Exhibit 99.01
| |
| |
| 414 Nicollet Mall |
| Minneapolis, MN 55401 |
August 1, 2006
INVESTOR RELATIONS EARNINGS RELEASE
XCEL ENERGY ANNOUNCES SECOND QUARTER 2006 EARNINGS
MINNEAPOLIS – Xcel Energy Inc. (NYSE: XEL) announced income from continuing operations of $98 million, or 24 cents per share on a diluted basis, for the second quarter of 2006, compared with $78 million, or 19 cents per share, in the second quarter of 2005.
Net income for the quarter, which includes the impact of discontinued operations, was $98 million, or 24 cents per share, in 2006, compared with $83 million, or 20 cents per share, in 2005.
Xcel Energy’s net income for the second quarter of 2006 included the following:
· Regulated utility income from continuing operations was $102 million, or 24 cents per share, compared with $94 million, or 22 cents per share, in 2005;
· Holding company loss from continuing operations was $1 million, or less than 1 cent per share, compared with a loss of $14 million, or 3 cents per share in 2005; and
· Income from discontinued operations was $0.3 million, or less than 1 cent per share, compared with income of $6 million, or 1 cent per share, in 2005.
Increased earnings for the second quarter of 2006 were primarily due to stronger base electric and natural gas utility margins, partially offset by lower short-term wholesale margins. The stronger utility margins reflect a natural gas rate increase in Colorado, an electric and natural gas rate increase in Wisconsin, an interim electric rate increase in Minnesota and revenue associated with the Metro Emissions Reduction Project.
“Our earnings growth for the quarter and first six months of the year demonstrate that our strategy is delivering the results we anticipated,” said Richard C. Kelly, chairman, president and chief executive officer. “Earnings growth is on track with our objectives, and we are reaffirming our 2006 earnings guidance of $1.25 to $1.35 per share.”
1
At 9 a.m. CDT today, Xcel Energy will host a conference call to review second quarter financial results. To participate in the conference call, please dial in five to 10 minutes prior to the scheduled start and follow the operator’s instructions.
US Dial-In: | (800) 374-0832 |
International Dial-In: | (706) 634-5081 |
The conference call also will be simultaneously broadcast and archived on Xcel Energy’s Web site at www.xcelenergy.com. To access the presentation, click on Investor Information. If you are unable to participate in the live event, the call will be available for replay from 12 p.m. CDT on Aug. 1 through 11:59 p.m. CDT on Aug. 4.
Replay Numbers
US Dial-In: | (800) 642-1687 |
International Dial-In: | (706) 645-9291 |
Conference ID: | 1450036 |
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership; structures that affect the speed and degree to which competition enters the electric and natural gas markets; the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; and the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Risk Factors in Item 1A and Exhibit 99.01 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005.
For more information, contact:
R J Kolkmann | Managing Director, Investor Relations | (612) 215-4559 |
P A Johnson | Director, Investor Relations | (612) 215-4535 |
|
For news media inquiries only, please call Xcel Energy media relations | (612) 215-5300 |
| | | |
Xcel Energy Internet address: www.xcelenergy.com
This information is not given in connection with any
sale, offer for sale or offer to buy any security.
