Exhibit 99.01
414 Nicollet Mall
Minneapolis, MN 55401
July 25, 2007
INVESTOR RELATIONS EARNINGS RELEASE
XCEL ENERGY ANNOUNCES SECOND QUARTER 2007 EARNINGS
MINNEAPOLIS – Xcel Energy Inc. (NYSE: XEL) announced income from continuing operations of $124 million, or 29 cents per share on a diluted basis, for the second quarter of 2007, compared with $98 million, or 24 cents per share, in the second quarter of 2006.
Net income for the quarter, which includes the impact of discontinued operations, was $76 million, or 18 cents per share, in 2007, compared with $98 million, or 24 cents per share, in 2006.
Xcel Energy’s total earnings for the second quarter of 2007 included the following:
· Regulated utility earnings from continuing operations were $140 million, or 32 cents per share, compared with $102 million, or 24 cents per share, in 2006.
· Holding company and other costs from continuing operations were $14 million, or 3 cents per share, compared with costs of $1 million, or less than 1 cent per share in 2006.
· Results from discontinued operations for 2007 was a loss of $48 million, or 11 cents per share, compared with earnings of $0.2 million, or less than 1 cent per share, in 2006. The 2007 loss reflects the impact of the proposed settlement with the IRS regarding disputes associated with our corporate-owned life insurance (COLI) policies.
Higher second quarter 2007 earnings from continuing operations were primarily attributable to higher electric margin, reflecting the positive impact of the January 2007 Colorado rate increase and improved short term wholesale and trading margins. Additionally, lower operating and maintenance expenses, resulting from lower second quarter 2007 nuclear plant outage costs associated with the timing of plant refueling, as well as lower employee benefit costs also contributed to the higher current period earnings.
“We’ve had an excellent quarter on many fronts,” said Richard C. Kelly, chairman, president and chief executive officer. “We reached a positive settlement with the Internal Revenue Service (IRS) regarding our company-owned life insurance dispute. We received constructive decisions in our natural gas rate cases in Colorado and North Dakota. We completed the environmental upgrade of our King plant. We reached an agreement to build a 100-Mw wind farm in Minnesota. Finally, we recorded outstanding financial results from continuing operations for the quarter.”
“Based on our year-to-date progress and expectations for the remainder of the year, we are positioned to deliver earnings from continuing operations at the upper end or potentially exceeding our guidance range of $1.30 to $1.40 per share.”
1
At 9 a.m. CDT today, Xcel Energy will host a conference call to review first 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) 219-6110 |
International Dial-In: | (303) 262-2141 |
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 11 a.m. CDT on July 25 through 11:59 p.m. CDT on July 27.
Replay Numbers
US Dial-In: | (800) 405-2236 |
International Dial-In: | (303) 590-3000 |
Access Code: | 11092066 |
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; 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, 2006.
For more information, contact:
Paul Johnson, Managing Director, Investor Relations |
| (612) 215-4535 |
Jack Nielsen, Director, Investor Relations |
| (612) 215-4559 |
Cindy Hoffman, Senior Investor Relations Analyst |
| (612) 215-4536 |
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For news media inquiries only, please call Xcel Energy media relations Xcel Energy Internet address: www.xcelenergy.com |
| (612) 215-5300 |
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 of Dollars, Except Per Share Data)
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| June 30, |
| June 30, |
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| 2007 |
| 2006 |
| 2007 |
| 2006 |
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Operating revenues: |
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Electric utility |
| $ | 1,919,695 |
| $ | 1,786,571 |
| $ | 3,735,498 |
| $ | 3,632,443 |
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Natural gas utility |
| 330,868 |
| 270,990 |
| 1,258,290 |
| 1,289,130 |
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Nonregulated and other |
| 16,729 |
| 16,312 |
| 37,166 |
| 40,404 |
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Total operating revenues |
| 2,267,292 |
| 2,073,873 |
| 5,030,954 |
| 4,961,977 |
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Operating expenses: |
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Electric fuel and purchased power – utility |
| 1,031,899 |
| 951,214 |
| 2,011,470 |
| 1,945,909 |
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Cost of natural gas sold and transported – utility |
| 219,574 |
| 168,822 |
| 960,356 |
| 1,019,247 |
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Cost of sales – nonregulated and other |
| 3,702 |
| 4,437 |
| 9,727 |
| 12,667 |
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Other operating and maintenance expenses – utility |
| 434,912 |
| 442,093 |
| 895,335 |
| 876,363 |
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Other operating and maintenance expenses - nonregulated |
| 5,728 |
| 6,614 |
| 12,031 |
| 12,178 |
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Depreciation and amortization |
| 214,694 |
| 203,665 |
| 428,107 |
| 406,325 |
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Taxes (other than income taxes) |
| 66,236 |
| 71,325 |
| 144,411 |
| 149,859 |
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Total operating expenses |
| 1,976,745 |
| 1,848,170 |
| 4,461,437 |
| 4,422,548 |
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Operating income |
| 290,547 |
| 225,703 |
| 569,517 |
| 539,429 |
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Interest and other income, net of nonoperating expenses |
