather or declining sales usage.

Right and just one more question, how about the higher operating and maintenance expense, if I understand that this quarter you guys basically invested more to ensure reliability of the service. However, when I look at the nine month numbers, we are up almost 4%. Is that when I see the guidance that between 3% and a 4% growth, then on that expenses. Why do we see that this gross, what drives the higher costs?

There is a couple of things, there is two nuclear outages this year contributed to the expenses. We are 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 we’ll see a tail off a bit from what we experienced this year. The bottom line is we are making sure that our operating system is given adequate O&Ms that we can have reliable service and we have been pretty successful at that.

Okay thank you.

Your next question comes from Greg (inaudible) with Lehman Brothers.

Hi Craig.

Hi, how are you doing?

Good.

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

Okay, let me -- the drip, the drip typically adds about $40 million a year, so about $2 million shares or something like that. The time you have the hybrid security with -- I mean it’s -- it will depend, but we are forward looking at late to 2007, 2008 time frame for that. Was your first question related to the SPS situation?

Yeah.

And specifically what did you want to know Greg?

More detail on the accruals, just what they are related to.

Well, just by examining the compliance and the merits of the compliance we have established the $50 million reserved its --there are several different compliance all at the same average versus incremental fuel cost, and that’s where we think covers it.

Okay, thanks.

Your next question comes from Paul Ridzon with KeyBank.

Hi, Paul.

Good morning, how are you?

Good.

I think 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 a $0.2 to $0.3 reserve reversal. Just wondering when you put that reserve on, whether that was in ‘06 or for prior periods.

I will answer your last questions first, the tax reserve is just been over a period of time with and we haven’t filed a rate case is Minnesota for, I guess it’s been 12 years. So it was over a long period of time and that we were able to release that as we went through the right case and resolve some open issues. I forgot your first question?

What shows the higher, you have your wholesale outlook this winter?

Yeah, well basically it 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 position us to on the higher end of the guidance from that.

And step down next to your is just expected, you won’t have such positive results next year?

Yeah, well there is two big factors, the biggest one is the fact that is under the Colorado settlement and the Minnesota order we’ve agreed to share much of a percentage of our trading margins coming off of our generation stack that we had in the past that combine growing retail low is the reason why see a decline in trading margins.

Thank you very much.

Your next question comes from Nathan Judge with Atlantic Equities

Hi Nathan

Good morning, I wanted to follow up on the accrual of the -- will that $15 million would that fall into this quarter?

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

Okay great, also in the ONM recorded that your higher employee benefit cost is primarily performance basis it was negative $21 million impact. Could you quantify how much that was performance base?

The majority of it was in its -- a number different programs. The biggest driver was the short-term annual incentive as we look to be on upper end our earnings guidance range that means from incentive cost build-up. There was also some increases, Nathan on some longer return incentive related to the good performance that our stock exchange.

I see. Okay so looking forward in your expectation for 2007 would you expect that that kind of level to continue or is it more of a one time item?

I don’t think you would have the same level. I like to see it continue because that would mean that we are going very well, but it would be based around performance.

I understand, and based on 2007 levels what we -- if you were to achieve similar type of appreciation in your stock and see similar type of earning performance would it be similar type of impact for performance bank?

Jeez, but I think what you are seeing this year when you add to $21 million as an incentive program all in that and probably be pushing close to $35 million to $40 million and that is not what we would -- when we go into the next year the number would be roughly be say $10 million lower. So you had would see -- if the performance is on the upper-end and you might see some there, but Nathan that all depends on -- there is a lot of mechanics to go into that.

Sure, okay I appreciate that. Just finally on the capacity payments for your 2007 projection and assumption that you expect to $35 million it could stir up capacity cost. You just go into that more detail there?

Sure, as our level grows we need to make sure that we have the capacity whether owned or purchased to serve the load. And the good news is that under the Colorado settlement we were able to achieve a capacity wider so the capacity cost flow through automatically. But that’s very credit supportive 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, so as we need to add capacity for growing sales, the support growth, sales growth is what we are doing.

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

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

Right, I appreciate that. Thank you.

Your next question comes from Karen Choi with Alliance Bernstein.

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

I think the current plans would contemplate to be **0117issued at the holding company level.

Thank you.

Welcome.

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

Thanks, just to get 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 cost profile in Minnesota and SDS, isn’t that going to be a drag on your authorized returns, shouldn’t we assume that you ultimately file for those costs?

