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| XEL > SEC Filings for XEL > Form 10-Q on 30-Oct-2009 | All Recent SEC Filings |
30-Oct-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 Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2009.
RESULTS OF OPERATIONS
Earnings per Share Summary
The following table summarizes the diluted earnings per share for Xcel Energy:
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
Diluted earnings (loss) per
share 2009 2008 2009 2008
PSCo $ 0.20 $ 0.20 $ 0.51 $ 0.56
NSP-Minnesota 0.20 0.25 0.48 0.51
NSP-Wisconsin 0.03 0.03 0.08 0.07
SPS 0.08 0.05 0.14 0.06
Equity earnings of
unconsolidated subsidiaries
(WYCO) 0.01 0.01 0.02 0.01
Regulated utility - continuing
operations 0.52 0.54 1.23 1.21
Holding company and other costs (0.04 ) (0.03 ) (0.11 ) (0.11 )
Ongoing(a) diluted earnings per
share 0.48 0.51 1.12 1.10
PSRI - - (0.01 ) -
GAAP diluted earnings per share $ 0.48 $ 0.51 $ 1.11 $ 1.10
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PSCo - Earnings at PSCo were flat for the third quarter and decreased by five cents per share for the nine months ending Sept. 30, 2009, largely due to the negative impact of weather and rising costs. The decrease was partially offset by new electric rates that went into effect in July 2009. In May 2009, the CPUC approved an annual electric rate increase of $112 million.
NSP-Minnesota - Earnings at NSP-Minnesota decreased by five cents per share for the third quarter and by three cents per share for the nine months ending Sept. 30, 2009. The decrease is mainly due to the negative impact of weather, an increase in the effective tax rate and timing of nuclear outage expenses. The decrease was partially offset by an electric rate increase that went into effect in January 2009.
NSP-Wisconsin - Earnings at NSP-Wisconsin were flat for the third quarter and increased by one cent per share for the nine months ending Sept. 30, 2009, largely due to improved fuel recovery and new rates which were effective in January 2009.
SPS - Earnings at SPS increased by three cents per share for the third quarter and by eight cents per share for the nine months ending Sept. 30, 2009. The increase was primarily due to electric rate increases in Texas (effective in February 2009) and New Mexico (effective in July 2009) and the 2008 resolution of certain fuel cost allocation issues, which were partially offset by higher purchased capacity costs.
WYCO - Equity earnings of unconsolidated subsidiaries were flat for the third quarter and increased by one cent per share for the nine months ending Sept. 30, 2009, due to our investment in WYCO, which owns a natural gas pipeline in Colorado that began operations in late 2008, as well as a storage facility that commenced operations in July 2009.
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 Sept. 30, Nine Months Ended Sept. 30,
Contribution to Earnings (Millions of Dollars) 2009 2008 2009 2008
GAAP income (loss) by segment
Regulated electric income - continuing
operations $ 235.8 $ 223.4 $ 473.4 $ 423.3
Regulated natural gas income - continuing
operations (1.0 ) 4.0 71.1 83.4
Other regulated income(a) 4.2 7.3 17.9 23.3
Segment income - continuing operations 239.0 234.7 562.4 530.0
Holding company costs and other results(a) (17.2 ) (12.0 ) (47.7 ) (47.8 )
Total income - continuing operations 221.8 222.7 514.7 482.2
Discontinued operations (1.0 ) 0.1 (2.7 ) (0.7 )
Total GAAP net income $ 220.8 $ 222.8 $ 512.0 $ 481.5
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
2009 2008 2009 2008
GAAP earnings (loss) by segment
Regulated electric - continuing
operations $ 0.50 $ 0.51 $ 1.04 $ 0.97
Regulated natural gas - continuing
operations - 0.01 0.15 0.19
Other regulated income(a) 0.02 0.02 0.04 0.05
Segment earnings per share -
continuing operations 0.52 0.54 1.23 1.21
Holding company costs and other
results(a) (0.04 ) (0.03 ) (0.11 ) (0.11 )
Total earnings per share -
continuing operations 0.48 0.51 1.12 1.10
Discontinued operations - - (0.01 ) -
Total earnings per share -
continuing operations $ 0.48 $ 0.51 $ 1.11 $ 1.10