| 4,373 |
| 6,651 |
| 9,055 |
| 10,393 |
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Allowance for funds used during construction – equity |
| 8,695 |
| 4,668 |
| 16,271 |
| 8,452 |
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Interest charges and financing costs: |
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Interest charges – (includes other financing costs of $5,343, $6,393, $11,594 and $12,605, respectively) |
| 125,672 |
| 119,208 |
| 252,975 |
| 238,582 |
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Allowance for funds used during construction – debt |
| (8,442 | ) | (7,509 | ) | (15,648 | ) | (13,882 | ) | ||||
Total interest charges and financing costs |
| 117,230 |
| 111,699 |
| 237,327 |
| 224,700 |
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Income from continuing operations before income taxes |
| 186,385 |
| 125,323 |
| 357,516 |
| 333,574 |
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Income taxes |
| 62,282 |
| 27,234 |
| 119,233 |
| 92,366 |
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Income from continuing operations |
| 124,103 |
| 98,089 |
| 238,283 |
| 241,208 |
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Income from discontinued operations, net of tax |
| (48,102 | ) | 186 |
| (42,571 | ) | 8,365 |
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Net income |
| 76,001 |
| 98,275 |
| 195,712 |
| 249,573 |
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Dividend requirements on preferred stock |
| 1,060 |
| 1,060 |
| 2,120 |
| 2,120 |
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Earnings available for common shareholders |
| $ | 74,941 |
| $ | 97,215 |
| $ | 193,592 |
| $ | 247,453 |
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Weighted average common shares outstanding (in thousands): |
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Basic |
| 412,710 |
| 405,434 |
| 410,370 |
| 404,783 |
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Diluted |
| 432,861 |
| 429,099 |
| 432,471 |
| 428,349 |
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Earnings per share – basic: |
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Income from continuing operations |
| $ | 0.30 |
| $ | 0.24 |
| $ | 0.58 |
| $ | 0.59 |
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Income (loss) from discontinued operations |
| (0.12 | ) | — |
| (0.11 | ) | 0.02 |
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Total |
| $ | 0.18 |
| $ | 0.24 |
| $ | 0.47 |
| $ | 0.61 |
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Earnings per share – diluted: |
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Income from continuing operations |
| $ | 0.29 |
| $ | 0.24 |
| $ | 0.56 |
| $ | 0.58 |
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Income (loss) from discontinued operations |
| (0.11 | ) | — |
| (0.10 | ) | 0.02 |
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Total |
| $ | 0.18 |
| $ | 0.24 |
| $ | 0.46 |
| $ | 0.60 |
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Cash dividends declared per common share |
| $ | 0.23 |
| $ | 0.22 |
| $ | 0.45 |
| $ | 0.44 |
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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 diluted earnings per share contributions of Xcel Energy’s businesses.
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| 2007 |
| 2006 |
| 2007 |
| 2006 |
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Diluted Earnings (Loss) Per Share |
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Regulated utility segments – continuing operations – Note 2 |
| $ | 0.32 |
| $ | 0.24 |
| $ | 0.65 |
| $ | 0.62 |
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Holding company and other costs |
| (0.03 | ) | — |
| (0.09 | ) | (0.04 | ) | ||||
Earnings per share – continuing operations |
| 0.29 |
| 0.24 |
| 0.56 |
| 0.58 |
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Income (loss) from discontinued operations – Note 3 |
| (0.11 | ) | — |
| (0.10 | ) | 0.02 |
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Total earnings per share |
| $ | 0.18 |
| $ | 0.24 |
| $ | 0.46 |
| $ | 0.60 |
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Holding company and other costs increased in the current period primarily due to the recognition of a $17 million tax benefit in the second quarter of 2006 related to capital loss carry forwards offsetting financing costs.
The following table summarizes significant components contributing to the changes in the second quarter of 2007 diluted earnings per share compared with the same period in 2006, which are discussed in more detail later in the release.
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2006 Earnings per share |
| $ | 0.24 |
| $ | 0.60 |
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Components of change – 2007 vs. 2006 |
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Higher base electric utility margins |
| 0.05 |
| 0.05 |
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Higher short-term wholesale and commodity trading margins |
| 0.02 |
| — |
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Lower (higher) utility operating and maintenance expense |
| 0.01 |
| (0.03 | ) | ||
Higher natural gas margins |
| 0.01 |
| 0.04 |
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Higher depreciation and amortization expense |
| (0.02 | ) | (0.03 | ) | ||
Higher effective tax rate and other |
| (0.02 | ) | (0.05 | ) | ||
Net change in earnings per share – continuing operations |
| 0.05 |
| (0.02 | ) | ||
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Changes in Earnings Per Share – Discontinued Operations |
| (0.11 | ) | (0.12 | ) | ||
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2007 Earnings per share |
| $ | 0.18 |
| $ | 0.46 |
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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.
