埃克西爾能源 (XEL) 2005 Q4 法說會逐字稿

Good morning, my name is Dennis and I will be your conference operator. At this time, I would like to welcome everyone to the Xcel Energy fourth quarter 2005 earnings conference call. [OPERATOR INSTRUCTIONS]. I will now turn the conference over to Mr. Richard Kolkmann, Managing Director, Investor Relations. Please go ahead, sir.

Thanks, Dennis. And welcome to Xcel Energy's fourth quarter 2005 earnings release conference call. With me today is Ben Fowke, Vice President and CFO of Xcel Energy.

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 & Exchange Commission. I will now turn the call over to Ben.

Thanks, Dick, and welcome, everyone.

Xcel Energy recorded earnings from continuing operations of $1.20 per share for 2005, which was within our guidance range. This compares to $1.26 per share for 2004. Total earnings for 2005 were $1.23 per share compared with $0.87 per share for 2004. In 2005, we recorded earnings of $0.03 per share from discontinued operations, largely due to the final resolution of tax benefits associated with our divestiture of NRG. As a reminder, we recorded a loss of $0.39 per share in 2004, largely due to an asset impairment charge related to our Seren investment and a loss on the sale of Cheyenne Light, Fuel and Power.

The rest of my comments will be in relation to earnings from continuing operations. At the core of our company, we have our utilities subsidiaries, which provided earnings of $1.27 per share for 2005 compared with $1.32 per share for 2004. Our utility earnings declined by $0.05 per share despite higher electric utility margins that increased earnings by $0.23 per share.

The higher margins were offset by higher utility O&M expenses which decreased earnings by $0.12 per share, higher depreciation expense, which decreased earnings by $0.09 per share, lower short-term wholesale margins, which decreased earnings by $0.03 per share, and a higher effective tax rate and other items which netted to decrease earnings by about $0.04 per share.

Our holding company costs and results of other non-regulated companies reduced earnings by approximately $0.07 per share for 2005, which was comparable to a loss of $0.06 per share recorded last year. These costs are largely financing costs at the holding company. That summarizes our 2005 results.

Now let's look into the details. Our base electric utility margins increased by $163 million or $0.23 per share for 2005, largely driven by warm summer temperatures and sales growth. In 2005, we benefited from summer temperatures that were warmer than normal and significantly warmer than last year, which increased electric sales. As a result, favorable weather increased electric utility margins by $75 million.

In addition to favorable weather conditions, weather adjusted retail electric sales grew at 1.4%, increasing electric margin by 42 million. Our electric margins also improved because we had lower accruals per customer refunds under the various quality of service programs and for refunds related to the SPS Fuel reconciliation issue. The Texas Commission approved our fuel reconciliation settlement in December, as a point of reference, we accrued $25 million for the SPS Fuel reconciliation in 2004 compared with $4 million in 2005. For more information on electric margins, please refer to our earnings release.

Our short-term wholesale margins declined by $25 million in 2005. The decline in margins was actually less than we anticipated, driven by strong prices, particularly in the fourth quarter. In the fourth quarter, we saw increased market demand, causing more off-peak periods to have natural gas on the margin. Therefore, increases in gas commodity costs translated into both on and off-peak increased energy prices. Additionally, the warmer-than-expected temperatures at the end of December resulted in lower native load volumes facilitating additional surplus sales opportunities.

Despite strong fourth quarter results, our 2006 guidance reflects projected short-term margins of $30 to $50 million, which is a decline from the $86 million we recorded in 2005. The anticipated decline is due to decreased opportunities resulting from the [misocentralized dispatch] market, normal retail customer demand growth, reducing our surplus generation available for market sales and a reduction in the availability of our coal-fired resources due to work on the King plant as part of the MERP project. In addition, as part of the Minnesota Electric Rate Case, we are proposing a short-term wholesale margin sharing mechanism to share risk and incentives more equally between customers and shareholders. Our overall earnings guidance reflects the sharing of short-term wholesale margins.

