-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HKkqd/BzLtQYLs5dqTaG+LVoSiLPv1DaxaizdRhxeiTom72fud8rbz/TP5XdLUFQ aHPqaMaxWtpUv7DmcYycvQ== 0000950134-03-003112.txt : 20030226 0000950134-03-003112.hdr.sgml : 20030226 20030226143403 ACCESSION NUMBER: 0000950134-03-003112 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030226 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF COLORADO CENTRAL INDEX KEY: 0000081018 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 840296600 STATE OF INCORPORATION: CO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03280 FILM NUMBER: 03580777 BUSINESS ADDRESS: STREET 1: 1225 17TH ST STE 900 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3035717511 MAIL ADDRESS: STREET 1: P O BOX 840 STE 300 CITY: DENVER STATE: CO ZIP: 80201 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHWESTERN PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000092521 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 750575400 STATE OF INCORPORATION: NM FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03789 FILM NUMBER: 03580776 BUSINESS ADDRESS: STREET 1: SPS TOWER STREET 2: TYLER AT SIXTH ST CITY: AMARILLO STATE: TX ZIP: 79101 BUSINESS PHONE: 3035717511 MAIL ADDRESS: STREET 1: PO BOX 1261 CITY: AMARILLO STATE: TX ZIP: 79170 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN STATES POWER CO /WI/ CENTRAL INDEX KEY: 0000072909 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 390508315 STATE OF INCORPORATION: WI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03140 FILM NUMBER: 03580778 BUSINESS ADDRESS: STREET 1: 1414 W HAMILTON AVE CITY: EAU CLAIRE STATE: WI ZIP: 54702 BUSINESS PHONE: 7158392621 MAIL ADDRESS: STREET 1: P O BOX 8 CITY: EAU CLAIRE STATE: WI ZIP: 54702-008 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN STATES POWER CO CENTRAL INDEX KEY: 0001123852 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 411967505 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-31387 FILM NUMBER: 03580779 BUSINESS ADDRESS: STREET 1: 414 NICOLLET MALL CITY: MINNEAPOLIS STATE: MN ZIP: 55401 BUSINESS PHONE: 6123305500 MAIL ADDRESS: STREET 1: 414 NICOLLET MALL CITY: MINNEAPOLIS STATE: MN ZIP: 55401 10-K 1 c75034e10vk.htm FORM 10-K e10vk
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

(Mark One)

            þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended Dec. 31, 2002

OR

            o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

             
Exact name of Registrant as specified in its charter, State or other jurisdiction
Commission of incorporation or organization, Address of principal executive offices and IRS Employer
File Number Registrant’s Telephone Number, including area code Identification No.



000-31709
  NORTHERN STATES POWER COMPANY (a Minnesota Corporation)
414 Nicollet Mall, Minneapolis, Minn. 55401
Telephone (612) 330-5500
    41-1967505  
001-3140
  NORTHERN STATES POWER COMPANY (a Wisconsin Corporation)
1414 W. Hamilton Ave., Eau Claire, Wis. 54701
Telephone (715) 839-2625
    39-0508315  
001-3280
  PUBLIC SERVICE COMPANY OF COLORADO (a Colorado Corporation)
1225 17th Street, Denver, Colo. 80202
Telephone (303) 571-7511
    84-0296600  
001-3789
  SOUTHWESTERN PUBLIC SERVICE COMPANY
(a New Mexico Corporation)
Tyler at Sixth, Amarillo, Texas 79101
Telephone (303) 571-7511
    75-0575400  


      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No o

      Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o  No þ

      Northern States Power Co. (a Minnesota corporation), Northern States Power Co. (a Wisconsin corporation), Public Service Co. of Colorado and Southwestern Public Service Co. meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

      Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. All outstanding common stock is owned beneficially and of record by Xcel Energy Inc., a Minnesota corporation. Shares outstanding at Feb. 21, 2003:

         
Northern States Power Co.
(a Minnesota Corporation)
  Common Stock, $0.01 par value   1,000,000 Shares
Northern States Power Co.
(a Wisconsin Corporation)
  Common Stock, $100 par value   933,000 Shares
Public Service Co. of Colorado
  Common Stock, $0.01 par value   100 Shares
Southwestern Public Service Co.
  Common Stock, $1 par value   100 Shares




INDEX

Item l. Business
COMPANY OVERVIEW
UTILITY REGULATION
ELECTRIC UTILITY OPERATIONS
GAS UTILITY OPERATIONS
ENVIRONMENTAL MATTERS
EMPLOYEES
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis
NSP-Minnesota’s Management’s Discussion and Analysis
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplemental Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
PART III
Item 10. Directors and Executive Officers of the Registrant (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
Item 11. Executive Compensation (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
Item 12. Security Ownership of Certain Beneficial Owners and Management (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
Item 13. Certain Relationships and Related Transactions (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
Item 14. Controls and Procedures
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
UTILITY SUBSIDIARIES OF XCEL ENERGY VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
SIGNATURES
EX-12.01 Computation of Ratio of Earnings
EX-23.01 Consent of Independent Accountants
EX-99.01 Statement Pursuant to Securities Act
EX-99.03 Certification Pursuant to 18 USC Sec 1350


Table of Contents

             
Page
No.

PART I
       
Item 1 — Business
    3  
 
COMPANY OVERVIEW
       
 
UTILITY REGULATION
       
   
Ratemaking Principles
    4  
   
Fuel, Purchased Gas and Resource Adjustment Clauses
    5  
   
Other Regulatory Mechanisms and Requirements
    7  
   
Pending Regulatory Matters
    8  
 
ELECTRIC UTILITY OPERATIONS
       
   
Competition and Industry Restructuring
    13  
   
Capacity and Demand
    18  
   
Energy Sources
    18  
   
Fuel Supply and Costs
    20  
   
Trading Operations
    21  
   
Nuclear Power Operations and Waste Disposal
    22  
   
Electric Operating Statistics
    24  
 
GAS UTILITY OPERATIONS
       
   
Competition and Industry Restructuring
    27  
   
Capability and Demand
    28  
   
Gas Supply and Costs
    29  
   
Gas Operating Statistics
    30  
 
ENVIRONMENTAL MATTERS
    32  
 
EMPLOYEES
    33  
Item 2 — Properties
    33  
Item 3 — Legal Proceedings
    36  
Item 4 — Submission of Matters to a Vote of Security Holders
    38  
PART II
       
Item 5 — Market for Registrant’s Common Equity and Related Stockholder Matters
    38  
Item 6 — Selected Financial Data
    38  
Item 7 — Management’s Discussion and Analysis
    38  
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
    46  
Item 8 — Financial Statements and Supplementary Data
    48  
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    124  
PART III
       
Item 10 — Directors and Executive Officers of the Registrant
    124  
Item 11 — Executive Compensation
    124  
Item 12 — Security Ownership of Certain Beneficial Owners and Management
    124  
Item 13 — Certain Relationships and Related Transactions
    124  
Item 14 — Controls and Procedures
    124  
PART IV
       
Item 15 — Exhibits, Financial Statement Schedules, and Reports on Form 8-K
    125  
SIGNATURES
    135  

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Page
No.

EXHIBIT (EXCERPT)
       
Ratio of Earnings to Fixed Charges
       
Statement Pursuant to Private Securities Litigation Reform Act
       
Exhibit Regarding the Use of Arthur Andersen Audit Firm
       

      This combined Form 10-K is separately filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Co. of Colorado (PSCo); and Southwestern Public Service Co. (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are all wholly owned subsidiaries of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the U.S. Securities and Exchange Commission (SEC). Information in this report relating to any individual company is filed by such company on its own behalf. Each registrant makes representation only to itself and makes no representations as to information relating to the other registrants. This report should be read in its entirety.

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Item l.     Business

 
COMPANY OVERVIEW

      On Aug. 18, 2000, New Century Energies, Inc. (NCE) and Northern States Power Co. (NSP) merged and formed Xcel Energy Inc. (Xcel Energy). Xcel Energy, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). As part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed subsidiary of Xcel Energy named Northern States Power Co.

      Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. Four of these utility subsidiaries are SEC registrants, including Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Co. of Colorado, a Colorado corporation (PSCo); and Southwestern Public Service Co., a New Mexico corporation (SPS).

 
NSP-Minnesota

      NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an operating utility engaged in the generation, transmission and distribution of electricity and the transportation, storage and distribution of natural gas. NSP-Minnesota provides generation, transmission and distribution of electricity in Minnesota, North Dakota and South Dakota. NSP-Minnesota also purchases, distributes and sells natural gas to retail customers and transports customer-owned gas in Minnesota, North Dakota and South Dakota. NSP-Minnesota provides retail electric utility service to approximately 1.3 million customers and gas utility service to approximately 430,000 customers.

      NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds real estate; NSP Nuclear Corp., which holds NSP-Minnesota’s interest in the Nuclear Management Co.; and NSP Financing I, a special purpose financing trust.

