埃克西爾能源 (XEL) 2004 Q3 法說會逐字稿

Good morning. My name is David and I'll be your conference facilitator. At this time I would like to welcome everyone to the Xcel Energy third quarter 2004 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 period. [Caller instructions.] Thank you. I will now turn the call over to Mr. Richard Kolkmann, Managing Director of Investor Relations. Sir, please go ahead.

Thank you, David. And welcome to Xcel Energy's third quarter 2004 earnings release conference call. With me today 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 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. Welcome, everyone. This morning, I plan to discuss our third quarter financial results and our guidance for 2004 and 2005. The results for the quarter are relatively straightforward. Therefore, I plan to spend the majority of the call discussing our 2005 guidance. Xcel Energy recorded solid earnings from continuing operations of 40 cents per share for the third quarter of 2004 compared with 44 cents per share for the third quarter of 2003. Our total earnings which included the impact of discontinuing operations were 12 cents per share for the third quarter of 2004 compared with earnings of 69 cents per share for 2003. Total earnings for the third quarter of 2004 reflect an asset impairment charge related to our Seren investment while total earnings for the third quarter of 2003 include tax benefits associated with our previously held investment in NRG. In September, we announced that we had decided to put Seren, our telecommunications subsidiary up for sale. Seren has an excellent product and has improved their financial performance as they've added customers and controlled cost. However, Seren does not fit with our strategy of focusing on our core utility operations.

The reason for taking the action now is that the market for telecommunications and broadband assets has improved in the past several months. As a result of this decision, we'll now report the financial results for Seren as discontinued operations. During the third quarter, we recorded an estimated after-tax impairment charge of $112 million based upon the assumed sales price of $2400 per customer. We are beginning to get of get indicative bids and we're pleased with the level of interest that's been generated so far. We will true up the estimated impairment charge as more information becomes available. Based on our preliminary estimate, the sale of Seren would provide us with cash proceeds of approximately $100 million at 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 expect the sale of Seren to be completed in the first quarter of 2005. Our earnings release provides additional detail on earnings from discontinued operations so let me focus on our continuing operations. Let's start with the core of our business. Our utility subsidiaries provided earnings of 41 cents per share for the third quarter of 2004. Compared with earnings of 45 cents per share for the third quarter of 2003. The decline in earnings is largely due to mild weather which reduced earnings by 7 cents per share quarter over quarter. The weather impact was partially offset by lower depreciation expense that increased earnings by 1 cent per share, lower utility O&M expenses that increased earnings by almost 1 cent per share and other items which, together, increased earnings by approximately 1 cent per share. This summarizes our third quarter earnings.

Let me touch on a few of the significant drivers. As most of you know, the temperatures for the summer were very mild. We experienced this impact throughout our service territory. In fact, in Minnesota, we had the third coolest summer on record. Our internal models capture the weather impact using cooling degree days and THI which is a temperature humidity index. The models show that in the third quarter, THI degree days in Minnesota were 18% below normal and 32% lower than in 2003. In Colorado, cooling degree days were 28% below normal and 41% lower than 2003. And finally, in the Texas Panhandle, cooling degree days were 16% below normal and 23% lower than 2003. The cool temperatures translated into less air conditioning load. As a result, our retail electric margin was $50 million lower for the quarter which reduced earnings by 7 cents per share when compared with 2003. For the quarter, our short-term wholesale margins were flat with last year. However, during the year, we've had strong performance selling excess generation into the short-term market which has partially offset the adverse of weather on retail sales. Given our performance to date, we expect that our 2004 short-term wholesale and trading margins will be at least 30% higher than 2003 levels. Now, as you think about short-term margins for the rest of the year, you should be aware that our Prairie Island unit one nuclear plant went off-line in mid September for a planned outage. During the outage, we were replacing the steam generators and refueling the unit. The unit is expected to be back on-line in the middle of November.