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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 Nine Months
Ended Sept. 30, Ended Sept. 30,
2008 GAAP and ongoing(a) diluted earnings per share $ 0.51 $ 1.10
Components of change - 2009 vs. 2008
Higher electric margins 0.12 0.30
Lower depreciation and amortization expenses 0.02 0.02
Higher allowance for funds used during construction
- equity 0.01 0.02
Higher operating and maintenance expenses (0.06 ) (0.10 )
Higher conservation and DSM expenses (generally
offset in revenues) (0.03 ) (0.06 )
Lower other income (expense), net (0.02 ) (0.03 )
Dilution from DRIP, benefit plan and the 2008 common
equity issuance (0.02 ) (0.05 )
Higher taxes, other than income taxes (0.01 ) (0.02 )
Lower natural gas margins (0.01 ) (0.03 )
Higher interest expenses - (0.02 )
Other, including higher effective tax rate (0.03 ) (0.01 )
2009 GAAP diluted earnings per share 0.48 1.12
PSRI - (0.01 )
2009 ongoing(a) diluted earnings per share $ 0.48 $ 1.11
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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 Sept. 30, Nine Months Ended Sept. 30,
2009 vs. 2008 vs. 2009 vs. 2009 vs. 2008 vs. 2009 vs.
Normal Normal 2008 Normal Normal 2008
Retail electric $ (0.05 ) $ (0.01 ) $ (0.04 ) $ (0.05 ) $ (0.01 ) $ (0.04 )
Firm natural gas - - - (0.01 ) 0.01 (0.02 )
Total $ (0.05 ) $ (0.01 ) $ (0.04 ) $ (0.06 ) $ - $ (0.06 )
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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. The following tables detail the electric revenues and margin:
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
(Millions of Dollars) 2009 2008 2009 2008
Electric revenues $ 2,129 $ 2,576 $ 5,749 $ 6,704
Electric fuel and purchased power (982 ) (1,514 ) (2,704 ) (3,871 )
Electric margin $ 1,147 $ 1,062 $ 3,045 $ 2,833
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The following tables summarize the components of the changes in electric revenues and electric margin:
Electric Revenues
Three Months Nine Months
Ended Sept. 30, Ended Sept. 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Fuel and purchased power cost recovery $ (518 ) $ (1,143 )
Estimated impact of weather (26 ) (24 )
NSP-Minnesota rate case provision for refund (largely
offset in depreciation expense) (25 ) (30 )
Trading (11 ) (63 )
Sales mix and demand revenues (5 ) 10
Retail rate increases (Colorado, Minnesota, Texas, New
Mexico and Wisconsin) 98 190
Conservation and DSM revenues (generally offset by
expenses) 20 53
2008 refund of nuclear refueling outage revenues due
to change in recovery method 14 15
Non-fuel riders 4 18
MERP rider 3 13
Transmission revenue 3 9
Retail sales decline (excluding weather impact) - (17 )
SPS 2008 fuel cost allocation regulatory accruals - 12
Other, net (4 ) 2
Total decrease in electric revenue $ (447 ) $ (955 )
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Electric Margin
Three Months Nine Months
Ended Sept. 30, Ended Sept. 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Retail rate increases (Colorado, Minnesota, Texas, New
Mexico and Wisconsin) $ 98 $ 190
Conservation and DSM revenues (generally offset by
expenses) 20 53
2008 refund of nuclear refueling outage revenues due
to change in recovery method 14 15
Non-fuel riders 4 18
MERP rider 3 13
NSP-Wisconsin fuel recovery 3 10
Firm wholesale 2 10
Estimated impact of weather (26 ) (24 )
NSP-Minnesota rate case provision for refund (largely
offset in depreciation expense) (25 ) (30 )
Purchased capacity costs (11 ) (44 )
Sales mix and demand revenues (5 ) 10
Retail sales (decline excluding weather impact) - (17 )
SPS 2008 fuel cost allocation regulatory accruals - 12
Other, net 8 (4 )
Total increase in electric margin $ 85 $ 212
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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 Sept. 30, Nine Months Ended Sept. 30,
(Millions of Dollars) 2009 2008 2009 2008
Natural gas revenues $ 170 $ 259 $ 1,224 $ 1,737
Cost of natural gas sold and
transported (72 ) (156 ) (810 ) (1,299 )
Natural gas margin $ 98 $ 103 $ 414 $ 438
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The following tables summarize the components of the changes in natural gas revenues and margin:
