Attached files
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| 8-K - XCEL ENERGY INC 8-K 7-28-2011 - PUBLIC SERVICE CO OF COLORADO | form8k.htm |
Exhibit No. 99.01
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414 Nicollet Mall
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Minneapolis, MN 55401
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July 28, 2011
XCEL ENERGY
SECOND QUARTER 2011 EARNINGS REPORT
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·
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Ongoing 2011 second quarter earnings per share were $0.33 compared with $0.29 in 2010.
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·
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GAAP (generally accepted accounting principles) 2011 second quarter earnings per share were $0.33 compared with $0.30 per share in 2010.
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·
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Xcel Energy reaffirms 2011 ongoing earnings guidance of $1.65 to $1.75 per share.
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MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) today reported second quarter 2011 GAAP earnings of $159 million, or $0.33 per share compared with 2010 GAAP earnings of $140 million, or $0.30 per share.
Ongoing earnings, which exclude adjustments for certain items, were $0.33 per share for the second quarter of 2011 compared with $0.29 per share in 2010. The 2011 second quarter ongoing earnings increased primarily due to higher electric margins as a result of interim rates in Minnesota and North Dakota, which were partially offset by the impact of lower Colorado seasonal rates implemented in June 2010, expected increases in operating and maintenance expenses, property taxes and depreciation expense, in part from new generation plant investment.
“I am pleased to report solid financial performance in the second quarter,” said Richard C. Kelly, chairman and chief executive officer. “In addition, we continue to make progress on executing our strategic plan as evidenced by receiving approval to extend our Prairie Island nuclear power plant operating license for an additional 20 years, conditional approval of our Brookings, S.D. to Hampton, Minn. transmission line and the recently passed Minnesota legislation allowing multi-year rate plans. Our year-to-date financial results remain on track and position us to deliver 2011 ongoing earnings in the range of $1.65 to $1.75 per share.”
“I recently announced my plans to retire from the company. I’m very fortunate to be part of a company that is successfully executing its strategy. Our board of directors and I have been working on our succession planning process for more than two years in anticipation of my retirement and have elected Ben Fowke as Chairman and CEO, effective Aug. 24, 2011. Ben has a deep understanding of this company as well as the industry and will provide the kind of leadership that ensures continued long-term success,” asserted Kelly.
Earnings Adjusted for Certain Items (Ongoing Earnings)
The following table provides a reconciliation of ongoing earnings per share to GAAP earnings per share:
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Three Months Ended June 30,
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Six Months Ended June 30,
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Diluted Earnings (Loss) Per Share
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2011
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2010
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2011
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2010
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Ongoing(a) diluted earnings per share
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$ | 0.33 | $ | 0.29 | $ | 0.74 | $ | 0.71 | ||||||||
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COLI settlement and Medicare Part D (a)
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- | - | - | (0.06 | ) | |||||||||||
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Earnings per share from continuing operations
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0.33 | 0.29 | 0.74 | 0.65 | ||||||||||||
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Earnings per share from discontinued operations
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- | 0.01 | - | 0.01 | ||||||||||||
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GAAP diluted earnings per share
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$ | 0.33 | $ | 0.30 | $ | 0.74 | $ | 0.66 | ||||||||
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(a)
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See Note 6.
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1
At 9 a.m. CDT today, Xcel Energy will host a conference call to review financial results. To participate in the call, please dial in 5 to 10 minutes prior to the start and follow the operator’s instructions.
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US Dial-In:
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(866) 225-8754
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International Dial-In:
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(480) 629-9770
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Conference ID:
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4451887
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The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website 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 1:00 p.m. CDT on July 28 through 11:59 p.m. CDT on July 29.
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Replay Numbers
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US Dial-In:
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(800) 406-7325
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International Dial-In:
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(303) 590-3030
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Access Code:
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4451887#
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Except for the historical statements contained in this release, the matters discussed herein, including our 2011 full year earnings per share guidance and assumptions, 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. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their 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, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; 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 or imposed environmental compliance conditions; 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 by regulatory bodies impacting our nuclear operations, including those affecting costs, operations or the approval of requests pending before the Nuclear Regulatory Commission ; financial or regulatory accounting policies imposed by regulatory bodies; availability of cost of capital; employee work force factors; 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, 2010 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.