Turning to operating expenses, our 2005 O & M expenses increased $87 million or 5.5%, largely driven by higher benefit costs, increases in bad debt expense, and higher nuclear outage cost. When we established our 2005 guidance, we expected that O & M expenses would increase by 2% to 3%. For example, we knew that benefit costs were increasing. We also know that there would be two nuclear outages in 2005, compared with one in 2004. However, there were some cost pressures we didn't anticipate.

The best example is bad debt expense. In 2005, our bad debt expense was about $48 million, which was greater than anticipated. Part of the increase was an anomaly due to the change in bankruptcy laws as well as higher fuel prices. During the year, we realized that because of the high fuel price environment as well as other factors, we had to increase our focus on our collection and credit process. We made procedural changes to enhance the overall process, resulting in adjustments to our accruals. Going forward, these procedural changes, along with some changes in management, should allow us to better control bad debt expense.

In addition to bad debt expense, we had over $20 million of one-time O & M costs, which included approximately $10 million for additional maintenance at our power plants, driven by the high demand during the summer; $7 million for executive transition costs; and $5 million for charitable contributions to help customers pay their heating bills. We recognize that every year includes some one-time expenses, but in 2005, we had more than our share. As a result, we think O & M in 2006 should increase 3% to 4% over 2005 levels.

As expected, depreciation expense for 2005 was $61 million higher than 2004 levels. The increase is due to growth associated with normal system expansion and incremental depreciation for several large projects, including the new steam generators at Prairie Island and a new billing system. We expect recovery of these investments in future rate filings.

Our effective tax rate was 25.8% in 2005 compared with 23.7% in 2004. As you might recall, in 2004, we recorded tax benefits of approximately $34 million or $0.08 per share, primarily related to the completion of five tax audit cycles, which resolved several issues related to prior years. While we recorded some additional tax benefits in 2005, it wasn't at the level of 2004. As a result, our effective tax rate increased.

While that covers 2005 results, next I'd like to spend a few minutes on some recent developments. In 2005 we filed several rate cases as part of our regulatory strategy. These rate cases and others that we plan to file in 2006 are some of the building blocks of our earnings growth plan. We continue to make progress on these initiatives, in particular we've reached favorable conclusions in the Colorado and Wisconsin cases, and are on track with the Minnesota Electric case.

In May, 2005, PSCo filed for a $34 million natural gas rate increase based on an ROE of 11%. In December, 2005, PSCo and various interveners reached a settlement resolving all the issues in this proceeding. The Colorado Commission approved a $22 million rate increase based on an ROE of 10.5%. Rates are expected to be in effect in February.

In 2005, NSP Wisconsin requested an electric revenue increase of $58 million and a gas revenue increase of $8 million, based on an ROE of 11.9%. In early January, the Wisconsin Commission approved an electric rate increase of $43.4 million and a natural gas rate increase of $3.9 million, both were based on an authorized ROE of 11%. While we would have preferred the Commissions grant our requested rate increases in full, we believe that both the Colorado and Wisconsin rate orders were constructive outcomes overall, particularly if you consider the high fuel price environment.

In November, 2005, NSP Minnesota requested an electric rate increase of $168 million, which represents approximately an 8% increase. This request is based upon an ROE of 11%, a projected equity ratio of almost 52%, and projected rate base of $3.2 billion. In December, 2005, the Minnesota Commission authorized an interim rate increase of $147 million, subject to refund, which went into effect as of January 1, 2006. A final decision is expected in the third quarter.

Let me explain how we will account for the interim rates. Starting in the first quarter, our revenue recognition will include the interim rate increase based on the prorated amount of the $147 million authorized level. Prior to each quarter close, we will review whether there was any new evidence that recovery at the interim level was not probable. In the event this situation occurs, we may be required to recognize an estimated refund of a portion of the interim rates, depending on facts and circumstances. Ultimately, there may be a final revenue true-up in the third quarter to reflect the final rate order.