 
      NSP-Wisconsin

      NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility engaged in the generation, transmission and distribution of electricity to approximately 230,000 retail customers in northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin is also engaged in the distribution and sale of natural gas in the same service territory to approximately 90,000 customers.

      NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reserves; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

 
      PSCo

      PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged principally in the generation, purchase, transmission, distribution and sale of electricity and the purchase, transportation, distribution and sale of natural gas. PSCo serves approximately 1.3 million electric customers and approximately 1.2 million natural gas customers in Colorado.

      PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests of PSCo; PSR Investments, Inc., which owns and manages permanent life insurance policies on certain employees; Green and Clear Lakes Co., which owns water rights; and PSCo Capital Trust I, a special purpose financing trust. PSCo also holds a controlling interest in several other relatively small companies whose capital requirements are not significant. PS Colorado Credit Corp., a finance company that was owned by PSCo and financed certain of PSCo’s current assets was dissolved in 2002.

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      SPS

      SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, transmission, distribution and sale of electricity, which serves approximately 390,000 electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. The wholesale customers served by SPS comprise approximately 36 percent of the total kilowatt-hour sales.

      SPS owns a direct subsidiary, SPS Capital I, which is a special purpose financing trust.

 
UTILITY REGULATION

Ratemaking Principles

      The utility subsidiaries of Xcel Energy are subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under the PUHCA. As a result, the utility subsidiaries are subject to extensive regulation by the SEC with respect to issuances and sales of securities, acquisitions and sales of certain utility properties and intra-system sales of certain goods and services. In addition, the PUHCA generally limits the ability to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations.

      The Federal Energy Regulatory Commission (FERC) has jurisdiction over rates for electric transmission service in interstate commerce and wholesale electric energy, hydro facility licensing and certain other activities of Xcel Energy’s utility subsidiaries. Federal, state and local agencies also have jurisdiction over many of the utility subsidiaries’ other activities, including regulation of retail rates and environmental matters.

      The utility subsidiaries of Xcel Energy are unable to predict the impact on their operating results from the future regulatory activities of any of these agencies. The utility subsidiaries of Xcel Energy are responsible for compliance with all rules and regulations issued by the various agencies.

 
      NSP-Minnesota

      Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the jurisdiction of the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC) and the South Dakota Public Utilities Commission (SDPUC) within their respective states. The MPUC possesses regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans and gas supply plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 megawatts and transmission lines greater than 100 kilovolts. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electricity sales at market-based prices.

      The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites for new power plants with a capacity of 50 megawatts or more and wind energy conversion plants with a capacity of five megawatts or more. It also designates routes for electric transmission lines with a capacity of 100 kilovolts or more. No power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB.

 
      NSP-Wisconsin

      NSP-Wisconsin is subject to regulation of similar scope by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC). In addition, each of the state commissions certifies the need for new generating plants and electric and retail gas transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce.

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      The PSCW has a biennial base rate-filing requirement. June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the two-year period beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

 
      PSCo

      PSCo is subject to the jurisdiction of the Colorado Public Utilities Commission (CPUC) with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices. Also, PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.

 
      SPS

      The Public Utility Commission of Texas (PUCT) has jurisdiction over SPS’ Texas operations as an electric utility and over its retail rates and services. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. The New Mexico Public Regulatory Commission (NMPRC) has jurisdiction over the issuance of securities and accounting. The NMPRC, the Oklahoma Corporation Commission and the Kansas Corporation Commission have jurisdiction with respect to retail rates and services in their respective states. SPS is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. SPS has received authorization from the FERC to make wholesale electricity sales at market-based prices.

Fuel, Purchased Gas and Resource Adjustment Clauses

 
      NSP-Minnesota

      NSP-Minnesota’s retail electric rate schedules provide for monthly adjustments to billings and revenues for current changes in the cost of fuel and purchased energy compared with the last costs included in rates. NSP-Minnesota is permitted to recover the cost of financial instruments associated with fuel and purchased energy through a fuel clause adjustment. Changes in capacity charges are not recovered through the fuel clause. NSP-Minnesota’s electric wholesale customers do not have a fuel clause provision in their contracts. Instead, the contracts have an escalation factor.

      Retail gas rate schedules for NSP-Minnesota include a purchased gas adjustment (PGA) clause that provides for rate adjustments for changes in the current unit cost of purchased gas compared with the last costs included in rates. The PGA factors in Minnesota are calculated for the current month based on the estimated purchased gas costs for that month. The MPUC has the authority to disallow certain costs if it finds the utility was not prudent in its procurement activities.

      NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue and 0.5 percent of Minnesota gas revenue on conservation improvement programs (CIP). Electric and gas conservation and energy management program expenditures are recovered through an annual cost recovery mechanism. NSP-Minnesota is required to request a new cost recovery level annually.

 
      NSP-Wisconsin

      NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers. Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates. If the comparison results in a difference outside a prescribed range, the PSCW may hold hearings limited to fuel costs and revise rates (upward or downward). Any revised rates would be effective until the next rate case. The adjustment approved is calculated on an

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annual basis, but applied prospectively. NSP-Wisconsin’s wholesale electric rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

      NSP-Wisconsin has a monthly gas cost recovery mechanism in Wisconsin to recover the actual cost of natural gas.

      NSP-Wisconsin’s gas and retail electric rate schedules for Michigan customers include gas cost recovery factors and power supply cost recovery factors, which are based on 12-month projections. After each 12-month period, reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

 
      PSCo

      PSCo currently has seven adjustment clauses that recover fuel, purchased energy and resource costs: the incentive cost adjustment (ICA), the interim adjustment clause (IAC), the air quality improvement rider (AQIR), the demand side management cost adjustment (DSMCA), the qualifying facilities capacity cost adjustment (QFCCA), the gas cost adjustment (GCA) and the steam cost adjustment (SCA). These adjustment clauses allow certain costs to be recovered from retail customers. For certain adjustment mechanisms, PSCo is required to file applications with the CPUC for approval in advance of the proposed effective dates.

      The ICA allows for an equal sharing between retail electric customers and shareholders of certain fuel and purchased energy cost changes for fuel and purchased energy costs incurred prior to Dec. 31, 2002. The IAC recovers fuel and energy costs incurred during 2003 until the conclusion of the 2002 general rate case, at which time the fuel and purchased energy cost recovery from Jan. 1, 2003 onward shall be recalculated in accordance with the mechanism approved by the CPUC in the 2002 general rate case. The AQIR recovers over a 15-year period the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of voluntary investments to reduce emissions and improve air quality in the Denver metro area. The DSMCA clause currently permits PSCo to recover DSM costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. PSCo also has implemented a low-income energy assistance program. The costs of this energy conservation and weatherization program for low-income customers are recovered through the DSMCA. The QFCCA provides for recovery of purchased capacity costs from certain qualified facilities not otherwise reflected in base electric rates. The QFCCA will expire at the conclusion of the 2002 general rate case. Through its GCA, PSCo is allowed to recover its actual costs of purchased gas. The GCA rate is revised annually to coincide with changes in purchased gas costs. In 2002, PSCo requested to modify the GCA to allow for monthly changes in gas rates. A final decision on this proceeding is expected in 2003. Purchased gas costs and revenues received to recover gas costs are compared on a monthly basis and differences are deferred. PSCo, through its SCA, is allowed to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised annually to coincide with changes in fuel costs.

     SPS

      Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is part of SPS’ retail electric rates. If it appears that SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the PUCT. The rule requires refunding and surcharging over- or under-recovery amounts, including interest, when they exceed 4 percent of the utility’s annual fuel and purchased power costs, as allowed by the PUCT, if this condition is expected to continue. PUCT regulations require periodic examination of SPS fuel and purchased power costs, the efficiency of the use of such fuel and purchased power, fuel acquisition and management policies and purchase power commitments. Under the PUCT’s regulations, SPS is required to file an application for the PUCT to retrospectively review at least every three years the operations of SPS’ electric generation and fuel management activities.

      The NMPRC regulations provide for a fuel and purchased power cost adjustment clause for SPS’ New Mexico retail jurisdiction. SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC, which include the current over/ under fuel collection calculation, plus interest. In January 2002, the

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NMPRC authorized SPS to implement a monthly adjustment factor on an interim basis beginning with the February 2002 billing cycle.

Other Regulatory Mechanisms and Requirements

     NSP-Minnesota

      In December 2000, the NDPSC approved Xcel Energy’s “PLUS” performance-based regulation proposal, effective January 2001, for its electric operations in the state. The plan established operating and service performance standards in the areas of system reliability, customer satisfaction, price, and worker safety. The Company’s performance determines the range of allowed return on equity for its North Dakota electric operations. The plan will generate refunds or surcharges when earnings fall outside of the allowed return on equity range. The PLUS plan will remain in effect through 2005.