Let's shift the focus now to operating expense. Our third quarter 2004 regulated O&M expenses were $4 million or 1% lower than 2003. Which is basically flat. On a year-to-date basis, our O&M expense increased 2.3% over last year's level and we remain on track with our internal budget. Our average regulated O&M quarterly spend was approximately $388 million for the first 3 quarters of 2004. In contrast, for the first 3 quarters of 2003, our O&M expenses averaged $380 million per quarter. As you may recall, that in the fourth quarter of 2003, our O&M expenses spiked up to $431 million due to year-end accruals for incentive compensation and some other items. We do not expect this to reoccur in 2004. Therefore, we project 2004 O&M expenses will be relatively flat compared with 2003.

Now, that said, we may take the opportunity to spend some additional O&M. So we are well-positioned for 2005 from an operating perspective. For example, we may spend some additional O&M to ensure that our generating plants continue to operate at peak performance for next year. Depreciation expense was another positive factor, continuing to the trend for the last few quarters. Depreciation expense for the third quarter of 2004 was $10 million lower than 2003 levels. Largely due to the extension of depreciation life at Prairie Island as we've discussed at length in the past. Before completing the discussion of our third quarter utility results, I want to update you on a few regulatory accruals that we discussed last quarter. Our performance of Public Service Colorado under the quality of service plan has improved, allowing us to reduce our accruals by $1.2 million during the quarter. Year-to-date, in 2004, we have accrued $11.2 million for refunds under the quality of service plan. Last quarter, we accrued $2.4 million for potential customer refunds to certain gas customers at NSP Minnesota. We have substantially completed our meter investigation and as a result, we have reduce the accrual by $1.4 million during the quarter. That covers our non - - or rather our utility operations. Other non-regulated subsidiaries provided earnings of 1 cent per quarter in 2004 and 2003. While holding Company costs reduced earnings by 2 cents per share for the quarter in both 2004 and 2003. Over the past few years we've been very successful in divesting our non-core assets. Part of our strategy of focusing on our core utility operations. As a result, Eloigne and Utility Engineering are the only remaining non-regulated subsidiaries. And these Companies don't have a material impact on our financial results. So that covers our results for the quarter which, when added to the performance of the first 2 quarters, gives us year-to-date earnings from continuing operations of 97 cents per share versus 91 cents per share last year.

Turning our attention to the rest of 2004. Throughout year, our guidance range from earnings from continuing operations has remained at $1.15 to $1.25 per share. While of some our individual assumptions and drivers have changed in the course of the year, we've continued to maintain our established guidance range. However, I do want to provide you with some additional color on our expectations for 2004. We now expect to finish the year in the upper half of our guidance range. In addition, there is potential to realize tax benefits of up to 4 cents. We've recently completed 5 audit cycles and are in the process of finalizing our analysis related to the possible financial statement impact. Depending upon the outcome of that analysis, we could potentially end up exceeding the higher end of our guidance range. Looking ahead to next year, I think 2005 represents a transitional year for us. We started to implement our strategy of increasing our investment in our core business. As a result, we will see the impact of increased depreciation expense but we won't have any additional revenue recovery in 2005. Above normal sales growth to offset the costs associated with those investments and other expense increases.

In 2005, we will begin implementing our regulatory strategy to seek revenue increases to close the earnings gap in jurisdictions where we're not earning our authorized return. And also to recover a return on our incremental investment. We don't expect any material rate increases in 2005. With that in mind, our 2005 guidance range from earnings from continuing operations is $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 and Utility Engineering are expected to result in a loss of 9 cents per share. Our key assumptions for 2005 are as follows: We expect weather adjusted, retail sales to grow between 2% to 2.4% for electric and between 1% to 1.3% for gas. These growth rates are higher than we experienced during 2004. We're starting to see an economic recovery in our service territory and expect it to carry through into 2005. Possibly moderating this positive development, are high gas prices which may dampen demand more than we are forecasting. Partially offsetting sales growth are capacity costs which are expected to increase by $15 million net of recovery. In 2004, the Colorado commission approved a capacity rider. However, the rider only recovers capacity cost approved under the 1999 Resource Plan. Therefore, we do not have complete recovery of our capacity cost. In addition, we don't have a capacity rider in Minnesota.