2
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Thousands, Except Per Share Data)
| | Three months ended | | Six months ended | |
| | June 30, | | June 30, | |
| | 2006 | | 2005 | | 2006 | | 2005 | |
| | | | | | | | | |
Operating revenues: | | | | | | | | | |
Electric utility | | $ | 1,786,571 | | $ | 1,720,431 | | $ | 3,632,443 | | $ | 3,255,378 | |
Natural gas utility | | 270,990 | | 326,347 | | 1,289,130 | | 1,161,402 | |
Nonregulated and other | | 16,312 | | 17,277 | | 40,404 | | 37,808 | |
Total operating revenues | | 2,073,873 | | 2,064,055 | | 4,961,977 | | 4,454,588 | |
| | | | | | | | | |
Operating expenses: | | | | | | | | | |
Electric fuel and purchased power – utility | | 951,214 | | 912,400 | | 1,945,909 | | 1,673,809 | |
Cost of natural gas sold and transported – utility | | 168,822 | | 232,039 | | 1,019,247 | | 900,824 | |
Cost of sales – nonregulated and other | | 4,437 | | 5,158 | | 12,667 | | 13,418 | |
Other operating and maintenance expenses – utility | | 443,137 | | 437,639 | | 878,383 | | 840,109 | |
Other operating and maintenance expenses - nonregulated | | 6,614 | | 9,274 | | 12,178 | | 16,418 | |
Depreciation and amortization | | 203,665 | | 193,976 | | 406,325 | | 385,670 | |
Taxes (other than income taxes) | | 71,326 | | 71,334 | | 149,861 | | 147,086 | |
Total operating expenses | | 1,849,215 | | 1,861,820 | | 4,424,570 | | 3,977,334 | |
| | | | | | | | | |
Operating income | | 224,658 | | 202,235 | | 537,407 | | 477,254 | |
| | | | | | | | | |
Interest and other income (expense) – net | | 921 | | 4,516 | | 537 | | 2,442 | |
Allowance for funds used during construction – equity | | 4,668 | | 5,450 | | 8,452 | | 10,633 | |
| | | | | | | | | |
Interest charges and financing costs: | | | | | | | | | |
Interest charges – (includes other financing costs of $6,393, $6,418, $12,605 and $12,897, respectively) | | 119,283 | | 114,375 | | 238,657 | | 228,017 | |
Allowance for funds used during construction – debt | | (7,509 | ) | (4,534 | ) | (13,882 | ) | (9,368 | ) |
Total interest charges and financing costs | | 111,774 | | 109,841 | | 224,775 | | 218,649 | |
| | | | | | | | | |
Income from continuing operations before income taxes | | 118,473 | | 102,360 | | 321,621 | | 271,680 | |
Income taxes | | 20,537 | | 24,684 | | 73,873 | | 69,541 | |
Income from continuing operations | | 97,936 | | 77,676 | | 247,748 | | 202,139 | |
Income from discontinued operations – net of tax | | 339 | | 5,730 | | 1,825 | | 2,745 | |
Net income | | 98,275 | | 83,406 | | 249,573 | | 204,884 | |
Dividend requirements on preferred stock | | 1,060 | | 1,060 | | 2,120 | | 2,120 | |
Earnings available for common shareholders | | $ | 97,215 | | $ | 82,346 | | $ | 247,453 | | $ | 202,764 | |
| | | | | | | | | |
Weighted average common shares outstanding (in thousands): | | | | | | | | | |
Basic | | 405,434 | | 402,214 | | 404,783 | | 401,668 | |
Diluted | | 429,099 | | 425,552 | | 428,349 | | 425,004 | |
Earnings per share – basic: | | | | | | | | | |
Income from continuing operations | | $ | 0.24 | | $ | 0.19 | | $ | 0.61 | | $ | 0.50 | |
Income from discontinued operations | | ― | | 0.01 | | — | | — | |
Total | | $ | 0.24 | | $ | 0.20 | | $ | 0.61 | | $ | 0.50 | |
Earnings per share – diluted: | | | | | | | | | |
Income from continuing operations | | $ | 0.24 | | $ | 0.19 | | $ | 0.59 | | $ | 0.49 | |
Income from discontinued operations | | ― | | 0.01 | | 0.01 | | — | |
Total | | $ | 0.24 | | $ | 0.20 | | $ | 0.60 | | $ | 0.49 | |
3
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor Relations Release (Unaudited)
Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.
Note 1. Earnings per Share Summary
The following table summarizes the earnings-per-share contributions of Xcel Energy’s businesses.
| | Three months ended | | Six months ended | |
| | June 30, | | June 30, | |
| | 2006 | | 2005 | | 2006 | | 2005 | |
Earnings (Loss) Per Share | | | | | | | | | |
Regulated utility segments – continuing operations – Note 2 | | $ | 0.24 | | $ | 0.22 | | $ | 0.62 | | $ | 0.54 | |
Holding company costs and other | | ― | | (0.03 | ) | (0.03 | ) | (0.05 | ) |
Earnings per share – continuing operations | | 0.24 | | 0.19 | | 0.59 | | 0.49 | |
| | | | | | | | | |
Income (loss) from discontinued operations | | ― | | 0.01 | | 0.01 | | — | |
Total earnings per share – diluted | | $ | 0.24 | | $ | 0.20 | | $ | 0.60 | | $ | 0.49 | |
The reduction in holding company costs is due to the recognition of a tax benefit of $17 million for the second quarter and $18 million for the first six months of 2006 relating to capital loss carry-forwards that are now considered realizable, which offset increased financing costs. Previously, the tax benefits for the capital loss carry-forwards did not meet the recognition threshold under tax accounting requirements, due to the absence of likely capital gains, which provided the opportunity to make use of the capital loss carry-forwards.
