Xcel Energy Annual Report 2005

Plain-text annual report

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(cid:84)(cid:72)(cid:69)(cid:0)(cid:67)(cid:79)(cid:77)(cid:80)(cid:65)(cid:78)(cid:89)(cid:7)(cid:83)(cid:0)(cid:83)(cid:84)(cid:82)(cid:79)(cid:78)(cid:71)(cid:0)(cid:67)(cid:79)(cid:77)(cid:77)(cid:73)(cid:84)(cid:77)(cid:69)(cid:78)(cid:84)(cid:0)(cid:84)(cid:79)(cid:0)(cid:0) (cid:84)(cid:72)(cid:69)(cid:0)(cid:67)(cid:79)(cid:77)(cid:77)(cid:85)(cid:78)(cid:73)(cid:84)(cid:73)(cid:69)(cid:83)(cid:0)(cid:73)(cid:78)(cid:0)(cid:73)(cid:84)(cid:83)(cid:0)(cid:83)(cid:69)(cid:82)(cid:86)(cid:73)(cid:67)(cid:69)(cid:0)(cid:84)(cid:69)(cid:82)(cid:82)(cid:73)(cid:84)(cid:79)(cid:82)(cid:89)(cid:14) (cid:56)(cid:35)(cid:37)(cid:44)(cid:0)(cid:37)(cid:46)(cid:37)(cid:50)(cid:39)(cid:57)(cid:0)(cid:18)(cid:16)(cid:16)(cid:21)(cid:0)(cid:33)(cid:46)(cid:46)(cid:53)(cid:33)(cid:44)(cid:0)(cid:50)(cid:37)(cid:48)(cid:47)(cid:50)(cid:52)(cid:0)(cid:0)(cid:17)(cid:21)(cid:0)(cid:0) M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S BUSINESS SEGMENTS AND ORGANIZATIONAL OVERVIEW Xcel Energy Inc. (Xcel Energy), a Minnesota corporation, is a public utility holding company. In 2005, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); and Southwestern Public Service Co. (SPS). These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin. Along with WestGas InterState Inc. (WGI), an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations. Xcel Energy’s nonregulated subsidiaries reported in continuing operations include Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax reported credits). Discontinued utility operations include Viking Gas Transmission Co. (Viking), an interstate natural gas pipeline company that was sold in January 2003; Black Mountain Gas Co. (BMG), a regulated natural gas and propane distribution company that was sold in October 2003; and Cheyenne Light, Fuel and Power Co. (Cheyenne), a regulated electric and natural gas utility that was sold in January 2005. During 2003, Planergy International, Inc. (Planergy), (energy management solutions) closed, with ﬁnal dissolution completed in 2004. Several nonregulated subsidiaries are presented as a component of discontinued operations. They include Utility Engineering (UE), an engineering, design and construction management ﬁrm; Quixx Corp., a former subsidiary of UE that partners in cogeneration projects; Seren Innovations, Inc. (Seren), a broadband communications services company; NRG Energy, Inc. (NRG), an independent power producer; Xcel Energy International, Inc., an international independent power producer; and e prime inc. (e prime), a natural gas marketing and trading company. Discontinued operations classifications are the result of sales or plans to sell by management. See Note 2 to the Consolidated Financial Statements for further discussion of discontinued operations. 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. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain ﬁnancing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership; structures that affect the speed and degree to which competition enters the electric and natural gas markets; the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses; 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 Securities and Exchange Commission (SEC), including “Risk Factors” in Item 1A of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005, and Exhibit 99.01 to Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005. MANAGEMENT’S STRATEGIC PLAN Xcel Energy’s strategy, which we call Building the Core, is to invest in our core utility businesses and earn the return authorized by our regulatory commissions. We plan to invest approximately $7 billion over the next ﬁve years in our core operations to grow our business in response to an increase in customer demand. We anticipate a need for additional energy supply in both Colorado and Minnesota during the next 15 years. Additionally, we continue to focus on enhancing the reliability of our electrical system, which includes making signiﬁcant investment in our transmission and distribution systems. Over the past five years, we’ve divested 10 businesses or subsidiaries that were not closely linked to our core electric and natural gas businesses, realizing cash proceeds of nearly $440 million. Today, we’re a vertically integrated utility and we intend to stay that way. Our strategy of Building the Core has three phases. The ﬁrst phase is obtaining legislative and regulatory support for our large investment initiatives prior to making the investment. To avoid excessive risk for the company, it is critical to reduce regulatory uncertainty before making large capital investments. We accomplished this for both the Metro Emission Reduction Project (MERP) in Minnesota and the Comanche 3 coal plant in Colorado. Transmission legislation has been passed in Minnesota, allowing that state’s regulatory commission to approve recovery for transmission investments without ﬁling a general rate case. In Texas, the legislature authorized annual recovery for transmission infrastructure improvements. Both pieces of legislation will support necessary new investment in our transmission system. The second phase is making those investments. In a normal year, we spend approximately $1 billion on capital projects. In addition to our base level of capital investment, we expect to spend approximately $1 billion on MERP and $1 billion on Comanche 3 through 2010. As a result of these investments, as well as continued investments in our transmission and distribution system to ensure continued reliability and to meet our customer growth requirements, we expect that our rate base, or the amount on which we earn a return, will grow annually by slightly more than 4 percent on average. Finally, such investments will always be made with a clear focus on optimizing environmental protection, a signiﬁcant priority for Xcel Energy. 16 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S The third phase is earning a fair return on our investments. To ensure that we earn a fair return, our regulatory strategy is to receive regulatory approval for rate riders as well as general rate cases. A rate rider is a mechanism that allows us to recover certain costs and returns on investments without the costs and delays of ﬁling a rate case. These riders allow for timely revenue recovery and are good mechanisms to recover the costs of large projects or other costs that vary over time. As an example, a rider for MERP went into effect in January 2006, allowing us to earn a return on the project while the facility is being constructed. We also are ﬁling general rate cases to increase revenue recovery in most of the states in which we operate. In 2005, we ﬁled several rate cases as part of our regulatory strategy. These rate cases, and others that we plan to file in 2006, are some of the building blocks of our earnings growth plan. Following is the current status of these initiatives: – We reached constructive decisions in the Colorado natural gas case and Wisconsin electric and natural gas cases, which will increase revenue in 2006 (see Factors Affecting Results of Continuing Operations for further discussion). – We are on track with the Minnesota electric case, where interim rates, subject to refund, went into effect in January 2006. We expect a decision in the third quarter of this year. – Later in the year we plan to file electric cases in Colorado, Texas, New Mexico, and possibly North Dakota and South Dakota. If we are successful, these cases should increase revenue and earnings in 2007. Our regulatory strategy is based on ﬁling reasonable rate requests designed to provide recovery of legitimate expenses and a return on our utility investments. We believe that our commissions will provide us with reasonable recovery, and it’s important to note that our ﬁnancial plans include this assumption. Recent constructive results, along with past rulings, are evidence of reasonable regulatory treatment and give us conﬁdence that we are pursuing the right strategy. With any strategic plan, there are goals and objectives. We feel the following ﬁnancial objectives are both realistic and achievable: – Annual earnings-per-share growth rate target of 5 percent to 7 percent from 2005–2009; – Annual dividend increases of 2 percent to 4 percent; and – Senior unsecured debt credit ratings in the BBB+ to A range. Successful execution of our Building the Core strategic plan should allow us to achieve our ﬁnancial objectives, which in turn should provide investors with an attractive total return on a low-risk investment. FINANCIAL REVIEW 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 Consolidated Financial Statements and Notes. All note references refer to the Notes to Consolidated Financial Statements. S U M M A RY O F F I N A N C I A L R E S U LT S The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of generally accepted accounting principles (GAAP). Continuing operations consist of the following: – Regulated utility subsidiaries, operating in the electric and natural gas segments; and – Several nonregulated subsidiaries and the holding company, where corporate ﬁnancing activity occurs. Discontinued operations consist of the following: – Quixx Corp., which was classiﬁed as held for sale in the third quarter of 2005 based on a decision to divest this investment; – Utility Engineering Corp., which was sold in April 2005; – Seren, a portion of which was sold in November 2005, with the remainder sold in January 2006; – Viking and BMG, which were sold in 2003; – Cheyenne, which was sold in January 2005; – NRG, which emerged from bankruptcy and was divested in late 2003; and – Xcel Energy International and e prime, which were classiﬁed as held for sale in late 2003 based on the decision to divest them. Certain items in the statements of operations have been reclassified from prior-period presentation to conform to the 2005 presentation. See Note 2 to the Consolidated Financial Statements for a further discussion of discontinued operations. Contribution to earnings (Millions of dollars) 2005 2004 2003 GAAP income (loss) by segment Regulated electric utility segment income – continuing operations Regulated natural gas utility segment income – continuing operations Other utility results (a) Total utility segment income – continuing operations Holding company costs and other results (a) Total income – continuing operations Regulated utility income (loss) – discontinued operations NRG loss – discontinued operations Other nonregulated income (loss) – discontinued operations (b) Total income (loss) – discontinued operations Total GAAP net income $440.6 71.2 27.6 539.4 (40.3) 499.1 0.2 (1.1) 14.8 13.9 $513.0 $466.3 86.1 6.1 558.5 (36.2) 522.3 (9.0) – (157.3) (166.3) $356.0 $461.3 94.1 6.0 561.4 (38.6) 522.8 26.8 (251.4) 324.2 99.6 $622.4 XCEL ENERGY 2005 ANNUAL REPORT 17 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Contribution to earnings per share 2005 2004 2003 GAAP earnings (loss) per share contribution by segment Regulated electric utility segment – continuing operations Regulated natural gas utility segment – continuing operations Other utility results (a) Total utility segment earnings per share – continuing operations Holding company costs and other results (a) Total earnings per share – continuing operations Regulated utility earnings (loss) – discontinued operations NRG loss – discontinued operations Other nonregulated earnings (loss) – discontinued operations (b) Total earnings (loss) per share – discontinued operations Total GAAP earnings per share – diluted $1.04 0.17 0.06 1.27 (0.07) 1.20 – – 0.03 0.03 $1.23 $1.10 0.20 0.02 1.32 (0.06) 1.26 (0.02) – (0.37) (0.39) $0.87 $1.10 0.22 0.01 1.33 (0.07) 1.26 0.06 (0.60) 0.78 0.24 $1.50 (a) Not a reportable segment. Included in All Other segment results in Note 17 to the Consolidated Financial Statements. (b) Includes tax beneﬁt related to NRG. See Note 2 to the Consolidated Financial Statements. Earnings from continuing operations for 2005 were lower than in 2004. The 2005 results had higher operating margins, which were offset by higher operating and maintenance expenses, including scheduled nuclear plant outages in 2005, higher employee benefit costs, higher uncollectible receivable expense and higher depreciation expense. In addition, tax expense recorded in 2005 was higher than 2004, primarily attributable to tax benefits recorded in 2004 related to the successful resolution of various income tax audit issues. While earnings from continuing operations for 2004 were ﬂat compared with 2003, 2004 results were favorably impacted by electric sales growth, short-term wholesale markets and lower depreciation, offset by the negative impact of unfavorable weather, legal settlement costs and the impact of certain regulatory accruals, compared with the same period in 2003. Income from discontinued operations in 2005 includes the positive impact of a $17 million tax beneﬁt recorded to reﬂect the ﬁnal resolution of Xcel Energy’s divested interest in NRG. This was partially offset by Seren’s operating losses during 2005. The loss from discontinued operations in 2004 is largely due to an after-tax impairment charge of $143 million, or 34 cents per share, related to Seren. In addition, the loss from discontinued operations in 2004 is attributable in part to an after-tax loss of $13 million, or 3 cents per share, associated with the disposition of Cheyenne. The earnings in 2003 from discontinued operations are primarily due to an adjustment to previously estimated tax beneﬁts related to Xcel Energy’s write-off of its investment in NRG. Results from discontinued operations are discussed in the Discontinued Operations section later. Weather Xcel Energy’s earnings can be signiﬁcantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce expenses. The 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 has used per degree of temperature. The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from historical averages: – Weather in 2005 increased earnings by an estimated 3 cents per share; – Weather in 2004 decreased earnings by an estimated 8 cents per share; and – Weather in 2003 was close to normal and had minimal impact on earnings per share. STAT E M E N T O F O P E R AT I O N S A N A LYS I S – C O N T I N U I N G O P E R AT I O N S The following discussion summarizes the items that affected the individual revenue and expense items reported in the Consolidated Statements of Operations. E L E C T R I C U T I L I T Y, S H O RT- T E R M W H O L E SA L E A N D C O M M O D I T Y T R A D I N G M A R G I N S 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 retail customers in several states, most ﬂuctuations in these costs do not materially affect electric utility margin. Xcel Energy has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy-related purchase and sales activity, and the use of certain financial instruments associated with the fuel required for, and energy produced from, Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Commodity trading is not associated with Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Short-term wholesale and commodity trading activities are considered part of the electric utility segment. Short-term wholesale and commodity trading margins reﬂect the estimated impact of regulatory sharing, if applicable. Commodity trading revenues are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Operations. Commodity trading costs include purchased power, transmission, broker fees and other related costs. 18 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities: (Millions of dollars) 2005 Electric utility revenue (excluding commodity trading) Fuel and purchased power Commodity trading revenue Commodity trading costs Gross margin before operating expenses Margin as a percentage of revenue 2004 Electric utility revenue (excluding commodity trading) Fuel and purchased power Commodity trading revenue Commodity trading costs Gross margin before operating expenses Margin as a percentage of revenue 2003 Electric utility revenue (excluding commodity trading) Fuel and purchased power Commodity trading revenue Commodity trading costs Gross margin before operating expenses Margin as a percentage of revenue Base Electric Utility Short-Term Wholesale Commodity Trading Consolidated Totals $ 7,038 (3,802) – – $3,236 46.0% $5,989 (2,916) – – $3,073 51.3% $5,724 (2,588) – – $3,136 54.8% $196 (120) – – $ 76 38.8% $220 (125) – – $ 95 43.2% $179 (118) – – $ 61 34.1% $ – – 730 (720) $ 10 1.4% $ – – 610 (594) $ 16 2.6% $ – – 333 (316) $ 17 5.1% $ 7,234 (3,922) 730 (720) $3,322 41.7% $6,209 (3,041) 610 (594) $3,184 46.7% $5,903 (2,706) 333 (316) $3,214 51.5% The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the years ended Dec. 31: Base Electric Utility Revenue (Millions of dollars) Sales growth (excluding weather impact) Estimated impact of weather Fuel and purchased power cost recovery Firm wholesale Capacity sales Quality-of-service obligations Conservation and non-fuel riders Texas fuel reconciliation settlement Other Total base electric utility revenue increase 2005 vs. 2004 2004 vs. 2003 $ 57 91 706 67 15 7 16 21 69 $1,049 $ 73 (74) 230 62 (2) (12) (5) (25) 18 $265 2005 Comparison with 2004 Base electric revenues increased due to higher fuel and purchased power costs, which are largely recovered from customers; weather-normalized retail sales growth of approximately 1.4 percent; higher sales attributable to warmer than normal summer temperatures in 2005; higher revenues from firm wholesale customers; and lower regulatory accruals related to the Texas fuel reconciliation settlement. 2004 Comparison with 2003 Base electric utility revenues increased due to higher fuel and purchased power costs, which are largely recovered from customers; weather-normalized retail sales growth of approximately 1.8 percent; and higher revenues from ﬁrm wholesale customers. Partially offsetting the higher revenues was the impact of signiﬁcantly cooler summer temperatures in 2004, compared with the summer of 2003, as well as estimated customer refunds related to quality-of-service obligations in Colorado and the estimated Texas fuel reconciliation settlement. Base Electric Utility Margin (Millions of dollars) Estimated impact of weather on sales Sales growth (excluding weather impact) Conservation and non-fuel revenue Texas fuel reconciliation settlement Quality-of-service obligations Under-recovery of fuel costs (NSP-Wisconsin) Under-recovery and timing of recovery of fuel costs (other jurisdictions) Firm wholesale Pricing and other Total base electric utility margin increase (decrease) 2005 vs. 2004 2004 vs. 2003 $ 75 42 16 21 7 (15) (14) 23 8 $163 $(56) 55 (6) (25) (12) (10) (20) 27 (16) $(63) XCEL ENERGY 2005 ANNUAL REPORT 19 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S 2005 Comparison to 2004 Base electric utility margin increased due to the impact of weather, weather-normalized sales growth, higher ﬁrm wholesale margins, higher conservation and non-fuel rider revenues and lower accruals related to the fuel reconciliation proceedings in Texas, partially offset by higher amortization expense and lower regulatory accruals associated with potential customer refunds related to service-quality obligations in Colorado. These increases were partially offset by higher fuel and purchased energy costs not recovered through direct pass-through recovery mechanisms. 2004 Comparison to 2003 Base electric utility margin decreased due to the impact of weather, higher fuel and purchased energy costs not recovered through direct pass-through recovery mechanisms and regulatory accruals associated with potential customer refunds related to service-quality obligations in Colorado and fuel-reconciliation proceedings in Texas. These decreases were partially offset by weather-normalized sales growth. Short-Term Wholesale and Commodity Trading Margin 2005 Comparison to 2004 Short-term wholesale and commodity trading margins decreased $25 million for 2005 compared with 2004. The higher 2004 results reﬂect the impact of more favorable market conditions and higher levels of surplus generation available to sell. In addition, a pre-existing contract contributed $17 million of margin in the ﬁrst quarter of 2004 and expired at that time. 2004 Comparison to 2003 Short-term wholesale and commodity trading margins increased approximately $33 million in 2004 compared with 2003. The increase reﬂects a number of market factors, including higher market prices and additional resources available for sale, and the pre-existing contract described above. N AT U R A L G AS U T I L I T Y M A R G I N S The following table details the changes in natural gas utility revenue and margin. The cost of natural gas tends to vary with changing sales requirements and the unit cost of wholesale natural gas purchases. However, due to purchased natural gas cost-recovery mechanisms for sales to retail customers, fluctuations in the wholesale cost of natural gas have little effect on natural gas margin. See further discussion under Factors Affecting Results of Continuing Operations. (Millions of dollars) Natural gas utility revenue Cost of natural gas purchased and transported Natural gas utility margin 2005 $2,307 (1,823) $ 484 2004 $1,916 (1,446) $ 470 2003 $1,678 (1,191) $ 487 The following summarizes the components of the changes in natural gas revenue and margin for the years ended Dec. 31: Natural Gas Revenue (Millions of dollars) Sales growth (excluding weather impact) Purchased natural gas adjustment clause recovery Rate changes – Colorado, Minnesota and North Dakota Estimated impact of weather Transportation and other Total natural gas revenue increase 2005 vs. 2004 2004 vs. 2003 $ – 397 6 (5) (7) $391 $ (3) 257 (15) (10) 9 $238 2005 Comparison to 2004 Natural gas revenue increased primarily due to higher natural gas costs in 2005, which are recovered from customers. Retail natural gas weather-normalized sales were ﬂat when compared to 2004, largely due to the rising cost of natural gas and its impact on customer usage. 2004 Comparison to 2003 Natural gas revenue increased primarily due to higher natural gas costs in 2004, which are recovered from customers. Retail natural gas weather-normalized sales declined in 2004, largely due to the rising cost of natural gas and its impact on customer usage. Natural Gas Margin (Millions of dollars) Sales growth (excluding weather impact) Estimated impact of weather on ﬁrm sales Rate changes – Colorado, Minnesota and North Dakota Transportation Other Total natural gas margin increase (decrease) 2005 vs. 2004 2004 vs. 2003 $ 1 (2) 6 6 3 $14 $ – (5) (15) 1 2 $(17) 2005 Comparison to 2004 Natural gas margin increased due to rate changes in Minnesota and North Dakota, and higher transportation margins, partially offset by the impact of warmer winter temperatures in 2005 compared with 2004. 2004 Comparison to 2003 Natural gas margin decreased due to a full year of a base rate decrease in Colorado, which was effective July 1, 2003, and the impact of warmer winter temperatures in 2004 compared with 2003. 20 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S N O N R EG U L AT E D O P E R AT I N G M A R G I N S The following table details the changes in nonregulated revenue and margin included in continuing operations: (Millions of dollars) Nonregulated and other revenue Nonregulated cost of goods sold Nonregulated margin 2005 2004 $74 (25) $49 $75 (29) $46 2003 $134 (81) $ 53 2004 Comparison to 2003 Nonregulated revenue decreased in 2004, due primarily to the discontinued consolidation of an investment in an independent power-producing entity that was no longer majority owned. N O N- F U E L O P E R AT I N G E X P E N S E S A N D OT H E R I T E M S Other Utility Operating and Maintenance Expenses Other operating and maintenance expenses for 2005 increased by approximately $87 million, or 5.5 percent, compared with 2004. An outage at the Monticello nuclear plant and higher outage costs at Prairie Island in 2005 increased costs by approximately $26 million. Employee beneﬁt costs were higher in 2005, primarily due to increased pension benefits and long-term disability costs. Also contributing to the increase were higher uncollectible receivable costs, attributable in part to modifications to the bankruptcy laws, higher fuel prices and certain changes in the credit and collections process. Other operating and maintenance expenses for 2004 increased by approximately $21 million, or 1.4 percent, compared with 2003. Of the increase, $12 million was incurred to assist with the storm damage repair in Florida and was offset by increased revenue. The remaining increase of $9 million is primarily due to higher electric service reliability costs, higher information technology costs, higher plant-related costs, higher costs related to a customer billing system conversion and increased costs primarily related to compliance with the Sarbanes-Oxley Act of 2002. The higher costs were partially offset by lower employee beneﬁt and compensation costs and lower nuclear plant outage costs. (Millions of dollars) 2005 vs. 2004 2004 vs. 2003 Higher (lower) employee beneﬁt costs Higher (lower) nuclear plant outage costs Higher uncollectible receivable costs Higher donations to energy assistance programs Higher mutual aid assistance costs Higher electric service reliability costs Higher (lower) information technology costs Higher (lower) plant-related costs Higher costs related to customer billing system conversion Higher costs to comply with Sarbanes-Oxley Act of 2002 Other Total operating and maintenance expense increase $ 31 26 19 4 1 9 (6) (7) 4 – 6 $ 87 $(12) (13) 2 1 12 9 8 4 4 4 2 $ 21 Other Nonregulated Operating and Maintenance Expenses Other nonregulated operating and maintenance expenses decreased $16 million, or 35.4 percent, in 2005 compared with 2004, primarily due to the accrual of $18 million in 2004 for a settlement agreement related to shareholder lawsuits. Other nonregulated operating and maintenance expenses decreased $9 million, or 17.5 percent, in 2004 compared with 2003. This decrease resulted from the dissolution of Planergy International and the discontinued consolidation of an investment in an independent power- producing entity that was no longer majority owned after the divestiture of NRG. Depreciation and Amortization Depreciation and amortization expense for 2005 increased by approximately $61 million, or 8.7 percent, compared with 2004. The changes were primarily due to the installation of new steam generators at Unit 1 of the Prairie Island nuclear plant and software system additions, both of which have relatively short depreciable lives compared with other capital additions. The Prairie Island steam generators are being depreciated over the remaining life of the plant operating license, which expires in 2013. In addition, the Minnesota Renewable Development Fund and renewable cost-recovery amortization, which is recovered in revenue as a non-fuel rider and does not have an impact on net income, increased over 2004. The increase was partially offset by the changes in useful lives and net salvage rates approved by Minnesota regulators in August 2005. Depreciation and amortization expense for 2004 decreased by $21 million, or 2.9 percent, compared with 2003. The reduction is largely due to several regulatory decisions. In 2004, as a result of a Minnesota Public Utilities Commission (MPUC) order, NSP-Minnesota modified its decommissioning expense recognition, which served to reduce decommissioning accruals by approximately $18 million in 2004 compared with 2003. In addition, effective July 1, 2003, the Colorado Public Utilities Commission (CPUC) lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, reducing annual depreciation expense by $20 million. PSCo experienced the full impact of the annual reduction in 2004, resulting in a decrease in depreciation expense of $10 million for 2004 compared with 2003. These decreases were partially offset by plant additions. XCEL ENERGY 2005 ANNUAL REPORT 21 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Interest and Other Income (Expense), Net Interest and other income (expense), net decreased $8 million in 2005 compared with 2004. The decrease is due to interest income related to the finalization of prior-period IRS audits of $10.5 million in 2004, partially offset by a $2.2 million gain on the sale of water rights in 2005. Interest and other income, net of nonoperating expenses increased $15 million in 2004 compared with 2003. The increase is due mostly to interest income related to the ﬁnalization of prior-period IRS audits of $10.5 million. Interest and Financing Costs The 2005 interest charges and financing costs increased approximately $8 million, or 1.9 percent when compared with 2004, primarily due to increased short-term borrowing levels. The 2004 interest charges and ﬁnancing costs decreased approximately $17 million, or 3.7 percent when compared with 2003. The decrease for the year reﬂects savings from reﬁnancing higher coupon debt during 2003 and lower credit line fees, partially offset by interest expense related to prior-period IRS audits. Income Tax Expense The effective income tax rate for continuing operations was 25.8 percent for 2005, compared with 23.7 percent in 2004. Income taxes recorded in 2005 reﬂect tax beneﬁts of $10.0 million, primarily from increased research credits and a net operating loss carry back. Excluding the tax beneﬁts, the effective rate for 2005 would have been 27.3 percent. In 2004, income tax beneﬁts of $37.1 million were recorded, which included $22.3 million related to the successful resolution of various audit issues and other adjustments to current and deferred taxes. The effective income tax rate for continuing operations was 23.7 percent for 2004, compared with 24.6 percent for the same period in 2003. Excluding the tax benefits, the effective rate for 2004 would have been 29.1 percent. See Note 8 to the Consolidated Financial Statements. H O L D I N G C O M PA N Y A N D OT H E R R E S U LT S The following tables summarize the net income and earnings-per-share contributions of the continuing operations of Xcel Energy’s nonregulated businesses and holding company results: Contribution to Xcel Energy’s earnings (Millions of dollars) Eloigne Company Financing costs – holding company Holding company and other results Total nonregulated/holding company loss – continuing operations Contribution to Xcel Energy’s earnings per share Eloigne Company Financing costs and preferred dividends – holding company Holding company and other results Total nonregulated/holding company loss per share – continuing operations 2005 $ 6.2 (52.7) 6.2 $(40.3) 2005 $ 0.01 (0.09) 0.01 $(0.07) 2004 $ 8.5 (44.7) – $(36.2) 2004 $ 0.02 (0.08) – $(0.06) 2003 $ 7.7 (44.1) (2.2) $(38.6) 2003 $ 0.02 (0.09) – $(0.07) Financing Costs and Preferred Dividends Nonregulated 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 earnings-per-share impact of ﬁnancing costs and preferred dividends for 2005, 2004 and 2003 included above reﬂects dilutive securities, as discussed further in Note 9 to the Consolidated Financial Statements. The impact of the dilutive securities, if converted, is a reduction of interest expense resulting in an increase in net income of approximately $14 million, or 3 cents per share, in 2005; $15 million, or 4 cents per share, in 2004; and $11 million, or 3 cents per share, in 2003. 22 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S STAT E M E N T O F O P E R AT I O N S A N A LYS I S – D I S C O N T I N U E D O P E R AT I O N S ( N E T O F TA X) A summary of the various components of discontinued operations is as follows for the years ended Dec. 31: Income (loss) in millions Viking Gas Transmission Co. Black Mountain Gas Cheyenne Light, Fuel and Power Co. Regulated utility segments – income (loss) NRG segment – loss NRG-related tax beneﬁts (expense) Xcel Energy International e prime Seren Utility Engineering / Quixx Corp. Other Nonregulated/other – income (loss) Total income (loss) from discontinued operations Income (loss) per share Viking Gas Transmission Co. Black Mountain Gas Cheyenne Light, Fuel and Power Co. Regulated utility segments – income per share NRG segment – loss per share NRG-related tax beneﬁts (expense) Xcel Energy International e prime Seren Utility Engineering / Quixx Corp. Other Nonregulated/other – income (loss) per share Total income (loss) per share from discontinued operations 2005 2004 2003 $ – – 0.2 0.2 (1.1) 17.2 0.1 (0.1) 1.8 (4.4) 0.2 14.8 $13.9 $ – – – – – 0.04 – – – (0.01) – 0.03 $0.03 $ 1.3 – (10.3) (9.0) $ 21.9 2.4 2.5 26.8 – (251.4) (12.8) 7.3 (1.8) (156.6) 4.7 1.9 (157.3) $(166.3) $ – – (0.02) (0.02) 404.4 (45.5) (17.8) (18.3) 3.0 (1.6) 324.2 $ 99.6 $ 0.05 0.01 – 0.06 – (0.60) (0.03) 0.02 – (0.37) 0.01 – (0.37) $ (0.39) 0.96 (0.11) (0.04) (0.04) 0.01 – 0.78 $ 0.24 R EG U L AT E D U T I L I T Y R E S U LT S – D I S C O NT I N U E D O P E R AT I O N S In January 2004, Xcel Energy agreed to sell Cheyenne. Consequently, Xcel Energy reported Cheyenne results as a component of discontinued operations for all periods presented. The sale was completed in January 2005 and resulted in an after-tax loss of approximately $13 million, or 3 cents per share, which was accrued in December 2004. During 2003, Xcel Energy sold Viking and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded primarily related to the sale of Viking. Xcel Energy recorded minimal income related to Viking in 2003, due to its sale in January of that year. N R G R E S U LT S – D I S C O NT I N U E D O P E R AT I O N S Xcel Energy’s share of NRG results for 2003 is shown as a component of discontinued operations due to NRG’s emergence from bankruptcy in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG. Xcel Energy ﬁnancial statements do not contain any results of NRG operations in 2005 and 2004. NRG’s results included in Xcel Energy’s earnings for 2003 were as follows: (Millions of dollars) Six months ended June 30, 2003 Total NRG loss Losses not recorded by Xcel Energy under the equity method* Equity in losses of NRG included in Xcel Energy results for 2003 $(621) 370 $(251) * These represent NRG losses incurred in the ﬁrst and second quarters of 2003 that were in excess of the amounts recordable by Xcel Energy under the equity method of accounting limitations. As of the bankruptcy ﬁling date (May 14, 2003), Xcel Energy had recognized $263 million of NRG’s impairments and related charges as these charges were recorded by NRG prior to May 14, 2003. Consequently, Xcel Energy recorded its equity in NRG results in excess of its ﬁnancial commitment to NRG under the settlement agreement reached in March 2003 among Xcel Energy, NRG and NRG’s creditors. These excess losses were reversed upon NRG’s emergence from bankruptcy in December 2003. XCEL ENERGY 2005 ANNUAL REPORT 23 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S OT H E R N O N R EG U L AT E D R E S U LT S – D I S C O NT I N U E D O P E R AT I O N S In April 2005, Zachry Group, Inc. acquired all of the outstanding shares of UE, a nonregulated subsidiary. In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx Corp., a former subsidiary of UE that partners in cogeneration projects and was not included in the sale of UE to Zachry. As a result, Xcel Energy is reporting UE and Quixx as components of discontinued operations for all periods presented. In September 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren. As a result of the decision, Seren is accounted for as discontinued operations. In November 2005, Xcel Energy sold Seren’s California assets to WaveDivision Holdings, LLC. In January 2006, Xcel Energy sold Seren’s Minnesota assets to Charter Communications. During 2003, Xcel Energy’s board of directors approved management’s plan to exit businesses conducted by e prime and Xcel Energy International. e prime ceased conducting business in 2004. Also during 2004, Xcel Energy completed the sales of the Argentina subsidiaries of Xcel Energy International. 