埃克西爾能源 (XEL) 2004 Q1 法說會逐字稿

Good morning, my name is Marvin and I will be your conference facilitator. At this time I would like to welcome everyone to the Xcel Energy 1st Quarter 2004 Earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks will be a question and answer period. If you would like to ask a question during this time, simply press star and the number 1 on your telephone keypad. If you would like to withdraw your question, press star and the number 2 on your telephone keypad. We will be taking questions from financial analysts only. As a courtesy to others, we ask that you please limit your questions to one per participant. Thank you. Mr. Kolkmann, you may begin your conference.

Thank you, Marvin and thank you for those of you listening in on the phone lines and participating via the Internet. Welcome to Xcel Energy 1st quarter 2004 earnings release conference call. I am Dick Kolkmann, Managing Director of Investor Relations. And with me today is Ben Fowke, Vice President, CFO, and Treasurer 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 filings with the Securities and Exchange Commission. Now I will turn the call over to Ben Fowke.

Thanks, Dick, and welcome everyone. What I plan to do this morning is discuss our results and some key issues relating to Xcel Energy. We have a simple and straightforward story, and we continue to be on track to meet our financial goals. I am very pleased to report that Xcel Energy recorded earnings from continuing operations of 35 cents per share for the 1st quarter of 2004 compared with 31 cents per share for 1st quarter of 2003. Total earnings for the 1st quarter 2004 were 36 cents per share compared with 34 cents per share for 2003.

I plan to spend my time during the call discussing our earnings from continued operations. Our earnings release provides details on earnings from discontinued operations. So let's start with the core of our business, our utility subsidiaries provided earnings of 37 cents per share for the 1st quarter 2004. This compared with 35 cents per share for the 1st quarter 2003. This increase of 2 cents per share is largely due to the following items: Favorable short-term and trading margins increased earnings by 3 cents per share, lowered depreciation expense increased earnings by 2 cents per share, and lower financing costs increased earnings by 1 cent per share.

These favorable results were partially offset by higher O & M expenses which decreased earnings by 2 cents. Weather decreased earnings by 1 cent per share and all other items together reduced earnings by 1 cent per share. This summarizes our 1st quarter earnings. Looking at more detail, one of the key drivers in the 1st quarter was the performance of our power marketing area and the employees who operate our generation fleet. Our generation fleet has performed extremely well over the last several years and this quarter was no exception. This allowed us to meet our native load requirements and to sell excess generation into the short-term market.

As a result, short-term wholesale and trading margin was $20 million higher for the 1st quarter of 2004. This is largely due to higher prices primarily in the map region and a pre-existing contract which expired at the end of the quarter. Although we are ahead of last year's pace, we still project that our short-term wholesale and trading margins will be slightly less than 2003 levels. There is, however, potential upside in the wholesale markets, depending on market conditions and plant availability.

Let's shift the focus now to operating expense. As expected, our 1st quarter 2004 O & M expenses were higher by 16 million or 4.3%. This is largely due to higher benefit cost including restricted stock expense accruals, higher medical costs and lower pension credits. The restricted stock expense relates to the accrual in the 1st quarter of the final costs associated with the 2003 restricted stock grant. In the 1st quarter of 2003, there was no expense associated with the restricted stock program. We have now fully accrued for the cost of this program.

As I've mentioned on previous calls and various conferences, we continue to expect that our 2004 O & M levels will be relatively flat compared with 2003 levels. Depreciation expense was another positive factor contributing to our favorable results for the quarter. Depreciation expense for the 1st quarter 2004 was $15 million lower than 2003 levels, largely due to 2 regulatory events that occurred last year. As part of the Colorado rate case that was settled in 2003, our depreciation accruals were lowered by approximately $20 million annually to reflect the lengthening of depreciable lives of certain utility plant. This change went into effect mid-year 2003 and was part of the reason for the rate decrease in Colorado. We are now experiencing the full-year impact of that rate change.

During 2003, we were successful in getting legislation passed in Minnesota that granted additional storage of spent nuclear fuel at our Prairie Island plant. We now have enough storage to run the plant through its licensed life. As a result of the legislation, the Minnesota PUC approved extending the appreciation life of 2 units at Prairie Island until 2003 and 2014. Previously we had assumed a depreciation life ending in 2007. We also changed the decommissioning accruals to reflect the move to a completely external decommissioning fund. These actions are expected to reduce 2004 depreciation expense by $18 million. These 2 regulatory adjustments more than offset the normal increases we typically see in depreciation expense.