Well, that's an update on our regulatory developments. Occasionally, investors will mention that there is regulatory risk associated with Xcel Energy because of the numerous rate cases we are filing. Our strategy is to file reasonable rate requests designed to provide recovery of legitimate expenses and a return on our utility investments. We believe that our commissions will provide us with reasonable recovery, and it's important to note that our guidance range includes this assumption. Recent constructive results, along with past rulings, are evidence of a reasonable regulatory treatment, and it gives us confidence we're pursuing the right strategy.

Moving onto other developments, there are two issues related to our Company-Owned Life Insurance program, also known as COLI. The first and most significant issue is the actual IRS dispute. The second issue is the potential accounting pronouncement from the FASB, which affects accounting recognition, but not the actual cash flows.

I'll start with the IRS dispute. There have been no new developments on the legal side in our dispute with the IRS. Litigation is currently proceeding with discovery with a trial to be held some time in early 2007. Because the decision reached following that trial can be appealed, it may be another two to three years before the litigation is finally concluded. There was a new development in the Dow IRS COLI dispute. In 2003, Dow won a COLI lawsuit against the IRS. The IRS appealed the decision. And in January of 2006, in a split decision, the 6th Circuit Court reversed the Dow decision and ruled in favor of the IRS.

While this is a new development, we don't feel it has much bearing on our case, and let me explain why. We have analyzed the impact of the Dow decision on our pending COLI litigation and concluded there are significant, factual differences. As we've said before, we believe the outcome of COLI is very fact-specific, and we believe our facts are stronger than the facts in the Dow case. The good news about the Dow decision is the majority reaffirmed that satisfying the 4 of 7 test is a Safe Harbor for interest reductions. This 4 of 7 test is an objective standard which we clearly satisfy.

In addition, the majority opinion in Dow outlines three indicators or tests of economic substance. These indicators are positive pre-deduction cash flows, [mortality] gains, and the buildup of cash values. The court found that Dow's COLI plans possessed none of these indicators of economic substance.

We believe it's only necessary to possess one of these indicators. Applying these three indicators of economic substance in Xcel Energy's COLI case demonstrates that our plans were projected to have sizable pre-deduction cash flows based upon the relevant assumptions when purchased, that our plans presented the opportunity for mortality gains that were not eliminated either retroactively or perspectively, Xcel Energy's COLI had no provision giving back any mortality gains it might realize, and that our plants had large cash value increases that were not encumbered by loans during the first seven years of these policies. We continue to believe our case has strong merits and feel confident about our facts and circumstances.

Now let me touch on the FASB issue. During the last few months, the FASB Board has had several meetings and made the following decisions: First, the FASB decided to use an asset model approach with a more likely than not recognition threshold. That means a company can record the tax benefit as long as there's a greater -- there's greater than a 50% probability that the Company will ultimately prevail in recognizing the tax benefit. Second, the FASB also decided on the implementation table, which for us would mean an effective date of 2007. While we will need to review the final interpretation and continue to monitor other COLI developments, at this time we believe we will be able to continue to book the COLI tax benefit on a financial reporting basis, and we will not be required to establish any reserves.

Changing topics, earlier this month we closed on the sale of Seren's Minnesota assets to Charter Communications. Our divestiture of Seren is now complete. Looking at other developments within the utility operations, in January temperatures were significantly warmer than normal in all of our service territories. Our preliminary analysis indicates that our earnings will be reduced by $0.03 for warmer-than-normal January weather. While it only represents one month of the year, it is something you should be aware of as you prepare your first quarter estimate.

Let me also give you an update on our coal supply situation. As you are probably aware, delivery of coal from the Powder River Basin has been disrupted by various factors, including deteriorated rail track in Wyoming. Unfortunately, recent deliveries have not improved, and this doesn't appear to be a short-term trend. As a result, we may need to continue with periodic mitigation strategies to preserve coal inventory at certain plants. The coal situation could potentially put downward pressure on the ECA incentive mechanism in Colorado. Clearly, it is still early in the year, and we will keep you posted on the situation.