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| 2007 vs. |
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| 2007 vs. |
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Retail electric |
| $ | 0.01 |
| $ | 0.03 |
| $ | (0.02 | ) | $ | 0.01 |
| $ | 0.01 |
| $ | — |
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Firm natural gas |
| — |
| (0.01 | ) | 0.01 |
| — |
| (0.02 | ) | 0.02 |
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Total |
| $ | 0.01 |
| $ | 0.02 |
| $ | (0.01 | ) | $ | 0.01 |
| $ | (0.01 | ) | $ | 0.02 |
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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, 2007, compared with the same period in 2006.
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| Actual |
| Normalized |
| Actual |
| Normalized |
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Electric residential |
| (1.5 | )% | 1.3 | % | 2.1 | % | 1.5 | % |
Electric commercial and industrial |
| 0.6 | % | 2.0 | % | 1.2 | % | 1.7 | % |
Total retail electric sales |
| 0.0 | % | 1.8 | % | 1.4 | % | 1.6 | % |
Firm natural gas sales |
| 19.7 | % | 2.7 | % | 14.9 | % | 1.9 | % |
Base Electric Utility, Short-term Wholesale and Commodity Trading Margins – The following table details the revenues and margin for base electric utility, short-term wholesale and commodity trading activities that are included in continuing operations:
(Millions of Dollars) |
| Base |
| Short-term |
| Commodity |
| Consolidated |
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3 months ended June 30, 2007 |
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Electric utility revenues (excluding commodity trading) |
| $ | 1,864 |
| $ | 57 |
| $ | — |
| $ | 1,921 |
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Electric fuel and purchased power utility |
| (980 | ) | (52 | ) | — |
| (1,032 | ) | ||||
Commodity trading revenues |
| — |
| — |
| 76 |
| 76 |
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Commodity trading expenses |
| — |
| — |
| (77 | ) | (77 | ) | ||||
Gross margin before operating expenses |
| $ | 884 |
| $ | 5 |
| $ | (1 | ) | $ | 888 |
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Margin as a percentage of revenues |
| 47.4 | % | 8.8 | % | (1.3 | )% | 44.5 | % | ||||
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3 months ended June 30, 2006 |
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Electric utility revenues (excluding commodity trading) |
| $ | 1,761 |
| $ | 34 |
| $ | — |
| $ | 1,795 |
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Electric fuel and purchased power-utility |
| (913 | ) | (38 | ) | — |
| (951 | ) | ||||
Commodity trading revenues |
| — |
| — |
| 119 |
| 119 |
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Commodity trading expenses |
| — |
| — |
| (127 | ) | (127 | ) | ||||
Gross margin before operating expenses |
| $ | 848 |
| $ | (4 | ) | $ | (8 | ) | $ | 836 |
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Margin as a percentage of revenues |
| 48.2 | % | (11.8 | )% | (6.7 | )% | 43.7 | % | ||||
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6 months ended June 30, 2007 |
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Electric utility revenues (excluding commodity trading) |
| $ | 3,616 |
| $ | 115 |
| $ | — |
| $ | 3,731 |
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Electric fuel and purchased power utility |
| (1,905 | ) | (106 | ) | — |
| (2,011 | ) | ||||
Commodity trading revenues |
| — |
| — |
| 153 |
| 153 |
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Commodity trading expenses |
| — |
| — |
| (149 | ) | (149 | ) | ||||
Gross margin before operating expenses |
| $ | 1,711 |
| $ | 9 |
| $ | 4 |
| $ | 1,724 |
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Margin as a percentage of revenues |
| 47.3 | % | 7.8 | % | 2.6 | % | 44.4 | % | ||||
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6 months ended June 30, /2006 |
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Electric utility revenues (excluding commodity trading) |
| $ | 3,555 |
| $ | 72 |
| $ | — |
| $ | 3,627 |
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Electric fuel and purchased power-utility |
| (1,882 | ) | (64 | ) | — |
| (1,946 | ) | ||||
Commodity trading revenues |
| — |
| — |
| 335 |
| 335 |
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Commodity trading expenses |
| — |
| — |
| (329 | ) | (329 | ) | ||||
Gross margin before operating expenses |
| $ | 1,673 |
| $ | 8 |
| $ | 6 |
| $ | 1,687 |
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Margin as a percentage of revenues |
| 47.1 | % | 11.1 | % | 1.8 | % | 42.6 | % | ||||
5
Note – The short-term wholesale and commodity trading results in the above table reflect the estimated impacts of the regulatory sharing of certain margins.