Moving on to wholesale margins, we expect short-term wholesale margins in 2005 will decline between $20 million and $45 million when compared with projected 2004 levels. This range is above 2002 levels and relatively close to 2003 levels. It presumes gas prices remain at current levels and our plants continue to perform well. We've had excellent performance by our employees at our generating plants and in our Energy Marketing Group during 2004. Key drivers in the year 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 mass, plant availability and cooler temperatures which made more generation available for wholesale sales. We continue to see high prices in 2005. But growth in retail load and our expectation of normal weather leaves less excess generation to sell into the wholesale market. Just as significantly as low lease our coal plants won't always be the marginal unit. While our goal is to maximize the value of our wholesale margins, our first priority is to serve 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 availability to lock in these higher price margins. As a result, our baseline budget is not projected to replicate 2004 results. During 2005, we will be opportunistic and we will work to maximize Company earnings on both the retail and wholesale side of our business.

That covers our revenue assumptions, let's move on to the expense assumptions. O&M expenses are projected to increase 2% to 3% in 2005. The increase in O&M expenses is driven by pension credits and medical costs. Pension credits are expected to decline due to changing assumptions and amortization of prior period results. We anticipate that O&M expenses in 2005 will increase by $30 to $40 million for pension and medical costs. In addition, there was only 1 nuclear outage in 2004 and we will have 2 outages scheduled in 2005. We typically incur $10 to $15 million of O&M expense for a nuclear outage. As always, we'll continue to look for opportunities to reduce costs in a manner which doesn't impact customer service or reliability. Our depreciation and amortization expense is projected to increase 7% to 8% in 2005. The increase is due to normal growth in rate base and incremental depreciation for several large projects including the steam generator at Prairie Island, the combustion turbines at NSP Minnesota and a new billing system that's in the process of being rolled out. We expect to receive recovery of these investments in future rate filings. We anticipate that 2005 interest expense will increase $10 to $15 million compared with 2004.

As we've indicated in our presentations throughout 2004, we expect our debt levels to be modestly higher in 2005 as we continue our strategy of investing in our core business. In addition, we expect that interest rates will be higher. Another assumption we have in our earnings guidance is the continued recognition of tax benefits from a financial reporting perspective. As you know, we have initiated a lawsuit against the I.R.S. to resolve our dispute on the deductibility of the COLI program. We believe our case has strong merits. Nothing has changed our view on the ultimate outcome of the case or in our ability to continue to receive cash associated with the tax deduction for COLI. There has, however, been activity from FASB by which could impact the accounting for COLI. In its late July meeting, the FASB verdict to issue a proposed interpretation of FAS 109 that could raise the threshold for recognizing uncertain tax benefits to a probable standard. At this point, the FASB has not issued its proposal. Once the proposal is issued, there will be a period for comments before any final rules are established. At this time, we can't determine what, if any the impact will be on Xcel Energy. We'll keep you posted for any new developments. Our guidance range assumes that COLI will provide tax benefits of approximately $35 million representing earnings of 8 cents per share.

Let me finish up the guidance with a few other items. As I mentioned when I discussed our depreciation assumption, we will have completed several significant projects by the end of 2004 or by the middle of 2005. These projects include the new steam generators at Prairie Island, the combustion turbines at NSP Minnesota and the a billing system. Once these projects are put into service, we'll stop recording AFUDC and start to record depreciation expense on the projects. Therefore, we anticipate AFUDC equity will be relatively flat in 2005. We believe our effective tax rate for 2005 will be 30% to 31%. And finally, the average share count including the dilutive effect of common stock equivalent is projected to be approximately 426 million shares.

