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| XEL > SEC Filings for XEL > Form 10-Q on 31-Jul-2009 | All Recent SEC Filings |
31-Jul-2009
Quarterly Report
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy's financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to the consolidated financial statements. Due to the seasonality of Xcel Energy's electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.
Forward-Looking Statements
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. 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 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 or impose 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; environmental laws and regulations, actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including "Risk Factors" in Item 1A of Xcel Energy's Form 10-K for the year ended Dec. 31, 2008, and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2009.
RESULTS OF OPERATIONS
Earnings per Share Summary
The following table summarizes the diluted earnings per share for Xcel Energy:
Three Months Ended June 30, Six Months Ended June 30,
Diluted earnings (loss) per share 2009 2008 2009 2008
PSCo $ 0.13 $ 0.15 $ 0.31 $ 0.37
NSP-Minnesota 0.11 0.11 0.27 0.26
NSP-Wisconsin 0.01 0.01 0.06 0.04
SPS 0.03 0.01 0.06 -
Equity earnings of unconsolidated
subsidiaries (WYCO) 0.01 - 0.01 -
Regulated utility - continuing
operations 0.29 0.28 0.71 0.67
Holding company and other costs (0.04 ) (0.04 ) (0.07 ) (0.08 )
Ongoing(a) diluted earnings per share 0.25 0.24 0.64 0.59
PSRI - - (0.01 ) -
GAAP diluted earnings per share $ 0.25 $ 0.24 $ 0.63 $ 0.59
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Earnings at PSCo declined by two cents per share for the second quarter and by six cents per share for the six months ending June 30, 2009, largely due to rising costs and relatively flat weather adjusted electric and gas sales margin. In May 2009, the CPUC approved an annual electric rate increase of $112 million and rates went into effect in July 2009.
Earnings at NSP-Minnesota were flat for the second quarter and increased by one cent per share for the six months ending June 30, 2009. In Minnesota, there is a pending rate case with interim rates, subject to refund, which went into effect in January 2009. These interim rates provided incremental revenue and cost recovery, which offset declining sales and rising costs.
Earnings at NSP-Wisconsin were flat for the second quarter and increased by two cents per share for the six months ending June 30, 2009, largely due to improved fuel recovery and new rates which were effective in January 2009.
Earnings at SPS increased by two cents per share for the second quarter and by six cents per share for the six months ending June 30, 2009, primarily due to electric rate increases in Texas (effective in February 2009), and New Mexico and the 2008 resolution of certain fuel cost allocation issues, which were partially offset by higher purchased capacity costs.
Equity earnings of unconsolidated subsidiaries increased by one cent per share for the second quarter and for the six months ending June 30, 2009, due to Xcel Energy's investment in WYCO, which owns a new gas pipeline in Colorado that began operations in late 2008.
Holding Company and Other Costs
Financing Costs and Preferred Dividends - Holding company and other results include interest expense and the earnings per share impact of preferred dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual subsidiaries.
The following table summarizes the earnings contributions of Xcel Energy's business segments on the basis of GAAP:
Three Months Ended June 30, Six Months Ended June 30,
Contribution to Earnings (Millions of Dollars) 2009 2008 2009 2008
GAAP income (loss) by segment
Regulated electric income - continuing
operations $ 123.9 $ 106.8 $ 245.3 $ 199.9
Regulated natural gas income - continuing
operations 10.2 11.8 70.5 79.4
Other regulated income(a) 0.5 6.3 7.6 16.0
Segment income - continuing operations 134.6 124.9 323.4 295.3
Holding company costs and other results(a) (17.5 ) (19.4 ) (30.5 ) (35.8 )
Total income - continuing operations 117.1 105.5 292.9 259.5
Discontinued operations - 0.1 (1.7 ) (0.8 )
Total GAAP net income $ 117.1 $ 105.6 $ 291.2 $ 258.7
Three Months Ended June 30, Six Months Ended June 30,
2009 2008 2009 2008
GAAP earnings (loss) by segment
Regulated electric - continuing
operations $ 0.27 $ 0.25 $ 0.54 $ 0.46
Regulated natural gas - continuing
operations 0.02 0.02 0.15 0.18
Other regulated income(a) - 0.01 0.01 0.03
Segment earnings per share -
continuing operations 0.29 0.28 0.70 0.67
Holding company costs and other
results(a) (0.04 ) (0.04 ) (0.07 ) (0.08 )
Total earnings per share - continuing
operations 0.25 0.24 0.63 0.59
Discontinued operations - - - -
Total earnings per share - continuing
operations $ 0.25 $ 0.24 $ 0.63 $ 0.59
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The following table summarizes significant components contributing to the changes in the 2009 diluted earnings per share compared with the same periods in 2008, which are discussed in more detail later.
