埃克西爾能源 (XEL) 2006 Q2 法說會逐字稿

At this time I would like to welcome everyone to the Xcel Energy second-quarter 2006 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 session. At that time we will only take questions from analysts and institutional investors. Any other questions from the news media can direct their questions to the Investor Relations department. (OPERATOR INSTRUCTIONS). Thank you and I will now turn the call over to Mr. Richard Kolkmann. Sir, you may begin your conference.

Thank you who are listening to us and welcome to Xcel Energy's second-quarter 2006 earnings release conference call. I am Dick Kolkmann, Managing Director of Investor Relations and with me is Ben Fowke, Vice President and Chief Financial Officer 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. With that I will turn the call over to Ben.

Thanks, Dick, and welcome everyone. Xcel Energy recorded earnings from continuing operations of $0.24 per share for the second quarter of 2006. This compares with $0.19 per share for the second quarter of 2005. Total earnings for the second quarter 2006 were $0.24 per share compared with $0.20 per share for 2005. Our earnings from continuing operations increased by $0.05 per share for the quarter, largely due to higher electric retail margins which increased earnings by $0.10 per share, a lower effective tax rate which increased earnings by $0.02 per share and other items that together increased earnings by about $0.01 per share. These positive factors were partially offset by lower short-term wholesale margins which decreased earnings by $0.06 per share, higher utility O&M expenses which decreased earnings by $0.01 per share and higher depreciation expense which decreased earnings by $0.01 per share. That summarizes our second-quarter 2006 results.

Now let's look into the details. Our base retail electric utility margins increased by $71 million or $0.10 per share for the quarter, largely driven by rate increases and weather. Electric margin grew by $54 million from various rate increases. This includes $40 million from the interim rate increase in Minnesota, $9 million for the implementation of the MERP Rider and $5 million for an electric rate increase in Wisconsin. Weather was also a positive factor. We experienced warmer than normal temperatures in Minnesota, Texas and Colorado in June. As a result our electric margin increased by $8 million compared with last year.

On a year-to-date basis our weather adjusted sales growth was a solid 1.8%, which is slightly higher than our annual assumption range of 1.3% to 1.7%. While we are not adjusting our sales growth assumptions we view this as a positive trend. While we are on the topic of retail margin, let me update you on a complaint filed with the FERC by several customers served by SPS. The dispute relates to whether fuel costs of certain wholesale customers should be based on system average cost or incremental fuel costs. In May 2006 and contrary to the position of FERC staff an administrative law judge recommended, among other things, that SPS recalculate its fuel clause billings to reduce fuel and purchased energy costs for certain customers. While we think the ALJ recommendation is incorrect, if the FERC was to affirm the ALJ's findings, the potential refund exposure could be up to $50 million. We do not think this is likely because we made wholesale firm power sales consistent with the FERC pricing policies for long-term sales.

That said, during the quarter we accrued $4 million, giving us a total reserve of $7 million for the potential liability based on our assessment of the FERC rules as it applies to both base rate and fuel items. We intend to vigorously challenge the ALJ's recommendations with the FERC.

Moving on to short-term wholesale margins for the quarter margins declined by approximately $43 million compared with last year. In the second quarter we recorded two adjustments which impacted short-term and energy trading margins. First, we reduced short-term wholesale margins by $13 million for a year-to-date adjustment for customers sharing in Minnesota under the proposed settlement agreement. This adjustment did not affect net income because the impact of the sharing agreement was already reflected in our accrual for [interim rates.] This is merely a reclassification to present the results consistent with the settlement agreement. (technical difficulty)

Excuse me. This is the operator. Excuse me, this is the operator.

Turning to operating expenses, our second-quarter O&M expenses increased $5 million or 1.3%. This increase was in line with our expectations. Based on our most current projection we believe that our 2006 O&M expenses should increase 3% to 4% over 2005 levels, which is consistent with our guidance assumptions. Now that said we will closely monitor the continued hot weather and its potential impact. We will spend the necessary dollars to maintain our system.