Oh there is a drag on the -- there is no doubt about it. It’s just like O&M, those are drags on your cost, Greg, but that’s what you have sales growth for another items.

Okay, so you don’t think that the -- that when we bottle these down 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 but some of that will depend on actual sales growth. I should point out 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 cost support increase sales growth there and margin growth there. So I think all in all it’s just the function of meeting increased revenues coming from our sales growth.

Okay, I understand so in it's totality it's really that top line revenue growth and that of these costs?

Yes.

Think of those things in together not separate?

Yes.

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

Yeah, I think if you -- we are going to give more detail on this, by the way, Greg, at the EEI conference but if you go through our capital expenditures the breakouts, you have your base capital expenditure programs, most of that’s going to be covered through your traditional regulatory cost recovery methods either historical forward attached year depending on the jurisdiction as MERP is a forward-looking rider recovery in Minnesota, Comanche 3 we had the ability to bring in forward-looking clip as we file away cases. Minnesota Wind Transmission and CapEx 2020 are coverage for forward rider mechanisms and as I mentioned the nuclear capacity increases in life extension. Right now the method would be filing the right case. We are going to work with the commission and staff next year to try to get alternative recovery mechanism in price.

Okay, so the 160 is spent this year and future CapEx you have forecast, those are not roll into our recovery mechanism as yet?

Correct.

Okay, thanks guys.

Okay.

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

Yeah I, just wondering how much capacity will you add to your plants and by what year?

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

Its just going to be upgrade, I’m sorry, yeah.

You’re talking about the capacity increase for our nuclear plants?

Yes.

Yeah, that will add 250 megawatts of increased capacity that wouldn’t come on line until -- yeah I believe the actual operates will be past the 2010 timeframe.

Okay, great thank you. This is the work that get -- the expenditures that get you there.

Yeah, thanks. operator: Your next question comes from Dan Jenkins with the State of Wisconsin.

Good morning. First of all I just want clarification on that transmission field reclassification, it looks like -- it’s coming out of but what has been going into?

First of all, Dan there is no net income impact from the re-class, basically as we look at the rules we apply those to contracts that were expiring and as we renegotiated those just put them where they will -- their components will better classified.

Where is the offset then for the --

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

Approximates on, are the revenue essentially or --?

It’s added, its increasing cost of goods sold, its lower in O&M.

Okay.

No net income impact.

Okay, Ben I was wondering on your nuclear outages list, what kind of assumptions you have for that for ‘07 and I didn’t see that list among your assumption?

It’s a good question. We only have one-outages next year versus two this year, which helps to keep the O&M at the lower level that we are assuming.

Which unit is that?

Minnesota, yeah it’s Minnesota.

Is that one of the units that will be upgraded? Will that --?

We are ultimately we’re looking to operate all three units.

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

No not at this outage that we are talking about in ‘07.

Okay, so it’s … after ‘07 that will see the operation of those various units?

Yeah, it operates and life extension. So we are 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 a decade.

Okay, have you all ready filed with the NRC to get the licenses extended as well.

Yes,

Okay you have gotten all those approvals?

Yeah, within the state as well we expect approval in actually November this year. We will expect to get some of the approvals, we have also filed with the Minnesota Public Utilities Commission those filings are going pretty well.

Okay. And then I was just curious on your capital structure, you mentioned you intend to continue to deleverage going forward, what do you have -- kind of a target debt or equity ratio that you are looking to get to?

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

Okay, thank you.

Okay.

Your next question comes from Elizabeth Parrella with Merrill Lynch.

Hi, Elizabeth.

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

For our capacity cost that we --

In Minnesota and Texas where you don’t get recovery, I know if you are seeing $35 million in ‘07, based on the contract for the signup that may be coming on in ‘08, how much of an increase sort of order of magnitude might we see in ‘08 for this.

You know, Elizabeth, but I don’t have -- I don’t think anybody else in the room has an answer of that. I know what it will be greater at SPS but you have to follow up on that also.

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

One that -- with the various regulatory compliance that we have?

Right, where you have accrued $16 million of the regulatory --

Well there is no set timetable. We expect the New Mexico hearing or order coming out any day but there is no firm timetable and there is no firm timetable for us to look at it.