Natural Gas Revenues
Three Months Nine Months
Ended Sept. 30, Ended Sept. 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Purchased natural gas adjustment clause recovery $ (85 ) $ (493 )
Sales mix (2 ) (4 )
Transportation margin (2 ) (1 )
Conservation and DSM revenues (generally offset by expenses) 1 2
Estimated impact of weather - (13 )
Other, net (1 ) (4 )
Total decrease in natural gas revenues $ (89 ) $ (513 )
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Natural Gas Margin
Three Months Nine Months
Ended Sept. 30, Ended Sept. 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Sales mix $ (2 ) $ (4 )
Transportation margin (2 ) (2 )
Estimated impact of weather (1 ) (13 )
Conservation and DSM revenues (generally offset by expenses) 1 2
Other, net (1 ) (7 )
Total decrease in natural gas margin $ (5 ) $ (24 )
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Non-Fuel Operating Expense and Other Items
Other Operating and Maintenance (O&M) Expenses - O&M expenses increased by approximately $43.9 million, or 10.4 percent, for the third quarter and approximately $70.4 million, or 5.3 percent for the first nine months of 2009, compared with 2008. The following table summarizes the changes in other O&M expenses:
Three Months Nine Months
Ended Sept. 30, Ended Sept. 30,
(Millions of Dollars) 2009 vs. 2008 2009 vs. 2008
Nuclear outage costs, net of deferral $ 27 $ 26
Higher employee benefit costs 15 40
Higher nuclear plant operation costs 4 20
Higher plant generation costs 3 5
Lower consulting costs (7 ) (19 )
Other, net 2 (2 )
Total increase in other operating and maintenance expenses $ 44 $ 70
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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 requirements.
† Lower consulting costs are primarily the result of cost management initiatives implemented in early 2009.
Conservation and DSM Program Expenses - Conservation and DSM program expenses increased approximately $19.7 million for the third quarter of 2009, and by $41.5 million for the first nine 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 our major jurisdictions or through base rates with tracker mechanisms.
Depreciation and Amortization - Depreciation and amortization expenses decreased by approximately $10.9 million, or 5.2 percent, for the third quarter of 2009, and by $13.2 million, or 2.1 percent, for the first nine months of 2009, compared with the same periods in 2008. In September 2009, as a result of the MPUC decision, in the Minnesota electric rate case, NSP-Minnesota began recognizing a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation, effective Jan. 1, 2009. In addition, in June 2009, the MPUC extended the recovery period of decommissioning expense by 10 years for the Prairie Island and the Monticello nuclear plants. These decreases were partially offset by normal system expansion.
Taxes (Other Than Income Taxes) - Taxes (other than income taxes) increased by approximately $8.7 million, or 12.3 percent, for the third quarter of 2009, and by $10.8 million, or 5.0 percent, for the first nine months of 2009, compared with the same periods in 2008. The increase is primarily due to increased property taxes.
Other Income (Expense), Net - Other income (expense), net, decreased $10.7 million during the third quarter of 2009 and $22.9 million for the first nine months of 2009, compared with the same periods in 2008. The net decline is mainly due to changes in our non-qualified benefit plan liabilities related to market activity, lower interest on under recovered deferred fuel balances and a decrease in interest received from WYCO for construction deposits.
Allowance for Funds Used During Construction, Equity and Debt (AFDC) - AFDC increased by approximately $2.3 million, or 8.8 percent, for the third quarter of 2009, and by $11.0 million, or 14.8 percent, for the first nine 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 be completed in the fourth quarter of 2009, as well as other construction projects.
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