For more information, contact:
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Paul Johnson, Managing Director, Investor Relations and Assistant Treasurer
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(612) 215-4535
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Jack Nielsen, Director, Investor Relations
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(612) 215-4559
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Cindy Hoffman, Senior Investor Relations Analyst
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(612) 215-4536
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For news media inquiries only, please call Xcel Energy media relations
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(612) 215-5300
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Xcel Energy internet address: www.xcelenergy.com
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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)
(amounts in thousands, except per share data)
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Three Months Ended June 30,
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Six Months Ended June 30,
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2011
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2010
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2011
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2010
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Operating revenues
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Electric
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$ | 2,128,397 | $ | 2,040,702 | $ | 4,158,369 | $ | 4,036,294 | ||||||||
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Natural gas
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291,538 | 249,410 | 1,056,887 | 1,039,560 | ||||||||||||
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Other
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18,287 | 17,652 | 39,506 | 39,372 | ||||||||||||
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Total operating revenues
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2,438,222 | 2,307,764 | 5,254,762 | 5,115,226 | ||||||||||||
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Operating expenses
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Electric fuel and purchased power
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989,413 | 986,088 | 1,921,241 | 1,974,566 | ||||||||||||
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Cost of natural gas sold and transported
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163,056 | 126,963 | 706,432 | 708,076 | ||||||||||||
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Cost of sales — other
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6,891 | 4,704 | 14,946 | 12,396 | ||||||||||||
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Other operating and maintenance expenses
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532,170 | 516,640 | 1,042,197 | 997,613 | ||||||||||||
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Conservation and demand side management program expenses
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65,497 | 55,551 | 140,795 | 113,590 | ||||||||||||
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Depreciation and amortization
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229,264 | 211,506 | 453,987 | 417,632 | ||||||||||||
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Taxes (other than income taxes)
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92,489 | 81,008 | 189,059 | 162,384 | ||||||||||||
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Total operating expenses
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2,078,780 | 1,982,460 | 4,468,657 | 4,386,257 | ||||||||||||
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Operating income
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359,442 | 325,304 | 786,105 | 728,969 | ||||||||||||
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Other income, net
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979 | 1,709 | 5,745 | 2,684 | ||||||||||||
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Equity earnings of unconsolidated subsidiaries
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7,677 | 7,362 | 15,390 | 14,763 | ||||||||||||
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Allowance for funds used during construction — equity
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13,606 | 12,996 | 26,850 | 26,286 | ||||||||||||
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Interest charges and financing costs
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Interest charges — includes other financing costs of $6,185, $5,146, $11,445 and $10,157, respectively
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146,338 | 141,455 | 290,692 | 285,285 | ||||||||||||
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Allowance for funds used during construction — debt
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(7,838 | ) | (6,575 | ) | (15,274 | ) | (14,312 | ) | ||||||||
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Total interest charges and financing costs
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138,500 | 134,880 | 275,418 | 270,973 | ||||||||||||
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Income from continuing operations before income taxes
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243,204 | 212,491 | 558,672 | 501,729 | ||||||||||||
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Income taxes
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84,533 | 76,866 | 196,534 | 198,764 | ||||||||||||
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Income from continuing operations
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158,671 | 135,625 | 362,138 | 302,965 | ||||||||||||
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Income from discontinued operations, net of tax
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91 | 4,151 | 193 | 3,929 | ||||||||||||
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Net income
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158,762 | 139,776 | 362,331 | 306,894 | ||||||||||||
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Dividend requirements on preferred stock
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1,060 | 1,060 | 2,120 | 2,120 | ||||||||||||
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Earnings available to common shareholders
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$ | 157,702 | $ | 138,716 | $ | 360,211 | $ | 304,774 | ||||||||
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Weighted average common shares outstanding:
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Basic
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484,918 | 460,041 | 484,283 | 459,483 | ||||||||||||
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Diluted
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485,241 | 460,432 | 484,775 | 460,068 | ||||||||||||
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Earnings per average common share — Basic:
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Income from continuing operations
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$ | 0.33 | $ | 0.29 | $ | 0.74 | $ | 0.65 | ||||||||
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Income from discontinued operations
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- | 0.01 | - | 0.01 | ||||||||||||
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Earnings per share
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$ | 0.33 | $ | 0.30 | $ | 0.74 | $ | 0.66 | ||||||||
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Earnings per average common share — Diluted:
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Income from continuing operations
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$ | 0.33 | $ | 0.29 | $ | 0.74 | $ | 0.65 | ||||||||
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Income from discontinued operations
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- | 0.01 | - | 0.01 | ||||||||||||
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Earnings per share
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$ | 0.33 | $ | 0.30 | $ | 0.74 | $ | 0.66 | ||||||||
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Cash dividends declared per common share
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$ | 0.26 | $ | 0.25 | $ | 0.51 | $ | 0.50 | ||||||||
3
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor Relations Earnings 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.
The only common equity securities that are publicly traded are common shares of Xcel Energy. The earnings and earnings per share (EPS) of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. EPS by subsidiary is a financial measure not recognized under accounting principles generally accepted in the United States of America (GAAP) that is calculated by dividing the net income or loss attributable to controlling interest of each subsidiary by the weighted average fully diluted Xcel Energy common shares outstanding for the period. We use this non-GAAP financial measure to evaluate earnings results and to provide details of earnings results. We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. This non-GAAP financial measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.
Note 1. Earnings Per Share Summary
The following table summarizes the diluted earnings per share for Xcel Energy:
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Three Months Ended June 30,
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Six Months Ended June 30,
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Diluted Earnings (Loss) Per Share
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2011
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2010
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2011
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2010
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Public Service Company of Colorado (PSCo)
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$ | 0.15 | $ | 0.17 | $ | 0.35 | $ | 0.40 | ||||||||
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NSP-Minnesota
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0.13 | 0.09 | 0.32 | 0.24 | ||||||||||||
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Southwestern Public Service Company (SPS)
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0.05 | 0.05 | 0.07 | 0.07 | ||||||||||||
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NSP-Wisconsin
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0.02 | 0.01 | 0.05 | 0.04 | ||||||||||||
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Equity earnings of unconsolidated subsidiaries
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0.01 | 0.01 | 0.02 | 0.02 | ||||||||||||
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Regulated utility — continuing operations (b)
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0.36 | 0.33 | 0.81 | 0.77 | ||||||||||||
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Holding company and other costs
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(0.03 | ) | (0.04 | ) | (0.07 | ) | (0.06 | ) | ||||||||
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Ongoing(a) diluted earnings per share
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0.33 | 0.29 | 0.74 | 0.71 | ||||||||||||
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COLI settlement and Medicare Part D (a)
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- | - | - | (0.06 | ) | |||||||||||
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Earnings per share from continuing operations
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0.33 | 0.29 | 0.74 | 0.65 | ||||||||||||
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Earnings per share from discontinued operation
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- | 0.01 | - | 0.01 | ||||||||||||
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GAAP diluted earnings per share
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$ | 0.33 | $ | 0.30 | $ | 0.74 | $ | 0.66 | ||||||||
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(a)
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See Note 6.