The following table summarizes significant components contributing to the changes in the second quarter and year-to-date 2006 earnings per share compared with the same periods in 2005, which are discussed in more detail later in the release.
| | Three months ended | | Six months ended | |
| | June 30, | | June 30, | |
2005 Earnings per share — diluted | | $ | 0.20 | | $ | 0.49 | |
| | | | | |
Components of change – 2006 vs. 2005 | | | | | |
Higher base electric utility margins | | 0.10 | | 0.20 | |
Lower short-term wholesale and commodity trading margins | | (0.06 | ) | (0.05 | ) |
Higher depreciation and amortization expense | | (0.01 | ) | (0.03 | ) |
Higher utility operating and maintenance expense | | (0.01 | ) | (0.06 | ) |
Lower effective tax rate and other | | 0.03 | | 0.04 | |
Net change in earnings per share – continuing operations | | 0.05 | | 0.10 | |
| | | | | |
Changes in Earnings Per Share – Discontinued Operations | | (0.01 | ) | 0.01 | |
2006 Earnings per share – diluted | | $ | 0.24 | | $ | 0.60 | |
4
Note 2. Regulated Utility Segment Results – Continuing Operations
Estimated Impact of Temperature Changes on Regulated Earnings –The following summarizes the estimated impact of temperature variations on utility results included in continuing operations, compared with sales under normal weather conditions.
| | Earnings per Share Increase (Decrease) | |
| | 2006 vs. Normal | | 2005 vs. Normal | | 2006 vs. 2005 | |
3 months ended June 30 | | $ | 0.02 | | $ | 0.01 | | $ | 0.01 | |
6 months ended June 30 | | $ | (0.01 | ) | $ | 0.00 | | $ | (0.01 | ) |
Sales Growth – The following table summarizes Xcel Energy’s regulated utility growth from continuing operations for actual and weather-normalized energy sales for the three- and six-month periods ended June 30, 2006, compared with the same period in 2005.
| | Three months ended | | Six months ended | |
| | June 30, | | June 30, | |
| | Actual | | Normalized | | Actual | | Normalized | |
Electric residential | | 3.1 | % | 1.4 | % | 1.5 | % | 1.6 | % |
Electric commercial and industrial | | 2.1 | % | 0.4 | % | 2.7 | % | 1.9 | % |
Total retail electric sales | | 2.3 | % | 0.7 | % | 2.4 | % | 1.8 | % |
Firm natural gas sales | | (17.5 | )% | 0.1 | % | (8.0 | )% | (1.7 | )% |
Base Electric Utility, Short-term Wholesale and Commodity Trading Margins – The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities that are included in continuing operations.
(Millions of Dollars) | | Base
Electric
Utility | | Short-term
Wholesale | | Commodity
Trading | | Consolidated
Total | |
3 months ended 06/30/2006 | | | | | | | | | |
Electric utility revenue (excluding commodity trading) | | $ | 1,761 | | $ | 34 | | $ | — | | $ | 1,795 | |
Electric fuel and purchased power utility | | (913 | ) | (38 | ) | — | | (951 | ) |
Commodity trading revenue | | — | | — | | 119 | | 119 | |
Commodity trading costs | | — | | — | | (127 | ) | (127 | ) |
Gross margin before operating expenses | | $ | 848 | | $ | (4 | ) | $ | (8 | ) | $ | 836 | |
Margin as a percentage of revenue | | 48.2 | % | (11.8 | )% | (6.7 | )% | 43.7 | % |
| | | | | | | | | |
3 months ended 06/30/2005 | | | | | | | | | |
Electric utility revenue (excluding commodity trading) | | $ | 1,655 | | $ | 58 | | $ | — | | $ | 1,713 | |
Electric fuel and purchased power-utility | | (878 | ) | (34 | ) | — | | (912 | ) |
Commodity trading revenue | | — | | — | | 115 | | 115 | |
Commodity trading costs | | — | | — | | (108 | ) | (108 | ) |
Gross margin before operating expenses | | $ | 777 | | $ | 24 | | $ | 7 | | $ | 808 | |
Margin as a percentage of revenue | | 46.9 | % | 41.4 | % | 6.1 | % | 44.2 | % |
| | | | | | | | | |
6 months ended 06/30/2006 | | | | | | | | | |
Electric utility revenue (excluding commodity trading) | | $ | 3,555 | | $ | 72 | | $ | — | | $ | 3,627 | |
Electric fuel and purchased power utility | | (1,882 | ) | (64 | ) | — | | (1,946 | ) |
Commodity trading revenue | | — | | — | | 335 | | 335 | |
Commodity trading costs | | — | | — | | (329 | ) | (329 | ) |