     PSCo

      The CPUC established an electric Performance-Based Regulatory Plan (PBRP) under which PSCo operates. The major components of this regulatory plan include:

  •  an annual electric earnings test with the sharing between customers and shareholders of earnings in excess of the following limits:

  •  a 10.50 percent return on equity for 2002;
 
  •  no earnings sharing for 2003;
 
  •  an annual electric earnings test with the sharing of earnings in excess of the return on equity to be determined in the pending 2002 rate case for 2004 through 2006;

  •  an electric Quality Service Plan (QSP) that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2006;
 
  •  a gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to gas leak repair time and customer service through 2007; and
 
  •  an ICA that provides for the sharing of energy costs and savings relative to an annual baseline cost per delivered kilowatt-hour. According to the terms of the merger agreement in Colorado, the annual baseline cost was reset in 2002, based on a 2001 test year. The recovery of fuel and purchased energy expense beginning Jan. 1, 2003 will be decided in the 2002 general rate case.

      PSCo regularly monitors and records, as necessary, an estimated customer refund obligation under the earnings test. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually. During 2002, PSCo filed that its electric department earnings were below the 11 percent return on equity threshold. PSCo has estimated no customer refund obligation for 2002 under the earnings test, the electric QSP or the gas QSP. The 2001 earnings test filing has not been approved. A hearing is scheduled for May 2003.

     SPS

      Prior to June 2001, SPS operated under an earnings test in Texas which required excess earnings to be returned to the customers. In May 2000, SPS filed its 1999 Earnings Report with the PUCT, indicating no excess earnings. In September 2000, the PUCT staff and the Office of Public Utility Counsel filed with the PUCT a Notice of Disagreement, indicating adjustments to SPS calculations, which would result in excess earnings. During 2000, SPS recorded an estimated obligation of approximately $11.4 million for 1999 and 2000. In February 2001, the PUCT ruled on the disputed issues in the 1999 report and found that SPS had excess earnings of $11.7 million. This decision was appealed by SPS to the District Court. On Dec. 11, 2001, SPS entered into an overall settlement of all earnings issues for 1999 through 2001, which reduced the excess earnings for 1999 to $7.3 million and found that there were no excess earnings for 2000 or through June 2001.

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The settlement also provided that the remaining excess earnings for 1999 could be used to offset approved transition costs that SPS was seeking to recover. The PUCT approved the overall settlement on Jan. 10, 2002.

Pending Regulatory Matters

     NSP-Minnesota

      Metro Emissions Reduction Program — In July 2002, NSP-Minnesota filed for approval by the MPUC of a proposal to invest in existing NSP-Minnesota generation facilities to reduce emissions under the terms of legislation adopted by the 2001 Minnesota Legislature. The Minnesota proposal includes the installation of state-of-the-art pollution control equipment at the A. S. King plant and conversion of the High Bridge and Riverside plants to use natural gas rather than coal. Under the proposal, major construction would start in 2005 and be completed in 2009. Under the terms of the statute, the filing concurrently seeks approval of a rate recovery mechanism for the costs of the proposal, estimated to total $1.1 billion. The rate recovery would be through an annual automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case, and is proposed to be effective at the expiration of the NSP-Minnesota merger rate freeze, which extends through 2005 unless certain exemptions are triggered. The rate recovery proposed by NSP-Minnesota would allow recovery of financing costs of capital expenditures prior to the in-service date of equipment to be installed at each plant. The proposal is pending comments by interested parties. Other regulatory approvals, such as environmental permitting, are needed before the proposal can be implemented. On Dec. 30, 2002, the Minnesota Pollution Control Agency issued a report to the MPUC in which it found that the NSP-Minnesota emission reduction proposal is appropriate and complies with the requirements of the 2001 legislation. The MPUC must now act on the proposal.

      Renewable Cost Recovery Tariff — In April 2002, NSP-Minnesota filed for MPUC authorization to recover in retail rates the costs of electric transmission facilities constructed to provide transmission service for renewable energy. The rate recovery would be through an automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case. In January 2003, the MPUC issued an order approving the tariff subject to certain modifications.

      Minnesota Financial and Service Quality Investigation — On Aug. 8, 2002, the MPUC asked for information related to the impact of the financial circumstances of NSP-Minnesota’s affiliate, NRG Energy, Inc. Subsequent to that date, several newspaper articles alleged concerns about the reporting of service quality data and NSP-Minnesota’s overall maintenance practices. In an order dated Oct. 22, 2002, the MPUC directed the Minnesota Department of Commerce and the Office of the Attorney General-Residential Utilities Division to investigate the accuracy of NSP-Minnesota’s reliability records and to allow for further review of its maintenance and other service quality measures. In addition, the order requires NSP-Minnesota to report specified financial information and work with interested parties on various issues to ensure NSP-Minnesota’s commitments are fulfilled. The Minnesota Department of Commerce and Office of the Attorney General have begun their investigation. There is no scheduled date for completion of this inquiry. The order references the NSP-Minnesota commitment (made at the time of the NSP/NCE Merger) to not seek a rate increase until 2006 unless certain exceptions are met. In addition, among other requirements, the order imposes restrictions on NSP-Minnesota’s ability to encumber utility property, provide intercompany loans and the method by which NSP-Minnesota can calculate its cost of capital in present and future filings before the MPUC. On Jan. 3, 2003, the MPUC subsequently issued an order bifurcating the financial aspect of this proceeding from the state agency’s inquiry into NSP-Minnesota’s service quality reporting and allowing the agencies to continue to investigate other allegations in existing dockets. As a result, these two matters will proceed under separate dockets.

      Time-of-Use Pilot Project — As required by MPUC Orders, NSP-Minnesota has been working to develop a time-of-use pilot project that would attempt to measure customer response and conservation potential of such a program. This pilot project explores providing customers with pricing signals and information that could better inform customer choices about their use of electricity based on its costs. NSP-Minnesota has petitioned the MPUC for recovery of program costs. 2002 program costs are approximately $2 million. The Department of Commerce has supported deferred accounting to provide for recovery of

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prudent, otherwise unrecovered and appropriate costs, subject to a normal prudence review process. The Office of the Attorney General has argued that cost recovery should be denied for several reasons. An MPUC hearing on these issues is likely in the first half of 2003.

      Electric Transmission Construction — In December 2001, NSP-Minnesota filed for certificates of need authorizing construction of various high voltage transmission facilities to provide generator outlet for up to 825 megawatts of wind generation in southwest Minnesota. The projected cost is approximately $160 million. On Jan. 30, 2003, the MPUC voted to issue certificates of need supporting NSP-Minnesota’s preferred transmission construction plan. The certificates of need were issued with conditions that require NSP-Minnesota to purchase wind powered electric generating capacity to match the increased transmission capacity created by the certified lines. The MPUC has not issued its written order.

      Filings will be made with the MEQB to decide routing issues associated with the transmission plan. MEQB decisions are expected by the end of 2003 and early 2004. Construction is expected to be complete in the spring of 2007.

      Merger Agreement — As part of the NCE and NSP merger approval process in Minnesota, NSP-Minnesota agreed to:

  •  reduce its Minnesota electric rates by $10 million annually through 2005;
 
  •  not increase its electric rates through 2005, except under limited circumstances;
 
  •  not seek recovery of certain merger costs from customers; and
 
  •  meet various quality standards.

     NSP-Wisconsin

      Retail Electric Fuel Rates — In August 2002, NSP-Wisconsin filed an application with the PSCW, requesting a decrease in Wisconsin retail electric rates for fuel costs. The amount of the proposed rate decrease was approximately $6.3 million on an annual basis. The reasons for the decrease include moderate weather, lower than forecast market power costs and optimal plant availability. On Aug. 7, 2002, the PSCW issued an order approving the fuel rate credit. The rate credit went into effect on Aug. 12, 2002.

      On Oct. 9, 2002, NSP-Wisconsin filed an application with the PSCW requesting another decrease in Wisconsin retail electric rates for fuel costs. The incremental amount of the second proposed rate decrease was approximately $5 million on an annual basis. The reasons for the additional decrease include continued moderate weather, lower than forecast market power costs and optimal plant availability. On Oct. 16, 2002, the PSCW issued an order approving the revised fuel rate credit, effective Oct. 19, 2002.

      On Oct. 22, 2002, NSP-Wisconsin filed an application with the PSCW requesting the establishment of a new fuel monitoring range and fuel recovery factor for 2003. On Jan. 30, 2003, the PSCW issued an order authorizing a new fuel monitoring range for 2003 and a new fuel recovery factor effective Feb. 3, 2003. This results in an annual revenue increase of approximately $5 million from the fuel credit factor the PSCW approved Oct. 16, 2002.

      Michigan Transfer Pricing — On Oct. 3, 2002, the MPSC denied NSP-Wisconsin’s request for a waiver of the section of the Michigan Electric Code of Conduct (Michigan Code) dealing with transfer pricing policy. The Michigan Code requires the price of goods and services provided by an affiliate to NSP-Wisconsin be at the lower of market price or cost plus 10 percent, and the price of goods and services provided by NSP-Wisconsin to an affiliate be at the higher of cost or market price. NSP-Wisconsin requested the waiver based on its belief that the Michigan Code conflicts with SEC requirements to price goods and services provided between affiliates at cost. In November 2002, NSP-Wisconsin filed a request for reconsideration of the Oct. 3, 2002 order. During its Jan. 31, 2003 meeting, the MPSC considered NSP-Wisconsin’s rehearing request and granted the Company’s request for waiver from this section of the Michigan Code. In its decision, the MPSC indicated that it should grant the waiver to avoid placing NSP-Wisconsin in a position where it may be unable to comply with the Michigan Code and the pricing standards enforced by the SEC.