For the last couple of years, we have been accruing for customer refunds in Colorado, related to the [Sadie] Measurement under the quality of service program, known as QSP. In 2005, we accrued approximately $8 million, which represents a $13 million accrual for 2005 and a $5 million credit to adjust accruals related to 2004 performance. I'm pleased to report that the Colorado Commission recently approved a QSP settlement. As a result, PSCo will not accrue any liability penalties for 2006, assuming we invest $11 million in incremental capital to improve reliability. We consider this settlement a true win/win for our customers and our shareholders.

So with that, I'll wrap things up. Overall in 2005, we made good progress in laying the foundation for future growth. With January under our belt, we've had some positive developments with the recent decisions in the Wisconsin and Colorado rate cases. On the other side of the ledger, we've had some unseasonably warm weather and continued coal delivery issues. All in all, we remain on track to deliver our 2006 earnings range guidance of $1.25 to $1.34 per share from continuing operations. $1.25 to $1.35 per share. I misspoke there.

With that, let's open it up for questions.

[OPERATOR INSTRUCTIONS]. Your first question is from the line of Dave Parker with Robert W. Baird.

Hi, good morning, everyone. Question just on the Minnesota rate case. Is there a potential, or have you commented on the potential for settlement in that case or expect it to go through the normal course?

Well, we're just, I think we're in the discovery process now, so the settlement's always possible, but we do expect if it goes through the normal course that we'd have a decision, Dave, in the third quarter of this year.

Okay, so what you're looking for is probably to pull together, at least make your initial rate case final-- well, I guess you have already made your initial rate case filings and see where it goes from there?

Yeah.

Okay, and can you quantify, you just talked about the positive on the Colorado customer service thing. What would that be earnings per share kind of positive '06 versus '05?

Well, you know, we have been accruing some pretty significant penalties under the Sadie Measurement. As I mentioned in my prepared remarks, the accrual for 2005 was $13 million, prior year we had significant accrual too. I can't remember the exact-- I think it was $11 million. So Dave, we think that's a really positive development. We put steel in the ground; replaced cable; fixed some things that have been causing the problem; get recovery of that $11 million; and not have the penalties accrue, and I mean, it's, I think it's a real sign of constructive regulatory treatment.

Yeah, I'd agree. Okay, thank you very much.

Your next question is from the line of Paul Ridzon with [G Key].

Good morning, Paul.

Good morning, how are you?

Good.

Can you quantify the on-going level of rail disruptions kind of on a percentage of what you would normally expect to receive?

Since the disruption started in May of last year, it's based-- our deliveries have been basically about 80% of what we've nominated, and that trend pretty much has continued. Sometimes it's up, sometimes it's down throughout the course, and it's frustrating for us. We really thought we'd see the deliveries be closer to 100% of nominations as we enter the winter season with some significant track repair behind us, but that's not what's happening, and as I mentioned, the railroads are telling us that we can expect some more delivery disruptions going forward potentially.

And kind of where does that leave your stock piles?

On a consolidated basis, we're-- we averaged 23 days, but there is some significant variance plant-to-plant. So what we had hoped to see, Paul in this winter season, is that we would actually be building the coal piles up, in the more to the line of the 30-day range with not so much variances plant-to-plant, and that hasn't happened to date. We continue to work on it. One of the things we did on our end was to lease a significant number of brand new aluminum rail cars. They're lighter, they can carry, I think it's 28% more coal than a typical steel rail car. That will help, but the bottom line is, we need the deliveries to be more equal to what we're nominating.

And you mentioned weather had been milder. Is there any-- aside from regulated sales, is there any potential offset that you see with free capacity being able to market that in an increasingly gas-priced market?

That's a great question. Typically-- it will depend on market conditions. Keep in mind that we've seen -- the gas prices have softened as we've entered '06, but typically, if your retail load is lighter than you expect it, it does create some opportunities to sell mortgage generation into the market. That's what happened primarily in December of just last year, and it created some nice short-term margins for us, but you need other market conditions to cooperate at the same time.