In the second quarter depreciation expense increased $10 million or 5%, driven by increased capital spending and changes in decommissioning accruals. There is no change in our guidance assumption for depreciation. In the second quarter of 2006 we had an effective tax rate of 17.3% compared with an effective tax rate of 24.1% in 2005. The lower effective tax rate in 2006 increased quarterly and year-to-date earnings by approximately $0.02 per share and was driven by two items. First, we recognized a tax benefit of almost $17 million resulting from a reversal of a valuation allowance for capital loss carryforwards. We also recorded an interim tax adjustment as required under APB 28, which partially offset the impact of a tax benefit on our effective tax rate. As a result of the realized tax benefits we have lowered our 2006 effective tax rate assumption. We are now expecting the effective tax rate to be between 24% to 26%.

That wraps up the explanation of the quarterly results. Next I would like to update you on our regulatory initiatives. Let me start with the case that is nearest completion. As you are probably aware, in Minnesota we have requested an electric rate increase of $156 million. This is based on an ROE of 11% and a forecasted test year with a projected equity ratio of almost 52% and projected rate base of $3.2 billion.

On July 6, the administrative law judge recommended a 2006 rate increase of approximately $135 million based on an ROE of 10.64%. She also recommended a $16 million reduction from that level for 2007 to reflect a large customer returning as a full requirements retail customer in 2007. While we don't agree with all of her conclusions, overall we think the ALJ made a fair and constructive recommendation. The Minnesota Commission is expected to hold its deliberation in the first two weeks of August; a final order is expected in September.

In April 2006 we requested an increase in Colorado electric rates of $210 million effective in 2007. The request is based on an ROE of 11% and equity ratio of almost 60% and a rate base $03.4 billion. While the case is based on a 2005 historic test year the filing is adjusted for known and measurable changes. A procedural schedule has been established and is included in the earnings release.

The next milestone is intervenor testimony, which is scheduled to be filed on August 18th. Hearings are expected to start in late October and a decision is expected by the end of the year with final rates in effect in early 2007.

In Texas we've requested an electric rate increase of $48 million based on an ROE of 11.6% and an historic test year with an equity ratio of 51% and a rate base of $943 million. Intervenor testimony is scheduled to be filed in late October and hearings are planned for late November through early December. A decision is expected during the first part of 2007; final rates should go into effect the first quarter of 2007. That's an update on our regulatory developments.

Another major component of our strategy is our investment in our utility assets. On the generation side of the business that includes our MERP and Comanche 3 projects. Both projects remain on track. For MERP all major contracts have been awarded for the King Plant. For the High Bridge Plant, 77% of the project is under contract, while at the Riverside Plant, which is the smallest and last in the schedule, approximately 18% of the project is under contract. We are currently forecasting to earn a return of 10.62% for the MERP projects.

For Comanche 3 all the major contracts are in place and 76% of the project is under contract. Looking at transmission, in June we announced the initial proposal of CapX 2020 which is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest which includes Xcel Energy. The CapX 2020 alliance has identified three groups of transmission projects that it proposes to complete by 2020. As you know adequate transmission is an issue nationally, and CapX 2020 will help address this issue in Minnesota and the surrounding area. Group 1, the first phase of the project is a series of four transmission lines. The preliminary estimate of the total investment for Group 1 is about $1.3 billion. Xcel Energy's investment will be about $700 million. Major construction is expected to start in 2009 or 2010 and end three or four years later. You should note that the capital expenditures for CapX 2020 will start ramping up just since the expenditures for Comanche 3 and MERP are winding down.

To support the CapX 2020 program Minnesota and South Dakota have passed legislation allowing us to recover transmission investments outside of a rate case through a rider mechanism. This allows us to earn a cash return on our transmission investment while the project is under construction. This type of recovery greatly reduces regulatory uncertainty and supports a strong balance sheet. We are very excited about the CapX 2020 project which represents a significant portion of the second phase of our build to core strategy.

Before I wrap things up I want to mention that yesterday we closed on the sale of our Oklahoma and Kansas assets to Tri-County Electric Cooperative and received net cash proceeds of approximately $24 million. While it is a small transaction it once again highlights that we are clearly focused on our core operations in the core jurisdictions that we serve.