Gross margin before operating expenses | | $ | 1,673 | | $ | 8 | | $ | 6 | | $ | 1,687 | |
Margin as a percentage of revenue | | 47.1 | % | 11.1 | % | 1.8 | % | 42.6 | % |
| | | | | | | | | |
6 months ended 06/30/2005 | | | | | | | | | |
Electric utility revenue (excluding commodity trading) | | $ | 3,157 | | $ | 91 | | $ | — | | $ | 3,248 | |
Electric fuel and purchased power-utility | | (1,622 | ) | (52 | ) | — | | (1,674 | ) |
Commodity trading revenue | | — | | — | | 232 | | 232 | |
Commodity trading costs | | — | | — | | (225 | ) | (225 | ) |
Gross margin before operating expenses | | $ | 1,535 | | $ | 39 | | $ | 7 | | $ | 1,581 | |
Margin as a percentage of revenue | | 48.6 | % | 42.9 | % | 3.0 | % | 45.4 | % |
Note – The short-term wholesale and commodity trading results in the above table reflect the estimated impacts of the regulatory sharing of certain margins.
5
Base electric utility margins, which are primarily derived from retail customer sales, increased approximately $71 million for the second quarter of 2006, compared with the second quarter of 2005. Base electric utility margins increased approximately $138 million for the first six months of 2006, compared with the same period in 2005. For more information see the following table.
Base Electric Utility Margin
| | Three months ended
June 30, | | Six months ended
June 30, | |
(Millions of Dollars) | | 2006 vs. 2005 | | 2006 vs. 2005 | |
NSP-Minnesota interim base rate changes, subject to refund | | $ | 40 | | $ | 65 | |
Sales growth (excluding weather impact) | | 4 | | 24 | |
Metro Emission Reduction Project rider | | 9 | | 18 | |
Firm wholesale | | 6 | | 14 | |
Conservation and non-fuel rider revenues | | 9 | | 13 | |
NSP-Wisconsin rate changes | | 5 | | 7 | |
Quality of service obligations | | 4 | | 6 | |
Purchased capacity costs | | (5 | ) | (6 | ) |
Estimated impact of weather | | 8 | | 4 | |
Other | | (9 | ) | (7 | ) |
Total base electric utility margin increase | | $ | 71 | | $ | 138 | |
On Jan. 1, 2006, an interim rate increase for NSP-Minnesota of $147 million, subject to refund, went into effect in Minnesota. In March 2006, the Minnesota Public Utilities Commission (MPUC) approved a new depreciation order, which lowered decommissioning accruals for 2006 from anticipated levels. Due to the seasonality of sales, the rate increase will not be recognized ratably throughout 2006.
Short-term wholesale margins consist of energy-related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from Xcel Energy’s generation assets and energy and capacity purchased to serve native load. Commodity trading margins are not associated with Xcel Energy’s generation assets or the capacity and energy purchased to serve native load.
Short-term wholesale and commodity trading margins decreased approximately $43 million and $32 million for the second quarter and first six months of 2006, respectively, compared with the same periods in 2005. As expected, short-term margins declined due to retail sales growth, which reduced surplus generation available for sale in the wholesale market, and decreased opportunities to sell due to the Midwest Independent Transmission System Operator (MISO) centralized dispatch market. In addition, during the second quarter of 2006 a $6 million charge was recorded to commodity trading margins for the estimated impact of a Federal Energy Regulatory Commission (FERC) order regarding the allocation of MISO charges to certain trading activities.
In addition, NSP-Minnesota entered into a wholesale electric sales margin settlement agreement in the second quarter of 2006 as part of the Minnesota rate case proceeding. The agreement is pending MPUC approval. The settlement agreement provides for a sharing of certain short-term wholesale and commodity trading margins with retail electric customers beginning Jan. 1, 2006. The three months ended June 30, 2006 short-term wholesale margin reflects approximately $13 million of year-to-date sharing adjustments, consistent with the proposed settlement agreement.