And to what extent are you forced to limit that type of opportunity in the name of saving stockpiles?

Well, I think what you're referring to, if you don't have as much coal resources because you're either conserving or-- in the case what I mentioned in the remarks, King, our King plant is being retrofitted as part of the MERP project. If you don't have the coal resources, then you potentially can't take advantage of those opportunities as well as we have in the past.

And then just in Colorado, the $13 million accrual for Sadie, you expect that to fully go away?

In '06 we do, yes.

And that hit '05 earnings?

Yes, it did. It was a net $8 million because we had some adjustments for '04, but that's the level of the accrual.

Is that pre-tax or after tax?

That's pre.

Thank you very much. That's all my questions.

Thanks.

Your next question comes from the line of Elizabeth Parrella with Merrill Lynch.

Thank you. Wanted to ask a little about your retail sales, especially the residential sales, which even on a weather normalized basis were pretty weak in 2005, and I know you've mentioned kind of the impact on consumption patterns from higher power prices, particularly in Colorado, but wondering if you could just revisit with us whether there were some other factors at work and is that something we should expect sort of continue into '06?

You know, that's a good question, Elizabeth. We continue to look at it. The sale-- you recall we did bring our sales assumption down in 2005 from our initial guidance. 2006 reflects what we were seeing in 2005, so we're comfortable with that assumption. You know, there might be some conservation going on, but we don't think we're seeing significant demand destruction. And what we've done, Elizabeth, is examine some of the fundamental economic indicators, housing starts, unemployment, et cetera. And they suggest a pretty good economy.

So with the exception of gas sales that we do think we've seen demand destruction on, we don't see that trend on the electric side. One of the things to keep in mind is that we had a pretty warm summer in 2005. It was preceded by a pretty mild summer in 2004. Sometimes our weather normalization models don't capture that maybe as well as they should. We're looking at that. We don't think we see a significant long-term trend. We're not concerned about overall declining electric sales, but we're going to watch it.

Okay. And also, you mentioned with the bad debt expense number was in 2005, I think you said $48 million. Do you have the comparable 2004 number?

Yes, we think 2006 bad debt expense will fall off to about $35 million. 2004 was at the $28, $29 million level. So we're kind of ' splitting the difference there.

Two things to think about, Elizabeth: We continue to be in a high steel environment, so we do think bad debt expense will continue to be relatively high, but we don't think we'll see bad debt expense at the level of 2005 for two factors: One, there kind of ' was a rush, we think, for some of our customers to get ahead of the new bankruptcy laws because the new ones I guess are more conservative; and the second thing is, internally, we've put a lot more focus and attention on our processes, and I'm confident that that's going to pay some dividends for us in '06.

Okay. And one last question, if I may. Do you have where operating cash flow and CapEx came in for '05 and how that might have compared with your, you know, your projections?

It came in pretty close to our projections. Cash from operations on a total basis was $1.2 billion. On cash from continuing operations was $1.1 billion. CapEx came in about where we were thinking too, Elizabeth, at $1.3 billion.

Okay, thank you.

Your next question is from the line of Steven Huang with Citigroup.

Hey, Steven.

Hey, good morning. Question I had here was on back to the PRB question here. With the delays continually going on right now, you guys don't anticipate then, based off what you're seeing, that you'll be able to get back to that more or less 30 days type of stockpile before summer?

We're going to do everything we can to get back to that 30 days. That's where we'd like to be, and we're working very closely with the railroads to get the nominations that we want, but it is an issue for us. And that's why if we can't get the deliveries, we might have to continue to do some mitigation that you saw us doing in 2005.

Now, remind me, was the mitigation plan then include going to the market and buying purchased power?

It includes that. It includes in some cases switching from coal to gas. We have that ability in some of our plants to do that. It includes changing some of the dispatch order, so essentially you're not using your coal plants as much as you would. You're using gas plants as an alternative to save coal.