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(b)
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See Note 2.
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PSCo — PSCo earnings decreased by $0.02 per share for the second quarter and by $0.05 per share for the six months ended June 30, 2011. The decreases are mainly due to seasonal rates, which were implemented in June 2010 and higher operating and maintenance (O&M) expenses, property taxes and depreciation expense. Seasonal rates are designed to be revenue neutral on an annual basis. Therefore, the quarterly pattern of revenue collection is different than in the past, as seasonal rates are higher in the summer months and lower throughout the other months of the year.
NSP-Minnesota — NSP-Minnesota earnings increased by $0.04 per share for the second quarter and by $0.08 per share for the six months ended June 30, 2011. The increases are primarily due to interim rate increases, subject to refund, in Minnesota and North Dakota effective in the first quarter of 2011, partially offset by higher O&M expenses, property taxes and depreciation expense.
SPS — SPS earnings per share were flat for the second quarter and for the six months ended June 30, 2011 when compared to the respective periods of 2010. Higher electric revenues, primarily due to Texas retail rate increases in February 2011 as well as warmer weather in May and June 2011were offset by higher O&M expenses, property taxes, depreciation expense and the reversal of fuel cost allocation reserves in 2010.
NSP-Wisconsin — NSP-Wisconsin earnings increased by $0.01 per share for both the second quarter and for the six months ended June 30, 2011. The increase is due to implementation of new electric rates, which were effective in January 2011, and were partially offset by higher O&M and depreciation expenses.
4
The following table summarizes significant components contributing to the changes in the 2011 diluted earnings per share compared with the same period in 2010, which is discussed in more detail later in the release.
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Three Months
Ended June 30,
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Six Months
Ended June 30,
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Diluted Earnings (Loss) Per Share
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2010 GAAP diluted earnings per share
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$ | 0.30 | $ | 0.66 | |||
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Earnings per share from discontinued operations
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(0.01 | ) | (0.01 | ) | |||
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2010 diluted earnings per share from continuing operations
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0.29 | 0.65 | |||||
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COLI settlement and Medicare Part D (a)
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- | 0.06 | |||||
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2010 ongoing(a) diluted earnings per share
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0.29 | 0.71 | |||||
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Components of change — 2011 vs. 2010
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Higher electric margins
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0.11 | 0.23 | |||||
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Higher natural gas margins
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0.01 | 0.03 | |||||
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Higher operating and maintenance expenses
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(0.02 | ) | (0.06 | ) | |||
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Higher depreciation and amortization
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(0.02 | ) | (0.05 | ) | |||
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Higher taxes (other than income taxes)
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(0.02 | ) | (0.04 | ) | |||
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Dilution from DSPP, benefit plans and the 2010 common equity issuance
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(0.02 | ) | (0.04 | ) | |||
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Higher conservation and DSM expenses (generally offset in revenues)
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(0.01 | ) | (0.04 | ) | |||
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Other, net
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0.01 | - | |||||
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2011 GAAP and ongoing(a) diluted earnings per share
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$ | 0.33 | $ | 0.74 | |||
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(a)
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See Note 6.
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Note 2. Regulated Utility Results — Continuing Operations
Estimated Impact of Temperature Changes on Regulated Earnings — Unseasonably hot summers or cold winters increase electric and natural gas sales while, conversely, mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per degree of temperature. Accordingly, deviations in weather from normal levels can affect Xcel Energy’s financial performance.
Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less weather sensitive.
Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction based on the time period used by the regulator in establishing estimated volumes in the rate setting process. The percentage increase (decrease) in normal and actual HDD, CDD and THI are as follows:
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Three Months Ended June 30,
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Six Months Ended June 30,
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2011 vs.
Normal
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2010 vs.
Normal
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2011 vs.
2010
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2011 vs.
Normal
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2010 vs.
Normal
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2011 vs.
2010
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HDD
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0.9 | % | (16.3 | ) % | 20.5 | % | 4.4 |
%
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(2.4 | ) |
%
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7.0 |
%
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CDD
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33.9 | 17.5 | 14.0 | 33.5 | 17.8 | 13.3 | ||||||||||||||||||||||
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THI
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(6.4 | ) | 6.4 | (12.1 | ) | (6.4 | ) | 6.4 | (12.1 | ) | ||||||||||||||||||
5
Weather — The following table summarizes the estimated impact on earnings per share of temperature variations compared with sales under normal weather conditions:
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Three Months Ended June 30,
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Six Months Ended June 30,
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2011 vs.
Normal
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2010 vs.
Normal
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2011 vs.
2010
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2011 vs.
Normal
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2010 vs.
Normal
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2011 vs.