6
Natural Gas Utility Margins - The following table details the changes in natural gas utility revenue and margin. The cost of natural gas tends to vary with changing sales requirements and the unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.
| | Three Months Ended
June 30, | | Six Months Ended
June 30, | |
(Millions of dollars) | | 2006 | | 2005 | | 2006 | | 2005 | |
| | | | | | | | | |
Natural gas utility revenue | | $ | 271 | | $ | 326 | | $ | 1,289 | | $ | 1,161 | |
Cost of natural gas sold and transported | | (169 | ) | (232 | ) | (1,019 | ) | (901 | ) |
Natural gas utility margin | | $ | 102 | | $ | 94 | | $ | 270 | | $ | 260 | |
The following summarizes the components of the changes in natural gas margin for the three and six months ended June 30:
Natural Gas Margin
| | Three months
ended June 30, | | Six months ended
June 30, | |
(Millions of dollars) | | 2006 vs. 2005 | | 2006 vs. 2005 | |
Base rate changes – Colorado, Wisconsin | | $ | 8 | | $ | 12 | |
Transportation | | 2 | | 4 | |
Estimated impact of weather | | (5 | ) | (8 | ) |
Sales growth (decline) - excluding weather impact | | 4 | | (1 | ) |
Other | | (1 | ) | 3 | |
Total natural gas margin increase | | $ | 8 | | $ | 10 | |
Other Operating and Maintenance Expenses – Utility – Other operating and maintenance expenses for the second quarter of 2006 increased $5 million, or 1.3 percent, compared with the same period in 2005. Other operating and maintenance expenses for the first six months of 2006 increased $38 million, or 4.6 percent, compared with the same period in 2005. Employee benefit costs decreased approximately $7 million for the three months ended June 30, 2006 compared with the same period in 2005, primarily due to the year-to-date true ups to new actuarial estimates for pension, retiree medical and disability costs. For the six months ended June 30, 2006 compared with the same period in 2005, higher plant operating expenses were partially offset by lower nuclear plant outage costs. Such outage costs were lower due to two nuclear plant refueling, inspection and upgrade outages in 2005 compared with one refueling outage in the same period of 2006. For more information, see the following table:
| | Three months
ended June 30, | | Six months ended
June 30, | |
(Millions of Dollars) | | 2006 vs. 2005 | | 2006 vs. 2005 | |
Lower nuclear plant outage costs | | $ | ― | | (18 | ) |
Higher nuclear plant operating costs | | 5 | | 9 | |
Higher combustion/hydro plant costs | | 4 | | 11 | |
Higher vegetation management and damage prevention costs | | 3 | | 9 | |
(Lower) higher bad debt expense | | (3 | ) | 6 | |
(Lower) higher information technology costs | | (1 | ) | 4 | |
Higher conservation incentive program costs | | 2 | | 4 | |
Higher insurance costs | | ― | | 2 | |
Lower employee benefit costs | | (7 | ) | ― | |
Other | | 2 | | 11 | |
Total operating and maintenance expense increase | | $ | 5 | | $ | 38 | |
| | | | | | | |
7
Depreciation and Amortization – Depreciation and amortization expense increased by approximately $10 million, or 5.0 percent, for the second quarter, and $21 million, or 5.4 percent, for the first six months of 2006, compared with the same periods in 2005. The increase is due to normal plant additions and a recently approved change in decommissioning accruals resulting in an additional depreciation expense of $5 million for the quarter and $10 million year-to-date.
Income Taxes – Income taxes for continuing operations decreased by $4.1 million for the second quarter of 2006, compared with 2005. The effective tax rate for continuing operations was 17.3 percent for the second quarter of 2006, compared with 24.1 percent for the same period in 2005. The reduction in income taxes and in the effective tax rate was primarily due to the recognition of a tax benefit of $16.6 million during the second quarter of 2006 relating to capital loss carry forwards that are now considered realizable. Previously, such tax benefits did not meet the recognition threshold under tax accounting requirements, due to the absence of likely capital gains which provided the opportunity to make use of the capital loss carry forwards.
Income taxes for continuing operations increased by $4.3 million for the first six months of 2006, compared with 2005. The increase in income taxes was primarily due to an increase in pre-tax earnings, partially offset by a tax benefit of $17.5 million for the first six months of 2006 for capital loss carry forwards, as previously discussed. The effective tax rate for continuing operations was 23.0 percent for the first six months of 2006, compared with 25.6 percent for the same period in 2005. The reduction in the effective tax rate was primarily due to the tax benefit for capital loss carry forwards.