Base Electric Utility Margin
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(Millions of Dollars) |
| 2007 vs. 2006 |
| 2007 vs. 2006 |
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Public Service Co – Colorado (PSCo) electric retail rate increase |
| $ | 26 |
| $ | 54 |
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Sales growth (excluding weather impact) |
| 16 |
| 25 |
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Metro Emission Reduction Project rider |
| 7 |
| 14 |
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SPS 2006 fuel recovery |
| 7 |
| — |
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NSP-Wisconsin fuel and purchased power cost recovery |
| (9 | ) | (19 | ) | ||
Estimated impact of weather |
| (7 | ) | 3 |
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Transmission fee classification change |
| (6 | ) | (11 | ) | ||
SPS potential regulatory settlements |
| — |
| (13 | ) | ||
Other, including sales mix, other fuel recovery and purchased capacity costs |
| 2 |
| (15 | ) | ||
Total increase in base electric utility margin |
| $ | 36 |
| $ | 38 |
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Short-Term Wholesale Margin
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 increased $16 million during the current quarter and were flat for the first six months of 2007, respectively, when compared to the same periods in 2006. The improved margins are, in part, attributable to the second quarter 2006 recognition of a $6 million change associated with the estimated impact of a Federal Energy Regulatory Commission order regarding the allocation of Midwest Independent Transmission System Operator charges to certain trading activities.
In addition, during the second quarter of 2006, NSP-Minnesota entered into a wholesale electric sales margin settlement agreement as part of the Minnesota rate case proceeding. The settlement agreement provided for a sharing of certain short-term wholesale and commodity trading margins with retail electric customers beginning Jan. 1, 2006.
Natural Gas Utility Margins - The following table details the changes in natural gas utility revenues 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.
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| Three Months Ended |
| Six Months Ended |
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(Millions of dollars) |
| 2007 |
| 2006 |
| 2007 |
| 2006 |
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Natural gas utility revenues |
| $ | 331 |
| $ | 271 |
| $ | 1,258 |
| $ | 1,289 |
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Cost of natural gas sold and transported |
| (220 | ) | (169 | ) | (960 | ) | (1,019 | ) | ||||
Natural gas utility margin |
| $ | 111 |
| $ | 102 |
| $ | 298 |
| $ | 270 |
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The following summarizes the components of the changes in natural gas margin for the three and six months ended June 30:
6
Natural Gas Margin
| Three months |
| Six months |
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(Millions of dollars) |
| 2007 vs. 2006 |
| 2007 vs. 2006 |
| ||
Base rate changes – Minnesota (interim), North Dakota |
| $ | 4 |
| $ | 8 |
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Estimated impact of weather |
| 3 |
| 13 |
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Sales growth - excluding weather impact |
| 1 |
| 3 |
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Transportation |
| — |
| 1 |
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Other, including late payment fees and other miscellaneous revenue |
| 1 |
| 3 |
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Total increase in natural gas margin |
| $ | 9 |
| $ | 28 |
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Other Operating and Maintenance Expenses – Utility – Other operating and maintenance expenses for the second quarter of 2007 decreased by approximately $7 million, or 1.6 percent, compared with the same period in 2006. Other operating and maintenance expenses for the first six months of 2007 increased $19 million, or 2.2 percent, compared with the same period in 2006. For more information see the following table:
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| Three months |
| Six months ended |
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(Millions of Dollars) |
| 2007 vs. 2006 |
| 2007 vs. 2006 |
| ||
Higher (lower) nuclear plant outage costs |
| $ | (12 | ) | 2 |
| |
Lower employee benefit costs |
| (12 | ) | (7 | ) | ||
Transmission fee classification change |
| (6 | ) | (11 | ) | ||
Higher combustion/hydro plant costs |
| 7 |
| 14 |
| ||
Higher labor costs |
| 5 |
| 8 |
| ||
Higher nuclear plant operation costs |
| 3 |
| 10 |
| ||
Higher material costs |
| 3 |
| 3 |
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Higher uncollectible receivable costs |
| 3 |
| — |
| ||
Higher donations |
| 3 |
| 5 |
| ||
Other |
| (1 | ) | (5 | ) | ||
Total (decrease) increase in other operating and maintenance expense-utility |
| $ | (7 | ) | $ | 19 |
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The lower nuclear plant outage costs are primarily attributable to the timing of scheduled plant refuelings. Lower current period performance based incentive plan expense, as well as improved retired employee health care experience, were the primary factors contributing to the lower employee benefit costs.
Depreciation and Amortization – Depreciation and amortization expense increased by approximately $11 million, or 5.4 percent, for the second quarter, and $22 million, or 5.4 percent, for the first six months of 2007, compared with the same periods in 2006. The increase was primarily due to increased property, plant and equipment expenditures for planned system expansion.
Income taxes – Income taxes for continuing operations increased by $35 million for the second quarter of 2007, compared with 2006. The effective tax rate for continuing operations was 33.4 percent for the second quarter of 2007, compared with 21.7 percent for the same period in 2006. The lower effective tax rate for second quarter 2006 was primarily due to the recognition of a tax benefit relating to capital loss carry forwards in 2006. Excluding these benefits, the effective tax rate for second quarter 2006 would have been 35.0 percent.