In closing, we've put together two good quarters of earnings results. Earnings, along with improvements in working capital have generated over $1.1 billion of cash from continuing operations year-to-date. Now cash from operations will move up and down throughout the year based on working capital needs but this is a year-to-date increase of almost $500 million compared with last year and represents a significant improvement. In June we experienced hot weather across our service territory. This trend continued into July. As a result, additional sales driven by air-conditioning load is estimated to contribute earnings of $0.02 to $0.03 per share in July. Even under the stress of summer heat our electric system has performed very well. This really is a credit to our employees throughout the organization who have toiled in the heat to ensure that our plants and transmission and distribution systems are up and running when our customers need the power.

Let me give you a quick example of strong operating performance. During the quarter we completed an outage at our Prairie Island nuclear plant, in which we replaced the reactor head and one-third of the fuel assemblies. Even with the outage our nuclear capacity factor for the first six months of the year was over 90%. That's pretty good performance. Everything considered, we are well positioned to deliver on our 2006 earnings guidance range of $1.25 to $1.35 per share from continuing operations. Let's open it up for questions.

(OPERATOR INSTRUCTIONS) Paul Ridzon.

Question on the tax item reducing the effective tax rate. Is that going to be an ongoing thing? I was a little confused about that.

The $0.04 of the capital loss carryforwards, which we recognized this quarter you should view that as a onetime event. That was offset -- $0.02 of that was offset by an interim tax adjustment that we were required to make under APB 28, the accounting for taxes. So together I would view that as a onetime event.

The $0.02 net was onetime?

The $0.02 net was onetime, yes. (technical difficulty)

Daniele Seitz.

Actually on this, so you are going back to a normal tax rate of 24% or so, is it supposed to be going back (technical difficulty)

For this year, Daniele, (technical difficulty) lower our effective tax rate assumption we think the range now will be in the 24% to 26% range.

I'm sorry I should have mentioned, I was talking about 2007. Are you going back to normal a tax rate, or is your tax rate still going to be relatively low?

No. Because these are onetime items we will issue that assumption with our 2007 guidance but it will be more of a normal effective tax rate.

Okay. May I ask another one? Just quick, you mentioned that you had made some reserves, the $7 million during the quarter. Is this also onetime or do you anticipate to continue reserving up to $50 million?

If you look at one times, we talked about the positive tax benefits which we talked about. To your point, we made a $4 million accrual which brought the reserve up to $7 million year to date for the SPS issue, both from a rate and fuel case item. I think you should view that as onetime. We will obviously have to monitor the litigation going forward. In addition, Daniele, we took a $6 million charge this quarter for the FERC recommendation to reallocate costs associated with some financial transactions made under MISO. I think you should view that as a onetime item, as well.

So in the case of FERC you're not going to continue reserving for that?

We will continue to assess the liability, but that is not --.

It's not in the plan?

Right.

Thank you so much.

Elizabeth Parrella.

I apologize if you addressed this in your initial remarks but I had to go on the call a little bit late. In the Minnesota rate case what is the amount that you're currently booking the revenues at, and how much did you book in Q2?

We booked, let me -- $65 million I believe year-to-date and $40 million for the three months ended June 30th.

And what kind of rate is that say relative to where the ALJ is, for example? You told us what it was in first quarter; I am not sure if you're still booking at that level though.

It is roughly equivalent to the ALJ recommendation, Elizabeth.

And then with respect to the CapX 2020 I think you said $700 million of CapEx, your share of this program, could you give us an idea as to kind of when you start spending on that and kind of how it looks (technical difficulty) roughly by year?

I don't know if I have a year to year breakout. We might have some additional detail. I don't have it with me. But the expenditures really start in the latter part of the decade, the '09, '10 and then continue for '11, '12 and '13. And Elizabeth, as you know that is about the time that our CapEx expenditures for MERP and Comanche 3 will be ramping down.

Okay. Thank you.

Paul Debbas.

Given the better weather and the lower tax rate, why haven't you raised the guidance?

Paul, we haven't done that because as you probably know, the third quarter for us is our busiest earning season, and it is also as I mention on the call, when we will get a final ruling on this significant rate case in Minnesota. So I think it makes a lot of sense to get through the summer and see how we did with the rate case and then if need be update you on our guidance range on the third quarter call.

Thank you.

