Xcel Energy Q4 2005 Earnings Conference Call Transcript (XEL)

Xcel Energy (XEL)
Q4 2005 Earnings Conference Call
February 1st 2006, 10:00 AM.

Executives:

Benjamin Fowke, Vice President and CFO

Analysts:

David Parker, Robert W. Baird.
Paul Ridzon, Keybanc Capital Mkts/ McDonald
Stephen Hsang, Citigroup.
Maura Shaughnessy, MFS
Elisabeth Parrella, Merrill Lynch.

Presentation

Operator

And welcome to Xcel Energy’s Fourth Quarter 2005 Earnings Release Conference Call. With me today is Benjamin 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 in Xcel Energy filings with the Securities and Exchange commission. I will turn the call over to Ben.

Benjamin Fowke, Vice President and CFO

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 investments and a loss from the sale of Cheyenne Light Fuel and Power. Rest of my comments will be related to earnings from continuing operations.

At the core of our company, we have our utility 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 cost 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 of the holding company. That summarizes our 2005 results, now lets 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 have lower accruals for 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 that 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 opportunity.

Despite strong fourth quarter results, our 2006 guidance reflects projected short-term margins of $30 million to $50 million, which is a decline from the $86 million we’ve recorded in 2005. The anticipated decline is due to decreased opportunities resulting from the MISO Centralized 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 Merck project. In addition, as part of the Minnesota Electric Rate Case, we are proposing a short-term wholesale margin sharing mechanism to share risks 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 5.55% largely driven by higher benefit cost, 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 the benefit costs were increasing, we also noticed there would be two nuclear outages in 2005 compared with one in 2004. However, there was 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. Quarterly 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 cost which included approximately $10 million for additional maintenance at our power plants driven by the high demands during the summer. $7 million for executive transition cost and $5 million for charitable contributions that help customers pay their heating bills. We recognized 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 level. The increase is due to growth associated with normal system expansion and incremental depreciation for several large projects including the new steam generators of Prairie Island and the new billing systems. 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. Well that covers 2005 results. Next, I would 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 Minnesota Electric Case.

In May 2005, PSQ filed for $34 million natural gas rate increase based on ROE of 11%. In December 2005, PSQ and various interveners reached a settlement resolving all the issues in this proceeding. The Colorado commission approved $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 commission’s 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 $158 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 1st 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 an interim rate increase based on the prorated amount of $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 maybe required to recognize an estimated refund of a portion of the interim rate depending on facts and circumstances. Ultimately, there maybe a final revenue “true-up