埃克西爾能源 (XEL) 2005 Q2 法說會逐字稿

Good morning. My name is Matthew, and I will be your conference facilitator today. At this time I would like to welcome everyone to the Xcel Energy second-quarter 2005 earnings conference call. (OPERATOR INSTRUCTIONS). Thank you. I would now like to turn the call over to Mr. Richard Kolkmann, Managing Director, Investor Relations. Sir, you may begin.

Thanks, Matthew, and I would like to welcome everyone to Xcel Energy's second-quarter 2005 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 filings with the Securities and Exchange Commission.

Now I will turn the call over to Ben Fowke.

Well, thanks, Dick, and welcome, everyone. Xcel Energy recorded earnings from continuing operations of $0.19 per share for the second quarter of 2005 compared with $0.21 per share for the second quarter of 2004. Total earnings for the second quarter 2005 were $0.20 per share compared with $0.21 per share for 2004. Our results from discontinued operations for the second quarter of 2005 reflect earnings of $0.01 per share which includes a gain on the expected sale of Seren, partially offset by Seren's operating results for the quarter.

Our utility subsidiaries provided earnings of $0.22 per share for the second quarter of 2005 compared with $0.21 per share for 2004. Utility earnings increased by $0.01 largely due to higher electric utility margins, which increased earnings by $0.08 per share; higher gas margins, which increased earnings by $0.01 per share, and higher short-term wholesale margins and other items which combined to increase earnings by $0.01 per share. These favorable results were partially offset by higher utility O&M expenses, which decreased earnings by $0.06 per share, and higher depreciation expense, which decreased earnings by $0.03 per share.

Our holding company costs resulted in a loss of $0.03 per share for the second quarter of 2005 compared with a breakeven position last year. The decline of $0.03 per share was due in part to changes in the effective tax rate and certain onetime adjustments which were recorded at the holding company. As a reminder, interest expense on debt issued at the parent level and preferred dividends reduced earnings by $0.02 per share for both periods.

That summarizes our second-quarter results, which were in line with our expectations. Now let's look at the details of the quarter.

Starting at the top of the income statement, our base electric utility margins increased by $60 million for the quarter, largely driven by temperatures that were warmer than last year and weather adjusted sales growth. In the second quarter of 2005, we benefited from temperatures in most of our major jurisdictions that were warmer than normal and warmer than last year. Favorable weather increased electric utility margins by $22 million or $0.03 per share. $0.01 of the improvement is due to the comparison to normal weather. The remainder reflects favorable improvements over weather conditions last year.

I would also like to point out that we continue to have warmer than normal weather in July that should provide positive earnings in the third quarter. From July 1st through July 25th in Minnesota, we had 14 days of over 90 degrees including nine days in a row. In Colorado we have had 15 days over 90 degrees and another six days over 100 degrees. And finally, in Texas we've had 23 days over 90 degrees and another one day over 100 degrees.

In addition to favorable weather conditions, we have also had solid sales growth in the quarter as weather adjusted retail electric sales grew at 2.3% increasing electric margin by $25 million. On a year-to-date basis, our whether adjusted retail electric sales have grown 1.4%, and this is consistent with our expectations for the year.

Electric margin also increased by $7 million due lower accruals for customer refunds under the Quality of Service Program or QSP in Colorado. As you might remember, last year in the second quarter we filed updated performance results under the QSP and accrued for customer refunds for 2002 through 2004. As a result we accrued $11 million for the QSP in the second quarter of 2004. In comparison, we accrued $3.4 million in the second quarter of 2005.

The maximum liability for the SAIDI measure is 13.6 million under the QSP program in Colorado for 2005. Year-to-date we have accrued at the 75% level based upon our best estimate of our performance. While our SAIDI performance has been good in our major Metropolitan areas, severe storms this spring caused us to exceed the threshold in two of our smaller geographic regions. For more information on our electric margins, please refer to our earnings release.

Turning to operating expenses, our second-quarter 2005 O&M expenses were higher by $45 million over last year. The increase in O&M expenses was driven by a planned outage at our Prairie Island nuclear plant which increased costs by approximately $20 million. In addition, employee benefit costs increased by $10 million, and performance-based compensation costs increased by approximately $7 million. Overall our year-to-date O&M expenses are 6.8% higher than last year. However, this is not indicative of a full-year trend.

Keep in mind that we had two planned nuclear outages in the first half of 2005 compared with none in the first half of 2004. In 2004 we had one nuclear average which occurred in the third quarter. I still expect our annual 2005 O&M expenses to increase approximately 2 to 3% compared with last year.

