埃克西爾能源 (XEL) 2004 Q4 法說會逐字稿

Good morning, ladies and gentlemen, my name is Paul and I will be your conference facilitator today. At this time I would like to welcome everyone to Xcel Energy's fourth quarter 2004 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer period. If you would like to ask a question during this time, simply press star, then the number 1 on your telephone keypad. If you would like to withdraw your question, press the number 2 on your telephone keypad. In order for everyone to have the opportunity to ask a question, please limit yourself to one question. If you have a follow-up question, please re-enter the queue. I would now like to turn the conference over to Mr. Richard Kolkmann, Managing Director, Investor Relations. Please go ahead, sir.

Thank you, Paul, and thank you to those listening in to our call today. Welcome to Xcel Energy's 2004 earning's release conference call. I'm Dick Kolkmann, Managing Director of Investor Relations. With me is Ben Fowke, Vice President and CFO of Xcel Energy. We also have several others here 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 anticipated are described in our earnings release and Xcel Energy filings with the Securities & Exchange Commission. Now I'll turn the call over to Ben Fowke.

Thanks, Dick, and welcome everyone. Xcel Energy recorded solid earnings from continuing operations of $1.27 per share for 2004, which equals our results for 2003. We are pleased that our results exceeded our guidance range. Our total earnings, which included the impact of discontinued operations were $0.97 per share for 2004, compared with earnings of $1.50 per share for 2003. Total earnings for 2004 reflect an asset impairment charge related to our Seren investment, while total earnings for 2003 included tax benefits associated with our previously held investment in NRG. As with every year, there are ups and downs, things like weather which can have a positive or negative impact on earnings. We expect these deviations year to year and try to establish an appropriate range for our guidance. However, as you develop your models and projections for 2005, I want to draw your attention to a few atypical items included in our 2004 earnings from continuing operations. These are items that we did not anticipate or bake into our 2004 earnings guidance.

In 2004, we recorded tax benefits of approximately $36 million or $0.09 per share. Although tax judgments occur every year, some positive, some negative, the majority of the tax benefits recorded in 2004 relate to the completion of five tax audit cycles which resolved several issues related to prior years. Coincidentally in 2003 we also recorded tax benefits of $36 million or $0.09 per share due to resolution of various tax issues. You should not view this as a trend, as we do not expect to record additional tax benefits for issue resolution in 2005. We also recorded a charge of 17.6 million or approximately $0.03 per share for a settlement of three lawsuits related to NRG. While we continue to believe that the Company acted appropriately, we feel the settlement was prudent considering the expense and risk of continued litigation. Now let's move on to the core of our business. Our utility subsidiaries provided earnings of $1.32 per share for 2004 compared with $1.34 per share for 2003. Although the earnings were relatively flat, there were a number of significant differences from last year. On the positive side, we had higher short-term wholesale margins, which increased earnings by $0.04 per share. We had lower depreciation expense, which increased earnings by $0.03 per share. And finally, we had lower interest expense, which increased earnings by $0.02 per share. Offsetting these positive deviations were mild weather, which reduced earnings by $0.08 per share and higher utility O&M expenses that decreased earnings by $0.03 per share. This summarizes our 2004 earnings.

I want to provide a little more detail now on some of the significant factors that affected our results in 2004. As you review the details of our earnings release, you will notice base electric utility margins declined by $59 million for the year. This is largely due to unfavorable weather and regulatory accruals. As most of you know, our summer and winter temperatures were very mild. We experienced this impact throughout our service territories. In Minnesota, THI degree days were 27 percent less than normal, while heating degree days were 4 percent less than normal. In Colorado cooling degree days were 29 percent less than normal while heating degree days were 6 percent less than normal. Finally in the Texas panhandle, both cooling degree days and heating degree days were 8 percent less than normal. As a result of the mild weather and warmer than normal winter seasons, our retail electric margin was $56 million lower for 2004 when compared with 2003.