So, with that, I'll wrap things up. We have a strategy of investing in our core utility business. We were working with our respective commissions to ensure that we are in a reasonable return on that investment. Our financial objectives deliver an average total return of 7% to 9% per year. Our build to core strategy will provide long-term earnings growth of 2% to 4% which when combined with our dividend yield will provide an attractive return for our investors. We are pleased with our year-to-date results. We're on track with our business plan and positioned to deliver solid results for '04 and 2005. Next week, we will be at the EEI Conference in California. Our presentation will be on Tuesday, October 25 at 10:30 Pacific Time and we'll be available by webcast. Please see our web page for more details. At the conference, we plan to discuss the 4 drivers of long-term earnings growth for Xcel Energy. Briefly, the drivers are service territory growth, an increase in the equity ratio of our utility operating companies, earning our authorized return in all jurisdictions and increasing our investment in our core utility business. We will also be discussing our regulatory strategy to seek rate increases where we are not earning our authorized return and also to recover a return on our incremental investment. Our EEI presentation will be posted to our web page later today. In addition, we will file it as an 8-K this afternoon. So with, that I'll open the lines for questions.

Ladies and gentlemen, at this time, I would like to remind everyone that we'll be taking questions from analysts only. Any media should contact the Xcel communications department and investors may call the investors relations department following today's call. If you are an analyst and would like to ask a question, press star then the number 1 on your telephone key pad. If you have a follow-up question, please re-enter the queue. Do pause for a moment to compile the Q&A roster. Your first question comes from Paul Ridzon of Key McDonald.

I was wondering if you could give more information on the nature of the potential 4 cent tax benefit? Is this a one-time? Is this ongoing and what is it derived from? And I missed your fourth quarter guidance.

We didn't give fourth quarter guidance. We just reconfirmed our guidance for the full year at $1.15 to $1.25. Paul, we do believe now that will be on the upper range of the guidance. Regarding tax benefits, it is the finalization of 5 separate audit cycles. We don't expect that this will continue going forward. Those audit cycle years range anywhere between '93 through 2001. We're not done yet. But we just wanted to alert you that it is a potential upside for the balance of the year.

What are you looking for COLI to earn in '04?

8 cents per share.

And your '05 guidance assumes flat?

Yes, exactly.

Thank you very much.

Your next question comes from Elizabeth Parrella of Merrill Lynch.

Yes, thank you. A couple of questions. On the wholesale guidance for this year, I know you're indicating up at least 30% over '03. If I do the math right, that implies only about 3 million of margin in the fourth quarter. I know last year, I think you did 18 million in the fourth quarter. Could you talk about how much that Minnesota contract - - the NSP contract you had helped in last year's fourth quarter? And even considering the Prairie Island outage, it seems like a fairly low assumption. If you could just elaborate on that?

Sure I can, Elizabeth. We said at least 30%. So, we'll have to - - the market conditions maintain, perhaps there is some upside there. But more specifically, last year, we were benefited from a $10 million contract associated with the utility in Canada.

Ok. And the second question might be, you mentioned in terms of one of the factors your have higher depreciation in '05 is the new customer billing system. Is that going to be throughout the Xcel system? Going to be kind of a uniform - - can you maybe talk about what you're doing there? And also, how much - - what's the investment in that project?

Sure. When we merged, we had separate billing systems. This goes back several years for what was New Century Energies and then NSP. We know we needed a new system. We're actually in phase two of the roll-out which means that the Texas Panhandle and Colorado are under the new system now. We expect the full system to be rolled out in the beginning of this coming year. The overall cost after AFUDC will be approximately $150 million.

So that's including the AFUDC?

Yes.

Ok. Thank you.

Your next question comes from Ali Agha of Wells Fargo Securities.

Thank you. I just wanted to clarify a couple of the regulatory issues that you raised in your assumptions as well. Specifically, in '05, you talked about the NSP Minnesota gas rate case and the FERC rate case. I wanted to just get a sense of where you are in that process? And also, and I may have missed that earlier, where you are in your Colorado coal plant project discussions with the Commission as well?