Three Months Six Months
Ended June 30, Ended June 30,
2008 GAAP and ongoing(a) diluted earnings per share $ 0.24 $ 0.59
Components of change - 2009 vs. 2008
Higher electric margins 0.07 0.18
Higher allowance for funds used during construction -
equity 0.01 0.02
Lower depreciation and amortization expenses 0.01 -
Higher operating and maintenance expenses (0.02 ) (0.04 )
Higher conservation and DSM expenses (generally offset
in revenue) (0.02 ) (0.03 )
Dilution from DRIP, benefit plan and the 2008 common
equity issuance (0.01 ) (0.03 )
Higher interest expenses (0.01 ) (0.02 )
Lower natural gas margins (0.01 ) (0.03 )
Other (0.01 ) (0.01 )
2009 GAAP diluted earnings per share 0.25 0.63
PSRI - 0.01
2009 ongoing(a) diluted earnings per share $ 0.25 $ 0.64
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Utility Results
The following table summarizes the estimated impact on diluted earnings per
share of temperature variations compared with sales under normal weather
conditions:
Three Months Ended June 30, Six Months Ended June 30,
2009 vs. 2008 vs. 2009 vs. 2009 vs. 2008 vs. 2009 vs.
Normal Normal 2008 Normal Normal 2008
Retail electric $ (0.01 ) $ (0.02 ) $ 0.01 $ (0.01 ) $ (0.01 ) $ -
Firm natural gas - - - (0.01 ) 0.01 (0.02 )
Total $ (0.01 ) $ (0.02 ) $ 0.01 $ (0.02 ) $ - $ (0.02 )
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Electric Revenues and Margin
Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers in most states, the fluctuations in these costs do not materially affect electric margin.
Electric - The following tables detail the electric revenues and margin:
Three Months Ended June 30, Six Months Ended June 30,
(Millions of Dollars) 2009 2008 2009 2008
Electric revenues $ 1,734 $ 2,154 $ 3,620 $ 4,128
Electric fuel and purchased power (797 ) (1,269 ) (1,722 ) (2,358 )
Electric margin $ 937 $ 885 $ 1,898 $ 1,770
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The following tables summarizes the components of the changes in electric revenues and electric margin:
Electric Revenues
Three Months Six Months
Ended June 30, Ended June 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Fuel and purchased power cost recovery $ (450 ) $ (625 )
Trading (26 ) (52 )
Retail sales decline (excluding weather impact) (16 ) (18 )
Retail rate increases (Minnesota interim, Texas,
Wisconsin and New Mexico) 43 84
Conservation and DSM revenues (generally offset by O&M
expenses) 16 34
Sales mix and demand revenues 8 15
Estimated impact of weather 7 1
Non-fuel riders 6 14
MERP rider 4 10
Transmission revenues 3 6
SPS 2008 fuel cost allocation regulatory accruals - 12
Other, net (15 ) 11
Total decrease in electric revenue $ (420 ) $ (508 )
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Electric Margin
Three Months Six Months
Ended June 30, Ended June 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Retail rate increases (Minnesota interim, Texas,
Wisconsin and New Mexico) $ 43 $ 84
Conservation and DSM revenues (generally offset by O&M
expenses) 16 34
Sales mix and demand revenues 8 15
Estimated impact of weather 7 1
Non-fuel riders 6 14
Firm wholesale 6 9
MERP rider 4 10
SPS 2008 fuel cost allocation regulatory accruals - 12
Retail sales decline (excluding weather impact) (16 ) (18 )
Purchased capacity costs (15 ) (33 )
NSP-Wisconsin fuel recovery (2 ) 7
Other, net (5 ) (7 )
Total increase in electric margin $ 52 $ 128
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Xcel Energy has experienced a decline in MwH sales, which we believe is driven by overall economic conditions, and to a lesser degree, increased conservation efforts. Our most significant declines have occurred in commercial and industrial sales, which are directly related to the economic downturn. The declines in MwH sales to the commercial and industrial customer class are partially offset by demand fees, which mitigate to a certain degree the impact of the lower MwH sales.