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     PSCo

      Merger Agreement — Under the Stipulation and Agreement approved by the CPUC in connection with the Xcel Energy merger, PSCo agreed to:

  •  file a combined electric, gas and steam rate case in 2002 with new rates effective in January 2003;
 
  •  extend its ICA mechanism through Dec. 31, 2002 with an increase in the ICA base rate from $12.78 per megawatt hour to a rate based on the 2001 actual costs;
 
  •  continue the electric PBRP and the electric QSP through 2006 with an electric department earnings cap of 10.5 percent return on equity for 2002 and no earnings sharing for 2003;
 
  •  develop a gas Quality Service Plan for calendar year 2002 through 2007 performance;
 
  •  reduce electric rates annually by $11 million for the period August 2000 to July 2002; and
 
  •  cap merger costs associated with electric operations at $30 million and amortize such costs through 2002.

      Incentive Cost Adjustment — PSCo’s 2001 calendar year energy costs under the ICA were approximately $19 per megawatt hour, compared to the $12.78 per megawatt hour rate that was billed to customers. The sharing of certain energy wholesale trading margins mitigated the significant under-recovery of energy costs for 2001. In early 2002, PSCo filed to increase the ICA rate earlier than what was agreed to in the merger stipulation and agreement to mitigate future cost deferrals and to recover the projected ICA energy costs for calendar year 2002. On May 10, 2002, the CPUC approved a Settlement Agreement between PSCo and other parties to increase the recovery of energy costs to $14.88 per megawatt hour, providing for recovery of the deferred costs as of Dec. 31, 2001 and the projected 2002 costs over a 34-month period from June 1, 2002 through Mar. 31, 2005.

      PSCo’s costs for 2002 were approximately $17 per megawatt hour or approximately $56 million less than the allowed energy recovery rate, which was based on the 2001 test year. Under the ICA mechanism, retail customers and PSCo share this difference equally. A CPUC proceeding to review and approve the incurred and recoverable 2001 costs under the ICA is in process. In 2003, PSCo will file for recovery of its 2002 costs. A review of the 2002 costs will be conducted in a separate future proceeding. The results of these rate proceedings could impact the cost recovery and sharing amounts recorded under the ICA for 2001 and 2002.

      On May 31, 2002, PSCo filed with the CPUC seeking to change its electric base rates and seeking to increase the recovery of fuel and purchased power expense by $113 million annually through a mechanism called the Electric Commodity Adjustment (ECA). The IAC, filed in January 2003, resulted in an annual increase in fuel and purchased expense recovery revenue of $123 million predicated on calendar year 2003 forecasted sales for PSCo retail. Finally, on Feb. 12, 2003 PSCo filed supplemental rebuttal testimony revising its original ECA request made on May 31, 2002. In this filing, PSCo is seeking ECA rates that would increase the annual recovery of fuel and purchased energy expense by $186 million over the annual level of recovery at May 31, 2002. Since $123 million of the requested $186 million is already in effect, the net increase requested on Feb. 12, 2003 is $64 million.

      There are four factors accounting for the change from $113 million requested in the May 31, 2002 filing and the $186 million requested in the Feb. 12, 2003 filing. Specifically, the Feb. 12, 2003 filing contains: (1) a revision in ECA costs caused by a renegotiated purchased power contract; (2) a revised 2003 sales forecast; (3) an updated forecast of natural gas costs used as a fuel source in electric generating stations; and (4) a correction for transformation and line losses made to the level of kilowatt-hours used in deriving the proposed level of annual ECA costs.

      2002 General Rate Case — In May 2002, PSCo filed a combined general retail electric, gas and thermal energy base rate case with the CPUC to address increased costs for providing services to Colorado customers. This filing was required as part of the Xcel Energy Merger Stipulation and Agreement previously approved by the CPUC. Among other things, the case includes establishing an electric energy recovery mechanism, elimination of the QFCCA, new depreciation rates and recovery of additional plant investment. PSCo

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requested an increase to its authorized rate of return on equity to 12 percent for electricity and 12.25 percent for natural gas. In early 2003, PSCo filed its rebuttal testimony in this rate case. At this point in the rate proceeding, PSCo is now requesting an overall annual increase to electric revenue of approximately $233 million. This is based on a $186 million increase for fuel and purchased energy expense and a $47 million electric base rate increase. PSCo is requesting an annual base rate decrease in natural gas revenue of approximately $21 million. The rebuttal case incorporates several adjustments to the original filing, including lower depreciation expense, higher fuel and energy expense and various corrections to the original filing.

      Intervenors, including the CPUC Staff and the Colorado Office of Consumer Council (OCC) have filed testimony requesting both electric and gas base rate decreases and increases in fuel and energy revenues that are less than the amounts requested by PSCo. On Feb. 19, 2003, the CPUC postponed the scheduled hearings for 30 days to allow parties to pursue a comprehensive settlement of all issues in this proceeding. New rates are expected to be effective during the second quarter of 2003. A final decision on the recovery of fuel and energy costs will be applied retroactive to Jan. 1, 2003. Until such time, PSCo is billing customers under the IAC, assuming 100 percent pass through cost recovery.

      Gas Cost Prudence Review — In May 2002, the staff of the CPUC filed testimony in PSCo’s gas cost prudence review case, recommending $6.1 million in disallowances of gas costs for the July 2000 through June 2001 gas purchase year. Hearings were held before an Administrative Law Judge (ALJ) in July 2002. On Feb. 10, 2003, the ALJ issued a recommended decision rejecting the proposed disallowances and approving PSCo’s gas costs for the subject gas purchase year as prudently incurred. The decision is subject to CPUC review should the CPUC staff file exceptions to the recommended decision, which must be filed by Mar. 3, 2003.

      Gas Rate Reduction — In September 2002, PSCo filed a request with the CPUC for a $65 million annual reduction in the natural gas cost component of rates in Colorado. The CPUC approved the requested decrease by order issued Sept. 27, 2002, with the new rates effective Oct. 1, 2002.

      2002 Wholesale Sales Data Investigation — In February 2002, after the bankruptcy filing by Enron Corp., the FERC initiated a fact-finding investigation into whether any entity, including Enron, manipulated short-term prices in electric or natural gas markets in the Western United States or otherwise exercised undue influence over wholesale prices in the West since January 2000. PSCo made market-based sales during this period and is included in the FERC investigation.

      Home Builders Association of Metropolitan Denver — Home Builders Association of Metropolitan Denver (HBA) filed a formal complaint with the CPUC on Feb. 23, 2001, requesting an award of reparations for excessive charges related to construction payments under PSCo’s gas extension tariff as a result of PSCo’s alleged failure to file revisions to its published construction allowances since 1996. HBA seeks an award of reparations on behalf of all of PSCo’s gas extension applicants since Oct. 1, 1996, in the amount of $13.6 million, including interest. HBA also seeks recovery of its attorney’s fees.

      Hearings were held before an ALJ on Aug. 29, 2001 and Sept. 24, 2001. On Jan. 15, 2002, the ALJ issued a recommended decision dismissing HBA’s complaint. The ALJ found that HBA failed to show that there have been any “excessive charges,” as required under the reparations statute, resulting from PSCo’s failure to comply with its tariff. The ALJ held that HBA’s claim for reparations (i) was barred by the filed rate doctrine (since PSCo at all times applied the approved construction allowances set forth in its tariff), (ii) would require the CPUC to violate the prohibition against retroactive ratemaking, and (iii) was based on speculation as to what the CPUC would do had PSCo made the filings in prior years to change its construction allowances. The ALJ also denied HBA’s request for costs and attorney’s fees. HBA filed exceptions to the ALJ’s decision. On June 19, 2002, the CPUC issued an order granting in part HBA’s exceptions to the ALJ’s recommended decision and remanding the case back to the ALJ for further proceedings. The CPUC reversed the ALJ’s legal conclusion that the filed rate doctrine and prohibition against retroactive ratemaking bars HBA’s claim for reparations under the circumstances of this case. The CPUC remanded the case back to the ALJ for a determination of whether and to what extent reparations should be awarded, considering certain enumerated issues.

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      A full-day hearing on remand was held on Jan. 10, 2003. Simultaneous briefs were filed on Feb. 5, 2003. Reply briefs were due Feb. 12, 2003. ALJ decision on remand is pending.