Note 3. Xcel Energy Capital Structure
The following is the preliminary capital structure of Xcel Energy at June 30, 2006:
(Billions of Dollars) | | Balance at
June 30, 2006 | | Percentage of
Total
Capitalization | |
Current portion of long-term debt | | $ | 0.8 | | 6 | % |
Short-term debt | | 0.1 | | 1 | % |
Long-term debt | | 6.2 | | 49 | % |
Total debt | | 7.1 | | 56 | % |
| | | | | |
Preferred equity | | 0.1 | | 1 | % |
Common equity | | 5.6 | | 43 | % |
Total equity | | 5.7 | | 44 | % |
| | | | | |
Total capitalization | | $ | 12.8 | | 100 | % |
8
Note 4. Rates and Regulation
NSP-Minnesota Electric Rate Case – NSP-Minnesota has requested an electric rate increase in Minnesota of $156 million, based on a requested 11 percent return on common equity, a projected equity ratio of 51.7 percent and a projected electric rate base of $3.2 billion. The interim rates are subject to refund pending a final order from the MPUC.
On April 24, 2006, NSP-Minnesota reached a settlement agreement regarding the treatment of wholesale electric sales margins. The settlement is with five intervenor groups, including the Office of Attorney General and a large industrial customer group. The settlement resolves recommendations of most parties regarding the treatment of wholesale electric sales margins. The settlement agreement is pending approval by the MPUC and will be considered in the MPUC’s determination of NSP-Minnesota’s overall requested increase.
On July 6, 2006, the administrative law judge (ALJ) recommended an overall increase in revenues for the 2006 test year of approximately $135 million. For 2007, the ALJ recommended the increase be revised downward to $119 million to reflect the increased revenues expected due to the return of Flint Hills, an oil refinery, as a full-requirements customer. The MPUC is expected to hold oral arguments in August, 2006, and issue its final order in September, 2006.
Public Service Co. of Colorado (PSCo) Electric Rate Case – On April 14, 2006, PSCo filed with the Colorado Public Utilities Commission (CPUC) to increase electricity rates by $210 million annually, beginning Jan. 1, 2007. The request is based on a return on equity of 11 percent, an equity ratio of 59.9 percent and electric rate base of $3.4 billion. No interim rate increase has been implemented. The expected procedural schedule is listed below. A decision is expected by the end of the year.
· | Intervenor Testimony | Aug. 18 |
· | Rebuttal Testimony | Sept. 29 |
· | Hearings | Oct. 23 through Nov. 9 |
· | Statement of Position | Nov. 20 |
· | Deliberations | Dec. 1 |
· | Initial Decision | Dec. 18 |
Southwestern Public Service Co. (SPS)-Texas Electric Rate Case - On May 31, 2006, SPS filed a Texas retail electric rate case requesting an increase in annual revenues of approximately $48 million, or 6.0 percent. The rate filing is based on a historical test year, an electric rate base of $943 million, a requested return on equity of 11.6 percent and a common equity ratio of 51.1 percent. Final rates are expected to be effective in the first quarter of 2007. No interim rate increase has been implemented. Following is the expected procedural schedule.
· | Intervenor Testimony | Oct. 24 and 31, 2006 |
· | PUCT Staff Testimony | Nov. 7, 2006 |
· | Hearings | Nov. 28 – Dec. 21, 2006 |
· | Proposal for Decision | To be determined |
· | Agreed Jurisdictional Deadline | March 2, 2007 |
SPS Wholesale Customer Complaints - In November 2004, several wholesale customers of SPS filed a rate complaint with the FERC. On May 24, 2006, a FERC ALJ issued an initial recommendation in the proceeding. The FERC will review the initial recommendation and issue a final order. SPS and others have filed exceptions to the ALJ’s initial recommendation. FERC’s order may or may not follow any of the ALJ’s recommendation.
In the recommendation decision, the ALJ resolved a number of disputed cost of service issues and ordered a compliance filing to determine the extent to which base revenues recovered under currently effective rates for the period beginning Jan. 1, 2005, through June 30, 2006 should be refunded to wholesale customers. The ALJ also
9
found that SPS should recalculate its fuel cost adjustment clause (FCAC) billings for the period beginning Jan. 1, 1999, to reduce the fuel and purchased power costs recovered from the complaining customers by allocating incremental fuel costs incurred by SPS in making wholesale sales of system firm capacity and associated energy to other firm customers at market-based rates during this period based on the view that such sales should be treated as opportunity sales.
