埃克西爾能源 (XEL) 2006 Q4 法說會逐字稿

I would like to welcome everyone to the Xcel Energy Fourth Quarter 2006 earning 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. [OPERATOR INSTRUCTIONS].

I will now turn the call over to Mr. Paul Johnson, Managing Director of Investor Relations. Please go ahead, sir.

Thank you, and welcome to Xcel Energy's 2006 year-end conference call. My name is Paul Johnson, Managing Director of Investor Relations. With me today is Ben Fowke, Vice President and CFO for Xcel Energy. We also have several others in the room available to answer your questions.

Today we plan to cover our year-end results, our regulatory progress, and some new projects that represent the expansion of our Build the Core strategy. I also want to point out that there are slides that are available on our web page that follow the presentation. Some of the comments that we make will contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and our energy filings with the SEC commission. With that, I'll turn it over to Ben Fowke.

Well, thanks, Paul, and welcome everyone. I'm pleased to report that 2006 earnings from continuing operations came in at the top of our guidance range at $1.35 per share. This compares with $1.20 per share for 2005. Coal earnings for 2006, which include the impact of discontinued operations, were $1.36 per share, compared with $1.23 per share for 2005. In 2006, we had $0.01 of earnings from discontinued operations due to a true-up of reserves or cost estimates for various asset sales. While in 2005, we had $0.03 of earnings from discontinued operations for tax benefits related to the divestiture of energy.

Our earnings from continuing operations increased by $0.15 per share for the year largely due to higher electric retail margins, which increased earnings by $0.33 per share; higher natural gas margins, which increased earnings by $0.04 per share; and other items that together increased earnings by about $0.01 per share. These positive factors were partially offset by higher utility O&M expenses, which decreased earnings by $0.09 per share; higher depreciation expense, which decreased earnings by $0.08 per share; and lower short-term wholesale margins, which decreased earnings by $0.06 per share. That summarizes the year-end results, so now let's look into the details.

Our base retail electric utility margins increased by $226 million or $0.33 per share for the year, largely driven by rate increases and sales growth. Electric margin grew by $208 million from various rate increases. This includes $129 million from the rate increase in Minnesota, $38 million from the MERP rider, and $31 million from an electric rate increase in Wisconsin. For the year, our weather adjusted electric retail sales growth was a solid 1.8%, which increased electric margin by $39 million.

Offsetting these positive drivers were several items that reduced electric margin. The first item was a $26 million transmission fee reclassification which moves certain expenses from O&M into cost of sales. While this reclassification has had no impact on net income, it does create a deviation in both electric margin and O&M expense. The second item was a $20 million decline in the PSCo electric commodity adjustment incentive, or the ECA. The ECA is both a cost recovery and an incentive mechanism in Colorado, which provides for a cap on any cost or benefit of approximately $11 million dollars. We experience an $11 million cost in 2006 while we recognized an ECA benefit of approximately $9 million in 2005. The ECA did expire at the end of 2006 and has been replaced with a more traditional cost recovery mechanism.

Finally, several reserves recorded for regulatory issues at SPS negatively affected electric margins. These reserves generally related to disputes regarding the use of system average fuel costs versus incremental cost. At this time, we feel we recorded the appropriate level of reserves for these issues. For more information on electric margin, please refer to the margin table in our earnings release. As expected, short-term wholesale margins declined by $43 million. The decline in margins reflect the implementation of customer sharing mechanisms, normal retail sales customer demand strength which reduces our surplus generation available for sales, and a reduction in the availability of a coal-fired tinge plant due to the MERP project.

Turning to operating expenses, O&M expenses increased approximately $64 million, or 3.8% in 2006, largely driven by higher employee benefit costs, which are primarily performance-based, and higher nuclear and combustion plant costs. These higher costs were partially offset by the reclassification of transmission fees, the establishment of a regulatory asset for private fuel storage costs, and gains on the disposal of certain assets. Moving on, depreciation expense increased $55 million, or 7.1% in 2006, driven by increased capital spending and changes in decommissioning accruals.