2010
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Retail electric
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$ | 0.00 | $ | 0.01 | $ | (0.01 | ) | $ | 0.01 | $ | 0.01 | $ | 0.00 | |||||||||||
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Firm natural gas
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0.00 | (0.01 | ) | 0.01 | 0.00 | (0.01 | ) | 0.01 | ||||||||||||||||
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Total
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$ | 0.00 | $ | 0.00 | $ | 0.00 | $ | 0.01 | $ | 0.00 | $ | 0.01 | ||||||||||||
Sales Growth (Decline) — The following table summarizes Xcel Energy’s sales growth (decline) for actual and weather-normalized sales in 2011:
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Three Months Ended June 30,
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Actual
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Weather
Normalized
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Actual
Lubbock (a)
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Weather
Normalized
Lubbock (a)
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Electric residential
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(0.8 | ) % | (0.2 | ) % | 0.2 | % | 0.7 | % | ||||||||
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Electric commercial and industrial
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(0.1 | ) | 0.0 | 0.8 | 0.9 | |||||||||||
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Total retail electric sales
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(0.2 | ) | 0.0 | 0.7 | 0.9 | |||||||||||
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Firm natural gas sales
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2.7 | (4.9 | ) | N/A | N/A | |||||||||||
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Six Months Ended June 30,
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Actual
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Weather
Normalized
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Actual
Lubbock (a)
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Weather
Normalized
Lubbock (a)
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Electric residential
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(0.3 | ) % | (0.5 | ) % | 0.6 | % | 0.4 | % | ||||||||
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Electric commercial and industrial
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0.3 | 0.3 | 1.2 | 1.2 | ||||||||||||
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Total retail electric sales
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0.2 | 0.1 | 1.1 | 1.0 | ||||||||||||
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Firm natural gas sales
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1.5 | (2.8 | ) | N/A | N/A | |||||||||||
| (a) | Adjusted for the October 2010 sale of SPS electric distribution assets to the city of Lubbock, Texas. |
Electric — Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following tables detail the electric revenues and margin:
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Three Months Ended June 30,
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Six Months Ended June 30,
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(Millions of Dollars)
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2011
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2010
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2011
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2010
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Electric revenues
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$ | 2,128 | $ | 2,041 | $ | 4,158 | $ | 4,036 | |||||||||
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Electric fuel and purchased power
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(989 | ) | (986 | ) | (1,921 | ) | (1,975 | ) | |||||||||
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Electric margin
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$ | 1,139 | $ | 1,055 | $ | 2,237 | $ | 2,061 | |||||||||
6
The following table summarizes the components of the changes in electric margin:
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(Millions of Dollars)
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Three Months
Ended June 30,
2011 vs. 2010
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Six Months
Ended June 30,
2011 vs. 2010
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Revenue requirements for PSCo gas generation acquisition (a)
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$ | 35 | $ | 69 | ||||
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Retail rate increases, including seasonal rates (Minnesota interim, Wisconsin, Texas, North Dakota interim and Colorado)
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23 | 58 | ||||||
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Conservation and DSM revenue, (partially offset by expenses)
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10 | 18 | ||||||
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Conservation and DSM incentive
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9 | 8 | ||||||
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Transmission revenue, net of costs
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7 | 10 | ||||||
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Non-fuel riders
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3 | 11 | ||||||
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Firm wholesale
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2 | 4 | ||||||
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Trading, including PSCo renewable energy credit sales
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2 | (2 | ) | |||||
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SPS fuel cost allocation regulatory accruals (b)
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(11 | ) | (11 | ) | ||||
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Other, net
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4 | 11 | ||||||
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Total increase in electric margin
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$ | 84 | $ | 176 | ||||
| (a) | The increase in revenue requirements for PSCo generation reflects the acquisition of the Rocky Mountain and Blue Spruce natural gas facilities in late 2010. These revenue requirements are partially offset by increased O&M expense, depreciation expense, property taxes and financing costs. |
| (b) | During the second quarter of 2010, SPS resolved certain fuel cost allocation issues allowing for the release of previously established reserves of approximately $11 million. |
Natural Gas — The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following tables detail natural gas revenues and margin:
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Three Months Ended June 30,
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Six Months Ended June 30,
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(Millions of Dollars)
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2011
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2010
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2011
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2010
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Natural gas revenues
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$ | 292 | $ | 249 | $ | 1,057 | $ | 1,040 | |||||||||
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Cost of natural gas sold and transported
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(163 | ) | (127 | ) | (706 | ) | (708 | ) | |||||||||
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Natural gas margin
|
$ | 129 | $ | 122 | $ | 351 | $ | 332 | |||||||||
The following table summarizes the components of the changes in natural gas margin:
|
(Millions of Dollars)
|
Three Months
Ended June 30,
2011 vs. 2010
|
Six Months
Ended June 30,
2011 vs. 2010
|
||||||
|
Estimated impact of weather
|
$ | 4 | $ | 9 | ||||
|
Conservation and DSM revenue, (partially offset by expenses)
|
1 | 11 | ||||||
|
Conservation and DSM incentive
|
1 | 1 | ||||||
|
Retail sales decrease (excluding weather impact)
|
(1 | ) | (3 | ) | ||||
|
Other, net
|
2 | 1 | ||||||
|
Total increase in natural gas margin
|
$ | 7 | $ | 19 | ||||
7
O&M Expenses — O&M expenses increased approximately $15.5 million, or 3.0 percent, for the second quarter and by $44.6 million, or 4.5 percent for the six months ended June 30, 2011 compared with 2010. The following table summarizes the changes in other O&M expenses:
|
(Millions of Dollars)
|
Three Months Ended June 30, 2011 vs. 2010
|
Six Months
Ended June 30,
2011 vs. 2010
|
||||||
|
Higher plant generation costs
|
$ | 13 | $ | 18 | ||||
|
Higher labor and contract labor costs
|
5 | 13 | ||||||
|
Higher bad debt expense
|
2 | 1 | ||||||
|
Higher employee benefit expense
|
- | 5 | ||||||
|
Other, net
|
(4 | ) | 8 | |||||
|
Total increase in operating and maintenance expenses
|
$ | 16 | $ | 45 | ||||
|
|
·
|
Higher plant generation costs are attributable to incremental costs associated with new generation placed in service in 2010 and a higher level of scheduled maintenance and overhaul work.