SPS believes the ALJ has erred on significant and material issues that contradict FERC policy or rules of law. Specifically, SPS believes, based on FERC rules and precedent, that it has appropriately applied its FCAC tariff to the proper classes of customers. These sales were of a long-term duration under FERC precedent and were made from SPS’ entire system. Accordingly, SPS believes that the ALJ erred in concluding that these transactions were opportunity sales, which require the assignment of incremental costs.
The FERC has approved system average cost allocation treatment in previous filings by SPS for sales having similar service characteristics and previously accepted for filing certain of the challenged agreements with average fuel cost pricing. The ALJ failed to acknowledge either factor.
Moreover, SPS believes that the ALJ’s recommendation constituted a violation of the Filed Rate Doctrine in that it effectively results in a retroactive amendment to the SPS FERC-approved FCAC tariff provisions. Under existing rules of law and FERC regulations, the FERC may modify a previously approved FCAC on a prospective basis. Accordingly, SPS believes it has applied its FCAC correctly and has sought review of the recommended decision by the FERC by filing a brief on the exceptions.
Based on FERC’s regulations and rules of law, SPS has evaluated all sales made from Jan. 1, 1999, to Dec. 31, 2005. Relying on this assessment, SPS has accrued approximately $7 million, of which $4 million was recorded in the second quarter of 2006, related to both the base-rate and fuel items. Notwithstanding that, SPS believes that it should ultimately prevail in this proceeding. However, if the FERC were to adopt the majority of the ALJ’s recommendations, the ultimate impact could be approximately $50 million.
On Sept. 15, 2005, Public Service Company of New Mexico (PNM) filed a separate complaint at the FERC in which it contended that its demand charge under an existing interruptible power supply contract with SPS is excessive and that SPS has overcharged PNM for fuel costs under three separate agreements through erroneous FCAC calculations. PNM’s arguments mirror those that it made as an intervenor in the cooperatives’ complaint case, and SPS believes that they have little merit. SPS submitted a response to PNM’s complaint in October 2005. In November 2005, the FERC accepted PNM’s complaint. Hearings have been scheduled for December 2006. Based on the fact that many of these issues are already being reviewed by the FERC in the complaint case filed by the cooperatives discussed above, the current status and expected outcome of this proceeding, SPS does not anticipate any additional liability.
Note 5. CapX 2020
In June 2006, CapX 2020, an alliance of electric cooperatives, municipals and investor-owned utilities including Xcel Energy, announced that it had identified three groups of transmission projects that it would propose to complete by 2020.
Group 1 project investments are expected to total approximately $1.3 billion, with major construction targeted to begin in 2009 or 2010 and ending three or four years later. Xcel Energy’s investment is expected to be approximately $700 million. The approximate lengths and general locations of the proposed lines in Group 1 are as follows:
· A 200-mile, 345-kilovolt line between Brookings, S.D., and the southeast Twin Cities, plus a related 30-mile, 345-kilovolt line between Marshall, Minn., and Granite Falls, Minn.;
· A 200-mile, 345-kilovolt line between Fargo, N.D., and the St. Cloud/Monticello, Minn., area;
10
· A 150-mile, 345-kilovolt line between the Twin Cities, Rochester, Minn., and La Crosse, Wis., and
· A 70-mile, 230-kilovolt line in the Bemidji area of north central Minnesota
The Group 1 transmission projects will require certificates of need and route permits. CapX 2020 plans to seek certificates of need in a consolidated filing by the end of 2006. The process to obtain a certificate of need typically takes 15 to 18 months for projects of this magnitude. The CapX2020 utilities plan to then seek route permits separately.
Before a certificate of need application can be filed, a plan for providing notice to those potentially affected must be filed and approved. In June 2006, CapX 2020 filed a notice plan in Minnesota. It is anticipated that the earliest route permit applications will be filed would be the fall of 2007. Final route permit decisions will likely be made six to12 months after a certificate of need is granted.
Xcel Energy’s capital expenditures and return on investment for transmission projects are expected to be recovered under a transmission rider mechanism authorized by Minnesota legislation.