Utility margins also declined due to a few regulatory accruals. Utility margins were adversely affected by increased accruals for customer refunds at -- under the quality of service plan. For 2004 we accrued a total of $18 million for refunds under the quality of service plan. This is an increase of $12 million over 2003 accruals. It should be noted that 7 million of the $18 million accrued related to prior years. In May of 2004, SPS filed its 2002 through 2003 fuel and purchase power cost reconciliation with the Texas commission. Although a similar issue was previously litigated and decided in SPSs favor in a prior fuel factor case certain interveners have objected to SPSs methodology for assigning average fuel cost to wholesale sales among other things. The amount of the recovery contested by the interveners ranges from $49 million to $86 million. We are confident in the merits of our position.

However, in 2004, we recorded our best estimate of potential liability related to fuel reconciliation at SPS. We are pursuing a settlement agreement with the parties involved. Since we are in settlement discussions, it's not appropriate to discuss the amount of the reserve. If we can't reach a reasonable settlement, we will vigorously contest this issue through the regulatory process. I think it's important to recognize that this is an issue of fuel cost allocation between retail and wholesale customers. For decades SPS has consistently allocated average system fuel cost to all firm sales including wholesale firm sales. Our position is that retail customers are attempting to allocate higher costs to the wholesale sector and away from retail customers in an attempt to avoid paying for higher natural gas prices. If we don't reach a settlement of this issue, the Texas commission is expected to decide this case by the end of May. We don't expect to accrue any additional reserves, and our 2005 guidance doesn't assume any margin adjustments related to this issue.

During 2004, we had strong performance selling into the short-term market, which partially offset the adverse impact of weather on retail sales. Our generation fleet has performed extremely well over the last several years. This allowed us to meet our native load requirements. And when native load is down, sell any excess generation into the short-term market. As a result, short-term wholesale and trading margin was $111 million in 2004, which was $34 million higher than last year. Key drivers included a significant contract at NSP, Minnesota, which provided $17 million of margin during the first quarter of 2004, higher on peak and off peak prices particularly in map, which made our low cost coal generation very attractive, plan availability and cooler temperatures which made more generation available for wholesale sales. As I've pointed out in the past, while our goal is to maximize the value of our wholesale margins, our first priority is to serve the retail load. We can only capture additional short-term wholesale margins if we have incremental capacity to sell after meeting our native requirements. Thus, we have limited ability to lock into these higher price margins. During 2005, we will be opportunistic and work to maximize Company earnings on both the retail and wholesale side of our business.

Let's now shift the focus to operating expense. Our 2004 regulated O&M expenses increased $22 million or 1.4 percent over 2003. In our original 2004 guidance, we indicated our O&M expenses were expected to be relatively flat in 2004. Approximately $12 million of the O&M increase was for services that we provide to other utilities or power companies, including helping the Florida utilities after the hurricanes. We are reimbursed for these costs, but the reimbursement is recorded in revenue. So while it doesn't have an impact on our net income, it does create a deviation in O&M expense and revenue. If you adjust our O&M expenses to remove the impact of these reimbursed services, O&M increased by $10 million or 0.6 percent. The remainder of the O&M increase is due to higher employee benefit cost, increased spending on initiatives and higher IT costs, which were all set in part by lower incentive compensation cost. Depreciation expense for 2004 was $21 million lower than 2003 levels, largely due to a couple of regulatory actions. We experienced the full year impact of a rate change in Colorado, which reduced depreciation expense by $10 million in 2004, and based on a Minnesota commission order, NSP Minnesota modified it's decommission and expense recognition, which served to reduce decommissioning accruals by $18 million when compared to 2003. These regulatory adjustments more than offset the normal increase we've seen in depreciation expense.