As a result of this, and a refined appreciation expense estimate, we now expect that our annual 2004 depreciation expense will decline between 1% to 2% from 2003 levels. This decline in depreciation expense will be experienced primarily in the 1st 3 quarters of 2004 because as you may remember, we recorded an annual depreciation adjustment in the 4th quarter of 2003 to reflect the Prairie Island ruling. Moving to interest expense, as we've mentioned in the past, we expect that our financing costs would decline in 2004. Our financing cost for the 1st quarter 2004 were $7 million lower than 2003 levels, largely due to the refinancing activities we completed last year. The decline in financing costs during 2004 will be more prevalent in the 1st and 2nd quarters of this year, since the majority of the refinancing activity took place during the summer of 2003. That covers our utility operations.

Let's now turn our attention to the nonregulated and holding company results. Our other nonregulated subsidiaries and holding company costs resulted in a loss of 2 cents per share for 1st quarter 2004. This compared with a loss of 4 cents per share last year. The reduced loss is largely due to improvement at utility engineering. Utility engineering recorded a loss for the 1st quarter 2003 partially due to project write-downs. 1st quarter results from Seren and Aloyn [Phonetic], our other non-regulated subsidiaries, were consistent with 2003 and are tracking with our expectations for 2004.

Turning our attention to the rest of 2004, clearly, we've had a very good 1st quarter and we are ahead of our plan at this point; however, we are maintaining our earnings guidance range of $1.15 to $1.25 per share. Some of our key financial assumptions have changed, however. We now expect depreciation expense to the 1% to 2% lower than last year. This is a positive change, which reflects a refined estimate of depreciation expense and in-service dates. This change in our depreciation forecast represents a projected increase of 3 to 4 cents per share. This earnings uptick which will be partially offset by our revised expectation of lower weather normalized electric and gas sales growth.

We now expect that weather-adjusted retail electric sales will increase by 2% compared with our original forecast of 2.2%. On the gas side of the business, we now expect our weather-adjusted firm gas sales will increase by approximately 1% compared with the original forecast of 2.4%. The revised gas sales projections reflect lower usage, as customers look for ways to offset the impact of higher natural gas prices. In total, the revised sales forecast represents a projected decline of approximately 2 cents per share from previous expectations.

Even though we've tempered our forecast, our service territory continues to grow. In the last year we have added approximately 60,000 electric customers and 50,000 gas customers. Our long-term growth prospects for both electric and gas sales remain bright. And lastly, although we haven't changed our guidance assumptions for our wholesale margins, we believe there may be some potential upside to sell excess generation into the wholesale markets. So overall, while the net change in our key assumptions is positive, it's still very early in the year, and as the old saying goes, there is a lot of golf left. Over the next several months, we should have additional clarity on several significant earnings drivers like weather, short-term wholesale margins and the outcome of our capacity rider request. We will continue to monitor our performance during this summer, and we will adjust guidance if and when we think it is appropriate.

As I mentioned earlier, one of our key drivers for 2004 and beyond is our capacity rider request in Colorado. Our overall capacity charges are projected to increase by $40 million in 2004, primarily in Colorado. We filed a capacity rider request in Colorado to recover these costs. Hearings were held on April 14 through the 16th, and post-hearing briefs were recently filed. As you might expect, our large customers have recommended the commission rule against the rider. The staff is supportive of the rider concept, but are recommending limiting recovery to only contracts approved under the 1999 IRP. This proposal would reduce our overall request by approximately 1/3. We anticipate the commission will rule on the issue shortly. Depending upon the timing of the commission ruling, the rate rider could go into effect on June 1, 2004.

If rates went into effect on June 1, and our request is granted as filed, we would get rate recovery of approximately $27 million in 2004. Since we are on the topic of regulation, let me give you a brief update on our resource plan filing. At the end of April, we will submit our resource plan in Colorado, which will include a proposal to build and operate a 750-megawatt base-load coal-fired plant to meet the growing demand in Colorado. This plant is expected to be operational by 2009, with a total cost currently estimated at approximately 1.3 billion.

There is potential for us to have partners on the project, which would reduce the scope of Xcel Energy's capital investment. In addition, we will seek a recovery mechanism that allows us to recover the cost during construction and in a financially prudent manner which supports credit objectives. Speaking of credit objectives, last week Moody's upgraded the credit ratings of Xcel Energy by 2 notches. The credit ratings for NSP Minnesota, NSP Wisconsin and Public Service Colorado were upgraded by 1 notch. The credit ratings for SPS were firmed at current ratings. The outlook is stable.

We are very pleased with Moody's actions. It's further affirmation of the strength of our company and of our strategy of building the core business. In March, S&P confirmed our corporate credit rating at triple B, their analysis imputed over $800 million of additional debt and associated interest cost for purchase power contracts. This adjustment for imputed debt increased the leverage on the balance sheet and reduced coverage ratios. We are taking steps to alleviate this issue. We will issue shares under our dividend reinvestment program to increase equity.