Ok, let's take the gas and the FERC rate case first. Those filings have been made. We anticipate that both of those filings will have rates in effect by the end of the year. Regarding the lease cost planning process in Colorado, we're in the middle of the procedural schedule right now. We expect that we'll have an answer from the Commission by the end of this year.

Ok. Thank you.

Next question comes from Daniele Seitz of Maxcor Financial.

Hi. I just was wondering given the - - let's say 1.5% to 2% growth rate, how much of an impact does it have on a yearly basis on your earnings?

The 1.5% to 2% growth rate in what? I'm sorry.

The 1% and 2% growth rate is in demand. Would you say that - - how much as far as EPS is concerned? How much of an upside for EPS is concerned?

Ok. I'm not sure if I have understood your question.

What is the impact of EPS from the growth rate in the demand?

Oh, okay. On the electric side, assuming a growth rate of 2% to 2.4%, that could yield anywhere between 9 cents to 11 cents. Obviously before cost considerations. On the gas side, the 1% to 1.3% adds about a penny to earnings.

Great. Thanks a lot.

Next question comes from David Grumhaus of Copia Capital.

Looking at '05 on the wholesale margins, you're projecting quite a decline there. I assume some of that is weather. Some of that is the roll-off of this Canadian contract. Are you using forward power prices or is there some also are you forecasting that power prices come down?

We are using forward power prices and those prices continue to remain strong. Primarily as a function of high gas prices. What is driving the forecast in our assumption federal decline of '04 levels is principally the impact of retail load growth. As well as more normalized weather. It means there's less generation to sell in the market. Keep in mind, we only do that on a short-term basis after our retail load doesn't use it. But probably the other factor that I think is just as significant as our load is growing, the marginal unit that we would sell into the wholesale market isn't always going to be coal-based. There will be some gas - - gas-fired generation that's now on a marginal unit and that won't enjoy quite the margin potential as a coal-based unit would.

That's helpful. And then the interest expense increase forecasted for '05, is that some of the investment that you're starting to make in '05 that we're not going to see the results on until '06?

Yes. That's exactly right. We've known all along we would issue modest amounts of debt to start to complete our plan to do incremental investment on our core utility operations. We've also forecasting interest rates to be a little bit higher next year than they are in '04.

Great. Okay. Thanks for the time.

Your next question comes from Paul Debbas of Value Line.

Assuming normal weather, what do you expect the absolute sales growth to be next year?

Well, we expect it to be in a range of between 2% to 2.4%. That's weather normalized. It would be higher because this year has been so mild. What would the absolute number be?

For the full year, I don't know if we have that. Does anyone know that?

We might be able to find that for you. Why don't you call back the investor relations group, Paul and they'll get that for you. I don't have it at my fingertips.

All right.

Your next question is a follow-up from Elizabeth Parrella from Merrill Lynch.

Thank you. Two other questions. You mentioned that you're working on redoing the holding Company credit facility. Could you remind us what the spread is on the existing facility and whether we might be likely to see some improvement in the term?

Yeah. We currently have a $400 million credit facility. It terminates in November of '05. Given the favorable bank market conditions, we went out early. We're expecting to close on a $600 million credit line, a 5 year facility unsecured. We're real pleased with the terms and conditions, Elizabeth. We really only have one financial covenant. We're taking advantage of a very good market. The rates should be very favorable as well.

And what is the rate on the existing one?

LIBOR - - I have George Tyson, our Treasurer with me. What is it George?

LIBOR plus 60 currently. We're going to LIBOR plus 75 on the new facility. On a fully drawn basis, the new facility will be 15 basis points higher than the existing.

Thanks, George.

Ok. And another question just on the FASB proposal regarding uncertain tax benefits. I know you've discussed it in the context of COLI. Is that really the only issue where this might have some impact on you?

Yes. This is - - Elizabeth, this isn't even an exposure draft yet. But it clearly is - - it could potentially be a big issue for us so we thought we would just get it out on the table early. We expect that exposure draft will be issued potentially some time in the fourth quarter. Comment period after that. We'll just have to wait and see.