Note 6. Xcel Energy Earnings Guidance
2006 Earnings Guidance – Xcel Energy’s 2006 earnings per share from continuing operations guidance and key assumptions are detailed in the following table.
| | 2006 Diluted EPS Range | |
Utility operations | | $1.25 - $1.35 | |
COLI tax benefit | | $0.10 | |
Holding company financing costs and other | | $(0.10) | |
Xcel Energy Continuing Operations – EPS | | $1.25 - $1.35 | |
Key Assumptions for 2006:
· Normal weather patterns are experienced for the remainder of the year;
· Reasonable rate recovery is approved in the Minnesota electric rate case;
· Weather-adjusted retail electric utility sales grow by approximately 1.3 percent to 1.7 percent;
· Weather-adjusted retail natural gas utility sales decline by approximately 0.0 percent to 2.0 percent;
· Short-term wholesale and commodity trading margins are within a range of $10 million to $30 million, which reflects sharing of margins in Minnesota under the proposed settlement agreement;
· Utility operating and maintenance expenses increase between 3 percent and 4 percent from 2005 levels;
· Depreciation expense increases approximately $50 million to $60 million, excluding decommissioning;
· Decommissioning accruals increase approximately $20 million, reflecting recent regulatory decisions in Minnesota and Wisconsin;
· No material incremental accruals related to the SPS wholesale FERC complaint;
· Interest expense increases approximately $20 million to $25 million from 2005 levels;
· Allowance for funds used during construction recorded for equity financing increases approximately $8 million to $12 million from 2005 levels;
· Xcel Energy continues to recognize corporate-owned life insurance tax benefits, which is currently being litigated with the Internal Revenue Service;
· The effective tax rate for continuing operations is approximately 24 percent to 26 percent; and
· Average common stock and equivalents total approximately 429 million shares, based on the “If Converted” method for convertible notes.
11
XCEL ENERGY INC. AND SUBSIDIARIES
UNAUDITED EARNINGS RELEASE SUMMARY
All dollars in thousands, except earnings per share
Three months ended June 30, | | 2006 | | 2005 | |
Operating revenue: | | | | | |
Electric and natural gas utility revenue, and trading margins | | $ | 2,057,561 | | $ | 2,046,778 | |
Nonregulated and other revenue | | 16,312 | | 17,277 | |
Total revenue | | $ | 2,073,873 | | $ | 2,064,055 | |
| | | | | |
Income from continuing operations | | $ | 97,936 | | $ | 77,676 | |
Income from discontinued operations | | 339 | | 5,730 | |
Net income | | $ | 98,275 | | $ | 83,406 | |
| | | | | |
Earnings available for common shareholders | | $ | 97,215 | | $ | 82,346 | |
Average shares – common and potentially dilutive (1000’s) | | 429,099 | | 425,552 | |
| | | | | |
Segments and Components of Earnings per share – diluted | | | | | |
Utility earnings – continuing operations | | $ | 0.24 | | $ | 0.22 | |
Losses from nonregulated subsidiaries and holding company | | ― | | (0.03 | ) |
Earnings per share - continuing operations | | 0.24 | | 0.19 | |
| | | | | |
Discontinued operations | | ― | | 0.01 | |
| | | | | |
Total earnings per share – GAAP | | $ | 0.24 | | $ | 0.20 | |
Six months ended June 30, | | 2006 | | 2005 | |
Operating revenue: | | | | | |
Electric and natural gas utility revenue, and trading margins | | $ | 4,921,573 | | $ | 4,416,780 | |
Nonregulated and other revenue | | 40,404 | | 37,808 | |
Total revenue | | $ | 4,961,977 | | $ | 4,454,588 | |
| | | | | |
Income from continuing operations | | $ | 247,748 | | $ | 202,139 | |
Income from discontinued operations | | 1,825 | | 2,745 | |
Net income | | $ | 249,573 | | $ | 204,884 | |
| | | | | |
Earnings available for common shareholders | | $ | 247,453 | | $ | 202,764 | |
Average shares – common and potentially dilutive (1000’s) | | 428,349 | | 425,004 | |
| | | | | |
Segments and Components of Earnings per share – diluted | | | | | |
Utility earnings – continuing operations | | $ | 0.62 | | $ | 0.54 | |
Losses from nonregulated subsidiaries and holding company | | (0.03 | ) | (0.05 | ) |
Earnings per share - continuing operations | | 0.59 | | 0.49 | |
| | | | | |
Discontinued operations | | 0.01 | | — | |
| | | | | |
Total earnings per share – GAAP | | $ | 0.60 | | $ | 0.49 | |
| | | | | |
Book value per share | | $ | 13.70 | | $ | 13.04 | |
12