We will use the NRG tax benefit at the holding company to infuse additional equity into our operating company. We recently retired $145 million of debt at Public Service Colorado. We are planning on adding generation capacity at NSP Minnesota and Public Service Colorado to reduce our dependence on purchase power and we will work with our regulators to take actions to improve credit quality. Our credit goals have not changed. It just might take us longer to get there with S&P, given their methodology.

One final item related to credit. As you will notice from the liquidity table in our earnings release, the credit facilities for NSP Minnesota and Public Service Colorado expire in the middle of May. We are in the process of renewing those facilities. We expect to renew the facilities on an unsecured basis. In addition, we plan to add a term-out provision and the facilities will only have 1 covenant, a debt-to-cap covenant. These terms are further evidence of our improved financial strength.

Finally, let me touch on the dividend. We plan to discuss the dividend with our board of directors within the next few months. Over the last 8 to 9 months, we have received some very helpful feedback from investors on how we should approach the dividend. We also continue to get questions about whether our view on dividend policy has changed due to the various external issues in the marketplace. Nothing's changed in our view on dividend.

Our long-term dividend policy will be based upon providing shareholders an appropriate return on our investment, our projected level of internal cash generation and the projected level of capital investment in our utility business. We will balance our dividend policy with the opportunity to invest in our core utility to maximize shareholder value. So with that, I will wrap things up. Our business model is very straightforward. Invest in the business and build the core to meet our customers' growing need for energy.

We are pursuing a strategy of investing in our core utility business. We are working with our respective commissions to ensure we are on a reasonable return on that investment. This strategy will provide long-term earnings growth of between 2 to 4%, which when combined with our dividend yield will provide an attractive total return for utility investors. We are very pleased with the 1st quarter results. We are ahead of our plan. And we are on track to deliver solid results for 2004. So with that I will open the lines for questions

Once again, if you would like to ask a question at this time simply press star then the number 1 on your telephone keypad. First question comes from Ashar Kahn with [ Inaudible ] Capital.

Good morning. Can you just go over what was the price increase wholesale -- what kind of prices did you -- [ Inaudible ] -- are you --

Ashar, you are breaking-- You're coming in and out. Can you repeat the question?

Can you hear me better now?

Yes.

Could you just generally tell us what kind of increase in wholesale prices you saw and is that continuing on for the rest of the year?

When we put together our estimates at the beginning -- at the end of last year, the markets generally in the map region have risen between $8 to $12 since that time frame, and they continue to look fairly strong, but one of the things that you -- that you have to be cautious about before you draw too many conclusions on that is our ability to sell excess generations a function of a native load requirements and plan availabilities and obviously what the market ultimately does as far as pricing.

Then you mentioned there was 1 contract which expired in 1st quarter which helped you. Can you tell us what that contributed?

We didn't break it out separately. But it's a factor in -- in our continued assumption that overall margins for the year will be slightly less than 2003 levels.

Thanks again.

Your next question comes from Paul Patterson with Glenrock Associates.

Hi, guys. I just have a quick question on depreciation. You guys describe in your press release how it went down. It looks like it was mostly at the utility, and that would indicate to me -- I mean, I am just wondering, is there really any EPS benefit from this, or did you have a corresponding decrease from -- from revenue decrease? I am sorry if you already went over this, I came on just a little bit late.

Well there is a EPS benefit from it. The primary -- the primary factors in it were the 2 regulatory events that happened last year. The extension of the Prairie Island nuclear plants to 2013 and 2014. We were originally anticipating they would -- their lives would end in '07 and depreciating accordingly, and then as part of the Colorado rate case, we did extend some of the utility plant lives. That, combined with some revised estimates associated with in-service dates, is the reason why we revised our estimate to be 1% to 2% less at '04 levels at 1% to 2% less than '03 levels.

Okay, but the commission didn't lower the revenue requirement corresponding they just simply-- I mean it looks like in both cases these were--

No, in Colo -- not at Northern States Power Minnesota but in Colorado that was part of the rate case.

Okay, so the $18 million is really -- okay, I gotcha. Okay, thank you very much.

Your next question comes from Ali Agage (ph) with Wells Fargo Securities.

Thank you. Ben, I wanted to follow up on a point you had made about your ability to sell excess capacity in the wholesale market. Given your load requirements and your capacity, could you give us a sense of over the course of the year on average, how much capacity do you generally have to sell into the wholesale market?

You know -- I don't have that available. It does fluctuate with plan availability and our load requirements. You know we keep very healthy reserve margins so we are in good shape as far as meeting the native load of our requirements. Everything else is what we would have available in the short- term wholesale markets.

One other question if I could, your Interest and Other Income line, the swing there of about $8 million. As we look at the rest of the year, how should we expect that line to trend?