Now with that said, we may take the opportunity to increase our O&M expense levels to ensure that our operating system is in good shape after the extended hot summer weather so that we are well positioned for 2006.

Depreciation expense for the second quarter of 2005 was $20 million higher than 2004 levels. The increase is due to growth associated with normal system expansion and incremental depreciation for several large projects, including a new steam generator at Prairie Island and a new billing system. We expect recovery of these investments in future rate filings. We now expect our 2005 depreciation expense to increase by 8 to 9% compared with last year.

While that covers our earnings results for the quarter, let me touch on our year-end outlook. While we have modified some of our individual assumptions as detailed in our earnings release, our 2005 guidance range from continuing operations remains at $1.18 to $1.28 per share.

Next I would like to discuss a few new term accomplishments, initiatives and points of interest, and let me start with our diminishing non-regulated segment.

In May we reached an agreement to sell Seren's California assets to WaveDivision holdings. In July we reached an agreement to sell Seren's Minnesota assets to Charter Communications. Based upon these agreements, we estimate that the sale of Seren's Minnesota and California assets in total would provide us with cash proceeds of about $65 to $70 million at closing net of transaction and closing costs.

In addition, we would have an NOL tax benefit of approximately $75 to $80 million that we will realize over time.

As part of the closing, we will need to transfer Seren's franchises and telephone services authority. This process generally takes three to four months to complete, so we expect to complete the sale of Seren in its entirety in the second half of 2005.

Looking at our core business, I'm pleased to report that we continue to make progress on the Comanche three coal plant. In July the Colorado Department of Public Health and Environment issued air quality permits for Comanche. In July we also reached an agreement on the water supply contract with the Water Works Board of (inaudible). These significant accomplishments were completed just seven months after the commission approved the plant. Major construction on the plant is expected to begin in the fall of this year.

In 2005 we are initiating several rate cases as part of our regulatory strategy. In May we filed a natural gas rate case in Colorado requesting a $34 million rate increase based on a return of equity of 11%. We expect final rates to be in effect in early 2006.

In June we filed an electric and natural gas rate case in Wisconsin. The filing requests an electric rate increase of $41 million and a gas rate increase of 7 million based on a return on equity of 11.9%. We expect final rates to be in effect in early 2006.

In July the Minnesota commission approved our gas rate increase of $5.8 million, and we expect a written order this August. In the fourth quarter, we plan to file electric rate cases in Minnesota and North Dakota. In both cases interim rates subject to refund will be effective 60 days after the filing, and we expect a final decision in the summer of 2006.

In 2006 we plan to file for electric rate increases in Colorado, South Dakota, Texas and potentially New Mexico with final rates in these cases to be in effect in 2007. In total these rate filings will contribute significant earnings in 2006 and 2007.

Over the past year we have done our best to keep you up-to-date on the COLI issue. In keeping with that practice, I wanted to update you on some recent events.

There are two issues related to COLI, which is our Company-owned life insurance program. And the first and more significant issue is the actual IRS dispute. The second issue is the potential accounting pronouncement from the FASB, which affects accounting recognition but not actual cash flows.

So I will start with the IRS dispute. As you know, we've had an outstanding dispute with the IRS related to the tax deductibility of interest associated with loans taken out against our COLI program. We have attempted to resolve the dispute with the IRS, but we have been unable to do so.

As a result, last year we started litigation to establish our entitlement to deduct this interest expense. We continue to deduct the expense because we are firmly convinced we are entitled to do so under tax law.

In an attempt to resolve this issue in a timely fashion, we've filed a motion for summary judgment. Oral arguments will be presented on August 19th. If the First District Court judge rules on the issue, the decision could be appealed to the 8th Circuit. If we're not successful with a summary judgment, litigation will proceed with a year or so of discovery and a trial likely to start in December 2006. The outcome of this trial could also be appealed, so as you can see, it may take several years to resolve this issue.

In any event, we believe our rate case has strong merits, and we feel confident about our facts and circumstances.

I'm going to touch on the FASB issue now. In July the FASB issued the long-awaited exposure draft for accounting for uncertain tax positions. If the interpretation is adopted as proposed, only tax benefits that meet the probable threshold may be recognized or continue to be recognized on the balance sheet. Therefore, if adopted as currently proposed, we would likely record an income statement charge to set up a reserve of approximately $350 million. This reserve is for COLI tax benefits and interest costs recognized through the end of 2005. Based on our initial review, we don't think we would be required to book a reserve for potential penalties.