All right, and then the other question would be just I guess two quicker related questions of -- you have mentioned things that could cause you to consider having to do equity and I’m wondering whether losing (inaudible) and having to make a substantial repayment to the IRS which obviously you funded a liquidity at least initially, does that cause your thinking on equity issuance to change at all?

Yeah I think, Elizabeth, that’s exactly the kind of thing that will keep our financing plans flexible for -- we obviously don’t anticipate losing (inaudible), but if that happened it would required and the way would be funded is about half of it would be in cash, half of it would be in acceleration of those forward-looking analog tax benefits that we talked about. So you are looking at -- and then we probably would like as you mentioned funded off of our credit lines. But and ultimately I think you would have to issues some equity to make sure that our credit matrix stay strong. We want to do that immediately and we have obviously worked with regulators etc and it wouldn’t be any -- while you are -- there wouldn’t be any cash outlay for say but I think your point is spot on and that’s the kind of credit, adverse credit event that we would adopt to.

Okay, and last question, can you get us the operating cash flow number for the quarter in the year-to-date?

I can give it to year-to-date, operating cash flow year-to-date was one $1.6 billion that is in total I think from continuing operations to about $100 to $150 million less than that.

Okay, thank you.

Actually, Elizabeth we have seen the falling fuel prices, the efforts we have made to improve our collection process, we have seen some pretty substantial increases in working capital so its been a pretty good cash year for us.

Yes, it’s apparent, okay, thanks Ben

Your next question comes from Shelby Tucker with Bank of America.

Hi, Ben

Hey Shelby.

Quick question on – sort of remind me your long-term dividend policies?

Long-term dividend policies 2% to 4%.

Okay, more compiled ratio.

Yeah, its 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 sheet strong. We stated previously that the pay out ratio the target range is 60% to 75%.

Okay, I guess if you look at my spreadsheet, about 65% that ratio by the end of this year or the next.

I am sorry on what pay out ratio?

About 65% and if that is the case at what point would you consider an increase in that gross rates.

Well, I think you better of -- shall be assuming the 2% to 4% range, I mean clearly that’s a board decision. Again that’s going to be balanced against the things we talked about one needs to keep a strong balance sheet, one into invest as we talked about so nothing is ever said in stone but I think that is the assumption I would be working off.

Okay, thank you.

Your next question is a follow up from Paul Rizdon with KeyBank.

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

No we did, we did have an order this year that changed the decommission in accruals, other than that no.

So, when you get this order is that potential upside to your G&A guidance?

No

You don’t plan on changing your depreciation lines or?

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

There is no change in the depreciation (inaudible) been ordered by the commission. Obviously as we spend more money investing the plants and looking at some recovery we’ll also address the depreciation lines for those plants.

So net, do you anticipate kind of the nuclear depreciation, kind of flat line or how does that going directionally.

Well, certainly if we extended in life, the depreciation go down but again keep in mind of the additional capital investment, (inaudible) commission look at what is the incremental capital that’s been invested, what is the change of depreciation life and come up to some kind of regulatory treatment to reflect that.

So the instant you get the NRC order its still need to be resolved at state level?

That’s correct. There is no windfall that built into our guidance range.

Thank you.

Thanks Paul

Your next question comes from Ashar Khan with SAC Capital.

My questions had been answered, just a follow-up. What makes the effective tax rate when 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 are able to take tax benefits that we typically don’t enjoy on a continuous basis. For example, this year we were able to release reserve that we had on some capital losses because we were able to put in a strategy that allow us to achieve capital gains. The reason why you see the effect of tax rate higher next year is because we don’t anticipate that sort of benefits. Then the other thing you need to look at Ashar is the level of base pre-tax income which will affect things as well, because remember the benefit is going to be there -- period. So as earnings grow your ETR rate will grow naturally. But the big driver is by far the ability that -- the amount of tax benefits that we have that are so 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? Benjamin Fowke - Chief Financial Officer and VP: Yeah, I have jus a couple. First I wanted to thank everybody for participating in our earnings call this morning. I also want to take a just 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 this year after 34 years of outstanding service. I’m going to miss him; the company is going to miss him. But we wishing well in his retirement and I think many of you will be at EEI we will be and please take a moment to wish Dick Kolkmann in his retirement. He is a class act all the way. So with that thank you and we look forward to see you at EEI, thanks.

This concludes today’s Excel Energy Q3 2006 Earnings Conference Call. You may now disconnect.