Looking at interest expense, as we've mentioned in the past, we expected our financing cost would decline in 2004, primarily due to the refinancing activities we completed in 2003. Our financing costs for 2004 were $16 million lower than 2003 levels. This sums up the details of our utility operations. Moving to nonregulated and holding Company cost, other nonregulated subsidiaries and costs at the holding Company provided earnings of $0.03 per share for 2004 compared to $0.02 per share for 2003. Eloigne and our utility engineering are the only remaining nonregulated subsidiaries included in continuing operations and these Companies don't have a material impact on our financial results. In addition, in 2004, we incurred legal settlement cost. While in 2003, we incurred restructuring costs related to the disposition of NRG. Financing costs reduced earnings by $0.08 per share in 2004 compared with a reduction of $0.09 per share in 2003. These costs reduced earnings by $0.08 per share in 2004 compared with a reduction of $0.09 per share in 2003. These costs for interest expense on debt issued at the parent Company.

Looking ahead, our 2005 guidance range for earnings from continuing operations remains at $1.18 to $1.28 per share. This includes utility earnings of $1.27 to $1.37 per share. The combination of financing costs at the holding Company and positive results from Eloigne utility engineering are expected to result in a loss of $0.09 per share. Because we've discussed our key assumptions several times in the past three months, I'm not going to cover the 2005 assumptions. We have updated a few of the assumptions and they are detailed in our earnings release for your review. That covers earnings for both 2004 and 2005. Next I would like to spend a few minutes on some strategic issues. We continuously evaluate our business portfolio. It's part of our strategy of focusing on the core utility operations. Over the past few years, we've been very successful in divesting our noncore assets.

In January 2005, we made further progress when we sold Cheyenne Light, Fuel and Power to Black Hills Power. The sale resulted in net cash proceeds of approximately $65 million. In the case of Cheyenne, we didn't have a significant presence in Wyoming or see much opportunity to grow our operations there. Therefore, it made sense for our customers and our shareholders to sell our Cheyenne assets. Our next priority is the sale of Seren, our telecommunications subsidiary. In September 2004, we announced that Seren was for sale. Seren has an excellent product and has improved its financial performance. However Seren does not fit with our strategy of focusing on our core utility operations. As a result of this decision, the financial results for Seren are reported as discontinued operations. In 2004, we recorded an estimated after-tax impairment charge of $112 million based upon an assumed sales price of $2,400 per customer. Based on our preliminary estimate, the sale of Seren would provide us with cash proceeds of approximately $100 million to closing. In addition, we would have an NOL tax benefit of approximately $65 million that will be realized over time. We will use these funds to reinvest in our utility business.

We've been meeting with prospective buyers and are pleased with the level of interest that's been generated so far. We narrowed the bidding list down to seven parties and expect final bids in February. Once a sales agreement is reached, we will need to transfer Seren's franchises and telephone services authority. Based on this process, which will take several months, we expect to complete the sale of Seren in the summer of 2005. 2004 was a good year for us, as we laid the foundation for investing our core utility, we had several significant accomplishments. Probably the most significant was receiving commission approval of our lease cost plan in Colorado, which will allow us to add a new coal unit at the existing Comanche plant site. This project will provide low cost generation for our customers and a future earning stream for our shareholders. In 2004, we successfully replaced the steam generators at Unit one at the Prairie Island nuclear plant. We took the plant out of service in September, and it was back up and running in November. The project went extremely well and was completed on budget.

As a matter of fact, the combined capacity factor at our three nuclear units was 91 percent for 2004, even with the replacement of the steam generators. We filed our Minnesota resource plan in November, although our current capital forecast does not include any projects related to the plan, the resource filing clearly indicates the need for additional generation and transmission assets in the upper midwest, which could drive earnings growth in the future. As part of the resource plan, we also started the process to extend the lives of our nuclear plants. We're well positioned for changing environmental rules and regulations based upon the work we've done in the last few years on projects like MERP. Finally and importantly to our shareholders we increased the dividend on annual basis from $0.75 to $0.83. Our objective is to deliver the financial results that will enable our board to grant annual dividend increases at a rate consistent with our long-term earnings growth rate. All things considered, it was a successful year. In the next couple of years, we will be filing rate cases in many of our jurisdictions.