Ok. Thank you.

Your next question comes from Vedula Murti of Zimmer Lucas.

Good morning.

Hi, Vedula.

A couple of things. One, I think you mentioned that you're looking at part of the cost increases that you're changing your assumptions on pension. And can you kind of go through what is being changed for '05 versus '04?

Yeah, well, we'll finalize those assumptions at the end of December per the accounting standard. But I mean we're still in a low interest rate environment. So, I suspect - - I think we're currently on the liability discount rate, we're at 6.25. I suspect that will be - - it will be less than 6.25 if things don't change in the next few months. So we're assuming that will fall to probably 6% at this point. But you know, that's not finalized.

Is that the only major change here in terms of pension?

We'll look at - - we have a 9% assumption for return on assets. I don't recall off the top of my head what the salary increase assumption is. So we'll look at all of those. But I think the discount rate will probably be the biggest driver.

So, when you mention the $30 to $40 million, how much of that would you attribute principally to pension - - attribute to these pension changes?

Well, a $20 to $30 million of the 30 to 40. Remember there's medical costs in there as part of the equation. That swing of 20 to 30 is basically just a variable depending on the assumptions and our actual performance on the investment side of the equation is for the balance of the year.

Ok. So, basically, you're going to be looking at possibly - - you're going to lower the discount rate and you could lower the return assumption as well?

We'll look at that. But you have to also look - - under the 5 year averaging method, you have to - - however your plan performs based upon the original projection, if it is plus or minus, you amortize that over 5 years. So that's always a variable as well, Vedula.

Ok. And I'm sorry I missed a little bit of the answer to Elizabeth's question. What again was the topic on which you were to get tax exposure by the end of the year?

FASB has, under consideration, under a new interpretation of 109 that would raise the standard to a probable standard for recognizing what they define as uncertain tax benefits. That - - this is really early, Vedula. So, I think you have to - - we have to just watch and see how this thing develops. But as we understand it, the probable standard would - - could potentially mean that you could no longer recognize COLI benefits under the new interpretation. We expect that we'll see an exposure draft sometime in the fourth quarter of this year. I expect there will be lengthy discussions and comment periods that takes place after that. You know, it is really too early to tell.

And also, one last thing. Can you kind of review for us in terms of your outlook at this point, what your thinking the earned ROEs will be for particularly at PSCO and NSP Minnesota and plans for filing a rate case for '06?

Well, I can't break out what the utility ROEs will be. You've probably seen in our other financial presentations what they were in '03. But we do plan, as you know, in filing a rate case in Colorado in '06. And we do plan on filing a rate case at NSP Minnesota at the end of '05 when the moratorium expires.

And can you provide any color particularly with Minnesota since that's closer in as to prospects there?

I think your best bet is to look at how much we underearn in '03. We'll at some point update what we did in '04 and just draw your conclusions from there. Vedula, we will be talking more about our regulatory strategy at the EEI presentation here in a couple of days.

Thank you very much.

Your next question is a follow-up question from Daniele Seitz from Maxcor financial.

So sorry. Vedula just asked the question I wanted. Thank you.

Ok.

Sir at this time, there are no further questions. Mr. Kolkmann, any closing remarks?

No. Appreciate everyone's attendance on the call. We look forward to seeing, I hope many of you at the EEI Conference in a few more days. If you have anymore questions, please feel free to call Paul Johnson or Dick Kolkmann. With that, I look forward to talking to you soon. Thank you.

Ladies and gentlemen, thank you for participating in today's Xcel Energy third quarter 2004 earnings conference call. This call will be available for replay beginning at 12:00 noon Eastern Time today through 11:59 p.m. on Friday, October 29, 2004. Conference I.D. number for the replay is 9915471. Again the conference I.D. number for the replay is 9915471. The number to dial for the replay is 1-800-642-1687 or 706-645-9291. This concludes today's conference call. You may now disconnect.