Income taxes for continuing operations increased by $27 million for the first six months of 2007, compared with 2006. The effective tax rate for continuing operations was 33.4 percent for the first six months of 2007, compared with 27.7 percent for the same period in 2006. The lower effective tax rate for the first six months of 2006 was primarily due to the recognition of a tax benefit relating to capital loss carry forwards in 2006. Excluding these benefits, the effective tax rate for the first six months 2006 would have been 32.9 percent.
7
Note 3. Results from Discontinued Operations
A summary of the earnings per share - diluted components of discontinued operations is as follows:
|
| Three months ended |
| Six months ended |
| ||||||||
|
| June 30, |
| June 30, |
| ||||||||
|
| 2007 |
| 2006 |
| 2007 |
| 2006 |
| ||||
PSRI earnings |
| $ | 0.02 |
| $ | — |
| $ | 0.03 |
| $ | 0.02 |
|
COLI tax settlement, net of tax |
| (0.13 | ) | — |
| (0.13 | ) | — |
| ||||
Total discontinued operations |
| $ | (0.11 | ) | $ | — |
| $ | (0.10 | ) | $ | 0.02 |
|
IRS Corporate-Owned Life Insurance Proposed Settlement
Background
On June 19, 2007, a settlement in principle was reached between Xcel Energy and representatives of the United States government concerning a tax dispute related to COLI policies purchased on the lives of PSCo employees. PSCo is a wholly owned subsidiary of Xcel Energy. PSRI, a wholly owned subsidiary of PSCo, owns and manages these COLI life insurance policies.
In April 2004, Xcel Energy filed suit against the government in the United States District Court for the District of Minnesota to establish its right to deduct the interest expense that had accrued during tax years 1993 through 1994 on policy loans related to the COLI policies.
The IRS subsequently sent statutory notices of deficiency to Xcel Energy for tax years 1995-2002. Xcel Energy timely filed Tax Court petitions challenging the denial of the COLI interest expense deductions for those years. PSRI also continued to take deductions for interest expense on policy loans for subsequent years. The total exposure for the tax years in dispute and through 2007 was approximately $583 million, which includes income tax, interest and potential penalties.
Proposed Settlement in Principle
Under the terms of the proposed settlement, Xcel Energy would pay the IRS $64.4 million (or approximately $56 million, net, after tax) in full settlement of all of the government’s claims for additional tax, penalties, and interest relating to these COLI plans for tax years 1993-2007.
Xcel Energy would further agree to claim no additional loan interest expense deductions resulting from its COLI plans for any tax year after 2007 and to surrender its policies following written acceptance of the offer by the government. The government would permit Xcel Energy to surrender the policies without incurring any tax liability on any gain from that surrender.
This settlement in principle requires final approval by the IRS and the Department of Justice Tax Division. There is no guarantee that such approvals will be obtained from these two entities. Among other things, the settlement process requires Xcel Energy to submit a written settlement offer setting forth these basic terms, which was done on July 2, 2007, and for the Department of Justice Tax Division and the IRS to review that offer before they decide to accept or reject it. It is expected that a decision on the proposed settlement will be reached during the third quarter of 2007.
PSRI Impact on Earnings
In 2007, PSRI was projected to provide an EPS contribution of $0.05 per share. These earnings represented the net impact of tax benefit associated with the COLI program of $0.11 per share and other expenses associated with the COLI program of $0.06 per share. As a result of the proposed settlement, which will allow PSRI to unwind the COLI program in a tax efficient manner, PSRI will no longer receive a tax benefit associated with COLI or incur the costs of the COLI program. The earnings from PSRI and the COLI settlement costs are accounted for as discontinued operations.
8
Note 4. Xcel Energy Capital Structure and Financing
Following is the preliminary capital structure of Xcel Energy at June 30, 2007:
(Billions of Dollars) |
| Balance at |
| Percentage of |
| |
Current portion of long-term debt |
| $ | 0.3 |
| 2 | % |
Short-term debt |
| 0.6 |
| 4 | % | |
Long-term debt |
| 6.6 |
| 49 | % | |
Total debt |
| 7.5 |
| 55 | % | |
|
|
|
|
|
| |
Preferred equity |
| 0.1 |
| 1 | % | |
Common equity |
| 6.0 |
| 44 | % | |
Total equity |
| 6.1 |
| 45 | % | |
|
|
|
|
|
| |
Total capitalization |
| $ | 13.6 |
| 100 | % |
During the third quarter, it is anticipated that PSCo will issue approximately $350 million of first mortgage bonds to fund construction projects and for general corporate purposes.
During the fourth quarter, it is anticipated that Xcel Energy will issue approximately $500 million of hybrid securities to fund construction projects and for general corporate purposes.