I think you will agree we've developed constructive agreements with our regulators on projects like MERP and Comanche 3. We think this illustrates the strong relationship we have with our commission. As we look to 2005 we're focused on several challenges besides the normal day to day operations of our utility business. We have to prepare for the operational uncertainties surrounding the implementation of MISO day two and the MERP market power issue, both of which could impact our short-term wholesale margins. We have to continue our efforts to improve reliability in our major jurisdictions, particularly Colorado. We expect to complete the sale of Seren. We need to get environmental permits for the Comanche 3 coal plant. Although we don't expect resolution in 2005, we need to continue to press our case with the IRS in the COLI dispute. Finally we need to develop a strong case for the Minnesota electric rate increase filing we plan to make at the end of 2005. The case will be critical as we move into 2006.

So with that, I'll wrap things up. In 2004, we continue to execute our build the core strategy. As we execute this plan, we expect to deliver an average total return of 7 to 9 percent per year. We're pleased with 2004 results, and we're positioned to deliver solid results for 2005. So with that, let's open it up for questions.

Ladies and gentlemen, if you are an analyst or investor and would like to ask a question, press star, then the number 1. In order for everyone to have the opportunity to ask a question, please limit yourself to one question. If you have a follow-up question, please re-enter the queue. Also, if you are with the media, please direct your questions to Xcel Energy's communication department. One moment, please, for our first response. Our first question comes from Ashar Khan with SAC capital.

Congratulations, Ben, on a successful year. Can I just ask ask you, well, in your last presentation to us around EI you had given us some CapEx number for the Colorado plant, they were about $33 million or $36 million in '05, jumping up to about an additional $186 million in '06. Can we use those still as a good guidance for expenditures going forward or is there more revised forecast that you can share with us?

No, I think those are the best numbers to use, Ashar.

So we can utilize the similar kind of return analysis that you had done over there to have the step ups. Is that accurate?

Yes.

Can you just talk about -- or is it too early to talk about the magnitude of the electric rate case that you'll file later on this year? Can you share with us what kind of ROE you're earning right now?

Well, we haven't completed the '04 regulatory ROEs. I think we have disclosed what we did in 2003. We expect those trends to pretty much continue as we do complete our analysis for '04. A little early to start talking about the size of the rate case at this point. We're doing a lot of work and analysis around that. So we'll announce that as soon as we're ready.

Could you remind us what your '03 was, ROE?

It was 9.3 percent at Minnesota and 9 percent in Colorado.

Okay. Okay. Thank you very much.

You're welcome.

Our next question comes from Elizabeth Parrella with Merrill Lynch.

Thank you. Wanted to ask with respect to your '05 guidance on the short-term wholesale and trading margins, looks like you refined it a bit from last quarter, implying that it looks like it's now maybe another $10 million decline versus where you had been. I'm just wondering if that's a different view on the markets or if it's some concern on the MISO issue or if it's just sort of a true up to '04 actuals? Maybe you could just elaborate a little on that.

It's just a refinement of the range, Elizabeth. You know, as we look at '05, there's a couple of factors that we need to consider. The first is we don't have a contract in place that we have this time last year that produced $17 million in margin. We are assuming a return to normalized weather as well as sales growth, so you have less generation available for -- to sell into the short-term markets. Finally we're going to a MISO day two market, the MISO region is where we made the lions' share of our margins this year. There's uncertainty around how those rules will ultimately translate to our ability to make margin. In addition, there is a two-month cost-based pricing scheme when MISO day two first rolls out. So you put all those factors together and we thought it was appropriate to refine our range.

I'm sorry, you say a two-month cost base pricing scheme.

Right. When the day two market first kicks off in April 1, for two months it will be cost-based pricing.

