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| XEL > SEC Filings for XEL > Form 10-Q on 30-Apr-2009 | All Recent SEC Filings |
30-Apr-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; 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 March 31, 2009.
RESULTS OF OPERATIONS
Earnings per Share Summary
The following table summarizes the diluted earnings per share contributions:
Three Months Ended March 31,
(Diluted earnings (loss) per share) 2009 2008
PSCo $ 0.17 $ 0.22
NSP-Minnesota 0.17 0.15
NSP-Wisconsin 0.04 0.03
SPS 0.02 (0.01 )
Equity earnings of unconsolidated subsidiaries (WYCO) 0.01 -
Regulated utility - continuing operations 0.41 0.39
Holding company and other costs (0.03 ) (0.04 )
Total earnings per share $ 0.38 $ 0.35
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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 March 31,
Contribution to Earnings (Millions of Dollars) 2009 2008
GAAP income (loss) by segment
Regulated electric income - continuing operations $ 121.4 $ 93.1
Regulated natural gas income - continuing operations 60.3 67.6
Other regulated income(a) 7.1 9.7
Segment income - continuing operations 188.8 170.4
Holding company costs and other results(a) (13.0 ) (16.4 )
Total income - continuing operations 175.8 154.0
Discontinued operations (1.7 ) (0.9 )
Total GAAP net income $ 174.1 $ 153.1
Three Months Ended March 31,
2009 2008
GAAP earnings (loss) per share by segment
Regulated electric - continuing operations $ 0.27 $ 0.21
Regulated natural gas - continuing operations 0.13 0.16
Other regulated income(a) 0.01 0.02
Segment earnings per share - continuing operations 0.41 0.39
Holding company costs and other results(a) (0.03 ) (0.04 )
Total earnings per share - continuing operations 0.38 0.35
Discontinued operations - -
Total earnings per share - continuing operations $ 0.38 $ 0.35
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The following table summarizes significant components contributing to the changes in the first quarter of 2009 diluted earnings per share compared with the same period in 2008, which are discussed in more detail later.
Three Months
Increase (Decrease) Ended March 31
2008 GAAP and ongoing(a) diluted earnings per share $ 0.35
Components of Change - 2009 vs. 2008
Higher electric margins 0.11
Higher allowance for funds used during construction - equity 0.01
Higher operating and maintenance expenses (0.02 )
Lower natural gas margins (0.02 )
Dilution from DRIP, benefit plan and the 2008 common equity
issuance (0.02 )
Higher interest expense (0.01 )
Higher conservation and demand side management expenses (0.01 )
Other (0.01 )
2009 GAAP and ongoing(a) diluted earnings per share $ 0.38
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Utility Results
The following table summarizes the estimated impact on diluted earnings per
share of temperature variations on first quarter results, compared with sales
under normal weather conditions:
Three Months Ended March 31,
2009 vs. 2008 vs.
Normal Normal 2009 vs. 2008
Retail electric $ - $ 0.01 $ (0.01 )
Firm natural gas - 0.01 (0.01 )
Total $ - $ 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 March 31,
(Millions of Dollars) 2009 2008
Electric revenues $ 1,887 $ 1,973
Electric fuel and purchased power (925 ) (1,088 )
Electric margin $ 962 $ 885
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The following summarizes the components of the changes in electric revenues and electric margin for the three months ended March 31:
Electric Revenues (Millions of Dollars) 2009 vs. 2008 Fuel and purchased power recovery $ (174 ) Trading (26 ) Estimated impact of weather (6 ) Retail sales decline (excluding weather impact) (2 ) Retail rate increases (Minnesota interim, Texas interim, Wisconsin and New Mexico) 45 Conservation and demand side management revenue 17 SPS 2008 fuel cost allocation regulatory accruals 12 Non-fuel riders 10 MERP rider 5 Other, net 33 Total decrease in electric revenues $ (86 ) |
Electric Margin (Millions of Dollars) 2009 vs. 2008 Retail rate increases (Minnesota interim, Texas interim, Wisconsin and New Mexico) $ 45 Conservation and demand side management revenue 17 SPS 2008 fuel cost allocation regulatory accruals 12 Non-fuel riders 10 NSP-Wisconsin fuel recovery 9 MERP rider 5 Purchased capacity costs (18 ) Estimated impact of weather (6 ) Retail sales decline (excluding weather impact) (2 ) Other, net 5 Total increase in electric margin $ 77 |
Xcel Energy has experienced a decline in per unit MwH sales, particularly in the commercial and industrial customer class. However, since these customers generally pay a demand fee, the impact of the lower MwH sales was mitigated to a certain degree.
Natural Gas Revenues and Margin
The following table details the changes in 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.