|
|
|
·
|
Higher labor and contract labor costs are primarily due to maintenance on our distribution facilities, particularly in Colorado, and the impact of annual wage increases.
|
|
|
·
|
Higher employee benefit costs for the six month comparable periods are primarily due to higher pension expense.
|
Conservation and DSM Program Expenses — Conservation and demand side management (DSM) program expenses increased by approximately $9.9 million, or 17.9 percent for the second quarter and by $27.2 million, or 24.0 percent for the six months ended June 30, 2011, compared with the same periods in 2010. The higher expense is attributable to timing and an increase in the rider rates used to recover the program expenses. Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.
Depreciation and Amortization — Depreciation and amortization increased by approximately $17.8 million, or 8.4 percent for the second quarter and by $36.4 million, or 8.7 percent for the six months ended June 30, 2011, compared with the same periods in 2010. The increase in depreciation expense is primarily due to Comanche Unit 3 going into service in mid-May 2010, the Nobles Wind Project commencing commercial operations in late 2010, the acquisition of two gas generation facilities in December 2010 and normal system expansion.
Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $11.5 million, or 14.2 percent for the second quarter and by $26.7 million, or 16.4 percent for the six months ended June 30, 2011, compared with the same periods in 2010. The increase is primarily due to an increase in property taxes in Colorado and Minnesota.
Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased by approximately $1.9 million, or 9.6 percent for the second quarter and by $1.5 million, or 3.8 percent for the six months ended June 30, 2011, compared with the same periods in 2010. The increase is primarily due to construction projects related to NSP-Minnesota‘s Monticello extended power uprate and the new SPS Jones Unit 3, which went in service in late June 2011.
Interest Charges — Interest charges increased by approximately $4.9 million, or 3.5 percent for the second quarter and by $5.4 million, or 1.9 percent for the six months ended June 30, 2011, compared with the same periods in 2010. The increase is due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.
Income Taxes — Income tax expense for continuing operations increased $7.7 million for the second quarter of 2011, compared with the same period in 2010. The increase in income tax expense was primarily due to an increase in pretax income in 2011 partially offset by increased wind production tax credits in 2011. The effective tax rate for continuing operations was 34.8 percent for the second quarter of 2011 compared with 36.2 percent for the same period in 2010. The lower effective tax rate for 2011 was primarily due to a lower forecasted annual effective tax rate for 2011 as compared to 2010, which was primarily due to increased wind production tax credits in 2011.
8
Income tax expense for continuing operations decreased $2.2 million for the first six months of 2011, compared with the first six months of 2010. The decrease in income tax expense was primarily due to the 2010 adjustments for a write-off of tax benefit previously recorded for Medicare Part D subsidies, an adjustment related to the corporate owned life insurance (COLI) Tax Court proceedings, and an increase in 2011 wind production tax credits. These were partially offset by a reversal of a valuation allowance for certain state tax credit carryovers in 2010 and an increase in pretax income in 2011. The effective tax rate for continuing operations was 35.2 percent for the six months ended June 30, 2011 compared with 39.6 percent for the same period in 2010. The higher effective tax rate for 2010 was primarily due to the Medicare Part D, COLI, and valuation allowance adjustments referenced above. Without these adjustments, the effective tax rate for continuing operations for the first six months of 2010 would have been 35.8 percent.
Note 3. Xcel Energy Capital Structure, Financing and Credit Ratings
Following is the capital structure of Xcel Energy:
|
Percentage
|
|||||||||
|
(Billions of Dollars)
|
of Total
|
||||||||
|
June 30, 2011
|
Capitalization
|
||||||||
|
Current portion of long-term debt
|
- | - | % | ||||||
|
Short-term debt
|
0.7 | 4 | |||||||
|
Long-term debt
|
9.3 | 51 | |||||||
|
Total debt
|
10.0 | 55 | |||||||
|
Preferred equity
|
0.1 | - | |||||||
|
Common equity
|
8.2 | 45 | |||||||
|
Total capitalization
|
$ | 18.3 | 100 | % | |||||
Financing Plans — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund construction programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. In addition to the periodic issuance and repayment of short-term debt, Xcel Energy and its utility subsidiaries’ financing plans are as follows:
|
|
·
|
PSCo plans to issue approximately $250 million of first mortgage bonds during the third quarter of 2011.
|
|
|
·
|
SPS plans to issue approximately $200 million of bonds in the third quarter of 2011.
|
|
|
·
|
Xcel Energy also anticipates issuing approximately $75 million of equity through the Dividend Reinvestment and Stock Purchase Plan (DSPP) and various benefit programs in 2011.
|
Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors.