Okay. And if I could ask another question just on the whole Colorado process, on the lease cost plan, can you talk us through a little bit the next step both on the coal plant and around any RFPs that you may be issuing in Colorado this year. And to the extent any of that capacity were to come on-line this year or next, would the capacity cost of those be expensed by the Company, or given that you had gotten the rider adjustment last year but that was based on the previous, you know, resource plan.

Yes. Well, first of all, on the coal plant, we received the -- final order did come out just recently. The next step on the coal plant is to start working on the environmental permits. That's where the lions' share of our efforts will be next year. That's the expenses primarily that you see as well. On the RFPs we did do a 500 megawatt RFP for wind power. I think that's been scaled down to 400 megawatts in part because of the difficulty in putting these things together with the uncertainty around the tax benefits. So I forgot the second part of your question.

To the extent that any of that wind or any other new capacity comes on line through an RFP process this year or next, given that you're not going to get a base rate adjustment during this period in Colorado, are those capacity costs expensed by Xcel?

Yes. I mean, the rider that we received was for specific capacity costs, power purchase capacity cost related to the 1999 RFP. So to the extent we had more capacity in between now and filing our rate case, that would be an item that was expensed, unless it falls under some other rider type mechanism.

I guess the '05 piece of that is reflected in your assumption of $15 million net increase.

That's right.

Okay. Okay. Thank you.

Our next question comes from Greg Gordon with Smith Barney.

Thanks. Tax related question in two parts. The first is your tax rate guidance, looks like it's changed honestly. You're saying 28 to 31 percent tax rate. I think prior to this you were saying 30 to 31 percent tax rate. Am I incorrect or if not, what's the --?

That's right, Greg. You're correct.

And can you explain why you have a better tax rate on a pro forma basis?

We widen the range, because if you take out some of the nonrecurring things I referred to on the call, I believe our effective tax rate would be roughly around 28 percent. It seemed to us logical to assume that that would -- that rate, there's potential to have that rate as we look at 2005. Again, you know, you have some typical year on year type adjustments that you make. We don't anticipate any major adjustments and issue resolution that we saw in '03 and '04, but it did lead us --.

I'm sorry.

But we felt that the range probably should be widened to reflect where we are today.

Okay. The follow-up on that is, you mentioned here in the last paragraph of the release on page 11 that the FASB could potentially release an exposure draft of an accrual which might raise the bar on recognition of tax benefits that are under -- that are in dispute with the IRS.

Right.

Could you explain to us what it is that you know about the potential position that FASB might be taking? While obviously you can't -- I don't think any of us can say anything definitive what your lawyers are telling your decision path might be towards the resolution of that issue.

We first surfaced this on the third quarter earnings call when we got wind that an exposure draft may be issued by FASB. That exposure draft is not out yet. We do anticipate that it will come out soon. Then of course once it's in exposure draft, theres a comment period. And ultimately it could or could not be adopted. If it's adopted, and we don't anticipate that it would be adopted before the fourth quarter of this year, then what it would require is for us to reverse out the benefits that we've enjoyed and approved for prior periods out of retained earnings. That amount at the end of the year was $311 million and $368 million if you added interest and penalties.

Okay. And then on a go-forward basis obviously you would book any incremental credits -- any incremental earnings until hopefully this was resolved in your favor.

You'd stop booking the benefits going forward. That could potentially be a $0.09 impact for us in '05. But just keep in mind, that doesn't change the fact that we would still enjoy the cash flow benefit of that. This is just financial reporting. As you mentioned, we would ultimately resolve that in court.

Then if it was resolved in your favor --?

It would all come back on.

It would come back. If it was resolved to your detriment, not only would if not come back but there could potentially be a cash outflow.

You've got it right.

Thank you very much.

Next question comes from Ali Agha with Wells Fargo.

Thank you. Good morning.

Good morning.