Three Months Ended March 31,
(Millions of Dollars) 2009 2008
Natural gas revenues $ 789 $ 1,034
Cost of natural gas sold and transported (592 ) (823 )
Natural gas margin $ 197 $ 211
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The following tables summarize the components of the changes in natural gas revenues and margin for the three months ended March 31:
Natural Gas Revenues (Millions of Dollars) 2009 vs. 2008 Purchased natural gas adjustment clause recovery $ (235 ) Other, net (10 ) Total decrease in natural gas revenues $ (245 ) |
Natural Gas Margin (Millions of Dollars) 2009 vs. 2008 Estimated impact of weather $ (10 ) Sales decline (excluding weather impact) (1 ) Other, net (3 ) Total decrease in natural gas margin $ (14 ) |
Non-Fuel Operating Expense and Other Items
Other Operating and Maintenance Expenses - Other operating and maintenance expenses for the first quarter of 2009 increased by approximately $10.9 million, or 2.4 percent, as compared with 2008. For more information, see the following table:
Three Months Ended
March 31,
(Millions of Dollars) 2009 vs. 2008
Higher employee benefit costs $ 16
Higher nuclear plant operation costs 10
Higher labor costs 5
Nuclear outage costs, net of deferral (12 )
Lower consulting costs (4 )
Other, net (4 )
Total increase in other operating and maintenance expense $ 11
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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. The decline in nuclear outage expense is due to NRC 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.
Depreciation and Amortization - Depreciation and amortization expenses increased by approximately $3.1 million, or 1.5 percent, for the first quarter of 2009, compared with 2008. The increase is primarily due to normal system expansion from investments in our utility operations.
Conservation and Demand Side Management (DSM)- Conservation and DSM expenses increased approximately $9.6 million, or 27.1 percent for the first quarter of 2009, compared with 2008. The higher expense is primarily 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 general rate cases.
Allowance for Funds Used During Construction, Equity and Debt (AFDC) - AFDC increased by approximately $4.7 million, or 19.8 percent, for the first quarter of 2009, compared with the 2008. The increase was due primarily to the construction of Comanche 3, a power facility located in Colorado which is nearing completion, as well as other construction projects.
Interest Charges- Interest charges increased by approximately $9.6 million, or 7.3 percent, for the first quarter of 2009, compared with 2008. The increase was primarily the result of increased debt levels to fund new capital investments.
Income Taxes - Income taxes for continuing operations increased by $10.5 million for the first 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 33.5 percent for the first quarter of 2009, compared with 33.2 percent for 2008.
Equity Earnings of Unconsolidated Subsidiaries - Equity earnings of unconsolidated subsidiaries increased by $2.6 million for the first quarter of 2009, compared with 2008, primarily due to increased earnings from the equity investment in WYCO Development LLC (WYCO) as a result of the High Plains gas pipeline commencing operations in late 2008.
Factors Affecting Results of Continuing Operations
Fuel Supply and Costs
See the discussion of fuel supply and costs at Factors Affecting Results of Continuing Operations in Xcel Energy's Annual Report on Form 10-K filed for the year ended Dec. 31, 2008.
Public Utility Regulation
Excelsior Energy - In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba Energy Project. Excelsior filed this petition making claims pursuant to Minnesota statutes relating to an Innovative Energy Project and Clean Energy Technology. NSP-Minnesota opposed the petition.
The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior's petition. The contested case proceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.
The MPUC issued its order for phase 1 of the hearing on Aug. 30, 2007. In it, the MPUC found among other things, that Excelsior and NSP-Minnesota should resume negotiations toward an acceptable purchase power agreement, with assistance from the Minnesota Department of Commerce (MDOC) and the guidance provided by the order.
On Sept. 24, 2008, the MPUC denied Excelsior Energy's Phase 2 request to approve a power purchase agreement related to its proposed second 600 MW IGCC generating facility. The MPUC also set a May 1, 2009 deadline for Phase 1 of the proceeding in which it had previously ordered negotiations. On Oct. 14, 2008, Excelsior sought rehearing of the MPUC's Sept. 24, 2008 order. On Dec. 9, 2008, the MPUC held further action in abeyance until after the May 1, 2009 deadline.
Wind Generation - In December 2008, the first NSP-Minnesota owned wind generation plant, the 100 MW Grand Meadow wind farm, went into service. The project was developed through a build-own-transfer arrangement with a large wind energy developer (enXco) at a cost of approximately $210 million. NSP-Minnesota plans to invest approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project. These projects are expected to be operational by the end of 2010 and 2011, respectively. On Dec. 3, 2008, NSP-Minnesota filed petitions with the MPUC and the NDPSC seeking the required regulatory approvals for the two wind powered generating facilities.