Ashar Khan.

My question has been answered. Thanks.

A follow-up from Paul Ridzon.

Kind of on Paul Debbas' question when you give your guidance are you treating the $0.02 tax benefit as an unusual item or is that embedded in the guidance?

When we give the -- when we reaffirm guidance? You're talking about '07 now?

'06.

No. It is embedded.

And any progress within the IRS?

No, nothing really -- you're talking about the COLI litigation?

Yes.

Nothing really to report; we filed a second motion for summary judgment. That will be heard later this month. No timetable on when we will get a decision on that. And as you probably know, the trial itself is scheduled to start the beginning of '07. We expect to have an answer two to three months later.

Okay. Thank you again.

Daniele Seitz.

I was wondering if it is more long-term, but when do you think of the planning for additional capacity either in Minnesota or Colorado, and is there a procedure that you have to go through?

We went through in Colorado, Daniele, the lease cost planning process a couple years ago, and Comanche 3 came out of that, along with more commitments to wind and other things. Here in Minnesota we are in the middle of that resource planning process and working very closely with the Commission and staff to develop recommendations; preliminary recommendations are more wind production, increase in baseload capacity of 375 megawatts. I believe we said we need that by 2014, and we are looking at other aspects of the resource plan too. So we're right in the midst of it here in Minnesota.

And there is no special requirement in terms of how much you're supposed to build relative to what you're supposed to purchase? Because I am assuming the wind production, would you be a builder or would you just buy it?

That remains to be seen. Historically we have been a buyer, not a builder.

Right. There is no requirement as to the level of purchase power that you will prefer?

No, it has to be clearly what you do is justify the lease cost.

Okay. Thank you.

(OPERATOR INSTRUCTIONS) Nathan Judge.

I wanted to just ask a question about the wholesale commodity trading margins. I know there is quite a bit going on there, including sharing, and I guess if I understand the text correctly there is some depression of margins as you didn't have enough of -- or as much availability to sell into wholesale market. But could you just go into -- it looks a bit weak, especially considering that you're looking for $10 to $20 million from that business for the full year. Could you go into greater detail, is it in line with your expectations, or --.

For the six months even with the reclassifications associated with the partial settlement, Nathan, which I can run through with you if you're not familiar with it, we are at $14 million. So I think that is the range -- is pretty appropriate. We're having a very hot summer, and not a lot of capacity to sell when you are meeting your own retail customer needs.

So the commodity trading margin of negative 8 and a short-term wholesale margin of 4, that as I understand it is pretty much in line with your expectations.

It is, just remember as I mention on the call you have to back out those adjustments that we made. The big adjustment being just basically the reclassification, the year-to-date reclassification to reflect this settlement agreement we entered into in Minnesota. Where for the last several years the majority of our trading margins, short-term wholesale trading margins have come from.

So if I were to look at what that was perhaps a year ago again is that 24.7 with readjustments or would only affect this year?

Only this year.

Okay. Thank you.

Dan Jenkins.

I was looking at your sales growth on a normalized basis in the quarter, the commercial and industrial were weaker than what they were in the first quarter. I was wondering if you could talk about that a little bit, what is going on.

Dan, I think what you really have to do is look at the year-to-date trend. You may recall on the last quarter I mentioned don't read too much into the stronger than anticipated sales that we saw in the first quarter 2006 compared to 2005. You're always going to have some noise in the system quarter to quarter. We were implementing last year a billing system. So that potentially can skew the data even more than you typically see quarter to quarter. So I would stick with the six-months trend as something more indicative of what we would expect for the full-year.

The 1.9 you would expect that would be more representative of what the second half would be like?

We haven't changed our assumption but that is, we do think that is far more indicative than the quarterly results.

Okay. Thank you.

(OPERATOR INSTRUCTIONS)

I understand that some of you have experienced some disconnects on the call today. We apologize for that. The call will be available for replay probably in a couple hours. So if you have any questions, you missed anything, just give Paula Johnson or myself a call.

I apologize for that, too, but I thank you for participating on the call today. And again, if you have any follow-up questions Dick and Paul will be here to help you. Thanks, everyone.

Ladies and gentlemen, this concludes today teleconference. You may now disconnect.