I just wanted to clarify exactly the schedule on the electric rate cases. When would you file the Colorado case?

Colorado case would be filed sometime in the early part of '06 with the anticipation that rates would go into effect in '07.

Into '07. Also, related to that, how much equity would you need to infuse in Colorado to get to that 56 percent equity?

We've already started infusing equity as we've retired some debt. The targets there is a 56 percent imputed debt level, 245 million is what we would need to get as far as additional equity to reach that goal of 56 percent equity ratio.

I see. And also, if could you remind me, the Minnesota, when is the next electric rate case coming up there?

Let me just follow up on that last question. Keep in mind that the equity can come from multiple sources, including -- the key is it will be injections of equity from the parent Company. And we have different sources of that cash. Your next question I think related to the Minnesota electric case?

Yes.

We anticipate that we would file that in the fourth quarter of this year 2005 with interim rates that would go into affect at the start of '06.

I see. There's no change in the equity ratio for Minnesota, is there?

There's no change in the targets. I mean, we'll be -- we obviously look at our equity ratios as it relates to our credit objectives.

That is 53 percent, if I recall correctly?

That sounds a little high. I think it's more in the 49 to 50 percent range.

Okay. Thank you.

You're welcome.

Next question comes from Charles Fishman with A.G. Edwards.

Good morning. On the $0.09 tax benefit for the full year, how much of that is in the $1.27?

All of it is in the $1.27, Charles.

Okay. I was just confused on that. Then COLI, I noticed the benefit from your last assumption I believe went from $0.08 to $0.09.

Yes.

Is that a trend -- assuming COLI continues and you win the IRS case, is that a trend that continues if the COLI increases?

It does go up over time. The change this year between $0.08 and $0.09 just a true up of our estimates.

Okay. Thank you.

Next question comes from Phyllis Gray with Dwight Asset Management.

Good morning.

Good morning.

One more follow-up question on the COLI. Can you tell me what the cash flow impact would be say in the case that you had an adverse -- if you did not prevail in your appeal?

Well, if we -- part of that will depend upon when this thing was actually went to court and we went through the appeal process and everything else, because every year we continue to take a cash benefit and receive cash for it. As of right now, it's $311 million, if you add interest and penalties to that, it would be approximately 368 million. So that would be the amount today that we'd have to pay in cash back to the IRS.

Okay. And and if I could also ask a quick question about the reference in your release to the regulatory plan in Colorado that permits you to increase your equity component of the capital structure.

Yes.

Can you talk a little bit about where the capital structure is currently and what your plans might be to increase the amount of equity?

We're about -- first of all, let me give you some history on that. We were allowed as part of a lease cost plan to increase our equity ratio to a target of about 56 percent. What we're trying to do there is to offset the impact of power purchase -- imputed debt associated with our power purchase contracts. It is part of SMPs methodology. Our credit metrix are impaired by that. The commission recognized that and understood that we needed to have a more conservative cap structure. As I mentioned to you previously, I think we're around the 50 percent equity ratio level now. We anticipate injecting from the parent Company roughly about $245 million of equity this year, part retiring debt as it comes due. So that when we file the rate case, our equity ratio will be about at the 56 percent level.

Okay. Thank you.

You're welcome.

Our next question comes from Carrie Stevens with Morgan Stanley.

Hi, good morning.

Hi, Carrie.

I just wanted to follow up on a couple of things. First, I know you've been talking about kind of the higher equity infusions and so forth into some of the utilities. I know your CapEx spending is increasing. Just current view on needs for equity. I know you had said kind of not near term but more intermediate term is that still the thinking?

Yes, you know, we know that at some point in the -- past '06 there will be a need for some equity issuance, but we don't anticipate any before that given our current level of capital expenditures. The reasons for that strong cash flow both from the operating utilities as well as the tax benefits that we're still enjoying associated with the NRG worthless stock deduction that we took.