Exposure draft has a 60-day comment period which runs through September 12. After the comment period, FASB will determine its next step. It is difficult to determine the actual impact on Xcel Energy until after the final rules are established. Again, it is important to recognize this potential FASB rule only affects the financial reporting of the tax benefit until the issue is resolved. It does not affect cash flow from the tax deduction. So if we were successful in our dispute with the IRS, the FASB ruling would merely represent a deferral of the recognition of the tax benefits. Hopefully that gets everybody up to speed on COLI.

Another important issue is the reduced level of Powder River Basin coal deliveries, which impacts numerous facilities including Xcel Energy. Delivery of coal from the Powder River Basin has been disrupted by trained derailments and other operational problems caused by approximately 100 miles of deteriorated rail track in Wyoming. The railroads have indicated that repair and reconstruction of the deteriorated sections of rail track beds may take the balance of the year.

Reduced deliveries of coal have lowered the inventories of coal at some of our powerplants. As a result to insure system reliability, we have modified the dispatch of our coal-fired electric generating stations to conserve existing coal supplies until coal deliveries return to normal levels. We have also increased power purchases and the use of natural gas generation to replace the coal-fired electric generation. These actions will increase the cost of generation in PSCo and SPS and to a lesser degree our NSP region. We expect to fully recover these costs in most jurisdictions.

In Colorado fuel costs are recovered through the ECA, which is an incentive-based mechanism. Under the ECA, if our generation costs are below a threshold benchmark, we keep up to 11.25 million of the savings. Correspondingly, if our generation costs rise above the benchmark, we are responsible for up to $11.25 million of the cost. Therefore, anything beyond the 11.25 million dead band is either flowed back to or recovered from our customers.

At the end of the second quarter, our accruals for the ECA were zero. In other words, no additional cost or benefit under the ECA has been recorded based upon our expectations for the full year.

In Wisconsin there is a dead band of 2% around projected fuel costs. If it appears we would be out of the band, we would file for a fuel cost adjustment.

So with that, I will wrap things up. Overall it was a good quarter in which we booked solid results. We have made significant progress in the approval process for Comanche 3 by getting air permits and reaching an agreement on the water supply contract. I'm also very pleased that even with extended periods of hot weather and lower coal deliveries we achieved strong operational performance at our plants and throughout our transmission and distribution system. And finally, we continue to make progress on our strategy of investing in the core utility business and working with our commissions to ensure that we earn a reasonable return on that investment.

So let's open up the line for questions.

(OPERATOR INSTRUCTIONS). Greg Gordon, Smith Barney.

Could you extrapolate on a couple of the key assumptions for 2005? You indicated allowance for funds used during construction is expected to decline, but in the first quarter I think the guidance was that that was going to be flat. What has changed there? And then you have just modestly tweaked your effective tax rate assumption. Could you comment on that as well?

Yes. Both of those are really just fine-tuning of our initial estimates. In the case of the AFUDC pickup, we have lower quick balances and we have higher short-term interest rates, all of which tend to pull that calculation down. And again, in the case of the effective tax rate, that is just a fine-tuning of our estimates.

But it does not have anything to do with a delay in the projects or anything before some of the AFUDC can kick over to '06 higher?

No, it is really just trueing up estimates.

Paul Patterson, Glenrock Associates.

Just on the COLI, you guys indicated that you felt that you were highly confident that you would do well with this issue with the IRS. And yet the probable standard does not seem to be met, and I was wondering if you could just elaborate a little bit on that and what you think the ongoing impact would be if we get the FASB ruling?

Let's take it in two pieces. The probable standard, what that means is that you basically have to get a legal opinion from a law firm. And that definition I think is that there is 75% roughly I think is the percentage confident that we prevail.

I can tell you, Paul, that is just from a practical reality about impossible to get. So regardless of how confident we are and we are, that is just the reality.

I think the second part of your question was, if the FASB has adopted as proposed, what would the impact be?

The ongoing.

The ongoing impact is one, we would have to reverse out benefits that we have taken today, and then on a perspective basis, we would not recognize roughly $0.09 of the COLI benefit. On a going forward basis, again it does not affect the cash flows, and assuming that we will successfully resolve this issue, which we believe we will, we would then bring those benefits back onto the income statement.

Okay. And that would not include potential penalties? Can you give us an idea what -- do you guys have any idea what those could be in the worst-case kind of unlikely scenario?

Worst-case scenario, those penalties through '05, I believe, would be $65 million.