Credit Facilities — As of July 25, 2011, Xcel Energy and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:
|
(Millions of Dollars)
|
Facility
|
Drawn(a)
|
Available
|
Cash
|
Liquidity
|
Maturity
|
|||||||||||||||
|
Xcel Energy Inc.
|
$ | 800.0 | $ | 332.1 | $ | 467.9 | $ | 0.3 | $ | 468.2 |
March 2015
|
||||||||||
|
PSCo
|
700.0 | 208.8 | 491.2 | 0.7 | 491.9 |
March 2015
|
|||||||||||||||
|
NSP-Minnesota
|
500.0 | 87.1 | 412.9 | 0.2 | 413.1 |
March 2015
|
|||||||||||||||
|
SPS
|
300.0 | 161.0 | 139.0 | 0.3 | 139.3 |
March 2015
|
|||||||||||||||
|
NSP-Wisconsin
|
150.0 | 46.5 | 103.5 | 0.1 | 103.6 |
March 2015
|
|||||||||||||||
|
Total
|
$ | 2,450.0 | $ | 835.5 | $ | 1,614.5 | $ | 1.6 | $ | 1,616.1 | |||||||||||
| (a) | Includes outstanding commercial paper and letters of credit. |
9
Credit Ratings — Access to reasonably priced capital markets is dependent in part on credit and ratings. The following ratings reflect the views of Moody’s Investors Service (Moody’s), Standard & Poor’s Rating Services (Standard & Poor’s), and Fitch Ratings (Fitch).
As of July 25, 2011, the following represents the credit ratings assigned to various Xcel Energy companies:
|
Company
|
Credit Type
|
Moody's
|
Standard & Poor's
|
Fitch
|
||||
|
Xcel Energy
|
Senior Unsecured Debt
|
Baa1
|
BBB+
|
BBB+
|
||||
|
Xcel Energy
|
Commercial Paper
|
P-2
|
A-2
|
F2
|
||||
|
NSP-Minnesota
|
Senior Unsecured Debt
|
A3
|
A-
|
A
|
||||
|
NSP-Minnesota
|
Senior Secured Debt
|
A1
|
A
|
A+
|
||||
|
NSP-Minnesota
|
Commercial Paper
|
P-2
|
A-2
|
F1
|
||||
|
NSP-Wisconsin
|
Senior Unsecured Debt
|
A3
|
A-
|
A
|
||||
|
NSP-Wisconsin
|
Senior Secured Debt
|
A1
|
A
|
A+
|
||||
|
PSCo
|
Senior Unsecured Debt
|
Baa1
|
A-
|
A-
|
||||
|
PSCo
|
Senior Secured Debt
|
A2
|
A
|
A
|
||||
|
PSCo
|
Commercial Paper
|
P-2
|
A-2
|
F2
|
||||
|
SPS
|
Senior Unsecured Debt
|
Baa1
|
A-
|
BBB+
|
||||
|
SPS
|
Commercial Paper
|
P-2
|
A-2
|
F2
|
Moody’s highest credit rating for debt is Aaa and lowest investment grade rating is Baa3. Both Standard & Poor’s and Fitch’s highest credit rating for debt are AAA and lowest investment grade rating is BBB-. Moody’s prime ratings for commercial paper range from P-1 to P-3. Standard & Poor’s ratings for commercial paper range from A-1 to A-3. Fitch’s ratings for commercial paper range from F1 to F3. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Note 4. Rates and Regulation
NSP-Minnesota Electric Rate Case — In November 2010, NSP-Minnesota filed a request with the Minnesota Public Utilities Commission (MPUC) to increase annual electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent. The rate filing is based on a 2011 forecast test year and included a requested return on equity (ROE) of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent. NSP-Minnesota requested an additional increase of $48.3 million or 1.81 percent effective Jan. 1, 2012, to address certain known and measurable cost increases in 2012.
The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011. The interim rates will remain in effect until the MPUC makes its final decision on the case. In May 2011, NSP-Minnesota revised its rate increase request to approximately $126.4 million or 4.7 percent for 2011, largely due to a revised requested ROE of 10.85 percent. NSP-Minnesota also reduced its requested increase for 2012 to $44.7 million.
The Department of Energy Resource (DOER) (formerly the Office of Energy Security or OES) recommended a $58 million rate increase, based on a 10.37 percent ROE and a $31 million adjustment for income taxes related to bonus depreciation. The Office of Attorney General (OAG) and the Xcel Large Industrial Group recommended a rate reduction and refund of depreciation reserves and reductions to or elimination of incentive compensation costs. The OAG recommended refunding the liability associated with retiree medical benefits.
At the hearings in June 2011, NSP-Minnesota resolved differences with the DOER on income taxes and sales forecast. NSP-Minnesota also made an adjustment to bad debt and incentive compensation expense. As a result of these adjustments, NSP-Minnesota revised its requested rate increase to $122.8 million. The DOER revised its recommended rate increase to approximately $84.7 million, reflecting these same changes. The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation are associated with the ROE and incentive compensation issues. The DOER recommended an additional rate increase of $34 million in 2012. In the second quarter of 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $15 million, which should be sufficient to address an outcome that is more consistent with the DOER position than NSP-Minnesota’s position on various issues. NSP-Minnesota can not predict the ultimate outcome of this pending regulatory proceeding. The MPUC decision is expected in the fourth quarter of 2011.