Finally, let me touch on taxes. In 2006, we recognized tax benefits of about $30 million related to the utilization of capital loss carry-forwards and the reversal of a regulatory reserve. In 2005, we recognized approximately $10 million of tax benefits that were also one-time in nature. So that's a more detailed look at 2006 results.

Next I'd like to provide a regulatory recap. Let's begin with the cases that we concluded in 2006. We reached constructive conclusions in our rate cases in both Colorado and Minnesota. The Minnesota decision increased rates in 2006, while the Colorado case will increase rates in 2007. These decisions provide us with regulatory certainty in our major jurisdictions. We also filed several cases in 2006 that will have impacts in 2007. In Minnesota, we requested an increase of $18.5 million, interim rates subject to refund were set at $15.9 million, and went into effect on January 8th. In Colorado, we requested an increase of $41.5 million. Colorado doesn't have interim rates, however we expect final rates to go into effect in the third quarter. In North Dakota, we requested an increase of $2.8 million, and we expect interim rates will be in place in early 2007. All three of these gas cases should be decided later this summer.

We also have a pending rate case in Texas, where we're seeking an electric rate increase of $48 million. In addition to the rate case, our 2004 through 2005 fuel reconciliation is being considered under the same docket, and we most recently filed our recommendations. In the base rate case, the recommendations range from a decrease of $56 million to a rate increase of $31 million, while recommendations related to fuel reconciliation have ranged from a disallowance of $8 million to a disallowance of $120 million. We just filed our rebuttal testimony, and hearings are expected to be held in February. Final rates are expected to be effective in the second quarter of 2007.

Looking ahead, later this spring, we will file our electric and natural gas rate cases in Wisconsin as required by law. Rates related to the Wisconsin cases will go into effect in 2008. That summarizes our regulatory developments.

I think you'll agree with me that 2006 was a positive and productive year on the regulatory front. As a result of the constructive regulatory environment in our major jurisdictions, we are expanding our Building the Core strategy. There are several projects that we're proposing that were not included in the capital expenditure forecast we published in the third quarter of 2006. The most significant project is an upgrade of our Sherco coal-fired plant in Minnesota. We're proposing to add 140 megawatts of capacity and reduce emissions by upgrading the environmental systems. This effort is similar to the MERP project at our King plant. The preliminary cost estimate is $900 million. With commission approval, construction would start in late 2008, and finish in 2012. We will file for a right of recovery mechanism in September and expect the Minnesota Commission to rule on the proposal in 2008.

Next, as you are probably aware, we are the largest retail provider of wind energy in the United States, in part because our service territory sits in the middle of wind alley. We currently have about 1300 megawatts of wind generation on our system. By the end of 2007, we expect to have 2800 megawatts under contract. For the most part, we don't own wind generation, as all but 25 megawatts of this generation is procured through power purchase agreements. However, we are proposing to spend $210 million to build 100-megawatt wind farm in Minnesota. If approved, we would expect to complete the project in 2009. This investment will be recovered through a renewable rider in Minnesota. Because of our environmental leadership, we are well-positioned to meet the various renewable energy standards being proposed by the states in our service territories. These standards also present us with investment opportunities for wind generation and also transmission. We think owning wind generation fits well into our Building the Core strategy.

Finally, we are proposing to develop a new natural gas transmission pipeline and storage system in Colorado through our WYCO partnership. The project will be regulated by FERC and is expected to go into commercial operation in 2009. We plan to invest approximately $145 million into WYCO over the next three years. WYCO will provide additional gas storage for our PSCo operations, and will provide a real benefit to our customers. Of these new projects I just discussed, all come with good regulatory recovery and will help meet our customer needs, while increasing earnings for our shareholders well into the next decade.

In summary, 2006 was an outstanding year. Our construction projects at both Comanche 3 and MERP remain on track with costs in line with our expectations. Construction on the King plant is now more than 85% complete, and the plant will come back online this spring. Our nuclear and fossil plants performed extremely well in 2006. In fact, our Monticello nuclear plant ran for 637 days straight, which set a new record for continuous operations at Xcel Energy. As you might have heard, the plant recently came back online after a minor forced outage.