2005 Nonregulated Results Compared with 2004 Results of discontinued nonregulated operations in 2005 include the impact of a $5 million reduction to the original asset impairment for Seren and the positive impact of a $17 million tax beneﬁt recorded to reﬂect the ﬁnal resolution of Xcel Energy’s divested interest in NRG. In 2004, the NRG tax basis study was updated and previously recognized tax beneﬁts were reduced by $13 million. 2004 Nonregulated Results Compared with 2003 Results of discontinued nonregulated operations in 2004 include the impact of the sales of the Argentina subsidiaries of Xcel Energy International. The sales were completed in three transactions, with a total sales price of approximately $31 million. In addition to the sales price, Xcel Energy also received approximately $21 million at the closing of one transaction as redemption of its capital investment. The sales resulted in a gain of approximately $8 million, including approximately $7 million of income tax beneﬁts realizable upon the sale of the Xcel Energy International assets. In addition, 2004 results from discontinued operations include the impact of an after-tax impairment charge for Seren of $143 million, or 34 cents per share. The impairment charge was recorded based on operating results, market conditions and preliminary feedback from prospective buyers. Tax Benefits Related to Investment in NRG Xcel Energy has recognized tax benefits related to the divestiture of NRG. Since these tax benefits are related to Xcel Energy’s investment in discontinued NRG operations, they are reported as discontinued operations. During 2002, Xcel Energy recognized an initial estimate of the expected tax beneﬁts of $706 million. Based on the results of a 2003 preliminary tax basis study of NRG, Xcel Energy recorded $404 million of additional tax beneﬁts in 2003. In 2004, the NRG basis study was updated and previously recognized tax benefits were reduced by $13 million. In 2005, a $17 million tax benefit was recorded to reflect the final federal income tax resolution of Xcel Energy’s divested interest in NRG. Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings from these tax beneﬁts through a refund of taxes paid in prior years and reduced taxes payable in future years. In 2005, 2004 and 2003, Xcel Energy used $24 million, $345 million and $116 million, respectively, of these tax benefits, and expects to use $180 million in 2006. The remainder of the tax benefit carry forward is expected to be used over subsequent years. FAC TO R S A F F E C T I N G R E S U LT S O F C O N T I N U I N G O P E R AT I O N S Xcel Energy’s utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions and affect Xcel Energy’s ability to recover its costs from customers. The historical and future trends of Xcel Energy’s operating results have been, and are expected to be, affected by a number of factors, including the following: General Economic Conditions Economic conditions may have a material impact on Xcel Energy’s operating results. The United States economy continues to grow as measured by projected growth in the gross domestic product. Management cannot predict the impact of a future economic slowdown, ﬂuctuating energy prices, terrorist activity, war or the threat of war. However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to raise capital resulting from a general slowdown in future economic growth or a signiﬁcant increase in interest rates. Sales Growth In addition to the impact of weather, customer sales levels in Xcel Energy’s utility businesses can vary with economic conditions, energy prices, customer usage patterns and other factors. Weather-normalized sales growth for retail electric utility customers was 1.4 percent in 2005 compared with 2004, and 1.8 percent in 2004 compared with 2003. Weather-normalized sales growth for ﬁrm natural gas utility customers was approximately 0.2 percent in 2005 compared with 2004, and (1.9) percent in 2004 compared with 2003. Projections indicate that weather- normalized sales growth in 2006 compared with 2005 will range between 1.3 percent and 1.7 percent for retail electric utility customers and 0.0 percent to 1.0 percent for ﬁrm natural gas utility customers. 24 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Fuel Supply and Costs Coal Deliverability Xcel Energy’s operating utilities have varying dependence on coal-ﬁred generation. At the utilities, coal-ﬁred generation comprises between 60 percent and 85 percent of the total annual generation. Approximately 70 percent of the annual coal requirements are supplied from the Powder River Basin in Wyoming. Delivery of coal from the Powder River Basin has been disrupted by train derailments and other operational problems purportedly caused by deteriorated rail track beds of approximately 140 miles in length in Wyoming. The BNSF Railway Co. (BNSF) and the Union Pacific Railroad (UPRR) jointly own the rail line. The BNSF operates and maintains the rail line. The coal delivery issues began in the first half of 2005. Based on discussions with the railroads, Xcel Energy expects that disrupted coal deliveries will continue at least through the ﬁrst part of 2006. Xcel Energy has taken a number of steps to mitigate the impact of the reduced coal deliveries. These steps include modifying the dispatch of certain generation facilities to conserve coal inventories. This modiﬁed dispatch was in place during the second half of 2005 and has continued in 2006, to date. In response to this reduced coal dispatch, Xcel Energy has increased purchases from third parties and has increased the use of natural gas for electric generation. In addition, Xcel Energy negotiated for the acquisition of additional, higher capacity rail cars and is working to upgrade certain coal-handling facilities. Delivery of the new cars began in January 2006 and will continue over the course of the year. The upgrades to the coal-handling facilities are expected to be completed in the ﬁrst half of 2006. Despite these efforts, coal inventories have declined to below target levels. While Xcel Energy has secured, under contract, approximately 99 percent of anticipated 2006 coal requirements, it cannot predict the likelihood of receiving the required coal. While Xcel Energy is planning to rebuild inventories during the year, there is no guarantee that it will be able to do so. The ultimate impact of coal availability cannot be fully assessed at this time, but could impact future financial results. The cost of purchased power and natural gas for electric generation is higher than for coal-ﬁred electric generation. The use of these sources to replace coal-ﬁred electric generation increased the price of electricity for retail and wholesale customers. Xcel Energy’s utility subsidiaries have discussed this situation with their respective state regulatory commissions. In Colorado, PSCo is subject to a retail electric adjustment clause that recovers fuel, purchased energy and resource costs. The Electric Commodity Adjustment (ECA) is an incentive adjustment mechanism that compares actual fuel and purchased energy expenses in a calendar year to a benchmark formula. The benchmark formula increases with natural gas prices, but not necessarily with increased volumes of natural gas usage due to coal supply disruption. Therefore, any disruption in coal supply could adversely affect fuel cost recovery. For 2005, PSCo recorded an incentive accrual of $8.5 million. The ECA provides for an $11.25 million cap on any cost sharing over or under the allowed ECA formula rate. Any cost in excess of the $11.25 million cap is completely recovered from customers, while any savings in excess of the $11.25 million cap is completely refunded to customers. Subject to the terms of the ECA, PSCo anticipates it would recover any increased fuel and purchased energy costs greater than the cap from its customers. Natural gas prices in 2005 were higher than projected when the ECA tariff rates were set in January 2005. On Oct. 5, 2005, PSCo ﬁled an application to adjust the ECA rate for November and December 2005 to reduce the ECA deferred balance and to update its projection of natural gas prices. This application was granted, which resulted in an increase to 2005 electric revenue of approximately $70 million, including unbilled revenues. As of Dec. 31, 2005, PSCo was carrying a deferred ECA balance, including unbilled revenue, of approximately $15 million. In Texas, fuel and purchased energy costs are recovered through a ﬁxed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates. If SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the Public Utility Commission of Texas (PUCT). The regulations require surcharging of under-recovered amounts, including interest, when they exceed 4 percent of SPS’ annual fuel and purchased energy costs, as allowed by the PUCT, if the condition is expected to continue. On Dec. 21, 2005, SPS reached a settlement with various parties that set the fuel surcharge request at $76.9 million, to be recovered over a 15- month period. The PUCT approved this settlement on Feb. 9, 2006, and the surcharge went into effect Feb. 13, 2006. In New Mexico, increases and decreases in fuel and purchased energy costs, including deferred amounts, are recovered through a monthly fuel and purchased power clause with a two-month lag. Wholesale customers, under the Federal Energy Regulatory Commission (FERC) jurisdiction also pay a monthly fuel cost adjustment calculated on actual fuel and purchased power costs in accordance with the FERC’s fuel clause regulations. While SPS believes that it should be allowed to recover these higher costs, the ultimate success of recovery could signiﬁcantly impact the future of SPS and possibly Xcel Energy. NSP-Minnesota’s retail electric rate schedules in the Minnesota, North Dakota and South Dakota jurisdictions include a fuel clause adjustment (FCA) to billings and revenues for changes in prudently incurred cost of fuel, fuel-related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms individually approved by the regulators in each jurisdiction. The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel-related items used to generate electricity at its plants and energy purchased from other suppliers. In general, capacity costs are not recovered through the FCA. NSP-Minnesota’s electric wholesale customers also have an FCA provision in their contracts. NSP-Minnesota anticipates it will recover increased costs resulting from its mitigation plan through the FCA. In Wisconsin, NSP-Wisconsin does not have an automatic electric fuel clause adjustment for Wisconsin retail customers. NSP-Wisconsin may seek deferred accounting treatment and future rate recovery of increased costs due to an “emergency” event, if that event causes fuel and purchased power costs to exceed the amount included in rates on an annual basis by more than 2 percent. Coal deliverability has not resulted in an emergency event to date. XCEL ENERGY 2005 ANNUAL REPORT 25 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Natural Gas Costs A variety of market factors have contributed to signiﬁcantly higher natural gas prices. The direct impact of these higher costs is generally mitigated for Xcel Energy through recovery of such costs from customers through various fuel cost-recovery mechanisms. However, higher fuel costs could signiﬁcantly impact the results of operations, if requests for recovery are unsuccessful. In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on Xcel Energy’s results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases are expected to have an impact on the cash ﬂows of Xcel Energy. Xcel Energy is unable to predict the future natural gas prices or the ultimate impact of such prices on its results of operations or cash ﬂows. Pension Plan Costs and Assumptions Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future and the interest rate used to discount future pension beneﬁt payments to a present value obligation for ﬁnancial reporting. In addition, the actuarial calculation uses an asset-smoothing methodology to reduce the volatility of varying investment performance over time. Note 10 to the Consolidated Financial Statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying ﬁnancial statements. Pension costs have been increasing in recent years, and are expected to increase further over the next several years, due to lower-than-expected investment returns experienced in prior years and decreases in interest rates used to discount beneﬁt obligations. While investment returns exceeded the assumed level of 8.75 percent in 2005, 9.0 percent in 2004 and 9.25 percent in 2003, investment returns in 2002 and 2001 were below the assumed level of 9.5 percent, and discount rates have declined from the 7.25-percent to 8-percent levels used in the 1999 through 2002 cost determinations, to 6.0 percent used in 2005. Xcel Energy continually reviews its pension assumptions and, in 2006, expects to maintain the investment return assumption at 8.75 percent and to lower the discount rate assumption to 5.75 percent. The investment gains or losses resulting from the difference between the expected pension returns assumed on asset levels and actual returns earned are deferred in the year the difference arises and recognized over the subsequent ﬁve-year period. This gain or loss recognition occurs by using a ﬁve-year, moving-average value of pension assets to measure expected asset returns in the cost-determination process, and by amortizing deferred investment gains or losses over the subsequent ﬁve-year period. Based on current assumptions and the recognition of past investment gains and losses over the next ﬁve years, Xcel Energy currently projects that the pension costs recognized for ﬁnancial reporting purposes in continuing operations will increase from a credit, or negative expense, of $2.4 million in 2005 to an expense of $15.3 million in 2006 and $18.7 million in 2007. Pension costs were a credit in 2005 due to the recognized investment asset returns exceeding the other pension cost components, such as beneﬁts earned for current service and interest costs for the effects of the passage of time on discounted obligations. Xcel Energy bases its discount rate assumption on benchmark interest rates from Moody’s Investors Service (Moody’s), and has consistently benchmarked the interest rate used to derive the discount rate to the movements in the long-term corporate bond indices for bonds rated Aaa through Baa by Moody’s, which have a period to maturity comparable to our projected beneﬁt obligations. At Dec. 31, 2005, the annualized Moody’s Baa index rate was 6.21 percent, and the Aaa index rate was 5.26 percent. Accordingly, Xcel Energy lowered the discount rate to 5.75 percent as of Dec. 31, 2005. This rate was used to value the actuarial beneﬁt obligations at that date, and will be used in 2006 pension cost determinations. At Dec. 31, 2004, the annualized Moody’s Baa index rate was 6.10 percent and the Aaa index rate was 5.43 percent. The corresponding pension discount rate was 6.00 percent. If Xcel Energy were to use alternative assumptions for pension cost determinations, a 1-percent change would result in the following impact on the estimated pension costs recognized by Xcel Energy: – A 100 basis point higher rate of return, 9.75 percent, would decrease 2006 recognized pension costs by $17.0 million; – A 100 basis point lower rate of return, 7.75 percent, would increase 2006 recognized pension costs by $17.0 million; – A 100 basis point higher discount rate, 6.75 percent, would decrease 2006 recognized pension costs by $5.4 million; and – A 100 basis point lower discount rate, 4.75 percent, would increase 2006 recognized pension costs by $7.1 million. Alternative Employee Retirement Income Security Act of 1974 (ERISA) funding assumptions would also change the expected future cash funding requirements for the pension plans. Cash funding requirements can be affected by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in recent years for Xcel Energy’s pension plans, and do not require funding in 2006. Assuming that future asset return levels equal the actuarial assumption of 8.75 percent for the years 2006 and 2007, Xcel Energy projects, under current funding regulations, that no cash funding would be required for 2006 or 2007. Actual performance can affect these funding requirements signiﬁcantly. Current funding regulations are under legislative review in 2006 and, if not retained in their current form, could change these funding requirements materially. Regulation Public Utility Holding Company Act of 1935 (PUHCA) Historically, Xcel Energy has been a registered holding company under the PUHCA. As a registered holding company, Xcel Energy, its utility subsidiaries and certain of its nonutility subsidiaries have been subject to extensive regulation by the SEC under the PUHCA with respect to numerous matters, including issuances and sales of securities, acquisitions and sales of certain utility properties, payments of dividends out of capital and surplus, and intra-system sales of certain nonpower goods and services. In addition, the PUHCA generally limited the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. On Aug. 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act), signiﬁcantly changing many federal statutes and repealing the PUHCA as of Feb. 8, 2006. However, as part of the repeal of the PUHCA, the FERC was given authority to review the books and records of holding companies and their nonutility subsidiaries to the extent relevant to the charges of jurisdictional utilities, authority to review service company cost allocations, and more authority over the merger and acquisition of public utilities. With the repeal of the PUHCA, 26 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S state commissions were given similar authority to review the books and records of holding companies and their nonutility subsidiaries. Despite these increases in the FERC’s authority, Xcel Energy believes that the repeal of the PUHCA will lessen its regulatory burdens and give it more ﬂexibility in the event it were to choose to expand its utility or nonutility businesses. Besides repealing the PUHCA, the Energy Act is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and the U.S. Department of Energy (DOE). The FERC and the DOE are in various stages of rulemaking in implementing the Energy Policy Act. While the precise impact of these rulemakings cannot be determined at this time, Xcel Energy generally views the Energy Act as legislation that will enhance the utility industry going forward. Customer Rate Regulation The FERC and various state regulatory commissions regulate Xcel Energy’s utility subsidiaries. Decisions by these regulators can signiﬁcantly impact Xcel Energy’s results of operations. Xcel Energy expects to periodically ﬁle for rate changes based on changing energy market and general economic conditions. The electric and natural gas rates charged to customers of Xcel Energy’s utility subsidiaries are approved by the FERC and the regulatory commissions in the states in which they operate. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy requests changes in rates for utility services through filings with the governing commissions. Because comprehensive general rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy’s ﬁnancial results. In addition to changes in operating costs, other factors affecting rate ﬁlings are new investments, sales growth, conservation and demand-side management efforts, and the cost of capital. In addition, the return on equity authorized is set by regulatory commissions in rate proceedings. The most recently authorized electric utility returns are 11.47 percent for NSP-Minnesota; 11.0 percent for NSP-Wisconsin; 10.75 percent for PSCo; and 11.5 percent for SPS. The most recently authorized natural gas utility returns are 10.4 percent for NSP-Minnesota, 11.0 percent for NSP-Wisconsin and 10.5 percent for PSCo. Wholesale Energy Market Regulation In April 2005, a Day 2 wholesale energy market operated by the Midwest Independent Transmission System Operator, Inc. (MISO) was implemented to centrally dispatch all regional electric generation and apply a regional transmission congestion management system. MISO now centrally issues bills and payments for many costs formerly incurred directly by NSP-Minnesota and NSP-Wisconsin. Both bills and payments from MISO for participation in this centrally dispatched market are received, resulting in a net cost in serving Xcel Energy’s native load obligation. This net result is recorded as a component of operating and maintenance expenses. The MPUC issued an interim order in April 2005 allowing MISO Day 2 charges to be recovered through the NSP-Minnesota Fuel Clause Adjustment (FCA) mechanism. In December 2005, the MPUC issued a second interim order approving the recovery of certain MISO charges through the FCA mechanism, but requiring that additional charges either be recovered as part of a general rate case or through an annual review process outside the FCA mechanism, and requiring refunds of non-FCA costs. However, the December 2005 MPUC order also suspended the refund obligation until such time as it could reconsider the matter. On Feb. 9, 2006, the MPUC voted to reconsider its December 2005 order. The MPUC on reconsideration determined that parties be directed to determine which charges are appropriately in the FCA and which are more appropriately established in base rates, and report back to the MPUC in 60 days; to grant deferred accounting treatment for costs ultimately determined to be included in base rates for a period of 36 months, with recovery of deferred amounts to be reviewed in a general rate case; and that amounts collected to date through the FCA under the April and December 2005 interim orders are not subject to refund. As a result, NSP-Minnesota will be allowed to recover its prudently incurred MISO costs either through existing fuel clause mechanisms or in base rates. In March 2005, the PSCW issued an interim order allowing NSP-Wisconsin deferred accounting treatment of MISO charges. However, the PSCW staff issued an interpretive memorandum in October 2005 asserting that certain MISO costs may not be recovered through the interim fuel cost mechanism and may not be deferrable. NSP-Wisconsin and the other Wisconsin utilities contested the PSCW’s interpretation in their November comments to the PSCW. To date, NSP-Wisconsin has deferred approximately $5.7 million of MISO Day 2 costs as a regulatory asset. Xcel Energy has notiﬁed MISO that NSP-Minnesota and NSP-Wisconsin may seek to withdraw from MISO if rate recovery of Day 2 costs is not allowed. Withdrawal would require the FERC’s approval and could require Xcel Energy to pay a withdrawal fee. In addition, pursuant to the FERC’s orders, NSP-Minnesota and NSP-Wisconsin are billed for certain MISO charges associated with the loads of certain wholesale transmission service customers taking service under pre-MISO grandfathered agreements (GFA). In March 2005, Xcel Energy ﬁled for the FERC’s approval to pass through these charges to GFA customers. The FERC accepted the ﬁling subject to refund and hearing procedures. In 2005, NSP-Minnesota and NSP-Wisconsin were billed for $1.1 million of MISO charges, which have not yet been recovered from GFA customers. The likelihood of full rate recovery is uncertain at this time. In addition, Xcel Energy has ﬁled an appeal of the FERC orders. Capital Expenditure Regulation Xcel Energy’s utility subsidiaries make substantial investments in plant additions to build and upgrade power plants, and expand and maintain the reliability of the energy distribution system. In addition to ﬁling for increases in base rates charged to customers to recover the costs associated with such investments, in 2003 the CPUC and MPUC approved proposals to recover, through a rate surcharge, certain costs to upgrade generation plants and lower emissions in the Denver and Minneapolis-St. Paul metropolitan areas. These rate-recovery mechanisms are expected to provide signiﬁcant cash ﬂows to enable recovery of costs incurred on a timely basis. Future Cost Recovery Regulated public utilities are allowed to record as regulatory assets certain costs that are expected to be recovered from customers in future periods, and to record as regulatory liabilities certain income items that are expected to be refunded to customers in future periods. In contrast, nonregulated enterprises would expense these costs and recognize the income in the current period. If restructuring or other changes in the regulatory environment occur, Xcel Energy may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on Xcel Energy’s results of operations in the period the write-off is recorded. XCEL ENERGY 2005 ANNUAL REPORT 27 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S At Dec. 31, 2005, Xcel Energy reported on its balance sheet regulatory assets of approximately $963 million and regulatory liabilities of approximately $1.7 billion that would be recognized in the statement of operations in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain stranded costs not recoverable under market pricing. See Notes 1 and 16 to the Consolidated Financial Statements for further discussion of regulatory deferrals. Pending and Recently Concluded Regulatory Proceedings NSP-Minnesota Electric Rate Case In November 2005, NSP-Minnesota requested an electric rate increase of $168 million, or 8.05 percent. This increase was based on a requested 11 percent return on common equity, a projected common equity ratio to total capitalization of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006. The anticipated procedural schedule is as follows: – March 2nd – Intervenor Direct Testimony – March 30th – Rebuttal Testimony – April 13th – Surrebuttal Testimony – April 20th – April 28th – Evidentiary Hearings – May 24th – Initial Briefs – June 6th – Reply Briefs – July 6th – Administrative Law Judge Report – September 5th – MPUC Order NSP-Wisconsin 2006 General Rate Case In 2005, NSP-Wisconsin requested an electric revenue increase of $58.3 million and a natural gas revenue increase of $8.1 million, based on a 2006 test year, an 11.9 percent return on equity and a common equity ratio of 56.32 percent. On Jan. 5, 2006, the PSCW approved an electric revenue increase of $43.4 million and a natural gas revenue increase of $3.9 million, based on an 11.0 percent return on equity and a 54 percent common equity ratio target. The new rates were effective Jan. 9, 2006. The order authorized the deferral of an additional $6.5 million in costs related to nuclear decommissioning and manufactured gas plant site clean up for recovery in the next rate case. The order also prohibits NSP-Wisconsin from paying dividends above $42.7 million, if its actual calendar year average common equity ratio is or will fall below 54.03 percent. It also imposes an asymmetrical electric fuel clause bandwidth of positive 2 percent to negative 0.5 percent outside of which NSP-Wisconsin would be permitted to request or be required to change rates. PSCo Natural Gas Rate Case In 2005, PSCo ﬁled for an increase of $34.5 million in natural gas base rates in Colorado, based on a return on equity of 11.0 percent with a common equity ratio of 55.49 percent. On Jan. 19, 2006, the CPUC approved a settlement agreement between PSCo and other parties to the case. Final rates became effective Feb. 6, 2006. The terms of the settlement include: – Natural gas revenue increase of $22 million; – Return on common equity of 10.5 percent; – Earnings over 10.5 percent return on common equity will be refunded back to customers; – Common equity ratio of 55.49 percent; and – Customer charges for the residential and commercial sales classes of $10 and $20 per month, respectively. Tax Matters Interest Expense Deductibility PSCo’s wholly owned subsidiary, PSR Investments, Inc. (PSRI), owns and manages permanent life insurance policies, known as COLI policies, on some of PSCo’s employees. At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce earnings by an estimated $361 million. In 2004, Xcel Energy received formal notiﬁcation that the IRS will seek penalties. If penalties (plus associated interest) are also included, the total exposure through Dec. 31, 2005, is approximately $428 million. Xcel Energy estimates its annual earnings for 2006 would be reduced by $44 million, after tax, which represents 10 cents per share, if COLI interest expense deductions were no longer available. See Note 14 to the Consolidated Financial Statements for further discussion. COLI Dow Chemical Court Decision On Jan. 23, 2006, the 6th Circuit of the U.S. Court of Appeals issued an opinion in a federal income tax case involving the interest deductions for a COLI program at Dow Chemical Company. The 6th Circuit denied the tax deductions and reversed the decision of the trial court in the case. Xcel Energy has analyzed the impact of the Dow decision on its pending COLI litigation and concluded there are signiﬁcant factual differences between its case and the Dow case. The court’s opinion in the Dow case outlined three indicators of potential economic beneﬁts to be examined in a COLI case and noted that the outcome of COLI cases is very fact determinative. These indicators are: – Positive pre-deduction cash ﬂows; – Mortality gains; and – The buildup of cash values. In a split decision, the 6th Circuit found that the Dow COLI plans possessed none of these indicators of economic substance. However, in Xcel Energy’s COLI case, the plans were projected to have sizeable pre-deduction cash flows, based upon the relevant assumptions when purchased. Moreover, the plans presented the opportunity for mortality gains that were not eliminated either retroactively or prospectively. Xcel Energy’s COLI plans had no provision for giving back any mortality gains that it might realize. In addition, Xcel Energy’s plans had large cash value increases that were not encumbered by loans during the ﬁrst seven years of the policies. Consequently, Xcel Energy believes that the facts and circumstances of its case are stronger than Dow’s case and continues to believe its case has strong merit. 28 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Environmental Matters Environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites and monitoring of discharges to the environment. A trend of greater environmental awareness and increasingly stringent regulation has caused, and may continue to cause, higher operating expenses and capital expenditures for environmental compliance. In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to operating expenses for environmental monitoring and disposal of hazardous materials and waste were approximately: – $147 million in 2005; – $133 million in 2004; and – $133 million in 2003. Xcel Energy expects to expense an average of approximately $176 million per year from 2006 through 2010 for similar costs. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain. Capital expenditures placed in service on environmental improvements at regulated facilities were approximately: – $37.1 million in 2005; – $20.9 million in 2004; and – $58.5 million in 2003. The regulated utilities expect to incur approximately $438 million in capital expenditures for compliance with environmental regulations and environmental improvements in 2006, and approximately $714 million of related expenditures during the period from 2007 through 2010. Included in these amounts are expenditures to reduce emissions of generating plants in Minnesota and Colorado. Approximately $347 million and $392 million of these expenditures, respectively, are related to modiﬁcations to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area pursuant to MERP, which are recoverable from customers through cost-recovery mechanisms. Expected expenditures related to environmental modiﬁcations on Comanche Units 1 and 2 are approximately $26 million in 2006 and $62 million during the period from 2007 through 2010. The remaining expected capital expenditures relate to various other environmental projects. See Note 14 to the Consolidated Financial Statements for further discussion of Xcel Energy’s environmental contingencies. The issue of global climate change is receiving increased attention. Debate continues concerning the extent to which the earth’s climate is warming, the causes of climate variations that have been observed and the ultimate impact that might result from a changing climate. There also is considerable debate regarding public policy for the approach that the United States should follow to address the issue. The United Nations-sponsored Kyoto Protocol, which establishes greenhouse gas reduction targets for developed nations, entered into force on Feb. 16, 2005. President Bush has declared that the United States will not ratify the protocol and is opposed to legislative mandates, preferring a program based on voluntary efforts and research on new technologies. Xcel Energy is closely monitoring the issue from both scientific and policy perspectives. While it is not possible to know the eventual outcome, Xcel Energy believes the issue merits close attention and is taking actions it believes are prudent to be best positioned for a variety of possible outcomes. Xcel Energy is participating in a voluntary carbon management program and has established goals to reduce its volume of carbon dioxide emissions by 12 million tons by 2009, and to reduce carbon intensity by 7 percent by 2012. In certain regulatory jurisdictions, the evaluation process for future generating resources incorporates the risk of future carbon limits through the use of a carbon cost adder or externality costs. Xcel Energy also is involved in other projects to improve available methods for managing carbon. Impact of Nonregulated Investments In the past, Xcel Energy’s investments in nonregulated operations have had a signiﬁcant impact on its results of operations. As a result of the divestiture of NRG and other nonregulated operations, Xcel Energy does not expect that its investments in nonregulated operations will continue to have such a signiﬁcant impact on its results. Xcel Energy does not expect to make any material investments in nonregulated projects. Inflation Inﬂation at its current level is not expected to materially affect Xcel Energy’s prices or returns to shareholders. C R I T I C A L AC C O U N T I N G P O L I C I E S A N D E ST I M AT E S Preparation of the Consolidated Financial Statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the Consolidated Financial Statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the ﬁnancial and operating environment also may have a signiﬁcant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the Consolidated Financial Statements and related disclosures, even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies that are most signiﬁcant to the portrayal of Xcel Energy’s ﬁnancial condition and results, and that require management’s most difficult, subjective or complex judgments. Each of these has a higher potential likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been discussed with the audit committee of the Xcel Energy board of directors. XCEL ENERGY 2005 ANNUAL REPORT 29 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Accounting Policy Judgments/Uncertainties Affecting Application See Additional Discussion At Regulatory Mechanisms and Cost Recovery – External regulatory decisions, requirements and regulatory environment – Anticipated future regulatory decisions and their impact Management’s Discussion and Analysis: Factors Affecting Results of Continuing Operations Regulation Notes to Consolidated Financial Statements – Impact of deregulation and competition on Notes 1, 14 and 16 ratemaking process and ability to recover costs Nuclear Plant Decommissioning and Cost Recovery – Costs of future decommissioning – Availability of facilities for waste disposal – Approved methods for waste disposal – Useful lives of nuclear power plants – Future recovery of plant investment and decommissioning costs Notes to Consolidated Financial Statements Notes 1, 14 and 15 Income Tax Accruals – Application of tax statutes and regulations to transactions Management’s Discussion and Analysis: Factors Affecting Results of Continuing Operations – Anticipated future decisions of tax authorities – Ability of tax authority decisions/positions to withstand legal challenges and appeals – Ability to realize tax beneﬁts through carry backs to prior periods or carry overs to future periods Tax Matters Notes to Consolidated Financial Statements Notes 1, 8 and 14 Beneﬁt Plan Accounting – Future rate of return on pension and other plan assets, including impact of any changes to investment portfolio composition Management’s Discussion and Analysis: Factors Affecting Results of Continuing Operations Pension Plan Costs and Assumptions – Discount rates used in valuing beneﬁt obligation Notes to Consolidated Financial Statements – Actuarial period selected to recognize deferred Notes 1 and 10 investment gains and losses Asset Valuation – Regional economic conditions affecting asset Management’s Discussion and Analysis: operation, market prices and related cash ﬂows Results of Operations – Regulatory and political environments and requirements Statement of Operations Analysis Discontinued Operations – Levels of future market penetration and Factors Affecting Results of Continuing Operations customer growth Impact of Nonregulated Investments Notes to Consolidated Financial Statements Note 2 Xcel Energy continually makes informed judgments and estimates related to these critical accounting policy areas, based on an evaluation of the varying assumptions and uncertainties for each area. For example: – Probable outcomes of regulatory proceedings are assessed in cases of requested cost recovery or other approvals from regulators. – The ability to operate plant facilities and recover the related costs over their useful operating lives, or such other period designated by Xcel Energy’s regulators, is assumed. – Probable outcomes of reviews and challenges raised by tax authorities, including appeals and litigation where necessary, are assessed. – Projections are made regarding earnings on pension investments, and the salary increases provided to employees over their periods of service. – Future cash inﬂows of operations are projected in order to assess whether they will be sufﬁcient to recover future cash outﬂows, including the impact of product price changes and market penetration to customer groups. The information and assumptions underlying many of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reﬂect the events and updated information that becomes available. The accompanying ﬁnancial statements reﬂect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2005. R E C E N T LY I M P L E M E N T E D AC C O U N T I N G C H A N G E S For a discussion of signiﬁcant accounting policies, see Note 1 to the Consolidated Financial Statements. P E N D I N G AC C O U NT I N G C H A N G E S Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004) – “Share Based Payment” (SFAS No. 123R) In December 2004, the FASB issued SFAS No. 123R related to equity-based compensation. This statement replaces the original SFAS No. 123 – “Accounting for Stock-Based Compensation.” Under SFAS No. 123R, companies are no longer allowed to account for their share-based payment awards using the intrinsic value allowed by previous accounting requirements, which did not require any expense to be recorded on stock options granted with an equal to or greater than fair market value exercise price. Instead, equity-based compensation arrangements will be 30 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S measured and recognized based on the grant-date fair value using an option-pricing model (such as Black-Scholes or Binomial) that considers at least six factors identiﬁed in SFAS No. 123R. An expense related to the difference between the grant-date fair value and the purchase price would be recognized over the vesting period of the options. Under previous guidance, companies were allowed to initially estimate forfeitures or recognize them as they actually occurred. SFAS No. 123R requires companies to estimate forfeitures on the date of grant and to adjust that estimate when information becomes available that suggests actual forfeitures will differ from previous estimates. Revisions to forfeiture estimates will be recorded as a cumulative effect of a change in accounting estimate in the period in which the revision occurs. Previous accounting guidance allowed for compensation expense related to performance share plans to be reversed if the target was not met. However, under SFAS No. 123R, compensation expense for performance share plans that expire unexercised due to the company’s failure to reach a certain target stock price cannot be reversed. Any accruals made for Xcel Energy’s restricted stock unit plan that were granted in 2004 and based on a total shareholder return could not be reversed if the target was not met. Implementation of SFAS No. 123R is required for annual periods beginning after June 15, 2005. Xcel Energy is required to adopt the provisions in the ﬁrst quarter of 2006. Implementation is not expected to have a material impact on net income or earnings per share. Accounting for Uncertain Tax Positions In July 2004, the FASB discussed potential changes or clariﬁcations in the criteria for recognition of income tax beneﬁts, which may result in raising the threshold for recognizing tax beneﬁts that have some degree of uncertainty. In July 2005, the FASB issued an exposure draft on accounting for uncertain tax positions under SFAS No. 109 – “Accounting for Income Taxes.” As issued, the exposure draft would have been effective Dec. 31, 2005, and only tax beneﬁts that meet the “probable” recognition threshold would be recognized or continue to be recognized on the effective date. Initial derecognition amounts would be reported as a cumulative effect of a change in accounting principle. Subsequent to the comment period that closed in September 2005, the FASB announced that the effective date of its new interpretation will be delayed, with a revised pronouncement to be released no earlier than the ﬁrst quarter of 2006. In redeliberations in November 2005, the FASB decided that the beneﬁt recognition approach in the exposure draft should be retained, but that the initial recognition threshold should be “more likely than not” rather than “probable.” In redeliberations on Jan. 11, 2006, the FASB addressed the issues of transition and effective date. For Xcel Energy, the new interpretation, if and when issued, is likely to be effective beginning Jan. 1, 2007, with any cumulative effect of the change reﬂected in retained earnings. Although Xcel Energy has not assessed the impact of a new recognition threshold on all of its open tax positions, based on available information, it believes that its COLI tax position meets the “more likely than not” threshold, and therefore it plans to continue to recognize all COLI tax beneﬁts in full. See Factors Affecting Results of Continuing Operations – Tax Matters for further discussion of this matter. DERIVATIVES, RISK MANAGEMENT AND MARKET RISK In the normal course of business, Xcel Energy and its subsidiaries are exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All ﬁnancial and commodity-related instruments, including derivatives, are subject to market risk. These risks, as applicable to Xcel Energy and its subsidiaries, are discussed in further detail later. Commodity Price Risk Xcel Energy and its subsidiaries are exposed to commodity price risk in their electric and natural gas operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products, and for various fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Xcel Energy’s risk-management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists. Short-Term Wholesale and Commodity Trading Risk Xcel Energy’s subsidiaries conduct various short-term wholesale and commodity trading activities, including the purchase and sale of capacity, energy and energy-related instruments. These marketing activities are primarily focused on specific regions where market knowledge and experience have been obtained and are generally less than one year in length. Xcel Energy’s risk-management policy allows management to conduct these activities within approved guidelines and limitations as approved by the company’s risk-management committee, which is made up of management personnel not directly involved in the activities governed by the policy. Certain contracts and ﬁnancial instruments within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 – “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133). The fair value of the commodity trading contracts as of Dec. 31, 2005, was as follows: (Millions of dollars) Fair value of trading contracts outstanding at Jan. 1, 2005 Contracts realized or settled during the year Fair value of trading contract additions and changes during the year Fair value of contracts outstanding at Dec. 31, 2005 $ – (6.1) 10.0 $ 3.9 XCEL ENERGY 2005 ANNUAL REPORT 31 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S As of Dec. 31, 2005, the fair values by source for the commodity trading and hedging net asset or liability balances were as follows: C O M M O D I T Y T R A D I N G C O NT R AC T S Futures/Forwards (Thousands of dollars) NSP-Minnesota PSCo Total futures/forwards fair value Options (Thousands of dollars) NSP-Minnesota PSCo Total options fair value H E D G E C O NT R AC T S Futures/Forwards (Thousands of dollars) NSP-Minnesota PSCo Total futures/forwards fair value Options (Thousands of dollars) NSP-Minnesota NSP-Wisconsin PSCo Total options fair value Source of Maturity Less than 1 Year Fair Value Maturity 1 to 3 Years Maturity Maturity Greater than 5 Years 4 to 5 Years Total Futures/ Forwards Fair Value 1 2 1 2 $ 663 15 1,352 1,382 $ 3,412 $ – 1,109 – 261 $1,370 $ – 322 – – $322 $ – – – – $ – $ 663 1,446 1,352 1,643 $ 5,104 Source of Maturity Less than 1 Year Fair Value Maturity 1 to 3 Years Maturity Maturity Greater than 5 Years 4 to 5 Years Total Options Fair Value 2 2 $ (251) (922) $(1,173) $ $ – – – $ – – $ – $ – – $ – $ (251) (922) $(1,173) Source of Maturity Less than 1 Year Fair Value Maturity 1 to 3 Years Maturity Maturity Greater than 5 Years 4 to 5 Years Total Futures/ Forwards Fair Value 2 2 $ 2,927 1,944 $ 4,871 $ $ – – – $ – – $ – $ – – $ – $ 2,927 1,944 $ 4,871 Source of Maturity Less than 1 Year Fair Value Maturity 1 to 3 Years Maturity Maturity Greater than 5 Years 4 to 5 Years Total Options Fair Value 2 2 2 $ (583) 726 (1,954) $ (1,811) $ – – 1,036 $1,036 $ – – – $ – $ – – – $ – $ (583) 726 (918) $ (775) 1 Prices actively quoted or based on actively quoted prices. 2 Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash ﬂows based upon underlying contractual terms. The models reﬂect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model. Normal purchases and sales transactions, as deﬁned by SFAS No. 133, and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not included in the commodity trading operations and are not qualifying hedges. At Dec. 31, 2005, a 10-percent increase in market prices over the next 12 months for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.7 million, whereas a 10-percent decrease would increase pretax income from continuing operations by approximately $0.8 million. Xcel Energy’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given conﬁdence interval under normal market conditions. Xcel Energy utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent conﬁdence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas. 32 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S As of Dec. 31, 2005, the VaRs for the commodity trading operations were: (Millions of dollars) Commodity trading (a) Year ended Dec. 31, 2005 Average $2.06 $1.44 (a) Comprises transactions for NSP-Minnesota, PSCo and SPS. As of Dec. 31, 2004, the VaRs for the commodity trading operations were: (Millions of dollars) Commodity trading (a) Year ended Dec. 31, 2004 Average $0.29 $0.97 (a) Comprises transactions for NSP-Minnesota, PSCo and SPS. During 2005 High $4.43 During 2004 High $2.09 Low $0.26 Low $0.27 Interest Rate Risk Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s policy allows interest rate risk to be managed through the use of ﬁxed rate debt, ﬂoating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options. Xcel Energy engages in hedges of cash ﬂow and fair value exposure. The fair value of interest rate swaps designated as cash ﬂow hedges is initially recorded in Other Comprehensive Income. Reclassiﬁcation of unrealized gains or losses on cash ﬂow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument, and generally offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or ﬁrm commitment. Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. To test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented. At Dec. 31, 2005 and 2004, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense by approximately $10.3 million and $6.8 million, respectively. See Note 12 to the Consolidated Financial Statements for a discussion of Xcel Energy and its subsidiaries’ interest rate swaps. Xcel Energy and its subsidiaries also maintain trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning, which are subject to interest rate risk and equity price risk. As of Dec. 31, 2005 and 2004, these funds were invested primarily in domestic and international equity securities and ﬁxed-rate ﬁxed-income securities. Per NRC mandates, these funds may be used only for activities related to nuclear decommissioning. The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore ﬂuctuations in equity prices or interest rates do not have an impact on earnings. Credit Risk In addition to the risks discussed previously, Xcel Energy and its subsidiaries are exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reﬂect changes and scope of operations. Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. At Dec. 31, 2005, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $44.2 million, while a decrease of 10 percent would have resulted in a decrease of $41.1 million. LIQUIDITY AND CAPITAL RESOURCES C AS H F LOW S (Millions of dollars) Cash provided by (used in) operating activities Continuing operations Discontinued operations Total 2005 2004 2003 $1,131 53 $1,184 $1,128 (315) $ 813 $1,106 275 $1,381 Cash provided by operating activities for continuing operations was basically unchanged for 2005 and 2004. Cash provided by operating activities for discontinued operations increased $368 million during 2005 compared with 2004. During 2004, Xcel Energy paid $752 million pursuant to the NRG settlement agreement, which was partially offset by tax beneﬁts received. XCEL ENERGY 2005 ANNUAL REPORT 33 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Cash provided by operating activities for continuing operations increased $22 million during 2004 compared with 2003, due to timing of payments made for trade payables partially offset by increased inventory costs related to higher natural gas costs, which will be collected from customers in future periods. Cash provided by operating activities for discontinued operations decreased $590 million during 2004 compared with 2003. During 2004, Xcel Energy paid $752 million pursuant to the NRG settlement agreement, which was partially offset by tax beneﬁts received. (Millions of dollars) Cash provided by (used in) investing activities Continuing operations Discontinued operations Total 2005 2004 2003 $(1,362) 136 $(1,226) $(1,268) 37 $(1,231) $(1,055) 126 $ (929) Cash used in investing activities for continuing operations increased $94 million during 2005 compared with 2004, primarily due to increased 2005 utility capital expenditures and restricted cash released in 2004. Cash provided by investing activities for discontinued operations increased $99 million during 2005 compared with 2004, primarily due to the receipt of proceeds from the sale of Cheyenne and Seren in 2005. Cash used in investing activities for continuing operations increased $213 million during 2004 compared with 2003, primarily due to increased utility capital expenditures. Cash provided by investing activities for discontinued operations decreased $89 million during 2004 compared with 2003, primarily due to the receipt of proceeds from the sale of Viking in 2003. (Millions of dollars) Cash provided by (used in) ﬁnancing activities Continuing operations Discontinued operations Total 2005 2004 2003 $111 – $111 $(111) – $(111) $(346) (21) $(367) Cash ﬂow from ﬁnancing activities related to continuing operations increased $222 million during 2005 compared with 2004, primarily due to increased short-term borrowings. Cash ﬂow from ﬁnancing activities related to continuing operations increased $235 million during 2004 compared with 2003, primarily due to increased short-term borrowings partially offset by a common stock repurchase. See discussion of trends, commitments and uncertainties with the potential for future impact on cash ﬂow and liquidity under Capital Sources. C A P I TA L R E QU I R E M E NT S Utility Capital Expenditures, Nonregulated Investments and Long-Term Debt Obligations The estimated cost of the capital expenditure programs of Xcel Energy and its subsidiaries, excluding discontinued operations, and other capital requirements for the years 2006, 2007 and 2008 are shown in the table below. (Millions of dollars) Electric utility Natural gas utility Common utility Total utility Other nonregulated Total capital expenditures Debt maturities Total capital requirements 2006 $1,386 110 84 1,580 – 1,580 835 $2,415 2007 $1,381 113 81 1,575 – 1,575 339 $1,914 2008 $1,169 132 81 1,382 2 1,384 632 $2,016 The capital expenditure forecast includes PSCo’s share of the 750-megawatt Comanche 3 coal-ﬁred plant in Colorado and the MERP project, which will reduce the emissions of three of NSP-Minnesota’s generating plants. The MERP project is expected to cost approximately $1 billion, with major construction starting in 2005 and finishing in 2009. Xcel Energy began recovering the costs of the emission-reduction project through customer rate increases effective Jan. 1, 2006. Comanche 3 is expected to cost approximately $1.35 billion, with major construction starting in 2006 and finishing in 2010. The CPUC has approved sharing one-third ownership of this plant with other parties. Consequently, Xcel Energy’s capital expenditure forecast includes $1 billion, approximately two-thirds of the total cost. The capital expenditure programs of Xcel Energy are subject to continuing review and modiﬁcation. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of restructuring requirements, compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements. Contractual Obligations and Other Commitments Xcel Energy has contractual obligations and other commercial commitments that will need to be funded in the future, in addition to its capital expenditure programs. The following is a summarized table of contractual obligations and other commercial commitments at Dec. 31, 2005. See additional discussion in the Consolidated Statements of Capitalization and Notes 3, 4, 13 and 14 to the Consolidated Financial Statements. 34 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S (Thousands of dollars) Total Less than 1 Year 1 to 3 Years 4 to 5 Years After 5 Years Long-term debt, principal and interest payments Capital lease obligations Operating leases (a) Unconditional purchase obligations (b) Other long-term obligations Payments to vendors in process Short-term debt Total contractual cash obligations (c) $ 10,387,694 98,684 208,249 11,972,606 265,925 129,315 746,120 $23,808,593 $1,236,074 6,447 41,376 2,573,587 38,213 129,315 746,120 $4,771,132 $1,672,323 12,426 64,589 2,639,833 55,376 – – $4,444,547 $2,148,700 11,794 48,055 2,057,622 52,706 – – $4,318,877 $ 5,330,597 68,017 54,229 4,701,564 119,630 – – $10,274,037 Payments Due by Period (a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms. At Dec. 31, 2005, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $110.8 million. (b) Obligations to purchase fuel for electric generating plants, and electricity and natural gas for resale. Certain contractual purchase obligations are adjusted based on indexes. However, the effects of price changes are mitigated through cost-of-energy adjustment mechanisms. (c) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $600 million of goods and services through the year 2020, in addition to the amounts disclosed in this table and in the forecasted capital expenditures. Common Stock Dividends Future dividend levels will be dependent on Xcel Energy’s results of operations, ﬁnancial position, cash ﬂows and other factors, and will be evaluated by the Xcel Energy board of directors. Xcel Energy’s objective is to deliver the ﬁnancial results that will enable the board of directors to grant annual dividend increases in the range of 2 percent to 4 percent per year. Xcel Energy’s dividend policy balances: – Projected cash generation from utility operations; – Projected capital investment in the utility businesses; – A reasonable rate of return on shareholder investment; and – The impact on Xcel Energy’s capital structure and credit ratings. In addition, there are certain statutory limitations that could affect dividend levels. Under the PUHCA, unless there was an order from the SEC, a holding company or any subsidiary could only declare and pay dividends out of retained earnings. Xcel Energy had $562 million of retained earnings at Dec. 31, 2005, and expects to declare dividends as scheduled. With the repeal of the PUHCA, this limitation on a holding company’s dividends will no longer apply. Notwithstanding the repeal of the PUHCA, federal law will still limit the ability of public utilities within a holding company system to declare dividends. Speciﬁcally, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The cash to pay dividends to Xcel Energy shareholders is primarily derived from dividends received from the utility subsidiaries. The utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory commissions to be paid to the holding company. The limitation is imposed through equity ratio limitations that range from 30 percent to 60 percent. Some utility subsidiaries must comply with bond indenture covenants or restrictions under credit agreements for debt to total capitalization ratios. The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only, i.e., not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to common stock plus surplus, divided by the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy’s capitalization ratio at Dec. 31, 2005, was 84 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock. C A P I TA L S O U R C E S Xcel Energy expects to meet future ﬁnancing requirements by periodically issuing short-term debt, long-term debt, common stock and preferred securities to maintain desired capitalization ratios. Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, were limited under the PUHCA in their ability to issue securities. Registered holding companies and their subsidiaries could not issue securities unless authorized by an exemptive rule or order of the SEC. Because Xcel Energy does not qualify for any of the main exemptive rules, it had received financing authority from the SEC under the PUHCA for various ﬁnancing arrangements. Xcel Energy’s current ﬁnancing authority permits it, subject to certain conditions, to issue through June 30, 2008, up to $1.8 billion of new long-term debt, common equity and equity-linked securities, and $1.0 billion of short-term debt securities during the new authorization period, provided that the aggregate amount of long-term debt, common equity, and equity-linked and short-term debt securities issued during the new authorization period does not exceed $2.0 billion. Xcel Energy’s ability to issue securities under the financing authority was subject to a number of conditions. One of the conditions of the financing authority was that Xcel Energy’s consolidated ratio of common equity to total capitalization be at least 30 percent. As of Dec. 31, 2005, the common equity ratio was approximately 42 percent. Additional conditions require that a security to be issued, must at least be rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities that are rated must be rated investment grade by at least one nationally recognized rating agency. On Feb. 10, 2006, Xcel Energy’s senior unsecured debt was considered investment grade by Standard & Poor’s Ratings Services (Standard & Poor’s), Moody’s and Fitch Ratings (Fitch). XCEL ENERGY 2005 ANNUAL REPORT 35 M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Upon the repeal of the PUHCA, these limitations on Xcel Energy’s ﬁnancings generally will no longer apply, nor will the PUHCA restrictions generally apply to the financings by the utility subsidiaries. However, utility financings and intra-system financing will become subject to the jurisdiction of the FERC under the Federal Power Act. The FERC has granted a blanket authorization for certain intra-system financings involving holding companies. Requests to the FERC to clarify its rules or grant similar blanket authorizations are presently pending before the FERC. Xcel Energy and the utility subsidiaries are presently evaluating the speciﬁc applications that they will need to ﬁle with the FERC due to the repeal of the PUHCA. It is possible that in lieu of requesting authority from the FERC for intra-system ﬁnancings, Xcel Energy and the utility subsidiaries may rely in the interim on a transitional savings clause that would permit such ﬁnancing transactions to the extent authorized by the SEC ﬁnancing order and so long as the conditions in the SEC ﬁnancing order continue to be satisﬁed. Short-Term Funding Sources Historically, Xcel Energy has used a number of sources to fulﬁll short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on ﬁnancing needs for construction expenditures and working capital. Another signiﬁcant short-term funding need is the dividend payment. As of Feb. 14, 2006, Xcel Energy and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs: (Millions of dollars) Facility Drawn* Available Cash Liquidity Maturity NSP-Minnesota NSP-Wisconsin PSCo PSCo SPS Xcel Energy – holding company Total $ 450 – 600 50 250 700 $2,050 $162.7 – 212.0 – 82.0 393.5 $850.2 $ 287.3 – 388.0 50.0 168.0 306.5 $1,199.8 $ – – 49.2 – 12.7 0.8 $62.7 $ 287.3 – 437.2 50.0 180.7 307.3 $1,262.5 April 2010 April 2010 April 2006 April 2010 November 2009 * Includes direct borrowings, outstanding commercial paper and letters of credit. Operating cash ﬂow as a source of short-term funding is affected by such operating factors as weather; regulatory requirements, including rate recovery of costs; environmental regulation compliance and industry deregulation; changes in the trends for energy prices; and supply and operational uncertainties, all of which are difﬁcult to predict. See further discussion of such factors under Statement of Operations Analysis. Short-term borrowing as a source of funding is affected by regulatory actions and access to reasonably priced capital markets. For additional information on Xcel Energy’s short-term borrowing arrangements, see Note 3 to the Consolidated Financial Statements. Access to reasonably priced capital markets is dependent in part on credit agency reviews and ratings. The following ratings reﬂect the views of Moody’s, Standard & Poor’s, and Fitch. A security rating is not a recommendation to buy, sell or hold securities, and is subject to revision or withdrawal at any time by the rating agency. As of Feb. 23, 2006, the following represents the credit ratings assigned to various Xcel Energy companies: Company Credit Type Moody’s Standard & Poor’s Xcel Energy Xcel Energy NSP-Minnesota NSP-Minnesota NSP-Minnesota NSP-Wisconsin NSP-Wisconsin PSCo PSCo PSCo SPS SPS Senior Unsecured Debt Commercial Paper Senior Unsecured Debt Senior Secured Debt Commercial Paper Senior Unsecured Debt Senior Secured Debt Senior Unsecured Debt Senior Secured Debt Commercial Paper Senior Unsecured Debt Commercial Paper Baa1 P-2 A3 A2 P-2 A3 A2 Baa1 A3 P-2 Baa1 P-2 BBB- A-2 BBB- A- A-2 BBB A- BBB- A- A-2 BBB A-2 Fitch BBB+ F2 A A+ F1 A A+ BBB+ A- F2 A- F2 Note: 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 is 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, and Fitch’s ratings for commercial paper range from F1 to F3. In the event of a downgrade of its credit ratings to below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy all or a part of its exposures under guarantees outstanding. See a list of guarantees at Note 13 to the Consolidated Financial Statements. Xcel Energy has no explicit rating triggers in its debt agreements. Money Pool Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals. The utility money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company. NSP-Minnesota, PSCo and SPS participate in the utility money pool pursuant to approval from their respective state regulatory commissions. No borrowings or loans were outstanding at Dec. 31, 2005. Borrowing limits are $250 million, $250 million and $100 million, respectively. As a consequence of the repeal of the PUHCA and the recent amendments to section 203 of the Federal Power 36 XCEL ENERGY 2005 ANNUAL REPORT M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S Act, it may be necessary for Xcel Energy and the utility subsidiaries to submit its existing money pool arrangement to the FERC for its approval. Xcel Energy and the utility subsidiaries are presently evaluating the situation. Registration Statements Xcel Energy’s Articles of Incorporation authorize the issuance of 1 billion shares of common stock. As of Dec. 31, 2005, Xcel Energy had approximately 403 million shares of common stock outstanding. In addition, Xcel Energy’s Articles of Incorporation authorize the issuance of 7 million shares of $100 par value preferred stock. On Dec. 31, 2005, Xcel Energy had approximately 1 million shares of preferred stock outstanding. Xcel Energy and its subsidiaries have the following registration statements on ﬁle with the SEC, pursuant to which they may sell, from time to time, securities: – In February 2002, Xcel Energy ﬁled a $1 billion shelf registration with the SEC. Xcel Energy may issue debt securities, common stock and rights to purchase common stock under this shelf registration. Xcel Energy has approximately $482.5 million remaining under this registration. Xcel Energy has approximately $400 million remaining under the $1 billion unsecured debt shelf registration ﬁled with the SEC in 2000. – On March 22, 2005, NSP-Minnesota ﬁled a shelf registration statement with the SEC to register an additional $1 billion of secured or unsecured debt securities, which may be issued from time to time in the future. This registration became effective on April 7, 2005, and supplements the $40 million of debt securities previously registered with the SEC. After issuance of $250 million of ﬁrst mortgage bonds in July 2005, as discussed later, $790 million remains available under the currently effective registration statement. – PSCo has an effective shelf registration statement with the SEC under which $800 million of secured ﬁrst collateral trust bonds or unsecured senior debt securities were registered. PSCo has approximately $225 million remaining under this registration. F U T U R E F I N A N C I N G P L A N S Xcel Energy generally expects to fund its operations and capital investments primarily through internally generated funds. Xcel Energy plans to refinance existing long-term debt or scheduled long-term debt maturities at each of the regulated operating utilities based on prevailing market conditions. To facilitate potential long-term debt issuances at the utility subsidiaries, SPS intends to file a long-term debt shelf registration statement with the SEC for up to $500 million in 2006, and NSP-Wisconsin may ﬁle a long-term debt shelf registration for up to $100 million. O F F- B A L A N C E- S H E E T A R R A N G E M E NT S Xcel Energy does not have any off-balance-sheet arrangements that have or are reasonably likely to have a current or future effect on ﬁnancial condition, changes in ﬁnancial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. E A R N I N G S G U I DA N C E Xcel Energy’s 2006 earnings per share from continuing operations guidance and key assumptions are detailed in the following table. Utility operations COLI tax beneﬁt Other nonregulated subsidiaries Xcel Energy Continuing Operations 2006 Diluted Earnings Per Share Range $1.25 – $1.35 0.10 (0.10) $1.25 – $1.35 Key Assumptions for 2006: – Normal weather patterns are experienced; – Reasonable rate recovery is approved in the Minnesota electric rate case; – Weather-adjusted retail electric utility sales grow by approximately 1.3 percent to 1.7 percent; – Weather-adjusted retail natural gas utility sales grow by approximately 0.0 percent to 1.0 percent; – Short-term wholesale and commodity trading margins are projected to be within a range of approximately $30 million to $50 million; – Other utility operating and maintenance expenses increase between 3 percent and 4 percent from 2005 levels; – Depreciation expense increases approximately $100 million to $110 million, which includes increases in decommissioning accruals that are expected to be recovered through rates approved in the Minnesota electric rate case; – Interest expense increases approximately $10 million to $15 million from 2005 levels; – Allowance for funds used during construction recorded for equity ﬁnancing is expected to increase approximately $10 million to $15 million from 2005 levels; – Xcel Energy continues to recognize COLI tax beneﬁts; – The effective tax rate for continuing operations is approximately 27 percent to 29 percent; and – Average common stock and equivalents total approximately 428 million shares, based on the “If Converted” method for convertible notes. XCEL ENERGY 2005 ANNUAL REPORT 37 MANAGEMENT REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING The management of Xcel Energy is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy’s internal control system was designed to provide reasonable assurance to the company’s management and board of directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to ﬁnancial statement preparation and presentation. Xcel Energy management assessed the effectiveness of the company’s internal control over ﬁnancial reporting as of Dec. 31, 2005. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2005, the company’s internal control over ﬁnancial reporting is effective based on those criteria. Xcel Energy’s independent auditors have issued an audit report on our assessment of the company’s internal control over ﬁnancial reporting. Their report appears on the following page. R I C H A R D C. K E L LY Chairman, President and Chief Executive Ofﬁcer February 24, 2006 B E N JA M I N G. S. F OW K E I I I Vice President and Chief Financial Ofﬁcer February 24, 2006 38 XCEL ENERGY 2005 ANNUAL REPORT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Stockholders Xcel Energy Inc. We have audited management’s assessment, included in the accompanying Management Report On Internal ControlsOver Financial Reporting, that Xcel Energy Inc. and subsidiaries (the “Company”) maintained effective internal control over ﬁnancial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over ﬁnancial reporting and for its assessment of the effectiveness of internal control over ﬁnancial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over ﬁnancial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over ﬁnancial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over ﬁnancial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions. A company’s internal control over ﬁnancial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal ﬁnancial ofﬁcers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over ﬁnancial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of ﬁnancial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the ﬁnancial statements. Because of the inherent limitations of internal control over ﬁnancial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over ﬁnancial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management’s assessment that the Company maintained effective internal control over ﬁnancial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over ﬁnancial reporting as of December 31, 2005, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated ﬁnancial statements as of and for the year ended December 31, 2005, of the Company and our report dated February 24, 2006, expressed an unqualiﬁed opinion on those ﬁnancial statements. Minneapolis, Minnesota February 24, 2006 XCEL ENERGY 2005 ANNUAL REPORT 39 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Stockholders Xcel Energy Inc. We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, common stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these ﬁnancial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Xcel Energy Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2006, expressed an unqualiﬁed opinion on management’s assessment of the effectiveness of the Company’s internal control over ﬁnancial reporting and an unqualiﬁed opinion on the effectiveness of the Company’s internal control over ﬁnancial reporting. Minneapolis, Minnesota February 24, 2006 40 XCEL ENERGY 2005 ANNUAL REPORT C O N S O L I D A T E D S T A T E M E N T S O F O P E R A T I O N S (Thousands of dollars, except per share data) Operating revenues Electric utility Natural gas utility Nonregulated and other Total operating revenues Operating expenses Electric fuel and purchased power – utility Cost of natural gas sold and transported – utility Cost of sales – nonregulated and other Other operating and maintenance expenses – utility Other operating and maintenance expenses – nonregulated Depreciation and amortization Taxes (other than income taxes) Total operating expenses Operating income Interest and other income (expense), net (see Note 11) Allowance for funds used during construction – equity Interest charges and ﬁnancing costs Interest charges – (includes other ﬁnancing costs of $25,829, $27,296 and $31,992, respectively) Allowance for funds used during construction – debt Distributions on redeemable preferred securities of subsidiary trusts Total interest charges and ﬁnancing costs Income from continuing operations before income taxes Income taxes Income from continuing operations Income (loss) from discontinued operations – net of tax (see Note 2) Net income Dividend requirements on preferred stock Earnings available to common shareholders Weighted average common shares outstanding (in thousands) Basic Diluted Earnings (loss) per share – basic Income from continuing operations Income (loss) from discontinued operations (see Note 2) Earnings per share Earnings (loss) per share – diluted Income from continuing operations Income (loss) from discontinued operations (see Note 2) Earnings per share See Notes to Consolidated Financial Statements. Year ended Dec. 31 2004 2005 2003 $7,243,637 2,307,385 74,455 9,625,477 $6,225,245 1,915,514 74,802 8,215,561 $5,919,938 1,677,768 133,561 7,731,267 3,922,163 1,823,123 24,676 1,679,172 28,493 767,321 287,810 8,532,758 1,092,719 857 21,627 3,040,759 1,445,773 28,757 1,591,718 44,109 705,955 282,775 7,139,846 1,075,715 9,316 33,648 2,705,839 1,190,996 80,683 1,570,492 53,485 727,307 278,034 6,606,836 1,124,431 (5,234) 25,338 463,370 (20,744) – 442,626 672,577 173,539 499,038 13,934 512,972 4,241 $ 508,731 458,294 (23,814) – 434,480 684,199 161,935 522,264 (166,303) 355,961 4,241 $ 351,720 448,690 (20,402) 22,731 451,019 693,516 170,692 522,824 99,568 622,392 4,241 $ 618,151 402,330 425,671 399,456 423,334 398,765 418,912 $ $ $ $ 1.23 0.03 1.26 1.20 0.03 1.23 $ $ $ $ 1.30 (0.42) 0.88 1.26 (0.39) 0.87 $ $ $ $ 1.30 0.25 1.55 1.26 0.24 1.50 XCEL ENERGY 2005 ANNUAL REPORT 41 C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S (Thousands of dollars) Operating activities Net income Remove (income) loss from discontinued operations Adjustments to reconcile net income to cash provided by operating activities: Depreciation and amortization Nuclear fuel amortization Deferred income taxes Amortization of investment tax credits Allowance for equity funds used during construction Undistributed equity in earnings of unconsolidated afﬁliates Impairment of assets Unrealized gain (loss) on derivative ﬁnancial instruments Change in accounts receivable Change in inventories Change in other current assets Change in accounts payable Change in other current liabilities Change in other noncurrent assets Change in other noncurrent liabilities Operating cash ﬂows (used in) provided by discontinued operations Net cash provided by operating activities Investing activities Utility capital/construction expenditures Allowance for equity funds used during construction Purchase of investments in external decommissioning fund Proceeds from the sale of investments in external decommissioning fund Nonregulated capital expenditures and asset acquisitions Proceeds from sale of assets Equity investments, loans, deposits and sales of nonregulated projects Restricted cash Other investments Investing cash ﬂows provided by discontinued operations Net cash used in investing activities Financing activities Short-term borrowings – net Proceeds from issuance of long-term debt Repayment of long-term debt, including reacquisition premiums Proceeds from issuance of common stock Repurchase of common stock Dividends paid Financing cash ﬂows (used in) provided by discontinued operations Net cash (used in) provided by ﬁnancing activities Net increase (decrease) in cash and cash equivalents Net increase (decrease) in cash and cash equivalents – discontinued operations Net increase in cash and cash equivalents – adoption of FIN No. 46 Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year Supplemental disclosure of cash ﬂow information Cash paid for interest (net of amounts capitalized) Cash paid for income taxes (net of refunds received) See Notes to Consolidated Financial Statements. Year ended Dec. 31 2004 2005 2003 $ 512,972 (13,934) $ 355,961 166,303 $622,392 (99,568) 782,074 45,330 205,058 (11,620) (21,627) (712) 2,887 (3,923) (250,305) (94,605) (289,250) 281,430 30,923 (81,506) 37,242 53,283 1,183,717 (1,304,468) 21,627 (576,001) 494,529 (6,976) 11,228 – (6,226) 5,075 135,577 (1,225,635) 433,820 2,529,408 (2,517,698) 9,085 – (343,092) (200) 111,323 69,405 (20,570) – 23,361 72,196 $ 739,025 43,296 57,273 (12,189) (33,648) (3,342) – 6,206 (123,044) (46,220) (190,827) 133,278 2,494 (6,485) 39,669 (314,575) 813,175 (1,274,290) 33,648 (305,328) 228,676 (2,122) – (4,082) 42,628 12,474 37,119 (1,231,277) 253,737 419,848 (438,595) 6,985 (32,023) (320,444) (200) (110,692) (528,794) (12,018) 3,439 560,734 $ 23,361 757,838 43,401 100,869 (12,439) (25,338) (4,833) 8,856 2,404 (129,408) (911) (174,793) 106,087 (4,855) (142,849) 59,306 274,582 1,380,741 (944,421) 25,338 (144,367) 61,031 (2,055) – 10,588 (38,488) (22,380) 125,904 (928,850) (428,580) 1,689,317 (1,307,012) 3,219 – (303,316) (20,500) (366,872) 85,019 6,510 – 469,205 $560,734 $ 417,016 10,625 $ $ 423,673 $(355,639) $402,506 $ (6,379) 42 XCEL ENERGY 2005 ANNUAL REPORT C O N S O L I D A T E D B A L A N C E S H E E T S (Thousands of dollars) Assets Current assets: Cash and cash equivalents Accounts receivable – net of allowance for bad debts: $39,798 and $34,299, respectively Accrued unbilled revenues Materials and supplies inventories – at average cost Fuel inventory – at average cost Natural gas inventories – at average cost Recoverable purchased natural gas and electric energy costs Derivative instruments valuation – at market Prepayments and other Current assets held for sale and related to discontinued operations Total current assets Property, plant and equipment, at cost: Electric utility plant Natural gas utility plant Common utility and other property Construction work in progress Total property, plant and equipment Less accumulated depreciation Nuclear fuel – net of accumulated amortization: $1,190,386 and $1,145,228, respectively Net property, plant and equipment Other assets: Nuclear decommissioning fund and other investments Regulatory assets Derivative instruments valuation – at market Prepaid pension asset Other Noncurrent assets held for sale and related to discontinued operations Total other assets Total assets Liabilities and Equity Current liabilities: Current portion of long-term debt Short-term debt Accounts payable Taxes accrued Dividends payable Derivative instruments valuation – at market Other Current liabilities held for sale and related to discontinued operations Total current liabilities Deferred credits and other liabilities: Deferred income taxes Deferred investment tax credits Regulatory liabilities Derivative instruments valuation – at market Asset retirement obligations Customer advances Minimum pension liability Beneﬁt obligations and other Noncurrent liabilities held for sale and related to discontinued operations Total deferred credits and other liabilities Minority interest in subsidiaries Commitments and contingencies (see Note 14) Capitalization (see Statements of Capitalization): Long-term debt Preferred stockholders’ equity Common stockholders’ equity Total liabilities and equity See Notes to Consolidated Financial Statements. Dec. 31 2005 2004 $ 72,196 1,011,569 614,016 159,560 64,987 310,610 395,070 213,138 99,904 200,811 3,141,861 $ 23,361 761,264 435,431 161,323 64,265 214,964 264,628 129,218 149,538 367,248 2,571,240 18,870,516 2,779,043 1,518,266 783,490 23,951,315 (9,357,414) 102,409 14,696,310 18,236,957 2,617,552 1,476,553 721,335 23,052,397 (9,050,636) 74,308 14,076,069 1,145,659 963,403 451,937 683,649 164,212 401,285 3,810,145 $21,648,316 1,023,481 850,636 424,786 642,873 175,174 540,584 3,657,534 $20,304,843 $ 835,495 746,120 1,187,489 235,056 87,788 191,414 345,807 43,657 3,672,826 2,191,794 131,400 1,710,820 499,390 1,292,006 310,092 88,280 343,201 6,936 6,573,919 3,547 $ 223,655 312,300 903,609 216,439 83,405 135,098 348,557 112,931 2,335,994 2,065,665 143,028 1,630,545 450,883 1,091,089 303,928 62,669 327,662 89,242 6,164,711 3,220 5,897,789 104,980 5,395,255 $21,648,316 6,493,020 104,980 5,202,918 $20,304,843 XCEL ENERGY 2005 ANNUAL REPORT 43 C O N S O L I D A T E D S T A T E M E N T S O F C O M M O N S T O C K H O L D E R S ’ E Q U I T Y A N D C O M P R E H E N S I V E I N C O M E Common Stock Issued Shares Par Value Capital in Excess of Par Value 398,714 $ 996,785 $4,038,151 Retained Accumulated Other Earnings (Deﬁcit) Total Comprehensive Stockholders’ Equity Income (Loss) $(100,942) 622,392 $(269,010) 182,829 9,710 (14,005) 340 $ (90,136) (3) (7,935) (8,024) 164 $(105,934) (17,271) (8,919) 63 $4,664,984 622,392 182,829 9,710 (14,005) 340 801,266 (3,901) (299,127) 3,218 $5,166,440 355,961 (3) (7,935) (8,024) 164 340,163 (4,241) (323,742) 56,321 (32,023) $5,202,918 512,972 (17,271) (8,919) 63 486,845 (4,241) (343,234) 52,967 $5,395,255 251 627 398,965 $ 997,412 (720) (149,521) 2,591 $3,890,501 (3,181) (149,606) $ 368,663 355,961 3,297 (1,800) 8,243 (4,500) 400,462 $1,001,155 48,078 (27,523) $3,911,056 (4,241) (323,742) $ 396,641 512,972 (4,241) (343,234) 2,925 7,313 403,387 $1,008,468 45,654 $3,956,710 $ 562,138 $(132,061) (Thousands) Balance at Dec. 31, 2002 Net income Currency translation adjustments Minimum pension liability Net derivative instrument fair value changes during the period (see Note 12) Unrealized gain – marketable securities Comprehensive income for 2003 Dividends declared: Cumulative preferred stock Common stock Issuances of common stock Balance at Dec. 31, 2003 Net income Currency translation adjustments Minimum pension liability Net derivative instrument fair value changes during the period (see Note 12) Unrealized gain – marketable securities Comprehensive income for 2004 Dividends declared: Cumulative preferred stock Common stock Issuances of common stock Purchases for restricted stock issuance Balance at Dec. 31, 2004 Net income Minimum pension liability Net derivative instrument fair value changes during the period (see Note 12) Unrealized gain – marketable securities Comprehensive income for 2005 Dividends declared: Cumulative preferred stock Common stock Issuances of common stock Balance at Dec. 31, 2005 See Notes to Consolidated Financial Statements. 44 XCEL ENERGY 2005 ANNUAL REPORT C O N S O L I D A T E D S T A T E M E N T S O F C A P I T A L I Z A T I O N Long-Term Debt (Thousands of dollars) NSP-Minnesota First Mortgage Bonds, Series due: Dec. 1, 2005, 6.125% Dec. 1, 2006, 4.1%(a) Dec. 1, 2006–2008, 4.5%–5% (a) Aug. 1, 2006, 2.875% Aug. 1, 2010, 4.75% Aug. 28, 2012, 8% March 1, 2019, 8.5% (b) Sept. 1, 2019, 8.5% (b) July 1, 2025, 7.125% March 1, 2028, 6.5% April 1, 2030, 8.5% (b) July 15, 2035, 5.25% Senior Notes, due Aug. 1, 2009, 6.875% Borrowings under credit facility, due April 2010, 5.05% Retail Notes, due July 1, 2042, 8% Other Unamortized discount – net Total Less current maturities Total NSP-Minnesota long-term debt PSCo First Mortgage Bonds, Series due: Nov. 1, 2005, 6.375% June 1, 2006, 7.125% April 1, 2008, 5.625% (b) Oct. 1, 2008, 4.375% June 1, 2012, 5.5% (b) Oct. 1, 2012, 7.875% March 1, 2013, 4.875% April 1, 2014, 5.5% April 1, 2014, 5.875% (b) Sept. 1, 2017, 4.375% (b) Jan. 1, 2019, 5.1% (b) Jan. 1, 2024, 7.25% Unsecured Senior A Notes, due July 15, 2009, 6.875% Secured Medium-Term Notes, due March 5, 2007, 7.11% Capital lease obligations, 11.2% due in installments through 2028 Unamortized discount Total Less current maturities Total PSCo long-term debt SPS Unsecured Senior B Notes, due Nov. 1, 2006, 5.125% Unsecured Senior A Notes, due March 1, 2009, 6.2% Unsecured Senior C and D Notes, due Oct. 1, 2033, 6% Pollution control obligations, securing pollution control revenue bonds, due: July 1, 2011, 5.2% July 1, 2016, 3.58% at Dec. 31, 2005, and 2% at Dec. 31, 2004 Sept. 1, 2016, 5.75% Unamortized discount Total Less current maturities Total SPS long-term debt See Notes to Consolidated Financial Statements. Dec. 31 2005 2004 $ – 2,420 7,490 200,000 175,000 450,000 27,900 100,000 250,000 150,000 69,000 250,000 250,000 250,000 185,000 519 (7,278) 2,360,051 204,833 $2,155,218 $ – 125,000 – 300,000 – 600,000 250,000 275,000 – 129,500 48,750 – 200,000 100,000 47,581 (3,524) 2,072,307 126,334 $1,945,973 $ 70,000 4,750 9,790 200,000 175,000 450,000 27,900 100,000 250,000 150,000 69,000 – 250,000 – 185,000 367 (7,759) 1,934,048 74,685 $1,859,363 $ 134,500 125,000 18,000 300,000 50,000 600,000 250,000 275,000 61,500 – 48,750 110,000 200,000 100,000 48,935 (5,870) 2,315,815 135,854 $2,179,961 $ 500,000 100,000 100,000 $ 500,000 100,000 100,000 44,500 25,000 57,300 (1,024) 825,776 500,000 $ 325,776 44,500 25,000 57,300 (1,338) 825,462 – $ 825,462 XCEL ENERGY 2005 ANNUAL REPORT 45 C O N S O L I D A T E D S T A T E M E N T S O F C A P I T A L I Z A T I O N Long-Term Debt – continued (Thousands of dollars) NSP-Wisconsin First Mortgage Bonds, Series due: Oct. 1, 2018, 5.25% Dec. 1, 2026, 7.375% Senior Notes, due Oct. 1, 2008, 7.64% City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6% (a) Fort McCoy System Acquisition, due Oct. 15, 2030, 7% Unamortized discount Total Less current maturities Total NSP-Wisconsin long-term debt Other Subsidiaries Various Eloigne Co. Affordable Housing Project Notes, due 2007–2045, 0%–9.89% Other Total Less current maturities Total other subsidiaries long-term debt Xcel Energy Inc. Unsecured senior notes, Series due: July 1, 2008, 3.4% Dec. 1, 2010, 7% Convertible notes, Series due: Nov. 21, 2007, 7.5% Nov. 21, 2008, 7.5% Borrowings under credit facility, due November 2009, 3.09% Fair value hedge, carrying value adjustment Unamortized discount Total Xcel Energy Inc. debt Total long-term debt from continuing operations Long-Term Debt from Discontinued Operations First Mortgage Bonds – Cheyenne: Due Jan. 1, 2024, 7.5% Industrial Development Revenue Bonds, due Sept. 1, 2021–March 1, 2027, variable rate, 2.12% at Dec. 31, 2004 Total long-term debt from discontinued operations Cumulative Preferred Stock – authorized 7,000,000 shares of $100 par value; outstanding shares: 2005: 1,049,800; 2004: 1,049,800 $3.60 series, 275,000 shares $4.08 series, 150,000 shares $4.10 series, 175,000 shares $4.11 series, 200,000 shares $4.16 series, 99,800 shares $4.56 series, 150,000 shares Total preferred stockholders’ equity Common Stockholders’ Equity Common stock – authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2005: 403,387,159; 2004: 400,461,804 Capital in excess of par value on common stock Retained earnings Accumulated other comprehensive income (loss) Total common stockholders’ equity (a) Resource recovery ﬁnancing (b) Pollution control ﬁnancing See Notes to Consolidated Financial Statements. 46 XCEL ENERGY 2005 ANNUAL REPORT Dec. 31 2005 2004 $ 150,000 65,000 80,000 18,600 828 (919) 313,509 34 $ 313,475 $ 150,000 65,000 80,000 18,600 862 (985) 313,477 34 $ 313,443 $ $ 95,692 2,217 97,909 4,294 93,615 $ 110,412 9,830 120,242 13,082 $ 107,160 $ 195,000 600,000 $ 195,000 600,000 230,000 57,500 – (14,073) (4,695) $1,063,732 $ 5,897,789 230,000 57,500 140,000 (8,333) (6,536) $ 1,207,631 $6,493,020 $ – – $ – $ $ 7,800 17,000 24,800 $ 27,500 15,000 17,500 20,000 9,980 15,000 $ 104,980 $ 27,500 15,000 17,500 20,000 9,980 15,000 $ 104,980 $1,008,468 3,956,710 562,138 (132,061) $5,395,255 $1,001,155 3,911,056 396,641 (105,934) $5,202,918 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Business and System of Accounts Xcel Energy’s utility subsidiaries are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries were subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility commissions. All of the utility companies’ accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects. On Aug. 8, 2005, President Bush signed into law the Energy Act, signiﬁcantly changing many federal energy statutes. The Energy Act is expected to have a substantial long-term effect on energy markets, energy investment, and regulation of public utilities and holding company systems by the FERC, the SEC and the DOE. The FERC was directed by the Energy Act to address many areas previously regulated by other governmental entities under the statutes and determine whether changes to such previous regulations are warranted. The issues that the FERC has been required to consider associated with the repeal of the PUHCA include, but are not limited to, the expansion of the FERC authority to review mergers and sales of public utility companies and the expansion of the FERC authority over the books and records of holding companies and public utility companies, and the appropriate cost standard for the provision of non-power goods and services by service companies. The FERC is in various stages of rulemaking on these and other issues. Xcel Energy cannot predict the impact the new rulemakings will have on its operations or financial results, if any. Principles of Consolidation In 2005, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin. Along with WGI, an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations. Xcel Energy’s nonregulated subsidiaries in continuing operations include Eloigne Co. (investments in rental housing projects that qualify for low-income housing reported tax credits). Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Energy Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc. and Xcel Energy O&M Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy. Discontinued utility operations include the activity of Viking, an interstate natural gas pipeline company that was sold in January 2003; BMG, a regulated natural gas and propane distribution company that was sold in October 2003; and Cheyenne, a regulated electric and natural gas utility that was sold in January 2005. See Note 2 to the Consolidated Financial Statements for more information on the discontinued operations of Viking, BMG and Cheyenne. During 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of UE (engineering, construction and design) and Quixx Corp. (a former subsidiary of UE that partners in cogeneration projects). During 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren (broadband telecommunications services). During 2003, Planergy International, Inc. (energy management solutions) closed and began selling a majority of its business operations, with ﬁnal dissolution occurring in 2004. During 2003, Xcel Energy also divested its ownership interest in NRG, an independent power producer. On May 14, 2003, NRG filed for bankruptcy to restructure its debt. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. During 2003, the board of directors of Xcel Energy also approved management’s plan to exit businesses conducted by the nonregulated subsidiaries Xcel Energy International and e prime. NRG, Xcel Energy International, e prime, Seren, Planergy International, Inc., UE and Quixx Corp. are presented as components of discontinued operations. See Note 2 to the Consolidated Financial Statements. In 2004, Xcel Energy began consolidating the ﬁnancial statements of subsidiaries in which it has a controlling ﬁnancial interest, pursuant to the requirements of FASB Interpretation No. 46, as revised (FIN No. 46). Historically, consolidation has been required only for subsidiaries in which an enterprise has a majority voting interest. As a result, Xcel Energy is required to consolidate a portion of its affordable housing investments made through Eloigne, which for periods prior to 2004 are accounted for under the equity method. As of Dec. 31, 2005, the assets of the affordable housing investments consolidated as a result of FIN No. 46, as revised, were approximately $136 million and long-term liabilities were approximately $75 million, including long-term debt of $72 million. Investments of $51 million, previously reflected as a component of investments in unconsolidated affiliates, have been consolidated with the entities’ assets initially recorded at their carrying amounts as of Jan. 1, 2004. The long-term debt is collateralized by the affordable housing projects and is nonrecourse to Xcel Energy. Xcel Energy uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects for which it does not have a controlling ﬁnancial interest. Under this method, a proportionate share of pretax income is recorded as equity earnings from investments in afﬁliates. In the consolidation process, all signiﬁcant intercompany transactions and balances are eliminated. Xcel Energy has investments in several plants and transmission facilities jointly owned with other utilities. These projects are accounted for on a proportionate consolidation basis, consistent with industry practice. See Note 7 to the Consolidated Financial Statements. Revenue Recognition Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Xcel Energy’s utility subsidiaries have various rate-adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total XCEL ENERGY 2005 ANNUAL REPORT 47 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S amount collected under the clauses and the recoverable costs incurred. In addition, Xcel Energy presents its revenue net of any excise or other ﬁduciary-type taxes or fees. A summary of signiﬁcant rate-adjustment mechanisms follows: – NSP-Minnesota’s rates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowing dollar-for-dollar recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively. – NSP-Wisconsin’s rates include a cost-of-gas adjustment clause for purchased natural gas, but not for purchased electric energy or electric fuel. In Wisconsin, requests can be made for recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, and an interim fuel-cost hearing process. – PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through an electric-commodity adjustment clause. This fuel mechanism also has in place a sharing among customers and shareholders of certain fuel and energy costs, with an $11.25 million maximum on any cost sharing over or under an allowed electric-commodity adjustment formula rate, and a sharing among shareholders and customers of certain gains and losses on trading margins. – In Texas, SPS may request periodic adjustments to provide electric fuel and purchased energy cost recovery. In New Mexico, SPS has a monthly fuel and purchased power cost-recovery factor. – In Colorado, PSCo operates under an electric performance-based regulatory plan, which provides for an annual earnings test in which earnings above the authorized return on equity are refunded to customers. NSP-Minnesota and PSCo operate under various service standards in Minnesota and Colorado, respectively, which could require customer refunds if certain criteria are not met. NSP-Minnesota and PSCo’s rates in Minnesota and Colorado, respectively, also include monthly adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually. – NSP-Minnesota, NSP-Wisconsin, PSCo and SPS sell ﬁrm power and energy in wholesale markets, which are regulated by the FERC. Certain of these rates include monthly wholesale fuel cost-recovery mechanisms. Commodity Trading Operations All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the Consolidated Statements of Operations. Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value in accordance with SFAS No. 133, as amended. In addition, commodity trading results include the impact of any margin-sharing mechanisms. Derivative Financial Instruments Xcel Energy and its subsidiaries utilize a variety of derivatives, including commodity forwards, futures and options, index or ﬁxed price swaps and basis swaps, to mitigate market risk and to enhance its operations. For further discussion of Xcel Energy’s risk management and derivative activities, see Note 12 to the Consolidated Financial Statements. Property, Plant and Equipment and Depreciation Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Removal costs associated with regulatory obligations are recorded as regulatory liabilities. Signiﬁcant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses. Property, plant and equipment also includes costs associated with property held for future use. Xcel Energy determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.2 percent, 3.1 percent and 3.0 percent for the years ended Dec. 31, 2005, 2004 and 2003, respectively. Allowance for Funds Used During Construction (AFDC) AFDC represents the cost of capital used to ﬁnance utility construction activity. AFDC is computed by applying a composite pretax rate to qualiﬁed construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded to reﬂect returns on capital used to ﬁnance conservation programs in Minnesota. Decommissioning Xcel Energy accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. The fair value of external nuclear decommissioning fund investments are estimated based on quoted market prices for those or similar investments. Unrealized gains or losses are deferred as regulatory assets or liabilities. For more information on nuclear decommissioning, see Note 15 to the Consolidated Financial Statements. PSCo also previously operated a nuclear generating plant, which has been decommissioned and was repowered using natural gas. PSCo’s costs associated with decommissioning were deferred and amortized consistent with regulatory recovery. These costs were fully recovered through rates in July 2005. Nuclear Fuel Expense Nuclear fuel expense, which is recorded as the nuclear generating plants use fuel, includes the cost of fuel used in the current period, as well as future disposal costs of spent nuclear fuel. In addition, nuclear fuel expense includes fees assessed by the DOE for NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel-enrichment facility. 48 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Environmental Costs Environmental costs are recorded when it is probable Xcel Energy is liable for the costs and the liability can reasonably be estimated. Costs may be deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash ﬂow. Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and as remediation proceeds. If several designated responsible parties exist, only Xcel Energy’s expected share of the cost is estimated and recorded. Any future costs of restoring sites where operation may extend indeﬁnitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include ﬁnal remediation costs. Removal costs recovered in rates are classiﬁed as a regulatory liability. Legal Costs Litigation accruals are recorded when it is probable Xcel Energy is liable for the costs and the liability can be reasonably estimated. Legal accruals are recorded net of insurance recovery. Legal costs related to settlements are not accrued, but expensed as incurred. Income Taxes Xcel Energy and its domestic subsidiaries ﬁle consolidated federal income tax returns. Xcel Energy and its domestic subsidiaries ﬁle combined and separate state income tax returns. NRG and one or more of its domestic subsidiaries were included in some state returns, but not all, of these combined returns in 2003. NRG has not been consolidated or combined in any of Xcel Energy’s income tax returns since 2003. Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy in connection with combined state ﬁlings. In accordance with the PUHCA requirements, the holding company also allocates its own net income tax beneﬁts to its direct subsidiaries based on the positive tax liability of each company. Xcel Energy defers income taxes for all temporary differences between pretax ﬁnancial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse. Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their beneﬁts amortized over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 16 to the Consolidated Financial Statements. Use of Estimates In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, asset retirement obligations, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed or revised annually, if appropriate. Cash and Cash Equivalents Xcel Energy considers investments in certain debt instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Those debt instruments are primarily commercial paper and money market funds. Inventory All inventory is recorded at average cost. Regulatory Accounting Our regulated utility subsidiaries account for certain income and expense items in accordance with SFAS No. 71 – “Accounting for the Effects of Certain Types of Regulation.” Under SFAS No. 71: – Certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and – Certain credits, which would otherwise be reﬂected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates. Estimates of recovering deferred costs and returning deferred credits are based on speciﬁc ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See more discussion of regulatory assets and liabilities at Note 16 to the Consolidated Financial Statements. Stock-Based Employee Compensation Xcel Energy has several stock-based compensation plans. Those plans are accounted for using the intrinsic-value method. Compensation expense is not recorded for stock options because there is no difference between the market price and the purchase price at grant date. Compensation expense is recorded for restricted stock and stock units awarded to certain employees, which are held until the restriction lapses or the stock is forfeited. For more information on stock compensation impacts, see Note 9 to the Consolidated Financial Statements. Deferred Financing Costs Other assets also included deferred financing costs, net of amortization, of approximately $42 million and $44 million at Dec. 31, 2005 and 2004, respectively. Xcel Energy is amortizing these ﬁnancing costs over the remaining maturity periods of the related debt. XCEL ENERGY 2005 ANNUAL REPORT 49 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Accounts Receivable and Allowance for Uncollectibles Accounts receivable are stated at the actual billed amount net of write-offs and allowance for uncollectibles. Xcel Energy establishes an allowance for uncollectibles based on a reserve policy that reflects its expected exposure to the credit risk of customers. Reclassifications Certain items in the statements of operations, balance sheets and the statements of cash ﬂows have been reclassiﬁed from prior-period presentation to conform to the 2005 presentation. These reclassifications had no effect on net income or earnings per share. The reclassiﬁcations were primarily related to the presentation of UE as discontinued operations following the announcement of its sale in March 2005, as discussed later. In addition, fees collected from customers on behalf of governmental agencies were reclassiﬁed to be presented net of the related payments made to the agencies. 