10
NSP-Minnesota - North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent. The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent. NSP-Minnesota requested an additional increase of $4.2 million, or 2.6 percent, effective Jan. 1, 2012, to address certain known and measurable cost increases in 2012.
In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional increase in 2012, due to the termination of the Merricourt wind project.
The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011. The interim rates will remain in effect until the NDPSC makes its final decision on the case, which is anticipated in the first quarter of 2012. The remaining schedule is listed below:
|
|
·
|
Intervenor direct testimony due Aug. 18, 2011;
|
|
|
·
|
Rebuttal testimony due Sept. 20, 2011; and
|
|
|
·
|
Evidentiary hearings due Oct. 18-21, 2011.
|
NSP-Minnesota - South Dakota Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the South Dakota Public Utilities Commission to increase South Dakota electric rates by $14.6 million annually, effective in 2012. The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms. Net of current automatic recovery mechanisms, the requested increase was $13.9 million. The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent. NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello life cycle management and enhanced power uprate project that is not reflected in the test year.
PSCo 2010 Gas Rate Case — In December 2010, PSCo filed a request with the Colorado Public Utilities Commission
(CPUC) to increase Colorado retail gas rates by $27.5 million on an annual basis. In March 2011, PSCo revised its requested rate increase to $25.6 million.
The revised request was based on a 2011 forecast test year, a 10.90 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.10 percent. PSCo proposed recovering $23.2 million of test year capital and O&M expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006. PSCo also proposed removing the earnings on gas in underground storage from base rates.
In May 2011, PSCo filed a comprehensive settlement with CPUC Staff and the Colorado Office of Consumer Counsel to increase rates by $10.9 million, to institute rider recovery of future integrity management costs, and remove underground storage from base rates and recover those costs in the Gas Cost Adjustment (GCA) rider. The GCA recovery of the return on gas in storage is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs. Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent. New base rates and the GCA recovery are expected to go into effect in September 2011. The rider for integrity management costs is expected to go into effect on Jan. 1, 2012 and is expected to recover an estimated $13 million of incremental revenue in 2012. In July 2011, the presiding hearing commissioner approved the settlement with certain modifications and PSCo subsequently filed exceptions to the recommended decision.
NSP-Wisconsin 2011 Electric and Gas Rate Case — In June 2011, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) to increase electric rates approximately $29.2 million, or 5.1 percent and natural gas rates approximately $8.0 million, or 6.6 percent effective Jan. 1, 2012. The rate filing is based on a 2012 forecast test year and includes a requested ROE of 10.75 percent, and an equity ratio of 52.54 percent. The rate base in 2012 is forecast to be approximately $718 million for the electric utility and $84 million for the natural gas utility. A PSCW decision is anticipated in the fourth quarter of 2011.
SPS - New Mexico Electric Rate Case — In February 2011, SPS filed a request in New Mexico with the New Mexico Public Regulation Commission (NMPRC) seeking to increase New Mexico electric rates approximately $19.9 million. The rate filing is based on a 2011 test year adjusted for known and measurable changes for 2012, a requested ROE of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent. Rates are expected to go into effect during the first quarter of 2012.
11
The New Mexico Attorney General (NMAG) has filed a motion to dismiss the rate case or to toll the suspension period of rates and the NMPRC Staff has also filed a motion to reject the filing and for SPS to file additional information on the grounds that SPS’ information supporting its 2011 test year is incomplete. SPS has filed a response asserting that SPS’ filing is complete and asking the NMPRC to deny the motion. The NMPRC has not yet acted on the motion. The NMPRC has stated that SPS does not need to file a reply to Staff’s motion while the current negotiations to settle the case continue.
Note 5. Xcel Energy Ongoing Earnings Guidance
Xcel Energy’s 2011 ongoing earnings guidance is $1.65 to $1.75 per share. Key assumptions related to ongoing earnings are detailed below:
|
|
·
|
Normal weather patterns are experienced for the year.
|
|
|
·
|
Weather-adjusted retail electric utility sales, adjusted for the sale of the Lubbock distribution assets, are projected to grow approximately 1.0 percent.
|
|
|
·
|
Weather-adjusted retail firm natural gas sales are projected to decline 1.0 to 2.0 percent.
|
|
|
·
|
Constructive outcomes in all rate case and regulatory proceedings.
|
|
|
·
|
Rider revenue recovery is projected to be relatively flat.
|
|
|
·
|
O&M expenses are projected to increase up to 4 percent.
|
|
|
·
|
Depreciation expense is projected to increase $50 million to $60 million.
|
|
|
·
|
Interest expense is projected to increase approximately $10 million.
|
|
|
·
|
AFUDC — equity is projected to be relatively flat.
|
|
|
·
|
The effective tax rate is projected to be approximately 34 percent to 36 percent.
|
|
|
·
|
Average common stock and equivalents are projected to be approximately 486 million shares.
|
Note 6. Non-GAAP Reconciliation
Ongoing earnings exclude the impact of Internal Revenue Service (IRS) tax and interest adjustments related to COLI program, the write-off of previously recognized tax benefits relating to Medicare Part D subsidies due to the recently enacted Patient Protection and Affordable Care Act and a settlement related to the previously discontinued COLI program.