During the fourth quarter, it is anticipated that NSP-Wisconsin will refinance existing long-term debt for approximately $125 million for general corporate purposes.
Note 5. Rates and Regulation
NSP-Minnesota Natural Gas Rate Case — In November 2006, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $18.5 million, which represents an increase of 2.4 percent. The request is based on 11.0 percent ROE, a projected equity ratio of 51.98 percent and a natural gas rate base of $439 million. Interim rates, subject to refund, were set at a $15.9 million increase and went into effect on Jan. 8, 2007.
On April 10, 2007, NSP-Minnesota filed its rebuttal testimony and revised its requested relief to $16.8 million. The revised requested was caused primarily by an updated ROE estimate of 10.75 percent and an update to the sales forecast.
On April 24, 2007 the Minnesota Department of Commerce (MDOC) filed surrebuttal testimony recommending a rate increase of $10.9 million based on an updated ROE of 9.5 percent. The OAG filed surrebuttal testimony that continued to recommend a 9.26 percent ROE and made reference to the fact that Xcel Energy’s consolidated taxes are significantly lower than those requested for recovery, but made no specific recommendations on this issue.
The Minnesota Commission is expected to hold deliberation on the rate case in August 2007. Xcel Energy expects to receive the MPUC order on Sept. 10, 2007.
PSCo Natural Gas Rate Case Settlement - On Dec. 1, 2006, PSCo filed with the Colorado Public Utilities Commission (CPUC) a request to increase natural gas rates by $41.9 million, representing an overall increase of
9
2.96 percent. The request is based on a requested capital structure of 60.17 percent common equity, a return on common equity of 11.00 percent and a rate base of approximately $1.1 billion.
On June 18, 2007, the CPUC approved a settlement between PSCo, the CPUC staff and the OCC, which granted the following:
· A revenue increase of $32.3 million in annual revenues, based on a 10.25 percent return on equity and a 60.17 percent equity ratio.
· The CPUC modified the partial decoupling mechanism to allow PSCo recovery of additional revenues in future years to compensate for the portion of the decline in weather normalized residential use per customer, that exceeds the first 1.3 percent decline in use (to be reflective of 50 percent of the historic average decline in use).
NSP – North Dakota Gas Rate Case Settlement Agreement - On June 13, 2007, the NDPSC approved a settlement agreement with final rates effective July 1, 2007. The key provisions in the settlement include:
· A $2.3 million annual revenue increase;
· An authorized return on equity of 10.75 percent;
· A residential natural gas rate freeze until 2010;
· An earnings sharing mechanism, which will result in customer refunds should NSP-Minnesota’s natural gas operations in North Dakota exceed its authorized ROE during 2007, 2008 or 2009; and
· Fully decoupled residential rates.
NSP – Wisconsin Electric and Gas Rate Case Filing - On June 1, 2007, NSP-Wisconsin filed with the Public Service Commission of Wisconsin (PSCW) a request to increase retail electric rates by $67.4 million and retail natural gas rates by $5.3 million, representing overall increases of 14.3 percent and 3.3 percent, respectively. The request assumes a common equity ratio of 53.86 percent and a return on equity of 11.00 percent and combined electric and natural gas rate base of approximately $640 million. The PSCW is expected to rule on this filing during the fourth quarter of 2007 and new rates are expected to be implemented in early 2008.
NSP – Minnesota Annual Review of Remaining Lives Depreciation Filing – On June 4, 2007, as part of its annual review of remaining lives depreciation filing, NSP-Minnesota recommended lengthening the life of the Monticello nuclear plant by 20 years retroactive to Jan. 1, 2007 as well as certain other smaller life adjustments. On July 9, 2007, the MDOC recommended approval of the longer lives and sought a small adjustment to rate base in future rate cases to reflect this change so close to NSP-Minnesota’s last rate case. On July 19, 2007, Xcel Energy filed replies specifying the calculation of any potential future adjustment. Assuming the MPUC approves this filing, 2007 depreciation expense would decrease by approximately $31 million. The MPUC is expected to rule on this filing during the third quarter of 2007.
Texas Retail Base Rate And Fuel Reconciliation Case — On May 31, 2006, SPS filed a Texas retail electric rate case requesting an increase in annual revenues of approximately $48 million. The rate filing was based on a historical test year, an electric rate base of $943 million, a requested ROE of 11.6 percent and a common equity ratio of 51.1 percent.
In addition, SPS submitted a fuel reconciliation filing, which requested approval of approximately $957 million of Texas-jurisdictional fuel and purchased power costs for 2004 through 2005. As a part of the fuel reconciliation case, fuel and purchased energy costs were reviewed.
On March 27, 2007, SPS and various intervenors filed a unanimous stipulation agreement related to the Texas retail rate case as well as the fuel reconciliation portion of the proceeding. The agreement includes the following terms:
· The settlement provides for an annual base rate increase of $23 million, or approximately 3 percent.