Okay. Thanks a lot.

Elizabeth Parrella, Merrill Lynch.

Yes, on the O&M expense, it was up a lot in the quarter, and I understand the nuclear outage issue. But some of the other costs, employee and performance incentive type costs, are we going to see those continue to kind of recur at that type of year-on-year rate in the second half or were there some unusual factors in the quarter?

Yes, you will not see -- you should not use those as an indicative run-rate. Those costs were true-ups based upon where our stock performance is and what stock performance we have had to date in the case of the performance-based.

We annually get our actuarial reports -- we true those up, we true those up in the second quarter. So those are not again indicative of the run-rate going forward.

Okay. And just a quick follow-up, how much was the Seren gain in the quarter?

It was $0.01 to $0.02.

Okay.

George Ali Agha, Wells Fargo Securities.

That would not be my name, but anyway good morning. Listen, going back to the short-term wholesale and commodity margin assumption you have made for the year as being down for that range, are you seeing really higher state power and gas prices in the market? Would that in anyway impact that assumption you are making, especially as we go through this pretty hot summer going forward?

We certainly have seen higher spot prices in the market in the MISO region where most of those margins are generated, and that has in part been responsible for the performance we had in the second quarter. But going forward we're having very hot weather, and as you know, the retail low gets first call on our assets, so there is not going to be a lot to sell in the surplus markets.

The MISO day two market is a market that continues to evolve, so we need to continue to understand where the market opportunities are. And, of course, we have the issue with coal deliveries that we are looking at, too. So I think the guidance that we gave last year continues to hold true.

Okay and one follow-up. As you are starting the rate case agenda, which is also going to be very full going forward, any early indications or read from the various commissions and (inaudible) members that would suggest that you are pretty confident in the numbers you are laying out or anything you can share on that?

Well, I mean I guess what I would point you to is what we have done today. I think we will have a -- we've got the settlement approved in the Minnesota gas case, got the written order in August. There has not been any -- I don't think anything too surprising about any of that, so things are going smoothly there. And I guess I would use that as the best indicator going forward.

Fair enough. Thank you.

Paul Ridzon, Key McDonald.

A question on Powder River Basin coal and kind of what your assumptions and guidance are with regards to the dead band. I think you addressed it, but I was not quite clear on that.

I think I talked about two dead bands. There is a dead band in Wisconsin that is a plus or minus 2% where if you fall outside of that band you can go in and seek recovery.

The other dead band I referred to was in Colorado under our ECA mechanism, and that is a plus or minus $11.25 million. And if it falls outside of that, then you either refund or recover.

We currently have that ECA mechanism at zero, and we expect that that will be -- we expect that that will be consistent with where we see the full year ending up. Obviously we will be watching that.

Now coming into this quarter, we were actually positioned to be on the upside of that ECA mechanism. So we did reverse out this quarter the upside that we had recognized in the first quarter of this year.

Would continued hot weather kind of accelerate recognition of some dead bands? Is that the right way to look at it?

No, you are referring to in Colorado?

Yes.

Not really. It has some impact depending upon what generation you're burning, but it is pretty insignificant.

And then related to the PRB, there are some people who want to push this issue out past 2005. Is it kind of your view the way things stand now that things will be back up by November and we can kind of rebuild stockpiles and there should be de minimus '06 and '70 impacts?

That is the assumption we are operating on right now. We're going to monitor it obviously.

What is 2% in Wisconsin in millions?

That is probably maybe a $0.005 per share.

Okay, thank you very much.

Ashar Khan, SAC Capital.

Could you give us what your PMROEs are in Minnesota on the electric side?

PMREs?

Return on equity.

In Colorado?

In Minnesota and Colorado.

What do we have? It is 10.75 authorized in Colorado. I mean yes, Colorado. Let's see. I'm just looking at a chart here.

What are you earning LTM, latest 12 months?

Last year in Colorado we earned 9.2% off an authorized ROE of 10.75%. In Minnesota, because I think you asked that, we earned last year 10.73% off an authorized ROE of 11.47%. Keep in mind that last year we had very high short-term trading margins which tended to push that ROE up. We expect this year as we stated in our filings that the number would be in the low 9s.

Okay. That is in which jurisdiction low 9s?

Most of our jurisdictions (multiple speakers)

Okay. So both jurisdictions' ROEs are going to be low 9s?

That is about right.

Charles Fishman, A.G. Edwards.