 
SPS

      Texas Fuel Factor and Fuel Surcharge Application — In June 2002, SPS filed an application for the PUCT to retrospectively review the operations of the utility’s electric generation and fuel management activities. In this application, SPS filed its reconciliation for electric generation and fuel management activities totaling approximately $608 million, for the period from January 2000 through December 2001. This proceeding is ongoing, and intervenor and PUCT staff testimony is being reviewed. Intervenors have proposed that revenues from certain wholesale transactions be credited to Texas retail customers. SPS is opposing this proposed revenue treatment. Hearings are scheduled for March 2003.

      SPS has reported to the PUCT that it has under-collected its fuel costs under the current Texas retail fixed fuel factors. SPS is preparing to file for a fuel cost surcharge.

      New Mexico Fuel Factor — On Dec. 17, 2001, SPS filed an application with the NMPRC seeking approval of continued use of its fuel and purchased power cost adjustment using a monthly adjustment factor, authorization to implement the proposed monthly factor on an interim basis and approval of the reconciliation of its fuel and purchased power adjustment clause collections for the period October 1999 through September 2001. In January 2002, the NMPRC authorized SPS to implement a monthly adjustment factor on an interim basis beginning with the February 2002 billing cycle. Hearings were completed in May 2002. SPS’ continuation and reconciliation portion of the file is still pending before the NMPRC.

      New Mexico Renewable Energy Requirements — In December 2002, the NMPRC adopted new regulations requiring investor-owned utilities operating in New Mexico to promote the use of renewable energy technologies by procuring at least 10 percent of their New Mexico retail energy requirements from renewable resources by no later than 2011.

      Golden Spread Electric Cooperative, Inc. — In October 2001, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a complaint and request for investigation against SPS before the FERC. Golden Spread alleges SPS has violated provisions of a Commitment and Dispatch Service Agreement pursuant to which SPS conducts joint dispatch of SPS and Golden Spread resources. Golden Spread seeks damages in excess of $10 million. SPS denies all of Golden Spread’s allegations. SPS has filed a complaint against Golden Spread in which it has alleged that Golden Spread has failed to adhere to certain requirements of the Commitment and Dispatch Service Agreement. Both complaints are presently pending before the FERC and settlement procedures have been ordered by the Commission. Settlement discussions are ongoing. Even if SPS is required to pay more to Golden Spread for power purchased under this agreement, it believes that the amounts will likely be recoverable by customers under the various fuel clause mechanisms.

      Merger Agreement — As a part of the NCE and NSP merger approval process in Texas, SPS agreed to:

  •  guarantee annual merger savings credits of approximately $4.8 million and amortize merger costs through 2005;
 
  •  retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and
 
  •  comply with various service quality and reliability standards, covering service installations and upgrades, light replacements, customer service call centers and electric service reliability.

      As a part of the merger approval process in New Mexico, SPS agreed to:

  •  guarantee annual merger savings credits of approximately $780,000 and amortize merger costs through December 2004;
 
  •  share net non-fuel operating and maintenance savings equally among retail customers and shareholders;

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  •  retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and
 
  •  not pass along any negative rate impacts of the merger.

ELECTRIC UTILITY OPERATIONS

Competition and Industry Restructuring

      Retail competition and the unbundling of regulated energy service could have a significant financial impact on Xcel Energy and its utility subsidiaries, due to an impairment of assets, a loss of retail customers, lower profit margins and increased costs of capital. The total impacts of restructuring may have a significant financial impact on the financial position, results of operation and cash flows of Xcel Energy and its utility subsidiaries. Xcel Energy and its utility subsidiaries cannot predict when they will be subject to changes in legislation or regulation, nor can they predict the impacts of such changes on their financial position, results of operation or cash flows. Xcel Energy believes that the prices its utility subsidiaries charge for electricity and the quality and reliability of their service currently place them in a position to compete effectively in the energy market.

      Retail Business Competition — The retail electric business faces some competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electric energy. In addition, customers may have the option of substituting other fuels, such as natural gas for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. While each of Xcel Energy’s utility subsidiaries faces these challenges, these subsidiaries believe their rates are competitive with currently available alternatives. Xcel Energy’s utility subsidiaries are taking actions to manage their operating costs and are working with their customers to analyze energy efficiency and load management in order to better position Xcel Energy’s utility subsidiaries to more effectively operate in a competitive environment.

      Wholesale Business Competition — The wholesale electric business faces competition in the supply of bulk power, due to federal and state initiatives, to provide open access to utility transmission systems. Under current FERC rules, utilities are required to provide wholesale open access transmission services and to unbundled wholesale merchant and transmission operations. Xcel Energy’s utility subsidiaries are operating under a joint tariff in compliance with these rules. To date, these provisions have not had a material impact on the operations of Xcel Energy’s utility subsidiaries.

      Utility Industry Changes and Restructuring — The structure of the electric and natural gas utility industry continues to change. Merger and acquisition activity over the past few years has been significant as utilities combine to capture economies of scale or establish a strategic niche in preparing for the future. Some regulated utilities are divesting generation assets. All utilities are required to provide non-discriminatory access to the use of their transmission systems.

      Some states allow retail customers to choose their electricity supplier, and many other states are considering retail access proposals. However, the experience of the state of California in instituting competition, as well as the bankruptcy filing of Enron, have caused delays in industry restructuring.

      The utility subsidiaries cannot predict the outcome of restructuring proceedings in the electric utility jurisdictions they serve at this time. The resolution of these matters may have a significant impact on the financial position, results of operation and cash flows of the utility subsidiaries.

      For more information on the delay of restructuring for SPS in Texas and New Mexico, see Note 10 to the Consolidated Financial Statements.

      FERC Restructuring — During 2001 and 2002, the FERC issued several industry wide orders impacting (or potentially impacting) the Xcel Energy operating companies. In addition, the Xcel Energy utility subsidiaries submitted proposals to the FERC that could impact future operations, costs and revenues.

      FERC Investigation of All Wholesale Electric Sellers — In November 2001, the FERC issued an order under Section 206 of the Federal Power Act initiating a “generic” investigation proceeding against all

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jurisdictional electric suppliers making sales in interstate commerce at market-based rates. NSP-Minnesota, PSCo, and SPS previously received FERC authorization to make wholesale sales at market-based rates, and have been engaged in such sales subject to rates on file at the FERC. The order proposed that all wholesale electric sales at market-based rates conducted starting 60 days after publication of the FERC order in the Federal Register would be subject to refund conditioned on factors determined by the FERC.

      Several parties filed requests for rehearing, arguing the November 2001 order was vague and would require the affected utilities to conditionally report future revenues and earnings. In December 2001, the FERC issued a supplemental order delaying the effective date of the subject to refund condition, but subject to further investigation and proceedings. Numerous parties filed comments in January 2002, and reply comments were filed in February of that year. Further, the FERC staff convened a conference in this proceeding in February 2002. The FERC has not yet acted on the matter.

      On May 8, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator or Power Exchange, including Xcel Energy, to respond to data requests, including requests for admissions with respect to certain trading strategies in which the companies may have engaged. The investigation was in response to memoranda prepared by Enron Corp. that detailed certain trading strategies engaged in during 2000 and 2001 which may have violated market rules. On May 22, 2002, Xcel Energy reported to the FERC that they had not engaged directly in any of the trading strategies or activities outlined in the May 8, 2002 request.

      However, Xcel Energy reported that at times during 2000 and 2001, its regulated operations did sell energy to another energy company that may then have resold the electricity for delivery into California as part of an overstated electricity load in schedules submitted to the California Independent System Operator. During that period, the regulated operations of Xcel Energy made sales to the other electricity provider of approximately 8,000 megawatt-hours in the California intra-day market, which resulted in revenues to Xcel Energy of approximately $1.5 million. Xcel Energy cannot determine from its records what part of such sales was associated with over-schedules due to the volume of records and the relatively small amount of sales.

      To supplement the May 8, 2002 request, on May 21, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services in the United States portion of the Western Systems Coordinating Council during 2000 and 2001 to report whether they had engaged in activities referred to as “wash”, “round trip” or “sell/buyback” trading. On May 31, 2002, Xcel Energy reported to the FERC that it had not engaged in so-called “round trip” electricity trading as identified in the May 21, 2002 inquiry.

      On May 13, 2002, Xcel Energy reported that PSCo had engaged in a group of transactions in 1999 and 2000 with the trading arm of Reliant Resources in which PSCo bought a quantity of power from Reliant and simultaneously sold the same quantity back to Reliant. For doing this, PSCo normally received a small profit. PSCo made a total pretax profit of approximately $110,000 on these transactions. Also, PSCo engaged in one trade with Reliant in which PSCo simultaneously bought and sold power at the same price without realizing any profit. The purpose of this non-profit transaction was in consideration of future for-profit transactions. PSCo engaged in these transactions with Reliant for the proper commercial objective of making a profit. It did not enter into these transactions to inflate volumes or revenues and transactions were reported net.

      Xcel Energy and PSCo have received subpoenas from the Commodity Futures Trading Commission for documents and other information regarding these so-called “round trip” trades and other trading in electricity and natural gas for the period Jan. 1, 1999 to the present involving Xcel Energy or any of its subsidiaries.