· The settlement is a “black box” agreement, with no stipulated ROE or capital structure.
· The settlement disallows approximately $27 million of SPS’ 2004 and 2005 fuel expense.
· An additional $2.3 million will be deducted from the company’s next fuel reconciliation filing to be made in 2008, associated with the 2006-2007 fuel reconciliation period.
10
· All of SPS’ existing long-term firm and interruptible capacity wholesale sales will be assigned system average cost for purposes of Texas retail ratemaking, except for sales to El Paso Electric (EPE), which will be determined by the PUCT separately.
· The settlement also creates standards for cost assignment that would apply to future wholesale sale transactions, and establishes margin sharing of market based wholesale demand revenues.
· If SPS files a general rate case in 2008, the settlement would allow for an interim rate increase associated with a purchased power agreement with Lea Power Partners of approximately $1.5 million per month from the date of commercial operations. Interim rates would be subject to a true-up based on the outcome of the rate case proceeding and actual capacity costs incurred.
An estimated settlement allowance and reserve was established in 2006 and prior periods, which approximated the settled amounts of previously deferred or recovered fuel expense.
On March 27, 2007, the ALJ approved SPS’ request to implement the $23 million base rate increase, effective April 2007, on an interim basis until the PUCT acts on the stipulation. The $23 million base rate increase includes approximately $14 million of coal cost that was previously recovered through the fuel cost recovery mechanism, and approximately $6.2 million that results from interruptible customers converting to firm service.
On July 20, 2007, the PUCT voted to approve the settlement and assign incremental costs to the EPE sale. The effect of this decision under the terms of the settlement for 2007 would be to assign up to an additional $3 million in fuel costs assigned to EPE, which SPS will not recover either through its FCA. For 2008 the maximum amount could reach $6.3 million. SPS has previously given notice to EPE to terminate the agreement based on a regulatory out provision in the agreement and Xcel Energy expects that the termination will be effective in 2009.
11
Note 6. Xcel Energy Earnings Guidance
Xcel Energy’s 2007 diluted earnings per share and key assumptions are detailed in the following table.
| 2007 EPS Range |
| |
Utility operations |
| $1.45 - $1.55 |
|
Holding company financing costs and other |
| $(0.15) |
|
Xcel Energy Continuing Operations |
| $1.30 - $1.40 |
|
|
|
|
|
Discontinued operations – PSRI earnings |
| $0.03 - $0.05 |
|
Discontinued operations – PSRI COLI settlement |
| $(0.13) |
|
Total Discontinued operations – COLI |
| $(0.10) - $(0.08) |
|
|
|
|
|
Total Xcel Energy |
| $1.20 - $1.32 |
|
Key Assumptions for 2007:
· Normal weather patterns are experienced during the remainder of the year.
· No material incremental accruals related to the SPS regulatory proceedings.
· Reasonable rate recovery in the Minnesota natural gas rate case.
· Weather-adjusted retail electric utility sales grow by approximately 1.4 percent to 2.0 percent.
· Weather-adjusted retail firm natural gas sales grow by approximately 1.0 percent to 2.0 percent.
· Short-term wholesale and commodity trading margins are within a range of $20 million to $30 million.
· Capacity costs at NSP-Minnesota and SPS are projected to increase approximately $25 million. Capacity costs at PSCo are recovered under the Purchased Capacity Cost Adjustment.
· Utility operating and maintenance expenses increase between 2 percent and 3 percent.
· Absent approval of the Minnesota depreciation filing, depreciation expense is projected to increase approximately $35 million to $45 million. If the Minnesota Commission approves NSP-Minnesota’s request (as filed) to extend the depreciation life of the Monticello nuclear plant by 20 years, depreciation expense would increase $5 million to $15 million.
· Interest expense increases approximately $30 million to $35 million.
· Allowance for funds used during construction-equity increases approximately $15 million to $20 million.
· The COLI settlement is approved by the Department of Justice Tax Division and the Internal Revenue Service.
· The effective tax rate for continuing operations is approximately 31 percent to 34 percent.
· Average common stock and equivalents total approximately 433 million shares.