We improved reliability by reducing [inaudible] from 99.5 minutes in 2005 to 79.2 minutes in 2006, which represents upper quartile performance. We reached constructive resolutions in our rate cases in Minnesota, Colorado, and Wisconsin. We delivered outstanding earnings results in 2006. We've positioned ourselves for a strong 2007, and we have -- we are reaffirming our earnings guidance for continuing operations of $1.35 to $1.45 per share. Finally, we expand our capital expenditure program to meet customer needs and to provide sustainable earnings growth into the next decade. So with that, let's open it up for questions.

[OPERATOR INSTRUCTIONS]. Callers are remind that had this Q&A session is for the financial analysts only. People asking questions from the media may contact the media relations department once the call has concluded. Your first question will come from the line of Charles Fishman with A.G. Edwards.

Good morning, if I take the last capital expenditure forecast, which was about $1.5 billion per year, I think, '08 through 2010, can I just add this new -- these new investment projects? Obviously assuming they're approved, roughly during that time period?

Yes, well remember, you can, Charles. Remember the Sherco upgrade in environmental retrofitting, the construction will go through 2012, so you've got to take it a little further out.

Okay. Now, I guess obviously that begs the question as far as the financing, are you still thinking equity-wise, just the drip is all you're going to need?

Yes, at this point, Charles, we haven't changed our financing plans. We'll obviously have to continue to assess and monitor that going forward, but while these projects are significant capital investments, and they will drive earnings, when you do you're modeling, you'll see that they start to come in as some of our other capital expenditures start to wind down from the MERP and Comanche 3 project. And they also come with I think very good recovery mechanisms, so no change at this point.

On the win project, what is the advantage to doing a BOT-type structure versus just -- it's just a desire for you to eventually have ownership in the wind instead of just power purchase agreements or -- can you give a little more color there?

Whether it's a BOT structure or any kind of different asset ownership structure, we think wind's going to be a big part of our generation portfolio going forward, and we think we're a logical owner for it. It's going to be important that it's done in a very coordinated fashion. We're looking at some RPS standards that are going to have to make sure that we also have adequate fossil backups. So this is really going to take a holistic approach. We think it's a good investment opportunity, we think we're going to have good recovery mechanisms in place. We're excited about owning more wind.

Okay, thank you.

[OPERATOR INSTRUCTIONS]. Your next question comes from the line of Tom O'Neill with Highbridge.

A quick question, I don't know that I've ever asked you this, just from a historical perspective, why is it that you guys have contracted for so much of the wind as opposed to build it? Just from a regulator's perspective, the price that you're talking about seems high. Just kind of curious what was driving that to be as high as it is. I know parts in the pipeline are pretty heavy with demand, but --

Tom, is your question why haven't we owned it in the past?

Yes. And then just sort of if -- as you propose it to a regulator, that price strikes me as high. I'm kind of curious, there's a diversity element and a renewables push.

Well, when you look at gas at $7, we -- it actually, particularly with the PDC credits, fits very nicely as a lease cost planning resource in most of our jurisdictions. You know we're in wind alley, and we have very rich wind resources. Some of the capacity factors out of the Dakotas are pushing 50% versus 25% to 30% where you get into other parts of the country. It does fit well as just a lease cost planning resource. The fact that we haven't owned it in the past, I think there's probably a number of reasons. But we certainly want to change that going forward and rebalance.

Okay. And the reasons in the past have been more your own as opposed to regulatory?

I think it's probably just been because it hasn't, until recently, been a significant part of the portfolio, and it certainly looks like it's going to be a much more significant part of the portfolio going forward. And we think it's important we have an ownership element there.

Okay.

Your next question comes from the line of Jeff Coviello with Duquesne Capital.

Hi, Jeff.

Jeff, your line is open, please proceed.

Operator, we might be having some problems with the sound quality.

Mr. Coviello, please press "star 1" again if you would like to ask your question. And at this time, there are no further questions.

Okay. I apologize for the participants on the call if we've had sound quality issues. Hopefully that's not the case, but I think there might be some issues. I want to thank everybody for participating on our call this morning. If you have any follow-up questions, Paul Johnson will be available to take your calls. I look forward to working with all of you as we look towards another great year in '07. Thank you.

Ladies and gentlemen, this does conclude the Xcel Energy fourth quarter 2006 earnings call. You may now disconnect.