      Xcel Energy has also received a subpoena from the SEC for documents concerning “round trip” trades, as identified in the SEC subpoena, in electricity and natural gas with Reliant Resources, Inc. for the period Jan. 1, 1999 to the present. The SEC subpoena is issued pursuant to a formal order of private investigation that does not name Xcel Energy. Based upon accounts in the public press, management believes that similar subpoenas in the same investigations have been served on other industry participants. Xcel Energy and PSCo are cooperating with the regulators and taking steps to assure satisfactory compliance with the subpoenas.

      FERC Transmission Inquiry — The FERC has begun a formal, non-public inquiry relating to the treatment by public utility companies of affiliates in generator interconnection and other transmission matters.

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In connection with the inquiry, the FERC has asked Xcel Energy’s utility subsidiaries for certain information and documents. Xcel Energy’s utility subsidiaries are complying with the request.

      Midwest ISO Operations — In compliance with a condition in the January 2000 FERC order approving the Xcel Energy merger, NSP-Minnesota and NSP-Wisconsin entered into agreements to join the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) in August 2000. In December 2000, the FERC approved the Midwest ISO as the first approved regional transmission organization (RTO) in the United States, pursuant to FERC Order 2000. On Feb. 1, 2002, the Midwest ISO began interim operations, including regional transmission tariff administration services for the NSP-Minnesota and NSP-Wisconsin electric transmission systems. NSP-Minnesota and NSP-Wisconsin have received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and above) transmission systems to the Midwest ISO when the Midwest ISO is fully operational. The Midwest ISO will then control the operations of these facilities and the facilities of neighboring electric utilities.

      The Midwest ISO also submitted an application to the FERC for approval of the business combination of the Midwest ISO and the Southwestern Power Pool (SPP), of which SPS is a member. The FERC issued an order in December 2002, conditionally approving the proposed business combination. On Jan. 21, 2003, the Midwest ISO submitted a filing in compliance with the FERC’s December 2002 order, which required certain revisions to the tariff and related agreements. The Midwest ISO has requested that the FERC accept the revised Midwest ISO tariff and agreements to become effective on the day immediately following the consummation of the business combination between the Midwest ISO and the SPP. The Midwest ISO will be required to submit an application to the FERC under Section 203 of the Federal Power Act in order to effectuate the business combination with the SPP.

      In October 2001, the FERC issued an order in the separate proceeding to establish the initial Midwest ISO regional transmission tariff rates, ruling that all transmission services (with limited exceptions) in the Midwest ISO region must be subject to the Midwest ISO regional tariff and administrative surcharges to prevent discrimination between wholesale transmission service users. The FERC order unilaterally modified the agreement with the Midwest ISO signed in August 2000. The FERC order increased wholesale transmission costs to NSP-Minnesota and NSP-Wisconsin by up to $9 million per year.

      TRANSLink Transmission Co., LLC (TRANSLink) — In September 2001, Xcel Energy and several other electric utilities applied to the FERC to integrate operations of their electric transmission systems into a single system through the formation of TRANSLink, a for-profit, independent transmission-only company. The utilities will participate in TRANSLink through a combination of divestiture, leases and operating agreements. The applicants are: Alliant Energy’s Iowa company (Interstate Power and Light Co.), Corn Belt Power Cooperative, MidAmerican Energy Co., Nebraska Public Power District, Omaha Public Power District and Xcel Energy, on behalf of its operating utilities. The participants believe TRANSLink is the most cost-effective option available to manage transmission and to comply with regulations issued by the FERC in 1999, known as Order No. 2000, that require investor-owned electric utilities to transfer operational control of their transmission system to an independent RTO.

      Under the proposal, TRANSLink will be responsible for planning, managing and operating both local and regional transmission assets. TRANSLink also will construct and own new transmission system additions. TRANSLink will collect revenue for the use of Xcel Energy’s transmission assets through a FERC approved, regulated cost-of-service tariff and will collect its administrative costs through transmission rate surcharges. Transmission service pricing will continue to be regulated by the FERC, but construction and permitting approvals will continue to rest with regulators in the states served by TRANSLink. The participants also have entered into a memorandum of understanding with the Midwest ISO in which they agree that TRANSLink will contract with the Midwest ISO for certain other required RTO functions and services. In May 2002, the partners formed TRANSLink Development Co., LLC, which is responsible for pursuing the actions necessary to complete the regulatory approval of TRANSLink Transmission Co., LLC.

      In April 2002, the FERC gave conditional approval for the applicants to transfer ownership or operations of their transmission systems to TRANSLink and to form TRANSLink as an independent transmission company operating under the umbrella RTO organization of the Midwest ISO and a separate RTO in the

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West (once it is formed) for PSCo assets. The FERC conditioned TRANSLink’s approval on the resubmission of its tariff as a separate rate schedule to be administered by the Midwest ISO. TRANSLink Development Co. made this rate filing in October 2002. Eleven interveners had requested that the FERC clarify or reconsider elements of the TRANSLink decision. On Nov. 1, 2002, the FERC issued its order supporting the approval of the formation of TRANSLink. The FERC also clarified several issues covered in its April 2002 order. In December 2002, the FERC approved the TRANSLink rate schedule subject to refund, and required TRANSLink to engage in settlement discussions on several items. TRANSLink anticipates resolving these issues during the first quarter of 2003. In January 2003, the FERC also approved TRANSLink’s contractual relationship with the Midwest ISO. This contract delineates the role that TRANSLink will have within the RTO. Finally, in January 2003, TRANSLink also identified its nine member independent Board of Directors. The establishment of an independent board is required to satisfy FERC Order No. 2000 obligations. Several state approvals would be required to implement the proposal, as well as SEC approval. State applications were made in late 2002 and early 2003. Subject to receipt of required regulatory approvals, TRANSLink is expected to begin operations in the third quarter of 2003.

      Standards of Conduct Rulemaking — In October 2001, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the electric transmission and wholesale electric functions of the utility subsidiaries and the rules governing natural gas transportation and wholesale gas supply functions. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and could materially increase operating costs of the utility subsidiaries. In May 2002, the FERC staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. No final rule has been issued.

      Standard Market Design Rulemaking — In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design Rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale electric supply markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring that individual participants do not exercise unlawful market power. The FERC recently extended the comment period, but anticipates that the final rules will be in place in 2003 and the contemplated market changes will take place in 2003 and 2004. However, recent FERC actions indicate the schedule for the final rules may be delayed.

     NSP-Minnesota

      Minnesota Restructuring — In 2001, the Minnesota Legislature passed an energy security bill that included provisions intended to streamline the siting process of new generation and transmission facilities. It also included voluntary benchmarks for achieving renewable energy as a portion of the utility supply portfolio. There was no further action on restructuring in 2002. There is unlikely to be any further action on restructuring in 2003.

      North Dakota Restructuring — In 1997, the North Dakota Legislature established, by statute, an Electric Utility Competition Committee (EUC). The EUC was given six years to perform its research and submit its final report on restructuring, competition, and service territory reforms. To date, the committee has focused on the study of the state’s current tax treatment of the electric utility industry, primarily in the transmission and distribution functions. The report presented to the legislative council in early 2001 did not include recommendations to change the current tax structure. However, the legislature, without recommendation from the EUC, modified the coal severance and coal conversion taxes primarily to improve the competitive status of

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North Dakota lignite for generation. During 2002, the committee continued its review and presented legislation to the legislative assembly in January 2003. No legislation resulted from the review.

      TRANSLink — In December 2002, NSP-Minnesota filed for MPUC approval to transfer functional control of the Company’s electric transmission system to TRANSLink, of which, NSP-Minnesota would be a participant, and related approvals. The proposal would allow NSP-Minnesota to more cost-effectively comply with 1999 FERC rules regarding independent transmission operations, known as Order No. 2000. NSP-Minnesota requested approval by early second quarter 2003 so TRANSLink could commence operations in third quarter 2003. A similar filing was submitted to the NDPSC in early January 2003. MPUC and NDPSC action is pending.

     NSP-Wisconsin

      Wisconsin Restructuring — The state of Wisconsin passed legislation in 2001 that reduced the wholesale gross receipts tax on the sale of electricity by 50 percent starting in 2003. This legislation eliminates the double taxation on wholesale sales from non-utility generators, and should encourage the development of merchant plants by making sales from independent power producers more competitive. Additional legislation was passed that enables regulated utilities to enter into leased generation contracts with unregulated generation affiliates. The new legislation provides utilities a new financing mechanism and option to meet their customers’ energy needs. In 2002, the PSCW approved the first power plant proposal utilizing the new leased generation contract arrangement. While industry-restructuring changes continue in Wisconsin, the movement towards retail customer choice has virtually stopped.

      Michigan Restructuring — Since Jan. 1, 2002, NSP-Wisconsin has been providing its Michigan electric customers with the opportunity to select an alternative electric energy provider. This action was required by Michigan’s “Customer Choice and Electricity Reliability Act,” which became law in June 2002. NSP-Wisconsin developed and successfully implemented internal procedures, and obtained MPSC approval for these procedures to meet the Jan. 1, 2002 deadline. Key elements of internal procedures include the development of retail open access tariffs and unbundled billing, environmental and fuel disclosure information, and a code of conduct compliance plan. To date, none of the NSP-Wisconsin retail electric customers have converted to a competing supplier.