12
Note 7. Prior Period Earnings Reflecting Discontinued Operations
A summary of the income and earnings per share of continuing and discontinued operations restated for discontinued operations is as follows:
|
| Quarter Ended |
| Year Ended |
| |||||||||||
|
| March 31, 2006 |
| June 30, 2006 |
| Sept. 30, 2006 |
| Dec. 31, 2006 |
| Dec. 31, 2006 |
| |||||
(Thousands of Dollars, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
| |||||
Income from continuing operations |
| $ | 143,119 |
| $ | 98,089 |
| $ | 213,852 |
| $ | 93,148 |
| $ | 548,209 |
|
Income from discontinued operations |
| 8,179 |
| 186 |
| 10,610 |
| 4,570 |
| 23,545 |
| |||||
Net income |
| $ | 151,298 |
| $ | 98,275 |
| $ | 224,462 |
| $ | 97,718 |
| $ | 571,754 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings available for common shareholders |
| $ | 150,238 |
| $ | 97,215 |
| $ | 223,402 |
| $ | 96,658 |
| $ | 567,513 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings per share from continuing operations – diluted |
| $ | 0.34 |
| $ | 0.24 |
| $ | 0.50 |
| $ | 0.22 |
| $ | 1.30 |
|
Earnings per share from discontinued operations – diluted |
| 0.02 |
| — |
| 0.03 |
| 0.01 |
| 0.06 |
| |||||
Earnings per share total – diluted |
| $ | 0.36 |
| $ | 0.24 |
| $ | 0.53 |
| $ | 0.23 |
| $ | 1.36 |
|
Note – The four quarters of 2006 do not total the year-to-date number, due to rounding.
| Quarter Ended |
| ||
|
| March 31, 2007 |
| |
(Thousands of Dollars, except per share amounts) |
|
|
| |
Income from continuing operations |
| $ | 114,180 |
|
Income from discontinued operations |
| 5,531 |
| |
Net income |
| $ | 119,711 |
|
|
|
|
| |
Earnings available for common shareholders |
| $ | 118,651 |
|
|
|
|
| |
Earnings per share from continuing operations — diluted |
| $ | 0.27 |
|
Earnings per share from discontinued operations — diluted |
| 0.01 |
| |
Earnings per share total — diluted |
| $ | 0.28 |
|
13
XCEL ENERGY INC. AND SUBSIDIARIES
UNAUDITED EARNINGS RELEASE SUMMARY
All amounts in thousands, except earnings per share
Three months ended June 30, |
| 2007 |
| 2006 |
| ||
Operating revenues: |
|
|
|
|
| ||
Electric and natural gas utility and trading margins |
| $ | 2,250,563 |
| $ | 2,057,561 |
|
Nonregulated and other |
| 16,729 |
| 16,312 |
| ||
Total operating revenues |
| $ | 2,267,292 |
| $ | 2,073,873 |
|
|
|
|
|
|
| ||
Income from continuing operations |
| $ | 124,103 |
| $ | 98,089 |
|
Income from discontinued operations |
| (48,102 | ) | 186 |
| ||
Net income |
| $ | 76,001 |
| $ | 98,275 |
|
|
|
|
|
|
| ||
Earnings available for common shareholders |
| $ | 74,941 |
| $ | 97,215 |
|
Weighted average diluted common shares outstanding |
| 432,861 |
| 429,099 |
| ||
|
|
|
|
|
| ||
Segments and Components of Earnings per Share – Diluted |
|
|
|
|
| ||
Regulated utility segments – continuing operations |
| $ | 0.32 |
| $ | 0.24 |
|
Holding company and other costs |
| (0.03 | ) | 0.00 |
| ||
Earnings per share - continuing operations |
| 0.29 |
| 0.24 |
| ||
|
|
|
|
|
| ||
Discontinued operations |
| (0.11 | ) | 0.00 |
| ||
|
|
|
|
|
| ||
Total earnings per share |
| $ | 0.18 |
| $ | 0.24 |
|
Six months ended June 30, |
| 2007 |
| 2006 |
| ||
Operating revenues: |
|
|
|
|
| ||
Electric and natural gas utility and trading margins |
| $ | 4,993,788 |
| $ | 4,921,573 |
|
Nonregulated and other |
| 37,166 |
| 40,404 |
| ||
Total operating revenues |
| $ | 5,030,954 |
| $ | 4,961,977 |
|
|
|
|
|
|
| ||
Income from continuing operations |
| $ | 238,283 |
| $ | 241,208 |
|
Income from discontinued operations |
| (42,571 | ) | 8,365 |
| ||
Net income |
| $ | 195,712 |
| $ | 249,573 |
|
|
|
|
|
|
| ||
Earnings available for common shareholders |
| $ | 193,592 |
| $ | 247,453 |
|
Weighted average diluted common shares outstanding |
| 432,471 |
| 428,349 |
| ||
|
|
|
|
|
| ||
Segments and Components of Earnings per Share – Diluted |
|
|
|
|
| ||
Regulated utility segments – continuing operations |
| $ | 0.65 |
| $ | 0.62 |
|
Holding company and other costs |
| (0.09 | ) | (0.04 | ) | ||
Earnings per share - continuing operations |
| 0.56 |
| 0.58 |
| ||
|
|
|
|
|
| ||
Discontinued operations |
| (0.10 | ) | 0.02 |
| ||
|
|
|
|
|
| ||
Total earnings per share |
| $ | 0.46 |
| $ | 0.60 |
|
|
|
|
|
|
| ||
Book value per share |
| $ | 14.29 |
| $ | 13.70 |
|
14