And the new rate cases that you more or less got settled or the like, can you just remind me, where can you get trued up on the purchase power? Is that all your jurisdictions or are there areas where you're still going to eat the cost?

Well, those purchases-- are you talking about purchase that we might make for coal mitigation?

Right, for the customer --

Those would be considered energy purchases, and they would flow through the fuel costs, so I think you're familiar with our fuel cost recovery mechanisms.

Okay. Basically all it really is is that your potential off-system sales, which has declined significantly, if you were to go back into mitigation for this year?

It could impact that, yes.

Okay. And then the January weather, it was just-- the $0.03, you're talking primarily due to the gas business, right?

It's gas and some electric. I mean, when you tick on your furnace, there's an-- on your furnace, there's an electric component to that. I think I read in the paper it's the warmest Minnesota winter in 160 years. I haven't lived in Minnesota that long, but I don't think it typically rains in January and it did at my house a couple nights ago.

But you guys aren't changing your retail sales forecast because of any of that? I mean, I know -- on a normalized basis, but--

No, no we're not.

Okay, great. Thank you.

[OPERATOR INSTRUCTIONS]. The next question is from the line of Maura Shaughnessy with MFS.

Good morning. I guess harping on this coal issue again, I guess when we talked to the rails, they're infinitely more upbeat than the reality that you guys are portraying. What is the issue, since it's been on the highlight film, so-to-speak, since last spring? I mean, what is the problem that is created the continuation of this theme?

I wish we could get more some of their upbeatness in terms of coal delivered to our plants, and that's really what we want. Originally, it was the deteriorated rail track, which meant that the cars had to slow down significantly. They did a lot of work on those tracks prior to winter. When winter sets in, what we were anticipating, based upon conversations with the railroads, that you'd have-- the track would basically firm up because of the frozen ground and we could pretty much expect normal deliveries, but that hasn't happened.

There's been a number of issues that the railroads have talked about, issues with mining, labor, what have you, but most recently, they've mentioned that there is more demand than there is supply. And that's, that's why we've reported that we're going to have to continue to look at this. I think we've done absolutely everything we can, working with our commissions to do that. But we need the coal from the railroads and we're going to do everything we can to get it.

Now, in setting forth your guidance for '06, this was known in terms of the coal inventory situation when that guidance was set. How should we think about-- there were some offsets, probably the rate cases went better than expected or what have you, but you didn't materially change guidance, despite the situation on the fuel side. How should we think about that?

Well, we've had some ups and downs. The thing that I'm most pleased with is we continue to execute on our regulatory plan, and that's what I believe drives long-term growth for us. On the coal side, the thing that we'll be watching, that we'll be working real hard to mitigate is the potential impact it could have on our ECA recovery incentive mechanism in Colorado. We've earned pretty much at close to the top of that incentive mechanism, which is $11 million pre-tax over the last couple years. Mitigation combined with this overall increases in coal prices are going to put some downward pressure on that, but you know, it's one of several different variables.

Okay. Great. Good luck!

You have a follow-up question from the line of Elizabeth Parrella with Merrill Lynch.

Just wanted to follow up on that last question, actually. How much did you earn under the Colorado Incentive Mechanism in 2005? Because I thought at one point you were building in something that was fairly neutral? So it sounds like maybe you did a little better than you expected?

We did. We came out at $8.5 million, Elizabeth, for '05.

Okay. And in terms of your guidance, have you built in sort of a similar amount or...

The first thing is, the guidance is what we came out with in the third quarter, $1.25 to $1.35. It's just one of the multiple variables that we look at. I tell you, the biggest sensitivity, obviously, is the Minnesota Electric rate case, and that's the one that I think ultimately swings the needle the most.

Okay. Thank you.

As this time, there are no further questions.

All right, well I want to thank everybody for participating on the call this morning. I look forward to meeting many of you throughout the year. As a reminder, if you have any follow-up questions, Dick Kolkmann and Paul Johnson will be available to take your calls. Thank you.

This concludes today's Xcel Energy fourth quarter 2005 earnings conference call. You may now disconnect.