Okay. And I know you had just gone over the situation in Colorado with the higher equity ratio, do you not -- are you not trying to attempt to do that same structure for Minnesota? It sounded like you weren't. Or is there a need to?

The imputed debt isn't as big of an issue at NSP Minnesota, but we are looking at it, again, as we set the right equity ratios to achieve our credit objectives, that will be part of the equation.

Okay. And then just with CapEx, I know you gave a real -- you've been giving very detailed forecast. I just wanted to make sure I didn't see an updated one in this packet, that everything is kind of still the same I guess in line with where it was before.

Everything is the same. If we refine it, we'll get it out to you right away and everyone else.

Okay. Then lastly on the environmental permitting for Colorado, what amount of time have you built into your kind of budget and construction forecast to receive those approvals? And you know, what's your kind of view of maybe what an upside and downside case could be to that timing?

Well, we expect to get the necessary permits by the fall of this year and start construction shortly thereafter. You know, you always have some play as to when you get the permits, but I think that was one of the big benefits, Carrie, that we enjoy as part of the settlement that we reach with all the interveners, including the environmental parties, regarding the construction of the coal plant. So I think we've taken as much risk as you possibly can off the table as far as getting those permits. And you know, of course once you build it there's always some construction risk. But again I think the mechanisms we've got in place mitigated that absolutely about the best you can.

Okay. So you're feeling pretty comfortable with kind of, I guess, year end construction start date?

I think that's about right.

Okay. Great. Thanks again.

Thanks, Carrie.

Our next question comes from Vidula Merke with Zimmer Lucas.

Good morning.

Hey, Vidula.

Couple of follow-ups from I think what other people were asking. Carrie was talking about equity, I know you of guys have your dividend reinvestment plan, and you indicated that probably beyond '06, an additional increment of equity would probably be required. Can you kind of ballpark, you know, kind of like a range that we should kind of be thinking about for out in that area?

You know, it's a bit away, Vidula, so I think we just have to get some time on our side before we can hone in on that part of it's going to be how successful we are in the rate cases, the ultimate proceeds we receive from Seren, our ability to generate cash flow internally. There's a lot of different factors. So all I would say is that we do anticipate some level of equity issuance based upon our current level of capital expenditures and that five-year forecast that's been out there for a while.

In the meantime we still should continue about $40 million a year from the new issue to the reinvestment plan?

Right.

In the Minnesota case, will you be able to use a forward looking test year or will it be a historic test year in Minnesota.

Minnesota is a forward looking year.

You'll basically have a -- basically project those six-years that will be the basis for the case?

That's exactly right.

Now, Colorado is the other way around. You have a historic year, so you'll have a lot of issue there when we get around to that case?

Colorado is an historic test year. Of course, as part of the lease cost planning, we are able to capture Quip on a forward basis depending on what our credit rating is at the time. It would either be forward or historical, depending upon that credit rating. That asset associated with the Colorado -- with the coal plant Comanche 3.

So I mean if we think about that case, we'll be using an '05 test year with an update of the CapEx under the lease cost plan? Is that basically it?

That's right. Along with any known and measurable changes that you're always allowed to put into a rate case.

I guess one last thing, at least from watching it, it seems like things have been a little bit more normal, if not better than normal at least in Minnesota. Can you comment a little bit how the year has gotten started off in terms of weather and whether in sales or just general operations?

I think it's been generally mild in Colorado. I think in Minnesota it's -- it started out pretty cold. You know, I'm just giving you a weather forecast now. It seems warmer than usual in the last couple weeks. So I think we're probably going to be about neutral, no big material impact, although it has been mild in Colorado.

And all power plants and everything like that have -- thus far have operated as expected. No unplanned outages or anything like that has occurred thus far.

No, nothing of any material sort. We continue to run a very good suite.

Thank you very much.

Thanks, Vidula.

Next question comes from John Hanson with Imperial.

Good morning.

Morning.