NSP-Minnesota Transmission Certificates of Need - In August 2007, NSP-Minnesota and Great River Energy (on behalf of eight other regional transmission providers) filed a certificate of need application, for three 345 kilovolt (KV) transmission lines, as part of the CapX 2020 project. The project to build the three lines includes construction of approximately 600 miles of new facilities at a cost of approximately $1.7 billion, with construction to be completed in phases. The cost of the project to NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900 million. These cost estimates will be revised after the regulatory process is completed. The applicants filed rebuttal testimony recommending the modification of all three projects to be constructed as double circuit compatible with the first circuit strung during initial construction and the second circuit strung as needed. On April 16, 2009, the MPUC granted a certificate of need to construct three 345 KV electric transmission lines in Minnesota. The MPUC also included a condition regarding assuring a portion of the capacity of the Brookings, S.D. to Hampton, Minn. line is used for renewable energy.
As part of CapX 2020, NSP-Minnesota and Great River Energy have filed two route permit applications with the MPUC. On Dec. 29, 2008, the route permit application for the Brookings to Hampton Corner Project was filed. On April 8, 2009, the route permit application for the Monticello to St. Cloud portion of the Fargo Twin Cities project was filed. Route permit applications for the remaining parts of the three projects will be filed in Minnesota later this year. Permit filings will also be made in adjoining states. NSP-Minnesota anticipates the first routing decisions in early 2010.
As part of CapX 2020, Otter Tail Power Company, Minnesota Power and Minnkota Power Cooperative (on behalf of themselves and NSP-Minnesota and Great River Energy) filed a certificate of need application in March 2008 for a 230 KV transmission line between Bemidji and Grand Rapids, Minn. A route application for this project was filed in June 2008. The need application is uncontested; route hearings are expected to be conducted in late 2009, and an MPUC decision is anticipated by the second quarter of 2010. The Bemidji-Grand Rapids line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million, with construction to be completed by end of 2011. The estimated cost to NSP-Minnesota is approximately $26 million.
In the second quarter of 2009, NSP-Minnesota plans to file a certificate of need application with the MPUC for two 161 KV transmission lines in the Rochester, Minn. area to support ongoing development of wind powered generation in southeastern Minnesota. The proposal consists of an approximately 15 mile long, 161 KV transmission line north of Rochester, and an approximately 30 mile long, 161 KV transmission line southeast of Rochester. The project's estimated cost is $30 million. An MPUC decision is anticipated in early 2010.
Bay Front Biomass Gasification - On Feb. 23, 2009, NSP-Wisconsin filed an application with the PSCW for a certificate of authority to install biomass gasification technology at the Bay Front Power Plant in Ashland, Wis. On April 27, 2009, the pre hearing conference for the application for the Bay Front gasifier project was held. The PSCW's ALJ ruled on requests for intervention, established the issues list for the hearing and set the hearing date for Aug. 5, 2009. Currently, two of the three boilers at Bay Front use biomass as their primary fuel to generate electricity. The proposed project will convert the existing coal-fired unit to biomass gasification technology allowing the plant to use 100 percent biomass in all three boilers. The project, estimated to cost $58 million, will require additional biomass receiving and handling facilities at the plant, an external gasifier, minor modifications to the plant's remaining coal-fired boiler and an enhanced air quality control system. The total generation output of the plant is not expected to change significantly as a result of the project. However, the project will improve the environmental performance of the plant and contribute towards state renewable energy standards in the region. Following all state regulatory approvals, engineering and design work is expected to begin in 2010, and the unit could be operational by late 2012. When complete, the Bay Front Power Plant will be the largest biomass-fueled power plant in the Midwest and one of the largest in the nation.
Texas Energy Efficiency Cost Recovery Factor (EECRF) Rider - PUCT regulations established the mechanism under which electric utilities may recover costs associated with providing energy efficiency programs. That mechanism, an EECRF Rider, must be included in a utility's tariff and may be established in a utility's base rate case or through a separate request seeking to establish an EECRF. In accordance with this rule, SPS has removed its energy efficiency costs from its recent base rate proceeding, and has requested implementation of its EECRF Rider to recover the remaining unamortized balance of historic costs and its projected 2008 and 2009 energy efficiency costs. In September 2008, the PUCT concluded that the rule under which the application was filed does not apply to SPS and the energy efficiency costs could be recovered in the pending Texas retail base rate case. SPS filed supplemental testimony in the currently pending Texas retail base rate case seeking cost recovery. As part of the joint stipulation filed by the parties in the currently pending Texas retail base rate case, the parties asked the ALJs to certify a question to the PUCT asking whether SPS could recover or return amounts spent above or below the base rate amount, and if so, what mechanism could be used to recover or refund those amounts. Parties filed briefs addressing the issue on March 19, 2009. At its March 27, 2009 open meeting, the PUCT determined that SPS is allowed to accrue the additional energy efficiency expenditures as a regulatory asset for recovery in its next general rate case.
Texas Renewable Energy Zones - In 2007, the PUCT designated competitive . . .
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