I realize this question might become moot with what is going on in Congress right now, but assuming things don't go well with the PUCA repeal, or if there is something else lurking in the fine print of the energy bill, could this COLI charge that potentially could occur for prior periods, could that have any impact on the ability to pay the dividend? Sort of like what happened a couple of years ago when your retained earnings were not high enough to support the dividend. By my calculations, I realize the retained earnings would probably not be a problem, but is there anything else out there that could impact the dividend, you know, cause you to have to delay the dividend?

No, Charles, your calculation on retained earnings is right. That would not impact it. The one thing I think you're referring to on PUCA is the equity ratio I believe needs to be above 35%, and the impact of this write-off to be -- to bring down our equity ratio by about 200 basis points. 30% by the way, not 35% on the PUCA requirement.

So there's really nothing that you are aware of that could cause us to get into a situation like we had a couple of years ago?

No.

Daniele Seitz, Maxcor Financial.

In your guidance is the effect of FASB in that or is it not?

No. On the $1.18 to $1.28 of guidance we have this year, that assumes that we continued to recognize approximately a $0.09 benefit for COLI as per GAAP.

So this assuming that you get a decision before year-end, you will levy one (inaudible) in that adjustment until this is cleared up, and it will continue next year, I suppose?

If the FASB is implemented as proposed, and I think there is going to be a lot of comments on this, but if it is then we would -- basically I think the benefit would be removed as part of an accumulated change in accounting principle. So actually our understanding is the continuing operations piece of it, the COLI would stay up there and then you would remove it in this accumulated change.

Right.

Now on a perspective basis, you would not recognize it.

Okay. And on the COLI effect, when you're looking at the second half, you're saying that you can maintain pretty much the situation as it is now, or did I not quite understand it? Do you feel that there might be an impact on the future of system sales? I mean some sort of not direct but indirect impact possibly?

I think it could have an ability on our marketing group to sell into the short-term markets. Of course, we have higher spot prices, too. So we factored in all of those things when I made the statement that our guidance expectation for trading margins remains where it was when we initially issued it.

Right. And you do not anticipate any unusual outages in terms of powerplants for the second half?

No, we don't. They could always happen, but we don't anticipate them.

Not anticipated. Thank you.

The plants, by the way, have run very well through this extended hot weather.

Great.

Paul Patterson, Glenrock Associates.

You guys answered it. Thank you.

Elizabeth Parrella, Merrill Lynch.

Just going back to the cost recovery issue around PRB, you mentioned there was a dead band in Wisconsin. And as I remember, there is also one I think 4% in Texas. Within that dead band, are you committed to defer the costs and then on the assumption that you will get recovery, or do you have to extend up to that level and then go in for recovery and get it subsequently?

I think the answer to that is we can defer, but let me confirm that with Dave Sparby.

In Wisconsin we can request a deferral of the costs, and if we are outside that dead band, we will do that.

And in Texas can you do the same thing?

In Texas there is not the same opportunities, but we can file outside of our semi-annual filing sequence to recover the costs which we would do.

(OPERATOR INSTRUCTIONS). Steven Rountos, Talon Capital.

I apologize if you already talked about this, but I think previously when you talked about the FASB 109 drop, you talked about the dual threshold of the previously recognized tax benefits versus the benefits you would recognize going forward, and that because there is a probable versus more likely than not standard, that you would not necessarily need to take a write-off on the previously recognized benefits. What has changed then in your thinking about that?

The actual issuance of the exposure draft, we were trying to get as much information out as we could based upon a draft that had not even been issued yet. So when it has actually come out, it is not the case.

Okay. But there was nothing -- it's just an interpretation of the actual draft versus what you have felt the draft would look like before? Is that right?

That is right. I think there is still a more likely than not standard, but it has to do -- once it has passed the probable test, when would you derecognize it on a prospective basis, and perhaps that is where this dual threshold thing came in. But it is basically seeing the actual exposure draft versus picking up whatever you could pick up.

Okay. But this does not change the timing of any of the ongoing discussions with the IRS, etc.?

No, that is on its own track.

And summary judgment is scheduled for the end of August, the hearings for summary judgment?

The oral arguments are scheduled for August 19th, yes.

Gentlemen, at this time, there are no further questions. Do you have any closing remarks?

No, I appreciate everybody participating on the earnings call this morning. If you have any follow-up questions, there is always Dick Kolkmann and Paul Johnson will be available to take your calls. And thank you, everyone.

Ladies and gentlemen, that concludes Xcel Energy's second-quarter 2005 earnings conference call. We thank you for your participation. You may now disconnect.