Just want to clarify on the coal plant CapEx, that that will be getting Quip until you roll that into the Colorado case or you get cash returns on those.

Typically what you get when you're building a multi-year project is AFUDC which of course is an earnings -- it's a financial reporting earnings pickup not a cash pickup. What we're going to get is when we file rate cases and we will in this timeframe, we will get Quip rolled in the ra rate basis and we'll earn a return on that based on whatever return we get -- whatever the allowed ROE is. We'll get that on a forward looking basis if our credit rating is at one level, and it will be an historical basis if our credit rating is better I believe on a senior unsecured basis, BBB plus. Ultimately when the plants are completed, you would roll those into rate base when we filed rate case after the -- the '09, '10 timeframe. In 2005 and '06, since we won't have rates in effect we'll recognize AFUDC, because we only -- we'll get forward looking Quip in the rate case when we file rate case, those rates will go into effect in Colorado in '07. Up until that timeframe, we would recognize AFUDC.

Good. That helps me out. Thanks very much.

You're welcome.

We have a follow-up question from Ashar Khan with SAC capital.

Ben, you always have talked on a strategic front that you would look at tug in acquisitions. Is that still an area of focus for this year as you're looking at the changing environment around you guys?

I don't know if I'd say it's a focus. Our growth plans of 2 to 4 percent, which is part of the 7 to 9 percent total return equation, Ashar, don't rely on mergers or acquisitions. That said, I mean, you always want to be opportunistic. I think what we've talked about is, you know, the ideal thing would be a bolt on type acquisition that we could integrate into our service territories quickly. Our focus next year is going to be preparing for big rate increases, making sure we produce wealth for our customers, concentrate on reliability efforts, some of the things I mentioned on the call. The other items would be just opportunistic.

Nothing right now in your view, which is of high priority?

No, nothing.

Thank you.

We have another follow-up question from Elizabeth Parrella with Merrill Lynch.

Yes, thank you. I realize you didn't include it in your press release, but I was wondering if you yet had the operating cash flow and CapEx numbers for the quarter and the year.

We haven't completed our -- all that work, Elizabeth. I think we were originally forecasting cash flow from operations to be about $1.4 billion. The number will be somewhat less than that due to the increased cash needs associated with increasing working capital primarily that's the lead lag difference between paying for natural gas and actually collecting on it either through gas customers or through fuel charges. So we have seen some erosion in our working capital.

And the CapEx number, does that come relatively close to forecast?

I think that's going to be real close to forecast.

Okay. Thank you.

Next question comes from Daniele Seitz with Maxcor.

Hi, most of my questions have been answered. I was just wondering if you're looking at the long-term growth, do you anticipate some acceleration just presenting your expansion in capital?

Do I anticipate what, Daniele?

Some acceleration in your EPS growth as you get into '06, '07, '08?

I think when you get into the '06, '07 timeframe, you will see increased earnings associated with this step up in investment. And we've detailed that as well as we can, I think, in some of our investor presentations before. It's one of the levers of growth that we have. We have sales growth, we have increased investment, we have closing the gap on our authorized returns from actual returns.

Right. No, I just was wondering if you are seeing any negative out there that would slow it down. That's all. But you don't. This is just in that short progression.

Yes.

Okay.

Yes.

Thanks.

Okay.

Gentlemen, there are no further questions at this time. Do you have any further comments or any closing remarks you'd like to make?

No. I'd like to thank everyone for being on the call and look forward to a successful '05. Thank you.

Thank you again, ladies and gentlemen, for participating in today's Xcel Energy's fourth quarter 2004 earnings conference call. This conference will be available for replay beginning at 12:00 p.m. eastern today through 11:59 p.m. eastern on February 4, 2005. The conference ID number for the replay is 2808601. Again, the ID number is 2808601. The number to dial for the replay is 1-800-642-1687. Or 706-645-9291. Thank you again, and have a great afternoon.