      TRANSLink — In November 2002, NSP-Wisconsin filed for PSCW approval to transfer functional control of the Company’s electric transmission system to the TRANSLink, of which, NSP-Wisconsin would be a participant, and related approvals. The proposal would allow NSP-Wisconsin to more cost-effectively comply with FERC Order No. 2000 and Wisconsin statutes mandating independent transmission operations. NSP-Wisconsin requested approval by the end of first quarter 2003 so TRANSLink could commence operations in third quarter 2003. PSCW action is pending after submission of supportive comments by intervenors. A similar filing is not required in the Michigan jurisdiction.

     PSCo

      Colorado Restructuring — There was no legislative action with respect to restructuring in Colorado during the 2000, 2001 or 2002 legislative sessions. None is expected in 2003.

     SPS

      New Mexico Restructuring — In March 2001, the state of New Mexico enacted legislation that delayed customer choice until 2007 and amended the Electric Utility Restructuring Act of 1999. In 2001, SPS requested recovery of its costs incurred to prepare for customer choice in New Mexico of approximately $5.1 million. A decision on this and other matters is pending before the NMPRC. SPS expects to receive future regulatory recovery of these costs.

      Texas Restructuring — In June 2001, the Governor of Texas signed legislation postponing the deregulation and restructuring of SPS until at least 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (SB-7), which provided for retail electric competition beginning January 2002. Under the amended

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legislation, prior PUCT orders issued in connection with the restructuring of SPS are considered null and void. SPS’ restructuring and rate unbundling proceedings in Texas have been terminated. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7.

      In December 2001, SPS filed an application with the PUCT to recover $20.3 million in costs related to transition to retail competition from the Texas retail customers. The filing was amended in March 2002 to reduce the recoverable costs by $7.3 million, which were associated with over-earnings for the calendar year 1999. The PUCT approved SPS using the 1999 over-earnings to offset the claims for reimbursement of transition to competition costs. This reduced the requested net collection in Texas to $13.0 million. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million began in July 2002.

      For more information on restructuring in Texas and New Mexico, see Note 10 to the Consolidated Financial Statements.

      Kansas Restructuring — During the 2001 legislative session, several restructuring related bills were introduced for consideration by the state legislature but to date, there is no restructuring mandate in Kansas.

      Oklahoma Restructuring — The Electric Restructuring Act of 1997 was enacted in Oklahoma during 1997. This legislation directed a series of studies to define the orderly transition to consumer choice of electric energy supplier by July 1, 2002. In 2001, Senate Bill 440 (SB-440) was signed into law to formally delay electric restructuring until restructuring issues could be studied further and new enabling legislation could be enacted. SB-440 established the Electric Restructuring Advisory Committee. The Advisory Committee submitted a report to the Governor and Legislature on Dec. 31, 2001. During 2002, there was no action taken by the Legislature as a result of this report. Oklahoma continues to delay retail competition.

      TRANSLink — In November and December 2002, SPS filed for PUCT and NMPRC approval to transfer functional control of the Company’s electric transmission system to TRANSLink, of which, SPS would be a participant, and related approvals. The proposal would allow SPS to more cost-effectively comply with FERC Order No. 2000. SPS requested approval by early second quarter 2003 so TRANSLink could commence operations in third quarter 2003. PUCT and NMPRC action is pending.

Capacity and Demand

      Assuming normal weather during 2003, system peak demand and the net dependable system capacity for Xcel Energy’s electric utility subsidiaries are projected below. The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin are managed as an integrated system (referred to as the NSP System). The system peak demand for each of the last three years and the forecast for 2003 are listed below.

                                 
System Peak Demand

Operating Company 2000 2001 2002 2003 Forecast





(in megawatts)
NSP System
    7,936       8,344       8,259       8,090  
PSCo.
    5,406       5,644       5,872       5,947  
SPS
    3,870       4,080       4,018       4,052  

      The peak demand for all systems typically occurs in the summer. The 2002 system peak demand for the NSP System occurred on July 30, 2002. The 2002 system peak demand for PSCo occurred on July 18, 2002. The 2002 system peak demand for SPS occurred on Aug. 1, 2002.

Energy Sources

      Xcel Energy’s utility subsidiaries expect to use the following resources to meet their net dependable system capacity requirements: 1) Xcel Energy utility subsidiary electric generating stations, 2) purchases from

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other utilities, independent power producers and power marketers, 3) demand-side management options, and 4) phased expansion of existing generation at select power plants.

     Purchased Power

      Xcel Energy’s electric utility subsidiaries have contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in kilowatts or megawatts, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in kilowatt-hours or megawatt-hours, is a measure of the amount of electricity produced from a particular generating source over a period of time. Purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

      The utility subsidiaries of Xcel Energy also make short-term and non-firm purchases to replace generation from company owned units that are unavailable due to maintenance and unplanned outages, to provide each utility’s reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including company owned generation and/or long-term purchase power contracts, and for various other operating requirements.

     NSP System Resource Plan

      In December 2002, NSP-Minnesota filed its Resource Plan with the MPUC for 2003 to 2017. The plan describes how Xcel Energy intends to meet the energy needs of the NSP System. The plan presented conservation programs to reduce NSP System’s peak demand and conserve overall electricity use, an approximate schedule of power purchase solicitations to meet increasing demand, and programs and plans to maintain the reliable operations of existing resources. In summary, the plan includes the following elements:

  •  forecasts 1.7 percent annual growth in the NSP System’s energy and peak demand requirements;
 
  •  outlines NSP System’s demand side management and conservation programs;
 
  •  identifies various pending legislative and regulatory proceedings affecting over half of the generating capacity necessary to meet the demand for electricity;
 
  •  proposes additional power purchase solicitations to meet growing demand for electricity; and
 
  •  updates the status of spent nuclear fuel at the Prairie Island plant and at the Monticello plant and describes the alternatives to replace nuclear generation if the two plants must be replaced as the result of spent nuclear fuel storage limitations.

      The MPUC will receive comments on the plan in the coming months and act to approve, modify, or reject the plan late in the year. NSP-Minnesota has requested that the Minnesota Legislature address the issues of spent nuclear fuel storage limitations and their effect on the future of nuclear generation in Minnesota in the 2003 legislative session.

 
      PSCo Resource Plan

      PSCo estimates it will purchase approximately 31 percent of its total electric system energy input for 2003. Approximately 44 percent of the total system capacity for the summer 2003 system peak demand for PSCo will be provided by purchased power.

      To meet the demand and energy needs of the rapidly growing economy in Colorado, PSCo completed a solicitation process that will add approximately 1,800 megawatts of resources to its system over the 2002-2005 time period.

 
      Purchased Transmission Services

      Xcel Energy’s electric utility subsidiaries have contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers (retail and wholesale

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load obligations with terms of more than one year). Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered. Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

Fuel Supply and Costs

      The following tables show the delivered cost per million British thermal units (MMBtu) of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel, and the total weighted average cost of all fuels during such years.

                                         
Coal* Nuclear


Average
NSP System Generating Plants Cost Percent Cost Percent Fuel Cost






2002
  $ 0.96       59 %   $ 0.46       38 %   $ 0.81  
2001
    0.96       62       0.47       35       0.86  
2000
    1.11       60       0.45       36       0.91  


Includes refuse-derived fuel and wood

                                         
Coal Gas


Average
PSCo Generating Plants Cost Percent Cost Percent Fuel Cost






2002
  $ 0.91       79 %   $ 2.25       21 %   $ 1.19  
2001
    0.86       84       4.27       16       1.41  
2000
    0.91       87       3.97       13       1.30  
                                         
Coal Gas


Average
SPS Generating Plants Cost Percent Cost Percent Fuel Cost






2002
  $ 1.33       74 %   $ 3.27       26 %   $ 1.84  
2001
    1.40       69       4.35       31       2.31  
2000
    1.45       70       4.23       30       2.28  
 
      NSP-Minnesota and NSP-Wisconsin

      NSP-Minnesota and NSP-Wisconsin normally maintain between 30 and 45 days of coal inventory at each plant site. Estimated coal requirements at NSP-Minnesota’s major coal-fired generating plants are approximately 12 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 100 percent of 2003 coal requirements and up to 58 percent of their 2004 requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.

      NSP-Minnesota and NSP-Wisconsin expect that all of the coal they burn in 2003 will have a sulfur content of less than 1 percent. NSP-Minnesota and NSP-Wisconsin have contracts for a maximum of 38.4 million tons of low-sulfur coal for the next five years. The contracts are with two Montana coal suppliers and three Wyoming suppliers with expiration dates ranging between 2003 and 2007. NSP-Minnesota and NSP-Wisconsin could purchase approximately 42 percent of coal requirements in 2004 if spot prices are more favorable than contracted prices.