Impact of the Patient Protection and Affordable Care Act — Medicare Part D
In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, Xcel Energy is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment. Xcel Energy expensed approximately $17 million, or $0.04 per share, of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. Xcel Energy does not expect the $17 million of additional tax expense to recur in future periods.
COLI
During 2007, Xcel Energy reached a settlement with the IRS related to a dispute associated with its COLI program. These COLI policies were owned and managed by P.S.R. Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. As a follow on to the 2007 IRS COLI settlement, as part of the Tax Court proceedings, during the first quarter of 2010, Xcel Energy and the IRS reached an agreement in principle after a comprehensive financial reconciliation of Xcel Energy's statements of account, dating back to tax year 1993. Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $10 million (including $7.7 million tax expense and $2.3 million interest expense, net of tax), or $0.02 per share during the first quarter of 2010. During the third quarter of 2010, Xcel Energy and the IRS came to final agreement on the applicable interest netting computations related to these tax years. Accordingly, PSRI recorded a reduction to expense of $0.6 million, net of tax, during the third quarter of 2010. The Tax Court proceedings were dismissed in December 2010 and January 2011.
Xcel Energy’s management believes that ongoing earnings provide a meaningful comparison of earnings results and is representative of Xcel Energy’s fundamental core earnings power. Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for performance-based compensation, and when communicating its earnings outlook to analysts and investors.
12
The following table provides a reconciliation of ongoing earnings to GAAP earnings:
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|||||||||||||||
|
(Thousands of Dollars)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
|
Ongoing earnings
|
$ | 158,628 | $ | 136,305 | $ | 362,086 | $ | 331,833 | ||||||||
|
COLI settlement and Medicare Part D
|
43 | (680 | ) | 52 | (28,868 | ) | ||||||||||
|
Total continuing operations
|
158,671 | 135,625 | 362,138 | 302,965 | ||||||||||||
|
Income from discontinued operations
|
91 | 4,151 | 193 | 3,929 | ||||||||||||
|
GAAP earnings
|
$ | 158,762 | $ | 139,776 | $ | 362,331 | $ | 306,894 | ||||||||
13
XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (UNAUDITED)
(amounts in thousands, except earnings per share)
|
Three Months Ended June 30,
|
||||||||
|
2011
|
2010
|
|||||||
|
Operating revenues:
|
||||||||
|
Electric and natural gas revenues
|
$ | 2,419,935 | $ | 2,290,112 | ||||
|
Other
|
18,287 | 17,652 | ||||||
|
Total operating revenues
|
2,438,222 | 2,307,764 | ||||||
|
Income from continuing operations
|
158,671 | 135,625 | ||||||
|
Earnings from discontinued operations
|
91 | 4,151 | ||||||
|
Net income
|
$ | 158,762 | $ | 139,776 | ||||
|
Earnings available to common shareholders
|
$ | 157,702 | $ | 138,716 | ||||
|
Weighted average diluted common shares outstanding
|
485,241 | 460,432 | ||||||
|
Components of Earnings per Share — Diluted
|
||||||||
|
Regulated utility — continuing operations
|
$ | 0.36 | $ | 0.33 | ||||
|
Holding company and other costs
|
(0.03 | ) | (0.04 | ) | ||||
|
Ongoing(a) diluted earnings per share
|
0.33 | 0.29 | ||||||
|
COLI settlement and Medicare Part D (a)
|
- | - | ||||||
|
Earnings per share from continuing operations
|
0.33 | 0.29 | ||||||
|
Earnings per share from discontinued operations
|
- | 0.01 | ||||||
|
GAAP diluted earnings per share
|
$ | 0.33 | $ | 0.30 | ||||
|
Six Months Ended June 30,
|
||||||||
|
2011
|
2010
|
|||||||
|
Operating revenues:
|
||||||||
|
Electric and natural gas revenues
|
$ | 5,215,256 | $ | 5,075,854 | ||||
|
Other
|
39,506 | 39,372 | ||||||
|
Total operating revenues
|
5,254,762 | 5,115,226 | ||||||
|
Income from continuing operations
|
362,138 | 302,965 | ||||||
|
Earnings from discontinued operations
|
193 | 3,929 | ||||||
|
Net income.
|
$ | 362,331 | $ | 306,894 | ||||
|
Earnings available to common shareholders
|
$ | 360,211 | $ | 304,774 | ||||
|
Weighted average diluted common shares outstanding
|
484,775 | 460,068 | ||||||
|
Components of Earnings per Share — Diluted
|
||||||||
|
Regulated utility — continuing operations
|
$ | 0.81 | $ | 0.77 | ||||
|
Holding company and other costs
|
(0.07 | ) | (0.06 | ) | ||||
|
Ongoing(a) diluted earnings per share
|
0.74 | 0.71 | ||||||
|
COLI settlement and Medicare Part D (a)
|
- | (0.06 | ) | |||||
|
Earnings per share from continuing operations
|
0.74 | 0.65 | ||||||
|
Earnings per share from discontinued operations
|
- | 0.01 | ||||||
|
GAAP diluted earnings per share
|
$ | 0.74 | $ | 0.66 | ||||
|
Book value per share
|
$ | 16.99 | $ | 16.08 | ||||
| (a) | See Note 6. |
14