I don't think you are going to see quite the swing you saw in the 1st quarter. The biggest thing driving that is AFUDC equity.

Okay. Thank you.

Your next question comes from Charles Fishman with AG Edwards.

Hi, Ben. With respect to the Colorado rate case, if the commission was to rule sort of toward what the staff has suggested -- in other words, exclude any of the capacity contracts subsequent to the '99 rider -- '99 ERP, would you immediately go in for a rate case in Colorado or wait until '06 which I guess is the current plan.

I think we would have to just evaluate that if and when that happens. Charles, at this point. You know that's one of the reasons why we have the earnings guidance range that we do.

Okay. Thank you.

Your next question comes from Elizabeth Parrella with Merrill Lynch.

Thank you. A couple of questions. You talked a little bit about the coal plant that you would have envisioned building as part of your resource plan in Colorado. Would that fill the gap completely in terms of capacity needs for PSCO? Or would there be some other things in the plan, let's just say some smaller gas plants, or additional purchase power contracts that you might sign to fill the gap over the next 5 years? If could you just sort of fill in the picture a little bit for us on that.

Well, I think as you know, Elizabeth, the -- the coal plant itself will not meet all of the -- all of the capacity needs over the next decade. I think the -- the estimate we have is about 3,000 megawatts that need to be added in the next decade. Some of that assumes -- I think it is 1600 megawatts of renewal of existing power purchase contracts, and the balance has to be provided through incremental capacity so the coal plant's 750 megawatts of that. So there will need to be some more capacity needs met.

In the 10-year period from '09 -- I am sorry from -- what is sort of the starting point for this plan?

I think it starts in '04.

Okay. So in terms of that gap, you know, where do you envision that being filled in? Would it be additional third-party contracts?

That's the primary aspect.

Okay. Another question just on the wholesale side you mentioned the increase in map prices. Was that on-peak power prices, and is it possible to indicate what you see that as being mostly caused by, is it higher gas prices, higher coal prices driving prices up? Or--

I believe those numbers were mainly on-peak. Yeah, I think -- it's basically a function -- in the map region, the -- beyond the margin plants are gas-fired so it's a function primarily of higher gas prices. And we have -- our generation stack is mainly coal-based so we were able to take advantage of that, because of the strong performance of our generation plants.

Okay. And last question, Ben. Can you review for us the expectations for operating cash flow and the Cap Ex budget for Xcel for this year?

Yeah, well, we continue to have, as I have said in some conferences, we are looking at doing a little over $1.2 billion of Cap Ex this year. That's above and beyond what we normally spend in the 900 million to 950 million range. You know, I don't think there has been any change in our expectations on how we would meet those Cap Ex., Elizabeth.

So operating cash flow is about the same -- same number?

Yes.

Okay. Thank you.

Next question comes from Carrie Stevens with Morgan Stanley.

Hi, good morning.

Hey, Carrie.

I just wanted to touch on two things. 1st, with respect to your guidance. If I've got the kind of changes correct, I think you said 3 to 4 cents higher. You are tracking higher for wholesale? I am sorry for D & A, but the changes in the sales growth were kind of a 2-cent hit so overall from those 2 items you would be up 1 to 2 cents.

That's right, up 1 to 2 cents and we think we have upside as far as the wholesale margin assumptions goes, but we are not changing -- we are not changing that guidance on that --.

On that front yet. Okay. Is that mainly just from the higher pricing? Does it have anything to do with potentially a tight hydro situation in the west and you benefiting from that? Or where is that upside being --

It is mainly in the map region. Okay. And -- and you know -- that's where the majority of those margins have been achieved in the 1st quarter.

Okay.

Prices continue to look good. Again, there's a lot of things that could change that and we are basically selling into the short-term markets. So we just have to let the months to come play out.

Are you comfortable at least at this point saying higher end of guidance seems more achievable?

We are at $1.15 to $1.25, and what we need to do is get through the next several months. Weather is obviously very sensitive in the next several months. Our margins are sensitive, as are our regulatory requests and we will have a pretty good handle on that as we get through the next quarter.

Lastly, I count you said maybe 1/3 of the California capacity rider could potentially be at risk if they go forward with staff exact -- you know suggestion. And I calculated that was maybe a penny. Does that sound right?

Well, it's Colorado capacity rider. You know we filed, I believe, for 31.5 million. And, you know, there -- as I mentioned, the staff has come back with -- with lowered by about 1/3, so that's roughly a penny.

Yeah, okay. Great. Thanks a lot.

Once again, if you would like to ask a question at this time, press star and the number 1 on your telephone keypad. There are no further questions at this time.

Well if there are no further questions, I want to thank everyone for participating on the call. And we look forward to producing solid financial results in the future. Thanks, everyone.