2. DISCONTINUED OPERATIONS Xcel Energy classified and accounted for certain assets as held for sale at Dec. 31, 2005 and 2004. Assets held for sale are valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, management considered cash flow analyses, bids and offers related to those assets and businesses. Assets held for sale are not depreciated. Results of operations for divested businesses and the results of businesses held for sale are reported for all periods presented on a net basis as discontinued operations. In addition, the assets and liabilities of the businesses divested and held for sale in 2005 and 2004 have been reclassiﬁed to assets and liabilities held for sale in the accompanying Balance Sheet. R EG U L AT E D U T I L I T Y S EG M E NT During January 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, Cheyenne. Black Hills Corp. purchased all the common stock of Cheyenne, including the assumption of outstanding debt of approximately $25 million, for approximately $90 million, plus a working capital adjustment finalized in 2005. The sale was completed on Jan. 21, 2005, and resulted in an after-tax loss of approximately $13 million, or 3 cents per share, which was accrued at Dec. 31, 2004. During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment: Viking and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded for the natural gas utility segment, primarily related to the sale of Viking. N R G S EG M E NT Change in Accounting for NRG in 2003 Prior to NRG’s bankruptcy ﬁling in May 2003, Xcel Energy accounted for NRG as a consolidated subsidiary. However, as a result of NRG’s bankruptcy ﬁling, Xcel Energy no longer had the ability to control the operations of NRG. Accordingly, effective as of the bankruptcy ﬁling date, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 – “The Equity Method of Accounting for Investments in Common Stock.” After changing to the equity method, Xcel Energy was limited in the amount of NRG’s losses subsequent to the bankruptcy date that it was required to record. In accordance with these limitations under the equity method, Xcel Energy stopped recognizing equity in the losses of NRG subsequent to the quarter ended June 30, 2003. These limitations provided for loss recognition by Xcel Energy until its investment in NRG was written off to zero, with further loss recognition to continue if its financial commitments to NRG existed beyond amounts already invested. Prior to NRG entering bankruptcy, Xcel Energy recorded more losses than the limitations provided for as of June 30, 2003. Upon Xcel Energy’s divestiture of its interest in NRG in December 2003, the NRG losses recorded in excess of Xcel Energy’s investment in and ﬁnancial commitment to NRG were reversed. This resulted in an adjustment of the total NRG losses recorded for the year 2003 to $251 million. Xcel Energy’s share of NRG’s results for all 2003 periods is reported in a single line item, Equity in Losses of NRG, as a component of discontinued operations. NRG’s 2003 results do reﬂect some effects of asset impairments, as discussed below. NRG Asset Impairments In 2002, NRG experienced credit-rating downgrades, defaults under numerous credit agreements, increased collateral requirements and reduced liquidity. These events resulted in impairment reviews of a number of NRG assets. NRG completed an analysis of the recoverability of the asset-carrying values of its projects each period, factoring in the probability weighting of different courses of action available to NRG, given its ﬁnancial position and liquidity constraints at the time of each analysis. This approach was applied consistently to asset groups with similar uncertainties and cash ﬂow streams. As a result, NRG determined that many of its construction projects and its operational projects became impaired during 2002 and 2003 and required being written down to fair market value. In applying those provisions, NRG management considered cash ﬂow analyses, bids and offers related to those projects. N O N R EG U L AT E D S U B S I D I A R I E S – A L L OT H E R S EG M E NT Utility Engineering In March 2005, Xcel Energy agreed to sell its nonregulated subsidiary Utility Engineering Corp. (UE), to Zachry Group, Inc. In April 2005, Zachry acquired all of the outstanding shares of UE. Xcel Energy recorded an insigniﬁcant loss in the ﬁrst quarter of 2005 as a result of the transaction. In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx Corp., a former subsidiary of UE that partners in cogeneration projects, and was not included in the sale of UE to Zachry. Seren On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc., a wholly owned broadband subsidiary. On May 25, 2005, Xcel Energy reached an agreement to sell Seren’s California assets to WaveDivision Holdings, LLC, which was completed in November 2005. In July 2005, Xcel Energy reached an agreement to sell Seren’s Minnesota assets to Charter Communications, which was completed in January 2006. An estimated after-tax impairment charge, including disposition costs, of $143 million, or 34 cents per share, 50 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S was recorded in 2004. Based on the sales agreements entered into in 2005, the estimate was adjusted in 2005 to reﬂect a total asset impairment of $140 million. Xcel Energy International and e prime In December 2003, the board of directors of Xcel Energy approved management’s plan to exit the businesses conducted by its nonregulated subsidiaries Xcel Energy International and e prime. The exit of all business conducted by e prime was completed in 2004. Results of discontinued nonregulated operations in 2004 include the impact of the sale of the Argentina subsidiaries of Xcel Energy International. The sales took place in a series of three transactions, with a total sales price of approximately $31 million. In addition to the sales price, Xcel Energy also received approximately $21 million at the closing of one transaction as redemption of its capital investment. The sales resulted in a gain of approximately $8 million, including the realization of approximately $7 million of income tax beneﬁts realizable upon the sale of the Xcel Energy International assets. Results of discontinued nonregulated operations in 2003, other than NRG, include an after-tax loss expected on the disposal of all Xcel Energy International assets of $59 million, based on the estimated fair value of such assets. The fair value represents a market bid or appraisal received that is believed to best reflect the assets’ fair value at Dec. 31, 2003. Xcel Energy’s remaining investment in Xcel Energy International at Dec. 31, 2003, was approximately $39 million. Losses from discontinued nonregulated operations in 2003 also include a charge of $16 million for costs of settling a Commodity Futures Trading Commission trading investigation of e prime. Tax Benefits Related to Investment in NRG With NRG’s emergence from bankruptcy in December 2003, Xcel Energy divested its ownership interest in NRG. Xcel Energy has recognized tax beneﬁts related to the divestiture. These tax beneﬁts, since related to Xcel Energy’s investment in discontinued NRG operations, also are reported as discontinued operations. During 2002, Xcel Energy recognized an initial estimate of the expected tax beneﬁts of $706 million. Based on the results of a 2003 preliminary tax basis study of NRG, Xcel Energy recorded $404 million of additional tax beneﬁts in 2003. In 2004, the NRG basis study was updated and previously recognized tax beneﬁts were reduced by $13 million. In 2005, a $17 million tax beneﬁt was recorded to reﬂect the ﬁnal federal income tax resolution of Xcel Energy’s divested interest in NRG. XCEL ENERGY 2005 ANNUAL REPORT 51 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S S U M M A R I Z E D F I N A N C I A L R E S U LT S O F D I S C O NT I N U E D O P E R AT I O N S (Thousands of dollars) 2005 Operating revenue Operating and other expenses Special charges and impairments Pretax income (loss) from operations of discontinued components Income tax expense (beneﬁt) Income from operations of discontinued components Estimated pretax gain on disposal of discontinued components Income tax beneﬁt Gain on disposal of discontinued components Net income from discontinued operations 2004 Operating revenue Operating and other expenses Special charges and impairments Pretax loss from operations of discontinued components Income tax expense (beneﬁt) Loss from operations of discontinued components Estimated pretax gain on disposal of discontinued components Income tax beneﬁt Gain on disposal of discontinued components Net loss from discontinued operations 2003 Operating revenue Operating and other expenses Special charges and impairments (including net disposal losses) Equity in NRG losses Pretax income (loss) from operations of discontinued components Income tax expense (beneﬁt) Income (loss) from operations of discontinued components Estimated pretax gain on disposal of discontinued components Income tax expense Gain on disposal of discontinued components Net income (loss) from discontinued operations Utility Segment NRG Segment All Other Segment $ 6,579 6,131 – 448 268 180 – – – 180 $ $72,232 68,305 6,574 (2,647) 6,388 (9,035) – – – $ (9,035) $51,723 46,539 – – 5,184 1,667 3,517 40,072 16,780 23,292 $26,809 $ $ $ $ – – – – – – – – – – – – – – – – – – – – $ – – (1,664) 253,043 (251,379) – (251,379) – – – $(251,379) $ 63,206 68,669 – (5,463) (19,217) 13,754 – – – $ 13,754 $ 179,890 194,605 228,439 (243,154) (78,021) (165,133) 961 6,904 7,865 $(157,268) $ 298,550 330,538 58,700 – (90,688) (414,826) 324,138 – – – $ 324,138 Total $ 69,785 74,800 – (5,015) (18,949) 13,934 – – – $ 13,934 $ 252,122 262,910 235,013 (245,801) (71,633) (174,168) 961 6,904 7,865 $(166,303) $ 350,273 377,077 57,036 253,043 (336,883) (413,159) 76,276 40,072 16,780 23,292 $ 99,568 The major classes of assets and liabilities held for sale and related to discontinued operations as of Dec. 31 are as follows: (Thousands of dollars) Cash Restricted cash Trade receivables – net Deferred income tax beneﬁts Other current assets Current assets Property, plant and equipment – net Deferred income tax beneﬁts Other noncurrent assets Noncurrent assets Accounts payable – trade Other current liabilities Current liabilities Long-term debt Other noncurrent liabilities Noncurrent liabilities 52 XCEL ENERGY 2005 ANNUAL REPORT 2005 2004 $ 12,658 – 6,101 157,812 24,240 200,811 29,845 352,171 19,269 401,285 7,657 36,000 43,657 – 6,936 $ 6,936 $ 33,228 15,000 24,364 234,305 60,351 367,248 155,428 338,863 46,293 540,584 29,451 83,480 112,931 24,800 64,442 $ 89,242 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 3. SHORT-TERM BORROWINGS Notes Payable and Commercial Paper During 2005, Xcel Energy, PSCo and SPS resumed short-term borrowings in the commercial paper market. Information regarding notes payable and commercial paper for the years ended Dec. 31, 2005 and 2004, is presented in the following table: (Millions of dollars, except interest rates) Notes payable to banks Commercial paper Total short-term debt Weighted average interest rate at year-end 2005 $ – 746.1 $746.1 2004 $312.3 – $312.3 4.46% 4.15% Credit Facilities On Dec. 1, 2005, PSCo entered into an agreement with Wells Fargo Bank, N.A. to provide PSCo a committed five-month, $50 million seasonal revolving credit facility. The interest rate is based on either Wells Fargo Bank’s prime rate or the applicable London Interbank Offered Rate (LIBOR), plus a borrowing margin as determined by PSCo’s credit worthiness. PSCo entered into this agreement to ensure adequate liquidity for rising natural gas prices during the winter months. As of Dec. 31, 2005, PSCo had not borrowed against this facility. In addition, on Dec. 12, 2005, PSCo entered into a $25 million good-until-canceled uncommitted credit line with KBC Bank to provide additional short-term seasonal liquidity as a result of higher natural gas prices. As of Dec. 31, 2005, PSCo had not utilized this credit line. 4. LONG-TERM DEBT Credit Facilities At Dec. 31, 2005, Xcel Energy and its utility subsidiaries had the following committed credit facilities available: (Millions of dollars) NSP-Minnesota PSCo SPS Xcel Energy – holding company Total Credit Facility $ 450 $ 600 $ 250 $ 700 $2,000 Available* Term Maturity $190.3 $258.9 $164.4 $356.0 $969.6 Five year Five year Five year Five year April 2010 April 2010 April 2010 November 2009 * Net of credit facility borrowings, issued and outstanding letters of credit and commercial paper borrowings. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and backup support for commercial paper borrowings. Each credit facility has one ﬁnancial covenant requiring that the debt-to-total-capitalization ratio of each entity be less than or equal to 65 percent with which all were in compliance. The interest rates under these lines of credit are based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as determined by each entity’s credit worthiness. Xcel Energy has a $700 million, five-year senior unsecured revolving credit facility that matures in November 2009. Xcel Energy has the right to request an extension of the ﬁnal maturity date by one year. The maturity extension is subject to majority bank group approval. As of Dec. 31, 2005, Xcel Energy had no direct borrowings on this line of credit; however, the credit facility was used to provide backup for $325.5 million of commercial paper outstanding and $18.5 million of letters of credit. As discussed in Note 13 to the Consolidated Financial Statements, $35.2 million of letters of credit were outstanding at Dec. 31, 2005, of which $18.5 million were supported by the Xcel Energy credit facility and are included in the above table. Xcel Energy’s 2007 and 2008 series convertible senior notes are convertible into shares of Xcel Energy common stock at a conversion price of $12.33 per share. Conversion is at the option of the holder at any time prior to maturity. In addition, Xcel Energy must make additional payments of interest, referred to as protection payments, on the notes in an amount equal to any portion of regular quarterly per share dividends on common stock that exceeds $0.1875 that would have been payable to the holders of the notes if such holders had converted their notes on the record date for such dividend. On May 25, 2005, the board of directors of Xcel Energy voted to raise the quarterly dividend on its common stock from $0.2075 to $0.2150. Consequently, as of Dec. 31, 2005, a total of $2.4 million in additional interest expense has been recorded. All property of NSP-Minnesota and NSP-Wisconsin and the electric property of PSCo are subject to the liens of their ﬁrst mortgage indentures. In addition, certain SPS payments under its pollution-control obligations are pledged to secure obligations of the Red River Authority of Texas. Maturities of long-term debt are: 2006 2007 2008 2009 2010 $835.5 million $338.9 million $632.4 million $557.8 million $1,031.6 million XCEL ENERGY 2005 ANNUAL REPORT 53 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 5. PREFERRED STOCK Xcel Energy has authorized 7,000,000 shares of preferred stock with a $100 par value. At Dec. 31, 2005, Xcel Energy had six series of preferred stock outstanding, redeemable at its option at prices ranging from $102.00 to $103.75 per share plus accrued dividends. Under the PUHCA, unless there was an order from the SEC, a holding company or any subsidiary could declare and pay dividends only out of retained earnings. With the repeal of the PUHCA, restrictions on the ability of holding companies or utility subsidiaries to declare dividends set out in that statute no longer apply. The holders of the $3.60 series preferred stock are entitled to three votes per each share held. The holders of the other series of preferred stock are entitled to one vote per share. In the event dividends payable on the preferred stock of any series outstanding is in arrears in an amount equal to four quarterly dividends, the holders of preferred stocks, voting as a class, are entitled to elect the smallest number of directors necessary to constitute a majority of the board of directors. The holders of common stock, voting as a class, are entitled to elect the remaining directors. The charters of some of Xcel Energy’s subsidiaries also authorize the issuance of preferred stock. However, at Dec. 31, 2005, there are no preferred shares outstanding. SPS PSCo Preferred Shares Authorized 10,000,000 10,000,000 Par Value $1.00 $0.01 Preferred Shares Outstanding None None 6. MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS NSP Financing I, a wholly owned, special-purpose subsidiary trust of NSP-Minnesota, had $200 million of 7.875-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2037. The preferred securities were redeemable at NSP Financing I’s option at $25 per share, beginning in 2002. On July 31, 2003, NSP-Minnesota redeemed the $200 million of trust preferred securities. A certiﬁcate of cancellation was ﬁled to dissolve NSP Financing I on Sept. 15, 2003. PSCo Capital Trust I, a wholly owned, special-purpose subsidiary trust of PSCo, had $194 million of 7.60-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2038. The securities were redeemable at the option of PSCo after May 2003, at 100 percent of the principal amount outstanding plus accrued interest. On June 30, 2003, PSCo redeemed the $194 million of trust preferred securities. A certiﬁcate of cancellation was ﬁled to dissolve PSCo Capital Trust I on Dec. 29, 2003. Southwestern Public Service Capital I, a wholly owned, special-purpose subsidiary trust of SPS, had $100 million of 7.85-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2036. The securities were redeemable at the option of SPS after October 2001, at 100 percent of the principal amount plus accrued interest. On Oct. 15, 2003, SPS redeemed the $100 million of trust preferred securities. A certiﬁcate of cancellation was ﬁled to dissolve SPS Capital I on Jan. 5, 2004. Distributions paid to preferred security holders were reﬂected as a ﬁnancing cost in the Consolidated Statements of Operations, along with interest charges. 54 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 7. GENERATING PLANT OWNERSHIP AND OPERATION Joint Plant Ownership Following are the investments by Xcel Energy’s subsidiaries in jointly owned plants and the related ownership percentages as of Dec. 31, 2005: (Thousands of dollars) NSP-Minnesota Sherco Unit 3 Sherco Common Facilities Units 1, 2 and 3 Transmission facilities, including substations Total NSP-Minnesota PSCo Hayden Unit 1 Hayden Unit 2 Hayden Common Facilities Craig Units 1 and 2 Craig Common Facilities Units 1, 2 and 3 Comanche Unit 3 Transmission and other facilities, including substations Total PSCo Plant in Accumulated Service Depreciation Construction Work in Progress Ownership % $500,266 102,988 4,832 $608,086 $ 84,357 80,034 28,244 52,848 32,384 – 114,788 $392,655 $282,145 53,552 1,878 $ 337,575 $ 43,579 45,637 5,538 26,318 9,673 – 42,412 $173,157 $ 665 1,196 – $ 1,861 $ 635 1,006 – 24 – 54,960 13 $56,638 59.0 65.6 59.0 75.5 37.4 53.1 9.7 6.5–9.7 74.7 11.6–68.1 NSP-Minnesota is part owner of Sherco 3, an 860-megawatt, coal-fueled electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility accounts. PSCo’s current operational assets include approximately 320 megawatts of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. PSCo began major construction on a new jointly owned 750-megawatt, coal-ﬁred unit in Pueblo, Colo. in January 2006. Major construction on the new unit, Comanche 3, is expected to be completed in 2010. PSCo is the operating agent under the joint ownership agreement. Each of the respective owners is responsible for the issuance of its own securities to ﬁnance its portion of the construction costs. Nuclear Plant Operation The Nuclear Management Company (NMC) is an operating company that manages the operations, maintenance and physical security of several nuclear generating units on ﬁve sites, including three units / two sites owned by NSP-Minnesota. NSP-Minnesota continues to own the plants, controls all energy produced by the plants and retains responsibility for nuclear property and liability insurance and decommissioning costs. The Wisconsin Public Service Corporation is no longer participating in NMC after the sale of its Kewaunee nuclear power plant in July 2005. In January 2006, Florida Power & Light purchased the majority interest in the Duane Arnold plant from Alliant Energy and announced it will assume management of the plant. As a result, NSP-Minnesota’s ownership interest in NMC has increased to 25 percent. In accordance with the Nuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays its proportionate share of the operating expenses and capital improvement costs incurred by NMC. NSP-Minnesota paid NMC $257.1 million in 2005, $314.7 million in 2004 and $227.0 million in 2003. 8. INCOME TAXES Xcel Energy’s federal net operating loss and tax credit carry forwards are estimated to be $1.4 billion and $107.6 million, respectively. A portion of the net operating loss in the amount of $1.1 billion and a portion of the tax credit carry forwards in the amount of $28.8 million are accounted for in discontinued operations. The carry forward periods expire in 2023 and 2024. Xcel Energy also has net operating loss and tax credit carry forwards in some states. The state carry forward periods expire between 2014 and 2024. A valuation allowance was recorded against deferred tax assets for capital loss carry forwards related to discontinued operations. The valuation allowance was $44 million as of Dec. 31, 2005, and $46 million as of Dec. 31, 2004. The net reduction in valuation allowance of $2 million was due to capital gains. The capital loss carry forward period expires in 2009. Total income tax expense from continuing operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following is a table reconciling such differences for the years ending Dec. 31: Federal statutory rate Increases (decreases) in tax from: State income taxes, net of federal income tax beneﬁt Life insurance policies Tax credits recognized Regulatory differences – utility plant items Resolution of income tax audits and prior-period adjustments Other – net Effective income tax rate from continuing operations 2005 35.0% 2.5 (4.6) (4.4) (0.3) (0.3) (2.1) 25.8% 2004 35.0% 3.3 (4.0) (4.4) (0.1) (5.3) (0.8) 23.7% 2003 35.0% 2.3 (3.8) (3.9) 0.8 (5.1) (0.7) 24.6% XCEL ENERGY 2005 ANNUAL REPORT 55 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Income taxes comprise the following expense (beneﬁt) items for the years ending Dec. 31: (Thousands of dollars) Current federal tax expense Current state tax expense (beneﬁt) Current tax credits Deferred federal tax expense Deferred state tax expense Deferred tax credits Deferred investment tax credits Total income tax expense from continuing operations 2005 2004 2003 $ (4,122) (15,733) (45) 191,900 31,235 (18,077) (11,619) $173,539 $ 88,514 32,135 (3,798) 67,716 3,574 (14,017) (12,189) $161,935 $ 111,986 (592) (3,137) 83,245 3,298 (11,668) (12,440) $170,692 The components of Xcel Energy’s net deferred tax liability from continuing operations (current and noncurrent portions) at Dec. 31 were: (Thousands of dollars) Deferred tax liabilities: Differences between book and tax bases of property Regulatory assets Employee beneﬁts Partnership income/loss Service contracts Other Total deferred tax liabilities Deferred tax assets: Net operating loss carry forward Other comprehensive income Deferred investment tax credits Tax credit carry forward Regulatory liabilities Book reserves and other Total deferred tax assets Net deferred tax liability 2005 2004 $2,245,748 257,843 25,711 10,010 8,539 85,810 $2,633,661 $ 119,124 80,356 51,286 86,143 40,835 46,106 $ 423,850 $ 2,209,811 $2,056,951 244,388 33,191 10,310 11,369 31,227 $ 2,387,436 $ 88,159 63,469 55,967 51,046 39,415 70,892 $ 368,948 $ 2,018,488 9. COMMON STOCK AND STOCK-BASED COMPENSATION Common Stock and Equivalents Xcel Energy has common stock equivalents consisting of convertible senior notes, restricted stock units and stock options, as discussed later. In 2005, 2004 and 2003, Xcel Energy had 13.3 million, 14.3 million and 15.6 million options outstanding, respectively, that were antidilutive and therefore excluded from the earnings per share calculation. The dilutive impact of common stock equivalents affected earnings per share as follows for the years ending Dec. 31: (Shares and dollars in thousands, except per share amounts) Per Share Income Shares Amount Per Share Income Shares Amount Per Share Income Shares Amount 2005 2004 2003 Income from continuing operations Less: Dividend requirements on preferred stock Basic earnings per share Income from continuing operations Effect of dilutive securities: $230 million convertible debt $57.5 million convertible debt Convertible debt option Restricted stock units Options Diluted earnings per share Income from continuing operations and $499,038 (4,241) $522,264 (4,241) $522,824 (4,241) 494,797 402,330 $1.23 518,023 399,456 $1.30 518,583 398,765 $1.30 11,498 2,875 – – – 18,654 4,663 – – 24 11,940 2,985 – – – 18,654 4,663 – 544 17 11,213 311 – – – 18,654 507 508 464 14 assumed conversions $509,170 425,671 $1.20 $532,948 423,334 $1.26 $530,107 418,912 $1.26 Stock-Based Compensation Xcel Energy has incentive compensation plans under which stock options and other performance incentives are awarded to key employees. The weighted average number of common and potentially dilutive shares outstanding used to calculate Xcel Energy’s earnings per share include the dilutive effect of stock options and other stock awards based on the treasury stock method. The options normally have a term of 10 years and generally become exercisable from three to ﬁve years after grant date or upon speciﬁed circumstances. The tables on the following page include awards made by Xcel Energy and some of its predecessor companies, adjusted for the merger stock exchange ratio, and are presented on an Xcel Energy share basis. 56 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Activity in stock options was as follows for the years ended Dec. 31: (Awards in thousands) Outstanding beginning of year Exercised Forfeited Expired Outstanding at end of year Exercisable at end of year Options outstanding: Number outstanding Weighted average remaining contractual life (years) Weighted average exercise price Options exercisable: Number exercisable Weighted average exercise price 2005 2004 2003 Awards 14,606 (152) (213) (665) 13,576 13,529 Average Price $26.67 $17.30 $26.84 $23.71 $26.92 $26.91 Awards 15,614 (45) (172) (791) 14,606 10,096 Average Price $26.49 $15.08 $25.10 $24.08 $26.67 $26.58 Awards 16,981 (190) (580) (597) 15,614 9,358 Average Price $26.29 $12.21 $28.48 $23.41 $26.49 $25.59 $13.81 to $25.50 Range of Exercise Prices $25.51 to $27.00 $27.01 to $51.25 2,613,302 2.9 $20.44 2,613,302 $20.44 7,001,694 4.4 $26.28 7,001,694 $26.28 3,960,810 4.4 $32.31 3,913,810 $32.33 Certain employees also may elect to receive shares of common or restricted stock under the Xcel Energy Inc. Executive Annual Incentive Award Plan. Restricted stock vests in equal annual installments over a three-year period from the date of grant. Xcel Energy reinvests dividends on the restricted stock it holds while restrictions are in place. Restrictions also apply to the additional shares of restricted stock acquired through dividend reinvestment. Restricted stock has a value equal to the market-trading price of Xcel Energy’s stock at the grant date. Xcel Energy granted 28,626 shares of restricted stock in 2005 when the grant-date market price was $17.81. Xcel Energy granted 65,090 shares of restricted stock in 2004 when the grant-date market price was $17.40. Xcel Energy did not grant any shares of restricted stock in 2003. Compensation expense related to these awards was not signiﬁcant. On March 28, 2003, the governance, compensation and nominating committee of Xcel Energy’s board of directors granted restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan approved by the shareholders in 2000. Restrictions on the restricted stock units lapse upon the achievement of a 27-percent total shareholder return (TSR) for 10 consecutive business days and other criteria relating to Xcel Energy’s common equity ratio. Under no circumstances will the restrictions lapse until one year after the grant date. TSR is measured using the market price per share of Xcel Energy common stock, which at the grant date was $12.93, plus common dividends declared after grant date. The TSR was met in the fourth quarter of 2003, and approximately $31 million of compensation expense was recorded at Dec. 31, 2003. The remaining cost of $10 million related to the 2003 restricted stock units was recorded in the first quarter of 2004. In January 2004, Xcel Energy’s board of directors approved the repurchase of up to 2.5 million shares of common stock to fulﬁll the requirements of the restricted stock unit exercise. On March 29, 2004, the restricted stock units lapsed, and Xcel Energy issued approximately 1.6 million shares of common stock. The performance share award is entirely dependent on a single measure, the TSR. Xcel Energy’s TSR will be measured over a three-year period. Xcel Energy’s TSR is compared to the TSR of other companies in the Edison Electric Institute’s Electrics Index. At the end of the three-year period, potential payouts of the performance shares range from 0 percent to 200 percent, depending on Xcel Energy’s TSR compared to the peer group. On Dec. 9, 2003, the governance, compensation and nominating committee of Xcel Energy’s board of directors approved restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. On Jan. 2, 2004, Xcel Energy granted 836,186 restricted stock units and performance shares. The grant-date market price used to calculate the TSR for this grant is $17.03. On Dec. 14, 2004, the governance, compensation and nominating committee of Xcel Energy’s board of directors granted restricted stock units under the Xcel Energy Inc. Omnibus Incentive Plan. Payout of the units and the lapsing of restrictions on the transfer of units are based on two separate performance criteria. A portion of the awarded units plus associated earned dividend equivalents will be settled, and the restricted period will lapse after Xcel Energy achieves a speciﬁed earnings per share growth (adjusted for corporate-owned life insurance) measured against year-end earnings per share (adjusted for corporate-owned life insurance). Additionally, Xcel Energy’s annual dividend paid on its common stock must remain at $0.83 per share or greater. Earnings per share growth will be measured annually at the end of each ﬁscal year. However, in no event will the restrictions lapse prior to two years after the date of grant. The remaining awarded units plus associated earned dividend equivalents will be settled, and the restricted period will lapse after the average of actual performance results (adjusted for actual megawatt hours) for the three components of an environmental index measured as a percentage of target performance meets or exceeds 100 percent. The environmental index will be measured annually at the end of each ﬁscal year. However, in no event will the restrictions lapse prior to two years after the date of grant. If the performance criteria have not been met within four years of the date of grant, all associated units shall be forfeited. On Jan. 1, 2005, Xcel Energy granted 519,362 restricted stock units. On Dec. 14, 2004, the governance, compensation and nominating committee of Xcel Energy’s board of directors approved performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. On Jan. 1, 2005, Xcel Energy granted 323,889 performance shares. XCEL ENERGY 2005 ANNUAL REPORT 57 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S On Dec. 13, 2005, the governance, compensation and nominating committee of Xcel Energy’s board of directors approved restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. On Jan. 1, 2006, Xcel Energy granted approximately 653,000 restricted stock units and performance shares. Compensation expense related to restricted stock units and performance shares of approximately $14.9 million, $16.8 million and $35.0 million was recorded in 2005, 2004 and 2003, respectively. Xcel Energy applies Accounting Principles Board Opinion No. 25 – “Accounting for Stock Issued to Employees” in accounting for stock-based compensation and, accordingly, no compensation cost is recognized for the issuance of stock options, as the exercise price of the options equals the fair-market value of Xcel Energy’s common stock at the date of grant. In December 2002, the FASB issued SFAS No. 148 – “Accounting for Stock-Based Compensation – Transition and Disclosure,” amending SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair-value-based method of accounting for stock-based employee compensation, and requiring disclosure in both annual and interim Consolidated Financial Statements about the method used and the effect of the method used on results. The pro forma impact of applying SFAS No. 148 is as follows at Dec. 31: (Thousands of dollars, except per share amounts) Net income – as reported Less: Total stock-based employee compensation expense determined under fair-value-based method for stock options, net of related tax effects Pro forma net income (loss) Earnings per share: Basic – as reported Basic – pro forma Diluted – as reported Diluted – pro forma 2005 2004 2003 $512,972 $355,961 $622,392 (1,180) $511,792 (2,339) $353,622 (3,897) $618,495 $ $ $ $ 1.26 1.26 1.23 1.23 $ $ $ $ 0.88 0.87 0.87 0.86 $ $ $ $ 1.55 1.54 1.50 1.49 Common Stock Dividends Per Share Historically, Xcel Energy has paid quarterly dividends to its shareholders. Dividends on common stock are paid as declared by the board of directors. Dividends paid per share for the quarters of 2005, 2004 and 2003 are: 2005 First Quarter Second Quarter Third Quarter Fourth Quarter 2004 First Quarter Second Quarter Third Quarter Fourth Quarter 2003 First Quarter Second Quarter Third Quarter Fourth Quarter Dividends Per Share $0.2075 0.2150 0.2150 0.2150 $0.8525 $0.1875 0.2075 0.2075 0.2075 $0.8100 $0.1875 0.1875 0.1875 0.1875 $0.7500 Dividend and Other Capital-Related Restrictions Formerly, under the PUHCA, unless there was an order from the SEC, a holding company or any subsidiary could declare and pay dividends only out of retained earnings. In May 2003, Xcel Energy received authorization from the SEC to pay an aggregate amount of $152 million of common and preferred dividends out of capital and unearned surplus. Xcel Energy used this authorization to declare and pay approximately $150 million for its ﬁrst- and second-quarter dividends in 2003. At Dec. 31, 2005, Xcel Energy’s retained earnings were approximately $562.1 million. With the repeal of the PUHCA, restrictions on the ability of holding companies or utility subsidiaries to declare dividends set out in that statute will no longer apply. However, utility dividends will be subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of utility dividends out of capital accounts. The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only and not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this deﬁnition, the capitalization ratio at Dec. 31, 2005, was 84 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock. 58 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S In addition, NSP-Minnesota’s ﬁrst mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $854 million in additional cash dividends on common stock at Dec. 31, 2005. Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, were limited, under the PUHCA, in their ability to issue securities. Such registered holding companies and their subsidiaries could not issue securities unless authorized by an exemptive rule or order of the SEC. Because Xcel Energy did not qualify for any of the main exemptive rules, it sought and received ﬁnancing authority from the SEC under the PUHCA for various ﬁnancing arrangements. Xcel Energy’s current ﬁnancing authority permits it, subject to certain conditions, to issue through June 30, 2008, up to $1.8 billion of new long-term debt, common equity and equity-linked securities and $1.0 billion of short-term debt securities during the new authorization period, provided that the aggregate amount of long-term debt, common equity, and equity-linked and short-term debt securities issued during the new authorization period does not exceed $2.0 billion. Xcel Energy’s ability to issue securities under the financing authority was subject to a number of conditions. One of the conditions of the financing authority was that Xcel Energy’s ratio of common equity to total capitalization, on a consolidated basis, be at least 30 percent. As of Dec. 31, 2005, such common equity ratio was approximately 42 percent. Additional conditions require that a security to be issued that is rated, must be at least rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities that are rated must be rated investment grade by at least one nationally recognized rating agency. On Feb. 10, 2006, Xcel Energy’s senior unsecured debt was considered investment grade by Standard & Poor’s, Moody’s and Fitch. Upon the repeal of the PUHCA, these limitations on Xcel Energy’s ﬁnancings generally will no longer apply, nor will the PUHCA restrictions generally apply to the ﬁnancings by the utility subsidiaries. However, utility ﬁnancings and intra-system ﬁnancings will become subject to the jurisdiction of the FERC under the Federal Power Act. The FERC by rule has granted a blanket authorization under certain intra-system ﬁnancings involving holding companies. Requests to the FERC to clarify its rules or grant similar blanket authorizations ﬁled by other entities are presently pending before the FERC. Xcel Energy and the utility subsidiaries are presently evaluating the speciﬁc applications that they will need to ﬁle with the FERC due to the repeal of the PUHCA. It is possible that in lieu of requesting authority from the FERC for intra-company ﬁnancings, Xcel Energy and the utility subsidiaries may rely in the interim on a transitional savings clause that would permit such ﬁnancing transactions to the extent authorized by the SEC ﬁnancing order and so long as the conditions in the SEC ﬁnancing order continue to be satisﬁed. Stockholder Protection Rights Agreement In June 2001, Xcel Energy adopted a Stockholder Protection Rights Agreement. Each share of Xcel Energy’s common stock includes one shareholder protection right. Under the agreement’s principal provision, if any person or group acquires 15 percent or more of Xcel Energy’s outstanding common stock, all other shareholders of Xcel Energy would be entitled to buy, for the exercise price of $95 per right, common stock of Xcel Energy having a market value equal to twice the exercise price, thereby substantially diluting the acquiring person’s or group’s investment. The rights may cause substantial dilution to a person or group that acquires 15 percent or more of Xcel Energy’s common stock. The rights should not interfere with a transaction that is in the best interests of Xcel Energy and its shareholders because the rights can be redeemed prior to a triggering event for $0.01 per right. 10. BENEFIT PLANS AND OTHER POSTRETIREMENT BENEFITS Xcel Energy offers various beneﬁt plans to its beneﬁt employees. Approximately 56 percent of beneﬁting employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2005, NSP-Minnesota had 2,144 and NSP-Wisconsin had 417 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2007. PSCo had 2,165 bargaining employees covered under a collective-bargaining agreement, which expires in May 2006. SPS had 733 bargaining employees covered under a collective-bargaining agreement, which expires in October 2008. P E N S I O N B E N E F I T S Xcel Energy has several noncontributory, deﬁned beneﬁt pension plans that cover almost all employees. Beneﬁts are based on a combination of years of service, the employee’s average pay and Social Security beneﬁts. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and ﬁnancial reporting purposes, subject to the limitations of applicable employee beneﬁt and tax laws. Pension Plan Assets Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. In 2004, Xcel Energy completed a review of its pension plan asset allocation and adopted revised asset allocation targets. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in ﬁxed income investments and 20 percent in nontraditional investments, such as real estate, timber ventures, private equity and a diversiﬁed commodities index. The actual composition of pension plan assets at Dec. 31 was: Equity securities Debt securities Real estate Cash Nontraditional investments 2005 65% 20 4 1 10 100% 2004 69% 19 4 1 7 100% XCEL ENERGY 2005 ANNUAL REPORT 59 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 12 percent, which is greater than the current assumption level. The pension cost determinations assume the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments that can provide a higher-than-average return. As is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year. Investment returns in 2005, 2004 and 2003 exceeded the assumed level of 8.75, 9.0 and 9.25 percent, respectively. Xcel Energy continually reviews its pension assumptions. In 2006, Xcel Energy will continue to use an investment-return assumption of 8.75 percent. Benefit Obligations A comparison of the actuarially computed pension-beneﬁt obligation and plan assets, on a combined basis, is presented in the following table: (Thousands of dollars) Accumulated Beneﬁt Obligation at Dec. 31 Change in Projected Beneﬁt Obligation Obligation at Jan. 1 Service cost Interest cost Plan amendments Actuarial loss Settlements Beneﬁt payments Obligation at Dec. 31 Change in Fair Value of Plan Assets Fair value of plan assets at Jan. 1 Actual return on plan assets Employer contributions Settlements Beneﬁt payments Fair value of plan assets at Dec. 31 Funded Status of Plans at Dec. 31 Net asset Unrecognized prior service cost Unrecognized loss Net pension amounts recognized on Consolidated Balance Sheets Prepaid pension asset recorded (a) Intangible asset recorded – prior service costs Minimum pension liability recorded Accumulated other comprehensive income recorded – pretax Accumulated other comprehensive income recorded – net of tax 2005 2004 $2,642,177 $2,575,317 $2,732,263 60,461 160,985 300 85,558 – (242,787) $2,796,780 $2,632,491 58,150 165,361 – 133,552 (27,627) (229,664) $2,732,263 $3,062,016 254,307 20,000 – (242,787) $3,093,536 $3,024,661 284,600 10,046 (27,627) (229,664) $3,062,016 $ 296,756 214,702 281,519 $ 792,977 $ 683,649 3,563 (88,280) 198,542 123,279 $ 329,753 244,437 176,957 $ 751,147 $ 642,873 4,689 (63,967) 170,554 106,007 Measurement Date Dec. 31, 2005 Dec. 31, 2004 Signiﬁcant Assumptions Used to Measure Beneﬁt Obligations Discount rate for year-end valuation Expected average long-term increase in compensation level 5.75% 3.50% 6.00% 3.50% (a) $22.1 million of the 2005 prepaid pension asset and $23.9 million of the 2004 prepaid pension asset relates to Xcel Energy’s remaining obligation for companies that are now classiﬁed as discontinued operations. During 2002, one of Xcel Energy’s pension plans became underfunded, and at Dec. 31, 2005, had projected beneﬁt obligations of $739.5 million, which exceeded plan assets of $609.8 million. All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion and projected beneﬁt obligations of $2.1 billion on Dec. 31, 2005. A minimum pension liability of $88.3 million was recorded related to the underfunded plan as of that date. A corresponding reduction in Accumulated Other Comprehensive Income, a component of Stockholders’ Equity, also was recorded, as previously recorded prepaid pension assets were reduced to record the minimum liability. Net of the related deferred income tax effects of the adjustments, total Stockholders’ Equity was reduced by $123.3 million at Dec. 31, 2005, due to the minimum pension liability for the underfunded plan. Cash Flows Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require 60 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S cash funding in the years 2003 through 2005 for Xcel Energy’s pension plans, and are not expected to require cash funding in 2006. PSCo elected to make voluntary contributions to its pension plan for bargaining employees of $9 million in 2004 and $14.7 million in 2005, Cheyenne voluntarily contributed $0.9 million to its pension plan for bargaining employees in 2004 and $0.3 million in 2005 and Xcel Energy voluntarily contributed $5.0 million to the New Century Energies, Inc. (NCE) non-bargaining plans in 2005. PSCo expects to voluntarily contribute between $15 million and $30 million during 2006 to the pension plan for bargaining employees. Benefit Costs The components of net periodic pension cost (credit) are: (Thousands of dollars) Service cost Interest cost Expected return on plan assets Curtailment gain Settlement gain Amortization of transition asset Amortization of prior service cost Amortization of net (gain) loss Net periodic pension cost (credit) under SFAS No. 87 (a) Credits not recognized due to effects of regulation Net beneﬁt credit recognized for ﬁnancial reporting Signiﬁcant Assumptions Used to Measure Costs Discount rate Expected average long-term increase in compensation level Expected average long-term rate of return on assets 2005 2004 2003 $ 60,461 160,985 (280,064) – – – 30,035 6,819 (21,764) 19,368 $ (2,396) $ 58,150 165,361 (302,958) – (926) (7) 30,009 (15,207) (65,578) 38,967 $(26,611) $ 67,449 170,731 (322,011) (17,363) (1,135) (1,996) 28,230 (44,825) (120,920) 51,311 $(69,609) 6.00% 3.50% 8.75% 6.25% 3.50% 9.00% 6.75% 4.00% 9.25% (a) Includes pension credits related to discontinued operations of $1.3 million for 2005, $4.7 million for 2004 and $19.0 million for 2003. The 2003 credit is largely due to a $20.0 million curtailment gain related to termination of NRG employees as a result of the divestiture of NRG in December 2003. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2006 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a ﬁve-year period. Xcel Energy also maintains noncontributory, deﬁned beneﬁt supplemental retirement income plans for certain qualifying executive personnel. Beneﬁts for these unfunded plans are paid out of Xcel Energy’s operating cash ﬂows. D E F I N E D C O NT R I B U T I O N P L A N S Xcel Energy maintains 401(k) and other deﬁned contribution plans that cover substantially all employees. Total contributions to these plans were approximately $19.6 million in 2005, $21.9 million in 2004 and $15.9 million in 2003. P O ST R E T I R E M E NT H E A LT H C A R E B E N E F I T S Xcel Energy has a contributory health and welfare beneﬁt plan that provides health care and death beneﬁts to most Xcel Energy retirees. The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. Xcel Energy discontinued contributing toward health care beneﬁts for former NCE nonbargaining employees retiring after June 30, 2003. Employees of the former NCE who retired in 2002 continue to receive employer-subsidized health care beneﬁts. Nonbargaining employees of the former NSP who retired after 1998, bargaining employees of the former NSP who retired after 1999 and nonbargaining employees of the former NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy. In conjunction with the 1993 adoption of SFAS No. 106 – “Employers’ Accounting for Postretirement Beneﬁts Other Than Pension,” Xcel Energy elected to amortize the unrecognized accumulated postretirement beneﬁt obligation (APBO) on a straight-line basis over 20 years. Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued beneﬁt costs under SFAS No. 106. The Colorado jurisdictional SFAS No. 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997. Plan Assets Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement beneﬁts. In 2004, the investment strategy for the union asset fund was changed to increase the investment mix in equity funds. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan. XCEL ENERGY 2005 ANNUAL REPORT 61 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S The actual composition of postretirement beneﬁt plan assets at Dec. 31 was: Equity and equity mutual fund securities Fixed income/debt securities Cash equivalents Nontraditional Investments 2005 61% 17 21 1 100% 2004 54% 21 25 – 100% Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Investment-return volatility is not considered to be a material factor in postretirement health care costs. Benefit Obligations A comparison of the actuarially computed beneﬁt obligation and plan assets for Xcel Energy postretirement health care plans that beneﬁt employees of its utility subsidiaries is presented in the following table: (Thousands of dollars) Change in Beneﬁt Obligation Obligation at Jan. 1 Service cost Interest cost Plan amendments Plan participants’ contributions Actuarial gain (loss) Beneﬁt payments Obligation at Dec. 31 Change in Fair Value of Plan Assets Fair value of plan assets at Jan. 1 Actual return on plan assets Plan participants’ contributions Employer contributions Beneﬁt payments Fair value of plan assets at Dec. 31 Funded Status at Dec. 31 Net obligation Unrecognized transition obligation Unrecognized prior service cost Unrecognized loss Accrued beneﬁt liability recorded (a) Measurement Date Signiﬁcant Assumptions Used to Measure Beneﬁt Obligations Discount rate for year-end valuation 2005 2004 $929,125 6,684 55,060 – 12,008 (3,175) (61,530) $938,172 $318,667 14,507 12,008 68,211 (61,530) $351,863 $586,309 (103,022) 15,736 (364,745) $134,278 $775,230 6,100 52,604 (1,600) 9,532 148,341 (61,082) $929,125 $285,861 21,950 9,532 62,406 (61,082) $318,667 $610,458 (117,600) 17,914 (383,026) $ 127,746 Dec. 31, 2005 Dec. 31, 2004 5.75% 6.00% (a) $3.1 million of the 2005 accrued beneﬁt liability and $1.7 million of the 2004 accrued beneﬁt liability relate to Xcel Energy’s remaining obligation for companies that are now classiﬁed as discontinued operations. Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend assumption from 5.5 percent to 5.0 percent. The period until the ultimate rate is reached also was increased from two years to six years. Xcel Energy bases its medical trend assumption on the long-term cost inﬂation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan. A 1-percent change in the assumed health care cost trend rate would have the following effects: (Thousands of dollars) 1-percent increase in APBO components at Dec. 31, 2005 1-percent decrease in APBO components at Dec. 31, 2005 1-percent increase in service and interest components of the net periodic cost 1-percent decrease in service and interest components of the net periodic cost $104,967 $ (87,450) $ 8,177 $ (6,696) 62 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S The employer subsidy for retiree medical coverage was eliminated for former New Century Energies, Inc. nonbargaining employees who retire after July 1, 2003. Xcel Energy’s subsidiary Viking was sold on Jan. 17, 2003. The sale created a one-time curtailment gain of $0.8 million. NRG participants withdrew from the retiree life plan, resulting in a $1.3 million one-time curtailment gain in 2003. NRG employees’ participation in the Xcel Energy postretirement health care plan ended when NRG emerged from bankruptcy on Dec. 5, 2003. A settlement gain of $0.9 million was recognized. Cash Flows The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $75 million during 2006. Benefit Costs The components of net periodic postretirement beneﬁt costs are: (Thousands of dollars) Service cost Interest cost Expected return on plan assets Curtailment gain Settlement gain Amortization of transition obligation Amortization of prior service credit Amortization of net loss Net periodic postretirement beneﬁt cost under SFAS No. 106 (a) Additional cost recognized due to effects of regulation Net cost recognized for ﬁnancial reporting Signiﬁcant assumptions used to measure costs (income) Discount rate Expected average long-term rate of return on assets (pretax) 2005 2004 2003 $ 6,684 55,060 (25,700) – – 14,578 (2,178) 26,246 74,690 3,891 $78,581 $ 6,100 52,604 (23,066) – – 14,578 (2,179) 21,651 69,688 3,891 $73,579 $ 5,893 52,426 (22,185) (2,128) (916) 15,426 (1,533) 15,409 62,392 3,883 $66,275 6.00% 6.75% 5.50%–8.50% 5.50%–8.50% 8.00%–9.00% 6.25% (a) Includes amounts related to discontinued operations of $1.1 million of cost in 2005, $1.3 million of cost in 2004 and $(1.7) million of cost in 2003. P R O J E C T E D B E N E F I T PAY M E NT S The following table lists Xcel Energy’s projected beneﬁt payments for the pension and postretirement beneﬁt plans: (Thousands of dollars) 2006 2007 2008 2009 2010 2011–2015 Projected Pension Beneﬁt Payments Gross Projected Postretirement Health Care Beneﬁt Payments Expected Medicare Part D Subsidies Net Projected Postretirement Health Care Beneﬁt Payments $ 218,093 $ 221,166 $ 228,196 $ 234,663 $ 239,730 $1,216,821 $ 63,966 $ 65,851 $ 67,635 $ 69,303 $ 70,851 $366,454 $ 4,777 $ 5,196 $ 5,582 $ 5,936 $ 6,248 $34,719 $ 59,189 $ 60,655 $ 62,053 $ 63,367 $ 64,603 $331,735 11. DETAIL OF INTEREST AND OTHER INCOME, NET OF NONOPERATING EXPENSE Interest and other income, net of nonoperating expense, for the years ended Dec. 31 consists of the following: (Thousands of dollars) Interest income Equity income (loss) in unconsolidated afﬁliates Gain (loss) on disposal of assets Other nonoperating income Interest expense on corporate-owned life insurance and other employee-related insurance policies Other nonoperating expense Total interest and other income (expense) 2005 2004 $14,886 2,511 1,308 7,153 (25,000) (1) 857 $ $21,534 3,225 4,725 4,441 (24,601) (8) $ 9,316 2003 $ 17,653 (1,108) (581) 3,160 (21,320) (3,038) $ (5,234) XCEL ENERGY 2005 ANNUAL REPORT 63 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 12. DERIVATIVE INSTRUMENTS In the normal course of business, Xcel Energy and its subsidiaries are exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. Xcel Energy and its subsidiaries utilize, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance our operations. The use of these derivative instruments is discussed in further detail below. Utility Commodity Price Risk Xcel Energy’s utility subsidiaries are exposed to commodity price risk in their electric and natural gas operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy and other energy-related products, and for various fuels used for generation of electricity and in the natural gas utility operations. Commodity risk also is managed through the use of ﬁnancial derivative instruments. Xcel Energy’s utility subsidiaries utilize these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of our retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments is done consistently with the state regulatory cost-recovery mechanism. Xcel Energy’s risk-management policy allows it to manage market price risk within each rate-regulated operation to the extent such exposure exists. Short-Term Wholesale and Commodity Trading Risk Xcel Energy’s utility subsidiaries conduct various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and other energy-related instruments. These activities are primarily focused on specific regions where market knowledge and experience have been obtained and are generally less than one year in length. Xcel Energy’s risk-management policy allows management to conduct the marketing activity within approved guidelines and limitations as approved by our risk-management committee, which is made up of management personnel not directly involved in the activities governed by this policy. Interest Rate Risk Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s risk-management policy allows interest rate risk to be managed through the use of fixed-rate debt, floating-rate debt and interest-rate derivatives such as swaps, caps, collars and put or call options. Foreign Currency Exchange Risk Due to the discontinuance of NRG and Xcel Energy International’s operations in 2003, as discussed in Note 2 to the Consolidated Financial Statements, Xcel Energy no longer has material foreign currency exchange risk. T Y P E S O F A N D AC C O U NT I N G F O R D E R I VAT I V E I N ST R U M E NT S Xcel Energy and its subsidiaries use a number of different derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, as amended, are recorded at fair value. The classiﬁcation of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship. The fair values of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Operations, to the extent effective. SFAS No. 133, as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. Xcel Energy and its subsidiaries formally document hedging relationships, including, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk-management objectives and strategies for undertaking the hedged transaction. Xcel Energy and its subsidiaries also formally assess, both at inception and on an ongoing basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash ﬂows of the hedged items. Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain ﬁnancial instruments purchased to reduce commodity cost volatility. Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or ﬁrm commitment (fair value hedge). The types of qualifying hedging transactions that Xcel Energy and its subsidiaries are currently engaged in are discussed below. C AS H F LOW H E D G E S The effective portion of the change in the fair value of a derivative instrument qualifying as a cash flow hedge is recognized in Other Comprehensive Income, and reclassiﬁed into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings. Commodity Cash Flow Hedges Xcel Energy’s utility subsidiaries enter into derivative instruments to manage variability of future cash ﬂows from changes in commodity prices. These derivative instruments are designated as cash ﬂow hedges for accounting purposes. At Dec. 31, 2005, Xcel Energy had various commodity-related contracts classified as cash flow hedges extending through 2009. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on 64 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale. As of Dec. 31, 2005, Xcel Energy had no amounts in Accumulated Other Comprehensive Income related to commodity cash ﬂow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle. Xcel Energy had no ineffectiveness related to commodity cash ﬂow hedges during the years ended Dec. 31, 2005 and 2004. Interest Rate Cash Flow Hedges Xcel Energy and its subsidiaries enter into interest rate swap instruments that effectively ﬁx the interest payments on certain ﬂoating-rate debt obligations. These derivative instruments are designated as cash ﬂow hedges for accounting purposes. As of Dec. 31, 2005, Xcel Energy had net losses related to interest rate swaps of approximately $0.8 million in Accumulated Other Comprehensive Income that it expects to recognize in earnings during the next 12 months. Xcel Energy and its subsidiaries also enter into interest rate lock agreements, including treasury-rate locks and forward starting swaps, that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash ﬂow hedges for accounting purposes. As of Dec. 31, 2005, Xcel Energy had net gains related to settled interest rate lock agreements of approximately $1.4 million in Accumulated Other Comprehensive Income that it expects to recognize in earnings during the next 12 months. Xcel Energy had no ineffectiveness related to interest rate cash ﬂow hedges during the years ended Dec. 31, 2005 and 2004. Financial Impact of Qualifying Cash Flow Hedges The impact of qualifying cash flow hedges on Xcel Energy’s Accumulated Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity, is detailed in the following table: (Millions of dollars) Accumulated other comprehensive income related to hedges at Dec. 31, 2002 After-tax net unrealized gains related to derivatives accounted for as hedges After-tax net realized gains on derivative transactions reclassiﬁed into earnings Accumulated other comprehensive income related to hedges at Dec. 31, 2003 After-tax net unrealized gains related to derivatives accounted for as hedges After-tax net realized gains on derivative transactions reclassiﬁed into earnings Accumulated other comprehensive income related to hedges at Dec. 31, 2004 After-tax net unrealized gains related to derivatives accounted for as hedges After-tax net realized gains on derivative transactions reclassiﬁed into earnings Accumulated other comprehensive loss related to hedges at Dec. 31, 2005 $22.1 24.1 (38.1) $ 8.1 1.6 (9.6) $ 0.1 4.5 (13.4) $ (8.8) FA I R VA L U E H E D G E S The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or ﬁrm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings. Interest Rate Fair Value Hedges Xcel Energy enters into interest rate swap instruments that effectively hedge the fair value of ﬁxed-rate debt. The fair market value of Xcel Energy’s interest rate swaps at Dec. 31, 2005, was a liability of approximately $14.1 million. N O R M A L P U R C H AS E S O R N O R M A L SA L E S C O NT R AC T S Xcel Energy’s utility subsidiaries enter into contracts for the purchase and sale of various commodities for use in their business operations. SFAS No. 133, as amended, requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the deﬁnition of a derivative may be exempted from SFAS No. 133, as amended, as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a ﬁnancial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a speciﬁed event, such as a scheduled payment under a contract. Xcel Energy evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133, as amended. None of the contracts entered into within the commodity trading operations qualify for a normal designation. Normal purchases and normal sales contracts are accounted for as executory contracts as required under GAAP. XCEL ENERGY 2005 ANNUAL REPORT 65 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S The following discussion brieﬂy describes the use of derivative commodity and ﬁnancial instruments at Xcel Energy and its subsidiaries, and discloses the respective fair values at Dec. 31, 2005 and 2004. Commodity Trading Instruments At Dec. 31, 2005 and 2004, the fair value of commodity trading contracts was $3.9 million and $0.0 million, respectively. Hedging Contracts The fair value of qualifying cash ﬂow hedges at Dec. 31, 2005 and 2004 was $4.1 million and $(24.6) million, respectively. Financial Instruments Xcel Energy and its subsidiaries had interest rate swaps outstanding with a fair value that was a liability of approximately $44.7 million at Dec. 31, 2005. On Dec. 31, 2004, subsidiaries of Xcel Energy had interest rate swaps outstanding with a fair value that was a liability of approximately $30 million. 13. FINANCIAL INSTRUMENTS The estimated Dec. 31 fair values of Xcel Energy’s ﬁnancial instruments, separately identifying amounts that are within continuing operations and within discontinued operations, are as follows: (Thousands of dollars) Continuing Operations Nuclear decommissioning fund Other investments Long-term debt, including current portion Discontinued Operations Long-term debt, including current portion 2005 2004 Carrying Amount Fair Value Carrying Amount Fair Value $ 1,047,592 $ 24,286 $6,733,284 $1,047,592 $ 24,050 $7,245,346 $ 918,442 $ 43,141 $6,716,675 $ 918,442 $ 43,031 $7,391,616 $ – $ – $ 24,800 $ 26,333 The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates. The fair values of Xcel Energy’s debt securities in an external nuclear decommissioning fund and other investments are estimated based on quoted market prices for those or similar investments. The fair values of Xcel Energy’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality. The fair value estimates presented are based on information available to management as of Dec. 31, 2005 and 2004. These fair value estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current estimates of fair values may differ significantly. The following tables provide the external decommissioning fund’s approximate gains, losses and proceeds from the sale of securities for the years ended Dec. 31: (Thousands of dollars) Realized gains Realized losses Proceeds from sale of securities (Thousands of dollars) Unrealized gains Unrealized losses 2003 $ 4,999 $ 6,025 $57,768 2005 2004 8,967 $ $ 8,990 $489,697 $ 16,578 $ 20,180 $223,135 2005 2004 $253,991 $ 10,558 $240,960 $ 2,703 Xcel Energy provides guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the speciﬁed agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantee. Unless otherwise indicated on the following page, the guarantees require no liability to be recorded, contain no recourse provisions and require no collateral. 66 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S On Dec. 31, 2005, Xcel Energy had the following amount of guarantees and exposure under these guarantees, including those related to Seren and Xcel Energy Argentina, which are components of discontinued operations: (Millions of dollars) Nature of Guarantee Guarantee performance and payment of surety bonds for itself and its subsidiaries (d) (h) Guarantee performance and payment of surety bonds Guarantee the indemniﬁcation obligations of Xcel Energy Wholesale Group Inc. under a stock purchase agreement Guarantee the indemniﬁcation obligations of Xcel Energy Argentina under a stock purchase agreement Guarantee the indemniﬁcation obligations of Seren under an asset purchase agreement Guarantee of customer loans to encourage business growth and expansion Guarantee of collection of receivables sold to a third party Combination of guarantees beneﬁting various Xcel Energy subsidiaries Guarantor Guarantee Amount Current Exposure Term or Expiration Date Xcel Energy $132.9 2006–2008, 2012, (a) 2014, 2015 and 2022 PSCo $ 0.50 (a) 2006 Triggering Event Requiring Assets Held as Performance Collateral (e) (e) N/A N/A Xcel Energy $ 17.50 $ – 2010 (c) N/A Xcel Energy $14.70 Xcel Energy $12.50 $ $ – – Continuing Continuing NSP-Wisconsin $ 0.20 $0.20 NSP-Minnesota $ 0.12 $0.12 2006 2006 Xcel Energy $ 7.65 $ – Continuing (c) (c) (f) (b) (b) N/A N/A N/A (g) N/A (a) The total exposure of this indemniﬁcation cannot be determined. Xcel Energy believes the exposure to be signiﬁcantly less than the total amount of the outstanding bonds. (b) Nonperformance and/or nonpayment. (c) Losses caused by default in performance of covenants or breach of any warranty or representation in the purchase agreement. (d) Includes one performance bond with a notional amount of $11.1 million that guarantees the performance of Planergy Housing Inc., a subsidiary of Xcel Energy that was sold to Ameresco Inc. on Dec. 12, 2003. Ameresco Inc. has agreed to indemnify Xcel Energy for any liability arising out of any surety bond. (e) Failure of Xcel Energy or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy and the various surety companies, the surety companies have the discretion to demand that collateral be posted. (f) Non-timely payment of the obligations or at the time the debtor becomes the subject of bankruptcy or other insolvency proceedings. (g) Security interest in underlying receivable agreements. (h) Xcel Energy agreed to indemnify an insurance company in connection with surety bonds they may issue or have issued for Utility Engineering up to $80 million. The Xcel Energy indemniﬁcation will be triggered only in the event that Utility Engineering has failed to meet its obligations to the surety company. L E T T E R S O F C R E D I T Xcel Energy and its subsidiaries use letters of credit, generally with terms of one year, to provide ﬁnancial guarantees for certain operating obligations. At Dec. 31, 2005, there was $35.2 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace. 14. COMMITMENTS AND CONTINGENCIES C O M M I T M E NT S Legislative Resource Commitments In 1994, NSP-Minnesota received Minnesota legislative approval for on-site temporary spent-fuel storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. Commitments related to the 17 dry cask storage containers approved in 1994 have been fulfilled. As a result of legislative amendments in 2003, NSP-Minnesota is authorized to use as many dry cask storage containers as necessary to operate the plant through 2014. Current estimates indicate that this will require 29 dry cask storage containers. As of Dec. 31, 2005, NSP-Minnesota had filled and placed 20 dry cask containers in storage at Prairie Island. The 2003 legislation transfers the primary authority concerning future spent-fuel storage issues from the Legislature to the MPUC. In January 2005, NSP-Minnesota ﬁled an application with the MPUC for a certiﬁcate of need for up to 30 dry cask storage containers at the Monticello nuclear plant so that it can continue to operate beyond 2010. Xcel Energy expects a decision from the MPUC later this year. NSP-Minnesota also ﬁled its request with the NRC on March 24, 2005, for a 20-year extension to Monticello’s operating license. If a certiﬁcate of need is granted, it is stayed until the following June to provide the Minnesota Legislature the opportunity to review the MPUC’s action if it is determined appropriate. The 2003 legislation also requires NSP-Minnesota to add at least 300 megawatts of additional wind power by 2010, with an option to own 100 megawatts of this power. XCEL ENERGY 2005 ANNUAL REPORT 67 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Furthermore, payments during the remaining operating life of the Prairie Island plant are required. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously established Renewable Development Fund to $16 million per year beginning in 2003. All of the cost increases to NSP-Minnesota from these required payments and funding commitments are expected to be recoverable in Minnesota retail customer rates, mainly through existing cost- recovery mechanisms. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that NSP-Minnesota failed to make a good faith effort to store or dispose of the spent fuel out of state, in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year. Capital Commitments The estimated cost as of Dec. 31, 2005, of the capital expenditure programs and other capital requirements of Xcel Energy and its subsidiaries is approximately $1.6 billion in 2006, $1.6 billion in 2007 and $1.4 billion in 2008. The capital expenditure programs of Xcel Energy are subject to continuing review and modiﬁcation. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements. Leases Xcel Energy and its subsidiaries lease a variety of equipment and facilities used in the normal course of business. Two of these leases qualify as capital leases and are accounted for accordingly. The capital leases contractually expire in 2025 and 2029. The assets and liabilities acquired under capital leases are recorded at the lower of fair market value or the present value of future lease payments, and are depreciated over their actual contract term in accordance with practices allowed by regulators. Depreciation of assets under capital leases is included in depreciation expense for 2005 and 2004. Following is a summary of property held under capital leases: (Millions of dollars) Storage, leaseholds and rights Gas pipeline Accumulated depreciation Total property held under capital leases 2005 $40.5 20.7 61.2 (13.6) $ 47.6 2004 $40.5 20.7 61.2 (12.3) $48.9 The remainder of the leases, primarily for ofﬁce space, railcars, trucks, cars and power-operated equipment, are accounted for as operating leases. Rental expense under operating lease obligations for continuing operations was approximately $57.2 million, $57.5 million and $65.0 million for 2005, 2004 and 2003, respectively. Future commitments under operating and capital leases for continuing operations are: (Millions of dollars) Operating Leases Capital Leases 2006 2007 2008 2009 2010 Thereafter Total minimum obligation Interest component of obligation Present value of minimum obligation $41 $34 $31 $27 $21 $54 $ 7 6 6 6 6 68 $99 (51) $48 Technology Agreement Xcel Energy has a contract that extends through 2015 with International Business Machines Corp. (IBM) for information technology services. The contract is cancelable at our option, although there are ﬁnancial penalties for early termination. In 2005, Xcel Energy paid IBM $137.7 million under the contract and $3.5 million for other project business. The contract also has a committed minimum payment each year from 2006 through September 2015. Fuel Contracts Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a signiﬁcant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2006 and 2027. In total, Xcel Energy is committed to the minimum purchase of approximately $2.8 billion of coal, $117.6 million of nuclear fuel and $2.7 billion of natural gas, including $1.0 billion of natural gas storage and transportation, or to make payments in lieu thereof, under these contracts. In addition, Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements. Xcel Energy’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate-adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers. Purchased Power Agreements The utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with 68 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indexes. However, the effects of price adjustments are mitigated through cost-of-energy rate adjustment mechanisms. At Dec. 31, 2005, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows: (Thousands of dollars) 2006 2007 2008 2009 2010 2011 and thereafter Total $ 564,669 579,333 592,655 574,145 555,228 3,439,683 $6,305,713 E N V I R O N M E NTA L C O NT I N G E N C I E S Xcel Energy and its subsidiaries have been, or are currently involved with, the cleanup of contamination from certain hazardous substances at several sites. In many situations, the subsidiary involved is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy and its subsidiaries, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense for such unrecoverable amounts in its Consolidated Financial Statements. Site Remediation Xcel Energy must pay all or a portion of the cost to remediate sites where past activities of its subsidiaries and some other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including the following categories of sites: – The site of a former federal uranium enrichment facility; – Sites of former manufactured gas plants (MGPs) operated by Xcel Energy subsidiaries or predecessors; and – Third-party sites, such as landﬁlls, to which Xcel Energy is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes. Xcel Energy records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially. To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and ﬁnancial strength of other PRPs and the identiﬁcation of new environmental cleanup sites. Estimates are revised as facts become known. At Dec. 31, 2005, the liability for the cost of remediating these sites was estimated to be $27.8 million, of which $8.8 million was considered to be a current liability. Some of the cost of remediation may be recovered from: – Insurance coverage; – Other parties that have contributed to the contamination; and – Customers. Neither the total remediation cost nor the ﬁnal method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for Xcel Energy’s future costs for these sites. Federal Uranium Enrichment Facility Approximately $0.5 million of the long-term liability and $4.8 million of the current liability relate to a DOE assessment to NSP-Minnesota and PSCo for decommissioning a federal uranium enrichment facility. These environmental liabilities do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota’s nuclear generating plants. See Note 15 to the Consolidated Financial Statements for further discussion of nuclear obligations. Manufactured Gas Plant Sites Ashland Manufactured Gas Plant Site NSP-Wisconsin was named a PRP for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin, which was previously an MGP facility, and two other properties: an adjacent city lakeshore park area, on which an unafﬁliated third party previously operated a sawmill, and an area of Lake Superior’s Chequemegon Bay adjoining the park. As an interim action, NSP-Wisconsin proposed, and the Wisconsin Department of Natural Resources (WDNR) approved, a coal tar removal and groundwater treatment system for one area of concern at the site for which NSP-Wisconsin has accepted responsibility. The groundwater treatment system began operating in the fall of 2000. In 2002, NSP-Wisconsin installed additional monitoring wells in the deep aquifer under XCEL ENERGY 2005 ANNUAL REPORT 69 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S the former MGP site to better characterize the extent and degree of contaminants in that aquifer while the coal tar removal system is operational. In 2002, a second interim response action was also implemented. As approved by the WDNR, this interim response action involved the removal and capping of a seep area in a city park. Surface soils in the area of the seep were contaminated with tar residues. The interim action also included the diversion and ongoing treatment of groundwater that contributed to the formation of the seep. On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the United States Environmental Protection Agency (EPA) in determining which sites require further investigation. On Dec. 7, 2004, the EPA approved, with minor contingencies, NSP-Wisconsin’s proposed work plan to complete the remedial investigation and feasibility study. On Feb. 1, 2005, NSP-Wisconsin submitted its revised work plan to the EPA addressing all of the contingencies raised with the previous proposal. The ﬁnal approval results in speciﬁc delineation of the investigative ﬁeldwork and scientiﬁc assessments that must be performed. A determination of the scope and cost of the remediation of the Ashland site is not currently expected until 2007 or 2008. NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site. In 2005, NSP-Wisconsin spent $2.8 million in the development of the work plan, the interim response action and other matters related to the site. The WDNR and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary signiﬁcantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The EPA and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility, NSP-Wisconsin’s liability for the cost of remediating the Ashland site is not determinable. NSP-Wisconsin has recorded a liability of $19.7 million for its potential liability for remediating the Ashland site. Since NSP-Wisconsin cannot currently estimate the cost of remediating the Ashland site, the recorded liability is based upon the minimum of the estimated range of remediation costs, using information available to date and reasonably effective remedial methods. On July 2, 2004, the WDNR sent NSP-Wisconsin an invoice for recovery of past costs incurred at the Ashland site between 1994 and March 2003 in the amount of $1.4 million. On Oct. 19, 2004, the WDNR, represented by the Wisconsin Department of Justice, ﬁled a lawsuit in Wisconsin state court for reimbursement of the past costs. This lawsuit has been stayed until further action by either party. NSP-Wisconsin is reviewing the invoice to determine whether all costs charged are appropriate and has recorded an estimate of its potential liability. All appropriate insurance carriers have been notiﬁed of the WDNR’s invoice and the lawsuit, and will be invited to participate in any future efforts to address the WDNR’s actions. All costs paid to the WDNR are expected to be recoverable in rates. In addition to potential liability for remediation and WDNR oversight costs, NSP-Wisconsin may have liability for natural resource damages, including the assessment thereof (collectively NRDA) at the Ashland site. Section 107 of the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) as amended, provides that a natural resource damages trustee may recover for injury to, destruction or loss of natural resources, including the reasonable costs of assessment, resulting from releases of hazardous substances. Similarly, Section 311 of the Federal Water Pollution Control Act (or Clean Water Act) provides the federal and state governments with the ability to recover costs incurred in the restoration or replacement of natural resources damaged or destroyed as a result of a hazardous substance discharge. In addition to liability for injuries to or loss of services caused by a release from the Ashland site, NSP-Wisconsin could face exposure for additional indirect injuries that could result from the implementation of various remedial technologies during the cleanup phase of the project. NSP-Wisconsin has indicated to the relevant natural resource trustees its intent to pursue a cooperative assessment approach to the NRDA for the Ashland site whereby the question of natural resource damages is assessed and resolved in tandem with the studies required for selection of a cleanup remedy or remedies. It is, however, unknown at this time whether a cooperative assessment NRDA approach will be adopted at the Ashland site. Therefore, NSP-Wisconsin is not able to estimate its potential exposure for natural resource damages at the site, but has recorded an estimate of its potential liability based upon the minimum of its estimated range of potential exposure. NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process. Once approved by the PSCW, deferred MGP remediation costs, less carrying costs, are historically amortized over four or six years. Carrying costs vary directly with the balance in the deferred account and for the period 1995–2005 are estimated to total approximately $1.8 million. In addition, in 2003, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers. Fort Collins Manufactured Gas Plant Site Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property. An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo performed remediation and monitoring work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring. In May 2005, PSCo ﬁled a natural gas rate case with the CPUC requesting recovery of cleanup costs at the Fort Collins MGP plant spent through March 2005, which amounted to $6.2 million to be amortized over four years. Xcel Energy reached a settlement agreement with the parties in the case. The CPUC approved the settlement agreement on Jan. 19, 2006, and the final order became effective on Feb. 3, 2006. In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases increased the migration and environmental impact of the MGP byproducts at the site. PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache 70 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S la Poudre River. On Dec. 14, 2005, the court denied Schrader’s request to dismiss the PSCo suit. On Jan. 3, 2006, Schrader ﬁled a response to the PSCo complaint and a counterclaim against PSCo for its response costs under the CERCLA and under the Resource Conservation and Recovery Act (RCRA). Schrader has alleged as part of its counterclaim an “imminent and substantial endangerment” of its property as deﬁned by RCRA. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself. Third Party and Other Environmental Site Remediation Asbestos Removal Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Xcel Energy has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations elsewhere in Note 14. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects. Leyden Gas Storage Facility In February 2001, the CPUC approved PSCo’s plan to abandon the Leyden natural gas storage facility (Leyden) after 40 years of operation. In July 2001, the CPUC decided that the recovery of all Leyden costs would be addressed in a future rate proceeding when all costs were known. In 2003, PSCo began ﬂooding the facility with water, as part of an overall plan to convert Leyden into a municipal water storage facility owned and operated by the city of Arvada, Colo. In August 2003, the Colorado Oil and Gas Conservation Commission (COGCC) approved the closure plan, the last formal regulatory approval necessary before conversion. On Dec. 31, 2005, PSCo’s leases of the Leyden properties were terminated and the city of Arvada took custody of the facility. PSCo is obligated to monitor the site for two years after closure. As of Dec. 31, 2005, PSCo has incurred approximately $5.7 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs. PSCo has accrued an additional $0.2 million of costs expected to be incurred through 2006 to complete the decommissioning and closure of the facility. PSCo has deferred these costs as a regulatory asset. In May 2005, PSCo ﬁled a natural gas rate case with the CPUC requesting recovery of the Leyden costs, totaling $4.8 million to be amortized over four years. Xcel Energy has reached a settlement agreement with the parties in the case. The CPUC approved the settlement agreement on Jan. 19, 2006, and the ﬁnal order became effective on Feb. 3, 2006. Xcel Energy believes that the additional $0.9 million of costs incurred may be recovered in a future case. In December 2003, a homeowners’ association petitioned the EPA to assess the threat of a natural gas release from the Leyden facility pursuant to Section 105(d) of the CERCLA. The EPA completed its review in October 2004 and concluded that the risk to nearby residents is relatively low. The EPA referred the matter to its RCRA program. On Nov. 24, 2004, the EPA sent a letter to the COGCC requesting that the COGCC contact Xcel Energy and request certain information concerning the closure. To date no formal request has been received by PSCo. On Aug. 17, 2005, the EPA requested information from PSCo regarding the compliance status of the Leyden facility under the federal Clean Air Act (CAA). On Sept. 19, 2005, PSCo responded to the requests for information. PSCo believes the Leyden facility is in compliance with the CAA and other applicable state and federal environmental laws. Xcel Energy cannot predict the ultimate outcome of this inquiry; however, any consequence is not expected to have a material impact. Polychlorinated Biphenyl (PCB) Storage and Disposal In August 2004, SPS received notice from the EPA contending SPS violated PCB storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contends the ﬁne for the alleged violation is approximately $1.2 million. SPS is contesting the ﬁne and is in discussions with the EPA. Cunningham Station Groundwater Cunningham Station is a natural gas-ﬁred power plant constructed in the 1960s by SPS and has 28 water wells installed on its water rights. The well ﬁeld provides water for boiler makeup, cooling water and potable water. Following an acid release in 2002, groundwater samples revealed elevated concentrations of inorganic salt compounds not related to the release. The contamination was identiﬁed in wells located near the plant buildings. The source of contamination is thought to be leakage from ponds that receive blowdown water from the plant. In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan to address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the plant blowdown ponds through construction of a new lined pond, additional irrigation areas to minimize percolation, and installation of additional wells to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the corrective action plan. The action plan is subject to continued compliance with New Mexico regulations and oversight by the NMED. These actions, which are considered future improvements, are estimated to cost approximately $3.8 million through 2008 and will be capitalized or expensed as incurred. Other Environmental Requirements Clean Air Interstate and Mercury Rules In March 2005, the EPA issued two signiﬁcant new air quality rules. The Clean Air Interstate Rule (CAIR) further regulates sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions, and the Clean Air Mercury Rule (CAMR) regulates mercury emissions from power plants for the ﬁrst time. The objective of the CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota, Texas and Wisconsin, which are within Xcel Energy’s service territory. Xcel Energy generating facilities in other states are not affected. When fully implemented, CAIR will reduce SO2 emissions in 28 eastern states and the District of Columbia by over 70 percent, and NOx emissions by over 60 percent from 2003 levels. It is designed to address the transportation of fine particulates, ozone and emission precursors to nonattainment downwind states. CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve. XCEL ENERGY 2005 ANNUAL REPORT 71 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S On July 11, 2005, SPS, the City of Amarillo, Texas and Occidental Permian LTD ﬁled a lawsuit against the EPA and a request for reconsideration with the agency to exclude West Texas from the CAIR. El Paso Electric Co. joined in the request for reconsideration. Xcel Energy and SPS advocated that West Texas should be excluded from CAIR because it does not contribute signiﬁcantly to nonattainment with the ﬁne particulate matter National Ambient Air Quality Standard in any downwind jurisdiction. They argued that: – Emissions from plants located in the Texas panhandle are more than 1,000 kilometers away from cities like Chicago, St. Louis and Indianapolis and have no measurable impact on their air quality. – The EPA should not arbitrarily include the entire state of Texas in the rule. As a result of its size, there are signiﬁcant differences in the air quality impact of plants in the different regions of Texas. – The EPA has precedent for dividing the state into two regions. As part of the Texas Air Quality strategy, the Texas Commission on Environmental Quality split the state and imposed different requirements on West Texas. The Bush administration adopted a similar approach in its proposed Clear Skies Act. – The EPA excluded Oklahoma and Kansas from CAIR, but imposes CAIR’s burdens on plants in West Texas. Emissions from West Texas must pass through Oklahoma and Kansas – and over power plants in those states that are not subject to the rule – before reaching the downwind cities the rule is designed to protect. Under CAIR’s cap-and-trade structure, SPS can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Based on the preliminary analysis of various scenarios of capital investment and allowance purchase, capital investments could range from $30 million to $300 million, and allowance purchases or increased operating and maintenance expenses could range from $20 million to $30 million per year, beginning in 2011, based on the cost of allowance on Feb. 15, 2006. This does not include other costs that SPS will have to incur to comply with the EPA’s new mercury emission control regulations, which will apply to SPS’ plants. In addition, Minnesota and Wisconsin will be included in CAIR, and Xcel Energy has generating facilities in these states that will be impacted. Preliminary estimates of capital expenditures associated with compliance with CAIR in Minnesota and Wisconsin range from $30 million to $40 million. Xcel Energy is not challenging CAIR in these states. These cost estimates represent one potential scenario on complying with CAIR if West Texas is not excluded. There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a signiﬁcant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the ﬁnal CAIR rules makes it difﬁcult to project the ultimate amount and timing of capital expenditures and operating expenses. While Xcel Energy expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers. The EPA’s CAMR also uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-ﬁred generating units across the country that are greater than 25 megawatts. Compliance with this rule also occurs in two phases, with the ﬁrst phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. Similar to CAIR, states can choose to implement an emissions reduction program based on the EPA’s pro- posed model program, or they can propose another method, which the EPA would need to approve. Under CAMR, Xcel Energy can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Estimating the cost of compliance with CAMR is difficult because technologies specifically designed for control of mercury are in the early stages of development and there is no established market on which to base the cost of mercury allowances. Xcel Energy’s preliminary analysis for phase I compliance suggests capital costs of approximately $20 million and increased operating and maintenance expenses ranging between $10 million and $20 million, beginning in 2010. Further testing is planned during 2006 to conﬁrm these costs or determine if different measures will be necessary, which could result in higher costs. Additional costs will be incurred to meet phase II requirements in 2018. The Minnesota Legislature is expected to consider legislation in the 2006 session that could require up to a 90 percent reduction in mercury emissions from coal-fueled power plants, provided the MPUC determines that it is technically feasible and economically reasonable to do so. The cost impact of this potential legislation is unknown. The legislation is expected to allow for cost recovery by the utility. Regional Haze Rules On June 15, 2005, the EPA ﬁnalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retroﬁt technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Xcel Energy generating facilities in several states will be subject to BART requirements. Some of these facilities are located in regions where CAIR is effective. CAIR has precedence over BART. Therefore, BART requirements will be deemed to be met through compliance with CAIR requirements. States must develop their implementation plans by December 2007. States will identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities. Colorado is the ﬁrst state in Xcel Energy’s region to earnestly begin its BART rule development as the ﬁrst step toward the December 2007 deadline. Xcel Energy is actively involved in the stakeholder process in Colorado and will also be involved as other states begin their process. Due to the uncertainties of the many decisions involved in this process, Xcel Energy is not able to estimate the cost impact at this time. 72 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Federal Clean Water Act The federal Clean Water Act addresses the environmental impact of cooling water intakes. In July 2004, the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require Xcel Energy to perform additional environmental studies at several power plants in Minnesota, Wisconsin and Colorado to determine the impact the facilities may be having on aquatic organisms vulnerable to injury. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these plants. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved, including unresolved third-party legal challenges to the federal rule. Preliminary cost estimates range from less than $1 million at some plants to more than $10 million at others, depending on site-specific circumstances. Based on the limited information available, total capital and operating and maintenance costs to Xcel Energy are estimated at approximately $30 million over the next five to 10 years. Actual costs may be higher or lower depending on the final resolution of legal challenges to the rule, as well as pending state and federal decisions regarding interpretation of specific rule requirements. PSCo Notice of Violation On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche and Pawnee plants in Colorado. The NOV speciﬁcally alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. It believes that the projects identiﬁed in the NOV ﬁt within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR equipment replacement rulemaking promulgated in October 2003. On Dec. 24, 2003, the U.S. Court of Appeals for the District of Columbia circuit stayed this rule while it considers challenges to it. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the CAA, the EPA met with Xcel Energy in September 2002 to discuss the NOV. On March 10, 2005, the Rocky Mountain Environmental Labor Coalition (RMELC) provided notice to PSCo of its intent to sue PSCo for alleged violations of the CAA at the Comanche plant. The notice of intent to sue alleges PSCo has violated the CAA’s Prevention of Significant Deterioration regulations based on allegations that maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. The allegations are the same as those presented in the NOV. On June 9, 2005, Citizens for Clean Air and Water in Pueblo/Southern Colorado (CCAP) and Leslie Glustrom provided notice of intent to sue PSCo for alleged violations of the CAA at the Comanche Plant. The allegations in the notice of intent to sue by CCAP and Ms. Glustrom are substantially identical to those of RMELC. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself in any suit which may be ﬁled. Currently, Xcel Energy is not able to estimate any potential loss. AS S E T R E T I R E M E NT O B L I G AT I O N S Xcel Energy adopted Statement of Financial Accounting Standard SFAS No. 143 – “Accounting for Asset Retirement Obligations” (SFAS No. 143) effective Jan. 1, 2003. Xcel Energy records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47 – “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47) to clarify the scope and timing of liability recognition for conditional asset retirement obligations pursuant to SFAS No. 143. The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the fair value is estimable, even when the obligation is dependent on a future event. FIN No. 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized. Xcel Energy implemented FIN No. 47 as of Dec. 31, 2005. Included in these ﬁnancial statements is the recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis. Recorded Asset Retirement Obligations (ARO) Asset retirement obligations have been recorded for nuclear production, steam production, electric transmission and distribution system, natural gas distribution system and ofﬁce buildings. The steam production obligation includes asbestos, ash-containment facilities and decommissioning. The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota, PSCo and SPS. NSP-Minnesota also recorded asbestos recognition for its general office building. Generally, this asbestos abatement removal obligation originated in 1973 with the Clean Air Act, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. Asset retirement obligations also have been recorded for NSP-Minnesota, PSCo and SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landﬁlls. The origination date on the ARO recognition for ash-containment facilities at steam plants was the in-service date of various facilities. Xcel Energy recognized an ARO for the retirement costs of natural gas mains at NSP-Minnesota, NSP- Wisconsin and PSCo. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment at NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. The electric transmission and distribution ARO consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. These electric and natural gas assets have many in-service dates for which it is difﬁcult to assign the obligation to a particular year. Therefore, the obligation was measured at Dec. 31, 2005. The asset retirement cost was set to this recognized obligation and no cumulative effect adjustment was shown. A liability has also been recorded in previous years for nuclear decommissioning of an NSP-Minnesota steam production plant. This plant began operating as a nuclear production facility in 1964 before being converted to a steam production peaking facility in 1969. For the nuclear assets, the asset retirement obligation is associated with the decommissioning of two NSP-Minnesota nuclear generating plants, Monticello XCEL ENERGY 2005 ANNUAL REPORT 73 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S and Prairie Island, originates with the in-service date of the facility. Monticello began operation in 1971. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively. See Note 15 to the Consolidated Financial Statements for further discussion of nuclear obligations. A reconciliation of the beginning and ending aggregate carrying amounts of Xcel Energy’s asset retirement obligations is shown in the table below for the 12 months ended Dec. 31, 2005 and 2004: Liabilities Recognized Liabilities Settled Accretion Revisions to Prior Ending Balance Estimates Dec. 31, 2005 (Thousands of dollars) Electric Utility Plant Steam production asbestos Steam production ash containment Steam production retirement Nuclear production decommissioning Electric transmission and distribution Gas Utility Plant Gas transmission and distribution Common Utility and Other Property Common general plant asbestos Total liability Beginning Balance Jan. 1, 2005 $ – – 3,002 1,088,087 – $ 5,917 4,916 – – 2,350 – 43,245 – $1,091,089 575 $57,003 $ – – – – – – – $ – $ 28,406 16,018 150 70,736 – $ – – – 26,145 – $ 34,323 20,934 3,152 1,184,968 2,350 – – 43,245 2,459 $117,769 – $26,145 3,034 $1,292,006 (Thousands of dollars) Electric Utility Plant Steam production retirement Nuclear production decommissioning Total liability Beginning Balance Jan. 1, 2004 Liabilities Recognized Liabilities Settled Accretion Revisions to Prior Ending Balance Estimates Dec. 31, 2004 $ 2,860 1,021,669 $1,024,529 $ $ – – – $ $ – – – $ 142 66,418 $ 66,560 $ $ – – – $ 3,002 1,088,087 $1,091,089 The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $1.1 billion as of Dec. 31, 2005, including external nuclear decommissioning investment funds and internally funded amounts. Cumulative Effect of FIN No. 47 In March 2005, the FASB issued FIN No. 47. The interpretation clariﬁed the term “conditional asset retirement obligation” as used in SFAS No. 143. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. If Xcel Energy had implemented FIN No. 47 at Jan. 1, 2004, the liability for asset retirement obligations would have increased by $52.2 million. The same liability at Dec. 31, 2004, would have increased by $55.2 million. A summary of the accounting for the initial adoption of FIN No. 47, as of Dec. 31, 2005, is as follows: (Thousands of dollars) Reﬂect retirement obligation when liability incurred Record accretion of liability to adoption date Record depreciation of plant to adoption date Net impact of FASB Interpretation No. 47 Plant Assets Regulatory Assets Long-Term Liabilities $ 57,003 – (8,283) $ 48,720 $ – 46,883 8,283 $55,166 $ 57,003 46,883 – $103,886 Indeterminate Asset Retirement Obligations PSCo has underground gas storage facilities that have special closure requirements for which the ﬁnal removal date cannot be determined. Removal Costs Xcel Energy accrues an obligation for plant removal costs for other generation, transmission and distribution facilities of its utility subsidiaries. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, the utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs by entity are as follows at Dec. 31: (Millions of dollars) NSP-Minnesota NSP-Wisconsin PSCo SPS Total Xcel Energy 74 XCEL ENERGY 2005 ANNUAL REPORT 2005 $334 86 377 98 $895 2004 $323 81 383 104 $891 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Nuclear Insurance NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $10.8 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $10.5 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $100.6 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $15 million per reactor during any one year. NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.1 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $14.8 million for business interruption insurance and $26.5 million for property damage insurance if losses exceed accumulated reserve funds. L EG A L C O NT I N G E N C I E S In the normal course of business, Xcel Energy is subject to claims and litigation arising from prior and current operations. Xcel Energy is actively defending these matters and has recorded a reasonable liability related to the probable cost of settlement or other disposition when it can be reasonably estimated. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on Xcel Energy’s ﬁnancial position and results of operations. Bender et al. vs. Xcel Energy On July 2, 2004, ﬁve former NRG ofﬁcers ﬁled a lawsuit against Xcel Energy in the U.S. District Court for the District of Minnesota. The lawsuit alleges, among other things, that Xcel Energy violated the Employee Retirement Income Security Act of 1974 (ERISA) by refusing to make certain deferred compensation payments to the plaintiffs. The complaint also alleges interference with ERISA benefits, breach of contract related to the nonpayment of certain stock options and unjust enrichment. The complaint alleges damages of approximately $6 million. Xcel Energy believes the suit is without merit. On Jan. 19, 2005, Xcel Energy ﬁled a motion for summary judgment. On July 26, 2005, the court issued an order granting Xcel Energy’s motion for summary judgment in part with respect to claims for interference with ERISA beneﬁts, breach of contract for nonpayment of stock options and unjust enrichment. The court denied Xcel Energy’s motion in part with respect to the allegations of nonpayment of deferred compensation beneﬁts. Plaintiffs and Xcel Energy have ﬁled additional cross motions for summary judgment, with oral arguments presented on Feb. 24, 2006. The court has also ordered this lawsuit to be trial-ready by Feb. 1, 2006. Carbon Dioxide Emissions Lawsuit On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, ﬁled lawsuits in U.S. District Court for the Southern District of New York against ﬁve utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and four other utility companies ﬁled a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs have ﬁled a notice of appeal. Department of Labor Audit In 2001, Xcel Energy received notice from the Department of Labor (DOL) Employee Benefit Security Administration that it intended to audit the Xcel Energy pension plan. After multiple on-site meetings and interviews with Xcel Energy personnel, the DOL indicated on Sept. 18, 2003, that it is prepared to take the position that Xcel Energy, as plan sponsor and through its delegate, the Pension Trust Administration Committee, breached its ﬁduciary duties under ERISA with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998. The DOL has offered to conclude the audit if Xcel Energy is willing to contribute to the plan the full amount of losses from the questioned investments, or approximately $7 million. On July 19, 2004, Xcel Energy formally responded with a letter to the DOL that asserted no ﬁduciary violations have occurred and extended an offer to meet to discuss the matter further. In 2005, the DOL submitted two additional requests for information related to the investigation and has not indicated that they are prepared to close the ﬁle, or in the alternative, to assert charges against Xcel Energy or the pension plan. Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. On Nov. 19, 2003, a class action complaint ﬁled in the U.S. District Court for the Eastern District of California by Texas-Ohio Energy, Inc. was served on Xcel Energy naming e prime as a defendant. The lawsuit, ﬁled on behalf of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade publications in an effort to artiﬁcially raise natural gas prices in California. The case has been conditionally transferred by the Multi-District Litigation (MDL) Panel to U.S. District Judge Pro, in Nevada, who is the judge assigned to western area wholesale natural gas marketing litigation. In an order entered April 8, 2005, Judge Pro granted the defendants’ motion to dismiss based on the filed rate doctrine. On May 9, 2005, plaintiffs filed an appeal of this decision to the 9th Circuit Court of Appeals. Cornerstone Propane Partners, L.P. et al. vs. e prime inc. et al. On Feb. 2, 2004, a purported class action complaint was ﬁled in the U.S. District Court for the Southern District of New York against e prime and three other defendants by Cornerstone Propane Partners, L.P., Robert Calle Gracey and Dominick Viola on behalf of a class who purchased or sold one or more New York Mercantile Exchange natural gas futures and/or options contracts during the period from Jan. 1, 2000, to Dec. 31, 2002. The complaint alleges that defendants manipulated the price of natural gas futures and options and/or the price of natural gas underlying those contracts in violation of the Commodities Exchange Act. In February 2004, the plaintiff requested that this action be consolidated with a similar suit involving Reliant Energy Services. In February XCEL ENERGY 2005 ANNUAL REPORT 75 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 2004, defendants, including e prime, ﬁled motions to dismiss. In September 2004, the U.S. District Court denied the motions to dismiss. On Jan. 25, 2005, plaintiffs filed a motion for class certification, which defendants opposed. On Sept. 30, 2005, the U.S. District Court granted plaintiffs’ motion for class certification. On Oct. 17, 2005, defendants filed a petition with the U.S. Court of Appeals for the Second Circuit challenging the class certiﬁcation. On Dec. 5, 2005, e prime reached a tentative settlement with the plaintiffs that will require court approval. The settlement will be paid by e prime, and is not expected to have a material ﬁnancial impact on Xcel Energy. Fairhaven Power Company vs. Encana Corporation et al. On Sept. 14, 2004, a class action complaint was ﬁled in the U.S. District Court for the Eastern District of California by Fairhaven Power Co. and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artiﬁcially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inﬂate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Court Judge Pro. Defendants ﬁled a motion to dismiss, which was granted on December 19, 2005. The plaintiffs subsequently appealed. Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc. On Nov. 29, 2004, a class action complaint was ﬁled in the U.S. District Court for the Eastern District of California by Utility Savings and Refund Services LLP and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artiﬁcially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inﬂate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al and assigned to U.S. District Court Judge Pro. Defendants ﬁled a motion to dismiss, which was granted on December 19, 2005. Plaintiffs subsequently appealed. Abelman Art Glass vs. Ercana Corporation et al. On Dec. 13, 2004, a class action complaint was ﬁled in the U.S. District Court for the Eastern District of California by Abelman Art Glass and subsequently served on Xcel Energy. The lawsuit, ﬁled on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artiﬁcially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inﬂate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Court Judge Pro. Defendants ﬁled a motion to dismiss, which was granted on December 19, 2005. Sinclair Oil Corporation vs. e prime inc. and Xcel Energy, Inc. On July 18, 2005, Sinclair Oil Corporation ﬁled a lawsuit against Xcel Energy and its former subsidiary e prime in the U.S. District Court for the Northern District of Oklahoma, alleging liability and damages for purported misreporting of price information for natural gas to trade publications in an effort to artificially increase natural gas prices. The complaint also alleges that e prime and Xcel Energy engaged in a conspiracy with other gas sellers to inflate prices through alleged false reporting of gas prices. In response, e prime and Xcel Energy ﬁled a motion with the MDL Panel to have this matter transferred to U.S. District Court Judge Pro and ﬁled a second motion to dismiss the lawsuit. In response to this motion, the matter has been conditionally transferred to Judge Pro. Sinclair subsequently ﬁled a motion with the MDL Panel to vacate this transfer. The MDL Panel has yet to issue an order. e prime and Xcel Energy also ﬁled a motion to dismiss with the District Court in Oklahoma based upon the ﬁled rate doctrine. This motion is being held in abeyance pending a ruling from the MDL Panel. Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al. On June 21, 2005, a class action complaint was ﬁled in the U.S. District Court for the Eastern District of California by Ever-Bloom, Inc. The lawsuit names as defendants, among others, Xcel Energy and e prime. The lawsuit, ﬁled on behalf of a purported class of gas purchasers, alleges that defendants falsely reported natural gas trades to market trade publications in an effort to artiﬁcially raise natural gas prices in California, purportedly in violation of the Sherman Act. Xcel Energy and e prime intend to vigorously defend themselves against this claim. Learjet, Inc. vs. e prime and Xcel Energy et al. On Nov. 4, 2005, a purported class action complaint was ﬁled in state court for Wyandotte County of Kansas on behalf of all natural gas producers in Kansas. The lawsuit alleges that e prime, Xcel Energy and other named defendants conspired to raise the market price of natural gas in Kansas by, among other things, inaccurately reporting price and volume information to market trade publications. On Dec. 7, 2005, the defendants removed this matter to the U.S. District Court in Kansas. This case is in the early stages; no discovery has been conducted and e prime and Xcel Energy intend to vigorously defend themselves against these claims. J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al. On Oct. 17, 2005, J.P. Morgan, in its capacity as the liquidating trustee for Farmland Industries Liquidating Trust, filed an amended complaint in Kansas state court adding defendants, including Xcel Energy and e prime, to a previously ﬁled complaint alleging that the defendants inaccurately reported natural gas trades to market trade publications in an effort to artiﬁcially raise natural gas prices. The lawsuit was removed to the U.S. District Court in Kansas and subsequently transferred to U.S. District Court Judge Pro in Nevada, pursuant to an order from the MDL Panel. A motion to remand to state court has been filed by plaintiffs and that motion is currently pending. This case is in the early stages, there has been no discovery and e prime and Xcel Energy intend to vigorously defend themselves against these claims. Payne et al. vs. PSCo et al. In late October 2003, there was a wildfire in Boulder County, Colo. There was no loss of life, but there was property damage associated with this ﬁre. On Oct. 28, 2005, an action against PSCo related to this ﬁre was ﬁled in Boulder County District Court. There are 28 plaintiffs, including individuals, the City of Jamestown and one private corporation, and three co-defendants, including PSCo. Plaintiffs have asserted that a tree falling into PSCo distribution lines may have caused the fire. This lawsuit is in the early stages and PSCo intends to vigorously defend itself against the claim. This lawsuit is not expected to have a material financial impact and PSCo believes that its insurance coverage will cover any liability in this matter. 76 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Comanche 3 Permit Litigation On Aug. 4, 2005, CCAP and Clean Energy Action ﬁled suit against the Air Pollution Control Division, Colorado Department of Public Health and Environment in state district court in Pueblo, Colo. The suit alleges the issuance of environmental permits for the proposed Comanche 3 generating station by the Department violates the Colorado Air Pollution Prevention and Control Act. The plaintiffs have sought judicial review of the issuance of the permits. The plaintiffs have not sought a stay of the permits or an injunction on construction pending judicial review. On Aug. 19, 2005, the Colorado attorney general, on behalf of the Department, ﬁled an answer in the suit. On the same date, PSCo ﬁled a motion to intervene and an answer in the suit. On Nov. 20, 2005, the Division submitted the formal record which was entered by the Court. Plaintiffs’ brief was ﬁled on Feb. 2, 2006, and the government and PSCo will have 60 days to respond. Fru-Con Construction Corporation vs. Utility Engineering et al. On March 28, 2005, Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in U.S. District Court for the Eastern District of California against UE and the Sacramento Municipal Utility District (SMUD) for damages allegedly suffered during the construction of a natural gas-ﬁred, combined-cycle power plant in Sacramento County. Fru-Con’s complaint alleges that it entered into a contract with SMUD to construct the power plant and further alleges that UE was negligent with regard to the design services it furnished to SMUD. UE denies this claim and intends to vigorously defend itself. Because this lawsuit was commenced prior to the April 8, 2005, closing of the sale of UE to Zachry Group, Inc., Xcel Energy is obligated to indemnify Zachry up to $17.5 million. Pursuant to the terms of its professional liability policy, UE is insured up to $35 million. On June 1, 2005, UE ﬁled a motion to dismiss Fru-Con’s complaint. A hearing concerning this motion was held on July 18, 2005, with the court taking the matter under advisement. On Aug. 4, 2005, the court granted UE’s motion to dismiss. Because SMUD remains a defendant in this action, the court has not entered a ﬁnal judgment subject to an appeal with respect to its order to dismiss UE from the lawsuit. Metropolitan Airports Commission vs. Northern States Power Company On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota state district court asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past ﬁve years for relocation costs should be repaid. Both parties have asserted cross motions for partial summary judgment concerning legal obligations associated with rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves the MAC. This hearing was held in January 2006; the judge has not yet issued his decision. Both sides have scheduled depositions of key witnesses to take place in February and March of 2006. Trial has been set for May 2006; additional summary judgment motions are likely prior to trial. Siewert vs. Xcel Energy Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action against NSP-Minnesota alleg- ing negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and mainte- nance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system. Plaintiffs’ expert report on the economic damage to their dairy farm states that the total present value of plaintiffs’ loss is $6.8 million. Trial is scheduled to commence in March 2007. NSP-Minnesota denies these allegations and will vigorously defend itself in this matter. OT H E R C O NT I N G E N C I E S Tax Matters In April 2004, Xcel Energy ﬁled a lawsuit against the government in the U.S. District Court for the District of Minnesota to establish its right to deduct the policy loan interest expense that had accrued during tax years 1993 and 1994 on policy loans related to its company-owned life insurance (COLI) policies that insured certain lives of employees of PSCo. These policies are owned and managed by PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. After Xcel Energy ﬁled this suit, the IRS sent it two statutory notices of proposed deﬁciency of tax, penalty and interest for taxable years 1995 through 1999. Xcel Energy then ﬁled two Tax Court petitions challenging those notices. Xcel Energy anticipates that the dispute relating to its claimed interest expense deductions for tax years 1993 and later will be resolved in the refund suit that is pending in the Minnesota federal district court and that the two Tax Court petitions will be held in abeyance pending the outcome of the refund litigation. On Oct. 12, 2005, the district court denied Xcel Energy’s motion for summary judgment on the grounds that there were disputed issues of material fact that required a trial for resolution. At the same time, the district court denied the government’s motion for summary judgment that was based on its contention that PSCo had lacked an insurable interest in the lives of the employees insured under the COLI policies. However, the district court granted Xcel Energy’s motion for partial summary judgment on the grounds that PSCo did have the requisite insurable interest. The case is expected to proceed to trial and the litigation could take another two or more years. Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS, and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. As discussed above, the litigation could require several years to reach final resolution. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s ﬁnancial position, results of operations and cash ﬂows. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce earnings by an estimated $361 million. In 2004, Xcel Energy received formal notiﬁcation that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2005, is approximately $428 million. Xcel Energy annual earnings for 2006 would be reduced by approximately $44 million, after tax, or 10 cents per share, if COLI interest expense deductions were no longer available. XCEL ENERGY 2005 ANNUAL REPORT 77 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 15. NUCLEAR OBLIGATIONS Fuel Disposal NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $12 million in 2005, $13 million in 2004 and $13 million in 2003. In total, NSP-Minnesota had paid approximately $346 million to the DOE through Dec. 31, 2005. However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufﬁcient to fully fund the DOE’s permanent storage or disposal facility. The Nuclear Waste Policy Act required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. In 1996, the DOE notiﬁed commercial spent-fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations. NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and a dry cask facility. With the dry cask storage facility licensed by the NRC, approved in 1994 and again in 2003, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least the end of its license terms in 2013 and 2014. The Monticello nuclear plant has storage capacity in the pool to continue operations until 2010. Storage availability to permit operation beyond these dates is not known at this time. All of the alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities. Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium-enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from 1993 to 2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2005 was $4.7 million; future installments are subject to inﬂation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $8.3 million at Dec. 31, 2005, is deferred as a regulatory asset. Regulatory Plant Decommissioning Recovery Decommissioning of NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is planned for the period from cessation of operations through 2040, assuming the prompt dismantlement method. NSP-Minnesota is currently accruing the costs for decommissioning over the MPUC-approved cost-recovery period and including the accruals in Accumulated Depreciation. Upon implementation of SFAS No. 143, the decommissioning costs in Accumulated Depreciation and ongoing accruals are reclassiﬁed to a regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with SFAS No. 143. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. In 2003, the Minnesota Legislature changed a law that had limited expansion of on-site storage. On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants. NSP-Minnesota ﬁled its application for Monticello with the MPUC in January 2005, seeking a certiﬁcate of need for dry spent-fuel storage, and ﬁled an application in March 2005 with the NRC for an operating license extension of up to 20 years. A decision regarding Monticello relicensing is expected in 2007. Plant assessments and other work for the Prairie Island applications are planned in the next two or three years. The Prairie Island license renewal process has not yet begun. Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-speciﬁc cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Current authorized funding presumes that costs will escalate in the future at a rate of 4.19 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding. The net unrealized gain on nuclear decommissioning investments is deferred as a Regulatory Liability based on the assumed offsetting against decommissioning costs in current ratemaking treatment. The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in December 2003, using 2002 cost data. In October 2005, NSP-Minnesota ﬁled with the MPUC a nuclear decommissioning study using 2005 cost data. Xcel Energy’s recommendation is to reduce the 2006 funding if approved by the MPUC. Xcel Energy expects the MPUC to approve a new funding amount in 2006. Internal funding for all retail jurisdictions was transferred to the external funds by the end of 2005. Based on the last MPUC approval requiring the acceleration of the internal fund transfer, there is a step change in the level of the overall decommissioning expense at the expiration of the transfer beginning Jan. 1, 2006. Expecting to operate Prairie Island through the end of each unit’s licensed life, the approved capital recovery will allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2014. Xcel Energy believes future decommissioning cost accruals will continue to be recovered in customer rates. The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2005, primarily consisted of investments in ﬁxed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. 78 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S At Dec. 31, 2005, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $816 million. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters. These amounts are not those recorded in the ﬁnancial statements for the asset retirement obligation in accordance with SFAS No. 143. (Thousands of dollars) Estimated decommissioning cost obligation from most recently approved study (2002 dollars) Effect of escalating costs to 2005 and 2004 dollars (at 4.19 percent per year), respectively Estimated decommissioning cost obligation in current dollars Effect of escalating costs to payment date (at 4.19 percent per year) Estimated future decommissioning costs (undiscounted) Effect of discounting obligation (using risk-free interest rate) Discounted decommissioning cost obligation Assets held in external decommissioning trust Discounted decommissioning obligation in excess of assets currently held in external trust Decommissioning expenses recognized include the following components: 2005 2004 $1,716,618 224,946 1,941,564 1,851,801 3,793,365 (2,026,003) 1,767,362 1,047,592 $ 719,770 $1,716,618 146,866 1,863,484 1,929,881 3,793,365 (2,139,561) 1,653,804 918,442 $ 735,362 (Thousands of dollars) 2005 2004 2003 Annual decommissioning cost accrual reported as depreciation expense: Externally funded Internally funded (including interest costs) Interest cost on externally funded decommissioning obligation Earnings from external trust funds Net decommissioning accruals recorded $80,582 (57,561) (24,516) 24,516 $23,021 $80,582 (53,307) (19,026) 19,026 $ 27,275 $80,582 (35,906) (14,952) 14,952 $44,676 Decommissioning and interest accruals are included with Regulatory Liabilities on the Consolidated Balance Sheets. Interest costs and trust earnings associated with externally funded obligations are reported in Other Nonoperating Income on the Consolidated Statements of Operations. Negative accruals for internally funded portions in 2003, 2004 and 2005 reflect the impact of the 2002 decommissioning study, which approved an assumption of 100-percent external funding of future costs. The 2005 nuclear decommissioning ﬁling has not been used for the regulatory presentation because it is effective for 2006. However, the ﬁling and all the updated parameters were used for a new ARO layer for SFAS No. 143 recognition. XCEL ENERGY 2005 ANNUAL REPORT 79 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 16. REGULATORY ASSETS AND LIABILITIES Xcel Energy’s regulated businesses prepare their Consolidated Financial Statements in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of Xcel Energy’s business that is not regulated cannot use SFAS No. 71 accounting. If changes in the utility industry or the business of Xcel Energy no longer allow for the application of SFAS No. 71 under GAAP, Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in its Statements of Operations. The components of unamortized regulatory assets and liabilities of continuing operations shown on the balance sheet at Dec. 31 were: (Thousands of dollars) Regulatory Assets Net nuclear asset retirement obligations Contract valuation adjustments (e) AFDC recorded in plant (a) Losses on reacquired debt Conservation programs (a) Nonnuclear asset retirement obligations Nuclear decommissioning costs (b) Employees’ postretirement beneﬁts other than pension Renewable resource costs Environmental costs State commission accounting adjustments (a) Plant asset recovery (Pawnee II and Metro Ash) Unrecovered natural gas costs (c) Unrecovered electric production and transmission costs (d) Other Total regulatory assets Regulatory Liabilities Plant removal costs Pension costs – regulatory differences Contract valuation adjustments (e) Unrealized gains from decommissioning investments Investment tax credit deferrals Deferred income tax adjustments Interest on income tax refunds Fuel costs, refunds and other Total regulatory liabilities See Note(s) Remaining Amortization Period 2005 2004 End of licensed life Term of related contract Plant lives Term of related debt Various Plant lives Up to two years Seven years One to two years Varies, generally four to six years Plant lives 18 months One to two years To be determined Various 1, 15 12 1 14 10 14, 15 1 1 1, 15 10 12 15 1 $ 282,195 111,639 170,785 84,290 111,429 32,371 8,317 27,234 50,453 33,957 14,460 7,355 12,998 6,634 9,286 $ 963,403 $ 895,653 397,261 99,734 143,396 84,437 75,171 6,031 9,137 $1,710,820 $ 221,864 102,741 169,352 89,694 88,253 – 20,494 31,125 38,985 28,176 15,945 12,258 14,553 – 17,196 $ 850,636 $ 891,018 377,893 56,874 129,028 92,227 69,780 9,667 4,058 $1,630,545 (a) Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates. (b) These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to DOE assessments, as discussed previously in Note 15. In 2004, these costs also included unamortized costs for PSCo’s Fort St. Vrain nuclear plant decommissioning. (c) Excludes current portion expected to be returned to customers within 12 months of $16.3 million and $12.4 million for 2005 and 2004, respectively. (d) In 2004, excluded the current portion expected to be recovered within the next 12 months of $16.1 million. (e) Includes the fair value of certain long-term contracts used to meet native energy requirements. 80 XCEL ENERGY 2005 ANNUAL REPORT N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 17. SEGMENTS AND RELATED INFORMATION Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other. – Xcel Energy’s Regulated Electric Utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, New Mexico, Kansas and Oklahoma. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated Electric Utility also includes commodity trading operations. – Xcel Energy’s Regulated Natural Gas Utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits. To report income from continuing operations for Regulated Electric and Regulated Natural Gas Utility segments, Xcel Energy must assign or allocate all costs and certain other income. In general, costs are: – directly assigned wherever applicable; – allocated based on cost causation allocators wherever applicable; and – allocated based on a general allocator for all other costs not assigned by the above two methods. The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which are separately determined for each segment. Xcel Energy evaluates performance by each legal entity based on proﬁt or loss generated from the product or service provided. (Thousands of dollars) 2005 Operating revenues from external customers Intersegment revenues Total revenues Depreciation and amortization Financing costs, mainly interest expense Income tax expense (beneﬁt) Income (loss) from continuing operations 2004 Operating revenues from external customers Intersegment revenues Total revenues Depreciation and amortization Financing costs, mainly interest expense Income tax expense (beneﬁt) Income (loss) from continuing operations 2003 Operating revenues from external customers Intersegment revenues Total revenues Depreciation and amortization Financing costs, mainly interest expense Income tax expense (beneﬁt) Income (loss) from continuing operations Regulated Electric Utility $ 7,243,637 767 $ 7,244,404 $ 662,236 301,185 258,161 $ 440,578 $6,225,245 1,132 $6,226,377 $ 610,127 299,768 235,743 $ 466,307 $5,919,938 1,123 $5,921,061 $ 625,132 312,432 239,671 $ 461,363 Regulated Natural Gas Utility $ 2,307,385 17,732 $ 2,325,117 89,174 $ 47,145 32,923 71,213 $ $1,915,514 8,735 $1,924,249 82,012 $ 48,757 29,286 86,091 $ $1,677,768 10,868 $1,688,636 80,688 $ 57,673 31,314 94,056 $ All Other Reconciling Consolidated Total Eliminations $ 74,455 – $ 74,455 $ 15,911 108,538 (117,545) $ 35,733 $ 74,802 – $ 74,802 $ 13,816 100,784 (103,094) $ 12,173 $133,561 – $133,561 $ 21,487 103,825 (100,293) $ 4,984 $ – (18,499) $(18,499) $ – (14,242) – $(48,486) $ – (9,867) $ (9,867) $ – (14,829) – $(42,307) $ – (11,991) $ (11,991) $ – (22,911) – $ (37,579) $9,625,477 – $9,625,477 $ 767,321 442,626 173,539 $ 499,038 $8,215,561 – $8,215,561 $ 705,955 434,480 161,935 $ 522,264 $ 7,731,267 – $ 7,731,267 $ 727,307 451,019 170,692 $ 522,824 XCEL ENERGY 2005 ANNUAL REPORT 81 N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 18. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly unaudited ﬁnancial data is as follows: (Thousands of dollars, except per share amounts) Revenue Operating income Income from continuing operations Discontinued operations – income (loss) Net income Earnings available for common shareholders Earnings per share from continuing operations – basic Earnings per share from continuing operations – diluted Earnings (loss) per share from discontinued operations – basic Earnings (loss) per share from discontinued operations – diluted Earnings per share total – basic Earnings per share total – diluted (Thousands of dollars, except per share amounts) Revenue Operating income Income from continuing operations Discontinued operations – income (loss) Net income Earnings available for common shareholders Earnings per share from continuing operations – basic Earnings per share from continuing operations – diluted Earnings (loss) per share from discontinued operations – basic Earnings (loss) per share from discontinued operations – diluted Earnings per share total – basic Earnings per share total – diluted (a) 2005 results include unusual items as follows: March 31, 2005 (a) Quarter ended June 30, 2005 Sept. 30, 2005 (a) (a) Dec. 31, 2005 (a) $2,381,038 279,341 127,643 (6,165) 121,478 120,418 0.32 0.31 (0.02) (0.02) 0.30 0.29 $ $ $ $ $ $ $2,073,549 198,098 74,613 8,793 83,406 82,346 0.18 0.18 0.02 0.02 0.20 0.20 $ $ $ $ $ $ $2,288,653 364,725 197,817 (1,798) 196,019 194,959 0.49 0.47 (0.01) – 0.48 0.47 $ $ $ $ $ $ $2,882,237 250,555 98,964 13,104 112,068 111,008 0.25 0.24 0.03 0.03 0.28 0.27 $ $ $ $ $ $ March 31, 2004 (b) Quarter ended June 30, 2004 Sept. 30, 2004 (b) (b) Dec. 31, 2004 (b) $2,248,797 321,438 148,684 1,227 149,911 148,851 0.37 $ 0.36 $ $ – $ – 0.37 $ 0.36 $ $1,760,175 198,694 85,420 886 86,306 85,246 0.21 $ 0.21 $ $ – $ – 0.21 $ 0.21 $ $1,974,935 338,235 165,952 (119,232) 46,720 45,660 0.41 0.40 $ $ $ (0.30) $ (0.28) $ $ 0.11 0.12 $2,231,654 217,347 122,208 (49,184) 73,024 71,964 0.30 $ 0.30 $ $ (0.12) $ (0.12) 0.18 $ 0.18 $ – Third-quarter results from continuing operations were decreased by the accrual of legal settlements incurred by the holding company in the amount of $5 million. – Second-quarter results from discontinued operations were increased by $7.7 million due to a true-up on the estimated impairment expected to result from the disposal of Seren, as discussed in Note 2 to the Consolidated Financial Statements. – Fourth-quarter results from discontinued operations include the positive impact of a $17.2 million tax beneﬁt recorded to reﬂect the ﬁnal resolution of Xcel Energy’s divested interest in NRG. – First-quarter revenue has been reduced by $6.1 million as compared to the amount previously reported in the Quarterly Report filed on Form 10-Q with the SEC for the first quarter of 2005. This adjustment is a result of fees collected from customers on behalf of governmental agencies that were reclassified to be presented net of the related payments made to the agencies. (b) 2004 results include special charges in the fourth quarter and unusual items as follows: – Fourth-quarter results from continuing operations were decreased by the accrual of legal settlements incurred by the holding company in the amount of $17.6 million. – Third-quarter results from discontinued operations were decreased by $112 million, or 27 cents per share, due to the estimated impairment expected to result from the disposal of Seren, as discussed in Note 2 to the Consolidated Financial Statements. During the fourth quarter, an adjustment increasing the impairment by $31 million, or 7 cents per share, was recorded. – Fourth-quarter results from discontinued operations were decreased by $15.7 million, or 4 cents per share, related to a reduction of the NRG tax beneﬁts previously booked, after completion of an NRG tax basis study. – Fourth-quarter results from continuing operations were increased by $33.8 million, or 8 cents per share, due to the accrual of income tax beneﬁts which included $22.3 million related to the successful resolution of various issues and other adjustments to current and deferred taxes. – Fourth-quarter results from continuing operations were decreased by a $19.7 million accrual recorded to reﬂect SPS’ best estimate of any potential liability for the impact of its retail fuel cost-recovery proceeding in Texas. – First-quarter revenue has been reduced by $10.4 million as compared to the amount previously reported in the Quarterly Report filed on Form 10-Q with the SECfor the first quarter 2005. Revenue for the quarter ended Dec. 31, 2004, has been reduced by $10.3 million as compared to the amount previously reported in the Annual Report on Form 10-K for 2004. These adjustments are a result of fees collected from customers on behalf of governmental agencies that were reclassified to be presented net of the related payments made to the agencies. 82 XCEL ENERGY 2005 ANNUAL REPORT S H A R E H O L D E R I N F O R M A T I O N A N D F I S C A L A G E N T S SHAREHOLDER INFORMATION H E A D QU A RT E R S 414 Nicollet Mall, Minneapolis, Minnesota 55401 I NT E R N E T A D D R E S S www.xcelenergy.com I N V E STO R S H OT L I N E 1-877-914-9235 STO C K T R A N S F E R AG E NT The Bank of New York 101 Barclay Street New York, New York 10286 1-877-778-6786, toll free This is an automated phone system to expedite requests. However, staying on the line to speak with a representative is an option. Representatives are available from 7 a.m. to 7 p.m. CST. R E P O RT S AVA I L A B L E O N L I N E Financial reports, including ﬁlings with the Securities and Exchange Commission and Xcel Energy’s Report to Shareholders, are available online at www.xcelenergy.com. Click on Investor Information. STO C K E X C H A N G E L I ST I N G S A N D T I C K E R SY M B O L Common stock is listed on the New York, Chicago and Paciﬁc exchanges under the ticker symbol XEL. The New York Stock Exchange lists some of Xcel Energy’s preferred stock. In newspaper listings, it appears as XcelEngy. I N V E STO R R E L AT I O N S Internet address: www.xcelenergy.com or contact Richard Kolkmann, Managing Director, Investor Relations, at 612-215-4559 or Paul Johnson, Director, Investor Relations, at 612-215-4535. S H A R E H O L D E R S E RV I C E S Internet address: www.xcelenergy.com or contact Dianne Perry, Manager, Shareholder Services, at 612-215-4534 or e-mail dianne.g.perry@xcelenergy.com. C O R P O R AT E G OV E R N A N C E Xcel Energy has ﬁled certiﬁcations of its Chief Executive Ofﬁcer and Chief Financial Ofﬁcer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 as exhibits to its Annual Report on Form 10-K for 2005 that it has ﬁled with the Securities and Exchange Commission. It has also ﬁled with the New York Stock Exchange the CEO certiﬁcation for 2005 required by section 303A.12(a) of the New York Stock Exchange’s rules relating to compliance with the New York Stock Exchange’s corporate governance listing standards. FISCAL AGENTS X C E L E N E R G Y I N C. Transfer Agent, Registrar, Dividend Distribution, Common and Preferred Stocks The Bank of New York, 101 Barclay Street, New York, New York 10286 Trustee – Bonds Wells Fargo Bank Minnesota, N.A., Sixth Street and Marquette Avenue, Minneapolis, Minnesota 55479 Coupon Paying Agents – Bonds Wells Fargo Bank Minnesota, N.A., Minneapolis, Minnesota XCEL ENERGY 2005 ANNUAL REPORT 83 X C E L E N E R G Y D I R E C T O R S A N D P R I N C I P A L O F F I C E R S XCEL ENERGY DIRECTORS Richard C. Kelly* Chairman, President and CEO Xcel Energy Inc. Richard H. Anderson, 1, 4 Executive Vice President UnitedHealth Group, Inc. CEO Ingenix C. Coney Burgess 2, 3 Chairman and President Burgess-Herring Ranch Company Chairman Herring Bank Roger R. Hemminghaus 1, 3 Retired Chairman and CEO Ultramar Diamond Shamrock Corporation A. Barry Hirschfeld 2, 4 Chairman National Hirschfeld LLC Douglas W. Leatherdale 1, 2, 3 Retired Chairman and CEO The St. Paul Companies, Inc. Albert F. Moreno 1, 3 Retired Senior Vice President and General Counsel Levi Strauss & Co. Dr. Margaret R. Preska 1, 4 Owner and CEO Robinson Preska Company Distinguished Service Professor Minnesota State Universities President Emerita Minnesota State University, Mankato A. Patricia Sampson 2, 4 President and CEO The Sampson Group, Inc. Richard H. Truly 3, 4 Retired U.S. Navy Vice Admiral Board Committees: 1. Audit 2. Governance, Compensation and Nominating 3. Finance 4. Operations, Nuclear and Environmental *Richard C. Kelly is ex ofﬁcio member of all committees XCEL ENERGY PRINCIPAL OFFICERS Richard C. Kelly Chairman, President and CEO Paul J. Bonavia President – Utilities Group Benjamin G.S. Fowke III Vice President and Chief Financial Ofﬁcer Raymond E. Gogel Vice President – Customer and Enterprise Solutions and Chief Administrative Ofﬁcer Cathy J. Hart Vice President – Corporate Services and Corporate Secretary Gary R. Johnson Vice President and General Counsel Teresa S. Madden Vice President and Controller George E. Tyson II Vice President and Treasurer David M. Wilks President – Energy Supply PRINCIPAL SUBSIDIARIES OFFICERS Gary L. Gibson Michael L. Swenson Patricia K. Vincent President and CEO – Southwestern Public Service Company President and CEO – Northern States Power Company-Wisconsin President and CEO – Public Service Company of Colorado Cynthia L. Lesher President and CEO – Northern States Power Company-Minnesota 84 XCEL ENERGY 2005 ANNUAL REPORT U.S. Bancorp Center 414 Nicollet Mall Minneapolis, MN 55401 Xcel Energy investors hotline: 1-877-914-9235 www.xcelenergy.com © 2006 Xcel Energy Inc. Xcel Energy is a trademark of Xcel Energy Inc. Printed on recycled paper, using soy-based inks CSS#0208

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