Natural Gas Revenues and Margin
The cost of natural gas tends to vary with changing sales requirements and the cost of wholesale 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. The following tables detail natural gas revenues and margin:
Three Months Ended June 30, Six Months Ended June 30,
(Millions of Dollars) 2009 2008 2009 2008
Natural gas revenues $ 266 $ 444 $ 1,055 $ 1,478
Cost of natural gas sold and
transported (146 ) (320 ) (738 ) (1,143 )
Natural gas margin $ 120 $ 124 $ 317 $ 335
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The following tables summarize the components of the changes in natural gas revenues and margin:
Natural Gas Revenues
Three Months Six Months
Ended June 30, Ended June 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs 2008
Purchased natural gas adjustment clause recovery $ (173 ) $ (408 )
Estimated impact of weather (3 ) (12 )
Conservation and DSM revenues (generally offset by O&M
expenses) 2 1
Other, net including sales mix/price (4 ) (4 )
Total decrease in natural gas revenues $ (178 ) $ (423 )
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Natural Gas Margin
Three Months Six Months
Ended June 30, Ended June 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Estimated impact of weather $ (3 ) $ (12 )
Conservation and DSM revenues (generally offset by O&M
expenses) 2 1
Other, net (3 ) (7 )
Total decrease in natural gas margin $ (4 ) $ (18 )
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Non-Fuel Operating Expense and Other Items
Other Operating and Maintenance (O&M) Expenses - O&M expenses increased by approximately $15.6 million, or 3.4 percent, for the second quarter and approximately $26.5 million, or 2.9 percent for the first six months of 2009, compared with 2008. The following table summarizes the changes in other O&M expenses:
Three Months Six Months
Ended June 30, Ended June 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Nuclear outage costs, net of deferral $ 10 $ (1 )
Higher employee benefit costs 9 25
Higher nuclear plant operation costs 8 16
Lower consulting costs (7 ) (11 )
Lower material costs (3 ) (4 )
Other, net (1 ) 2
Total increase in other operating and maintenance expenses $ 16 $ 27
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The increase in nuclear outage costs is due to the timing of outages in conjunction with the commissions' approval of the change in the nuclear refueling outage recovery method from the direct expense method to the deferral and amortization method in the third quarter of 2008. Higher employee benefits costs are primarily attributable to increased pension costs, in part, related to market losses on retirement benefit plan assets as well as higher employee medical plan costs. The increase in nuclear plant operation costs is driven primarily by an increase in security costs and regulatory fees, resulting from new Nuclear Regulatory Commission (NRC) requirements.
Conservation and Demand Side Management (DSM) Program Expenses - Conservation and DSM expenses increased approximately $12.2 million, or 41.7 percent for the second quarter of 2009, and by $21.8 million, or 33.7 percent, for the first six months of 2009, compared with the same periods in 2008. The higher expense is attributable to the expansion of programs and regulatory commitments. Conservation and DSM program expenses are generally recovered through riders in Xcel Energy's major jurisdictions or through base rates with tracker mechanisms.
Depreciation and Amortization - Depreciation and amortization expenses decreased by approximately $5.4 million, or 2.6 percent, for the second quarter of 2009, and by $2.3 million, or 0.6 percent, for the first six months of 2009, compared with the same periods in 2008. Higher depreciation due to normal system expansion was offset by a decrease in decommissioning amortization as the recovery periods for the Prairie Island and the Monticello plants were both extended. Those recovery periods were approved by the MPUC in June 2009.
Allowance for Funds Used During Construction, Equity and Debt (AFDC) - AFDC increased by approximately $4.0 million, or 16.4 percent, for the second quarter of 2009, and by $8.7 million, or 18.1 percent, for the first six months of 2009, compared with the same periods in 2008. The increase was due primarily to the construction of Comanche Unit 3, a power facility located in Colorado which is expected to by completed in the fourth quarter of 2009, as well as other construction projects.
Interest Charges - Interest charges increased by approximately $5.6 million, or 4.2 percent, for the second quarter of 2009, and by $15.2 million, or 5.7 percent, for the first six months of 2009, compared with the same periods in 2008. The increase was primarily the result of increased debt levels to fund new capital investments.
Income Taxes - Income tax expense for continuing operations increased by $3.0 million for the second quarter of 2009, compared with 2008. The increase in income tax expense was primarily due to an increase in pretax income. The effective tax rate for continuing operations was 33.7 percent for the second quarter of 2009, compared with 34.3 percent for the same period in 2008. The lower effective tax rate for the second quarter of 2009 was primarily due to a decrease in the forecasted annual effective tax rate for 2009 as compared to 2008.
Income tax expense for continuing operations increased by $13.8 million for the first six months of 2009, compared with the first six months of 2008. The increase in income tax expense was primarily due to an increase in pretax income. The effective tax rate for continuing operations was 33.6 percent for the first six months of 2009, compared with 33.7 percent for the same period in 2008.
Equity Earnings of Unconsolidated Subsidiaries - Equity earnings of unconsolidated subsidiaries increased by $2.8 million for the second quarter of 2009, and by $5.6 million, for the first six months of 2009, compared with the same periods in 2008. The increase is primarily due to higher earnings from the equity investment in WYCO as a result of the High Plains gas pipeline, located in Colorado, commencing operations in late 2008.
Factors Affecting Results of Continuing Operations
Fuel Supply and Costs
See the discussion of fuel supply and costs in Item 7 - Managements Discussion and Analysis of Financial Condition and Results of Operations in Xcel Energy's Annual Report on Form 10-K filed for the year ended Dec. 31, 2008.
Public Utility Regulation
Minnesota Resource Plan - In 2007, NSP-Minnesota filed its resource plan, which covers 2008-2022. The plan would reduce CO2 emissions by 22 percent from 2005 by 2020, a 6 million ton reduction.
In July 2009 the MPUC approved NSP-Minnesota's 2007 resource plan, including the following components:
† Energy efficiency savings of 1.15 percent in 2010, 1.2 percent in 2011 and 1.3 percent in 2012;
† Install sufficient renewables to meet the Minnesota RES;
† Obtain required approvals to extend the life of the Prairie Island nuclear plant and to increase the output at both Prairie Island and Monticello;
† Continue ongoing capacity expansion at Sherco Unit 3;
. . .
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