      NSP-Minnesota and NSP-Wisconsin’s current fuel oil inventory is adequate to meet anticipated 2003 requirements, and they also have access to the spot market to buy more oil, if needed.

      To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment, and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion, and enrichment. Current contracts are flexible and cover 100 percent of uranium, conversion and enrichment requirements through the year 2005. These contracts expire at varying times between 2003 and 2006. The overlapping

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nature of contract commitments will allow NSP-Minnesota to maintain 50 percent to 100 percent coverage beyond 2002. NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Fuel fabrication is 100 percent committed through 2004 and 30 percent through 2010.
 
      PSCo

      PSCo’s primary fuel for its steam electric generating stations is low-sulfur western coal. PSCo’s coal requirements are purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2002, PSCo’s coal requirements for existing plants were approximately 10.1 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at Dec. 31, 2002 were approximately 47 days usage, based on the average burn rate for all of PSCo’s coal-fired plants.

      PSCo operates the Hayden Station, and has partial ownership in the Craig Station in Colorado. All of Hayden Station’s generating requirements are supplied under a long-term agreement. Approximately 75 percent of PSCo’s Craig Station coal requirements are supplied by two long-term agreements. Any remaining Craig Station requirements for PSCo are supplied via spot coal purchases.

      PSCo has secured more than 75 percent of Cameo Station’s coal requirements for 2003. Any remaining requirements may be purchased from this contract or the spot market. PSCo has contracted for coal supplies to supply approximately 100 percent of the Cherokee and Valmont Stations’ projected requirements in 2003.

      PSCo has long-term coal supply agreements for the Pawnee and Comanche Stations’ projected requirements. Under the long-term agreements, the supplier has dedicated specific coal reserves at the contractually defined mines to meet the contract quantity obligations. In addition, PSCo has a coal supply agreement to supply approximately 85 percent of Arapahoe Station’s projected requirements for 2003. Any remaining Arapahoe Station requirements will be procured via spot market purchases.

      PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

 
      SPS

      SPS purchases all of its coal requirements for Harrington and Tolk electric generating stations from TUCO, Inc. in the form of crushed, ready-to-burn coal delivered to SPS’ plant bunkers. For the Harrington station, the coal supply contract expires in 2016 and the coal handling agreement expires in 2004. For the Tolk station, the coal supply contract expires in 2017 and the coal handling agreement expires in 2005. At Dec. 31, 2002, coal supplies at the Harrington and Tolk sites were approximately 44 and 53 days supply, respectively. TUCO has coal supply agreements to supply 100 percent of the projected requirements for 2003 for Harrington Station and Tolk Station. TUCO has long-term contracts for supply of coal in sufficient quantities to meet the primary needs of the Tolk station.

      SPS has a number of short- and intermediate-term contracts with natural gas suppliers operating in gas fields with long life expectancies in or near its service area. SPS also utilizes firm and interruptible transportation to minimize fuel costs during volatile market conditions and to provide reliability of supply. SPS maintains sufficient gas supplies under short- and intermediate-term contracts to meet all power plant requirements; however, due to flexible contract terms, approximately 50 percent of SPS’ gas requirements during 2002 were purchased under spot market agreements.

Trading Operations

      Xcel Energy’s utility subsidiaries conduct various trading operations, including the purchase and sale of electric energy. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of each utility subsidiary. Xcel Energy’s utility subsidiaries reduce commodity price and credit risks by using physical and financial instruments, to minimize commodity

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price and credit risk and hedge supplies and purchases. Optimizing the utility subsidiaries’ physical assets by engaging in short-term sales and purchase commitments results in lowering the cost of supply for our customers and the capturing of additional margins from non-traditional customers. The utility subsidiaries also use these trading operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances, and changes in fuel prices.

Nuclear Power Operations and Waste Disposal

      NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. 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.

      Nuclear power plant operation produces gaseous, liquid and solid radioactive substances. The discharge and handling of such substances are controlled by federal regulation. High-level radioactive substance includes used nuclear fuel. Low-level radioactive substance consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

      Low-Level Waste Disposal — Federal law places responsibility on each state for disposal of its low-level radioactive substance. Low-level radioactive substance from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed of at the Barnwell facility located in South Carolina (all classes of low-level substance), and the Clive facility located in Utah (class A low-level substance only). Chem Nuclear is the owner and operator of the Barnwell facility, which has been given authorization by South Carolina to accept low-level radioactive substance from out of state. Envirocare, Inc. operates the Clive facility. NSP-Minnesota and Barnwell currently operate under an annual contract, while NSP-Minnesota uses the Envirocare facility through various low-level substance processors. NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their licensed life, if off-site low-level disposal facilities were not available to NSP-Minnesota.

      High-Level Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act requires the Department of Energy (DOE) to implement a program for nuclear substance management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances at a permanent storage or disposal facility by 1998. The DOE has accepted none of NSP-Minnesota’s spent nuclear fuel. See Item 3 — Legal Proceedings and Note 14 to the Consolidated Financial Statements for further discussion of this matter.

      NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. NSP-Minnesota has expanded the used nuclear fuel storage facilities at its Monticello plant by replacement of the racks in the storage pool and by shipping 1,058 used fuel assemblies to a General Electric storage facility. The Monticello plant is expected to have sufficient pool storage capacity to the end of its current operating license in 2010.

      The Prairie Island plant is licensed by the federal Nuclear Regulatory Commission (NRC) to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota legislature adopted a limit on dry cask storage of 17 casks for the entire state. The 17 casks, which stand outside the Prairie Island plant, are now full, and under the current configuration the storage pool within the plant would be full by 2007. Prairie Island cannot operate beyond 2007 unless the existing spent fuel is moved or the storage capacity is increased. Because the 17-cask limit is a statewide limit, the Monticello plant cannot, under current state law, store spent fuel in dry casks. Monticello’s on-site storage pool is expected to be full in 2010. Monticello cannot operate beyond 2010 unless the existing spent fuel is moved or the storage capacity is increased.

      NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, Private Fuel Storage, LLC (PFS) filed a license application with the NRC for a national temporary storage site for spent nuclear fuel. The PFS will undertake the development, licensing, construction and operation of a storage facility on the Skull Valley Indian Reservation in Utah. The

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NRC license review process consists of formal evidentiary hearings and opportunity for public input. These Atomic Safety and Licensing Board (ASLB) hearings were completed in 2002, and all legal contentions have been resolved. The ASLB is expected to issue its recommendation on licensing the site to the NRC in the first quarter of 2003. The NRG is expected to rule on the license request during the second quarter of 2003. Storage cask certification efforts are continuing, with one cask vendor on track to meet the project goals. The interim used fuel storage facility could be operational and able to accept the first shipment of spent nuclear fuel by 2004. However, due to uncertainty regarding regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all.

      If the Prairie Island plant is to continue operating, legislative authorization of additional storage space is needed. If additional storage space for continued operations is not authorized, legislation may be needed to ensure timely implementation of a replacement alternative.

      NSP-Minnesota has developed viable replacement power options, including purchasing new coal or natural gas generation, and also reviewed the feasibility of supplementing new natural gas generation with additional wind turbines. These options have been presented to the 2003 legislature. Each option involves trade-offs between cost, emissions and operational impacts.

      Based on analysis of the options, NSP-Minnesota believes the most reliable, lowest cost, environmentally sound way to provide the needed 1,700 megawatts of energy is to continue to operate the nuclear power plants at Prairie Island and Monticello.

      Due to the investment decisions required to be made in conjunction with the continued efficient operation of the nuclear plants, as well as the time and cost involved to develop alternatives to the existing nuclear power generation, NSP-Minnesota believes a decision is necessary in 2003 by the Minnesota legislature whether the state will allow the continued use of nuclear power in the future. Prairie Island will only be able to continue operating beyond 2007 with legislative authorization of additional storage space.

      In February 2001, NSP-Minnesota signed a contract with Steam Generating Team, Ltd. to perform engineering and construction services for the installation of replacement generators at the Prairie Island nuclear power plant. NSP-Minnesota is evaluating the economics of replacing two steam generators on unit 1 at the plant. NSP-Minnesota is taking steps to preserve the replacement option for as early as 2004. The total cost of replacing the steam generators is estimated to be approximately $132 million.

      The NRC has issued a number of regulations, bulletins and orders that require analyses, modification and additional equipment at commercial nuclear power plants. The NRC is engaged in various ongoing studies and rulemaking activities that may impose additional requirements upon commercial nuclear power plants. Management is unable to predict any new requirements or their impact on NSP-Minnesota’s facilities and operations.

 
      Nuclear Management Co. (NMC)

      During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp., and Alliant Energy Corp. established NMC. The Consumers Power subsidiary of CMS Energy Corp. joined NMC during 2000, and transferred operating authority for the Palisades nuclear plant to NMC in 2001. The five affiliated companies own eight nuclear units on six sites, with total generation capacity exceeding 4,500 megawatts.

      The NRC has approved requests by NMC’s affiliated utilities to transfer operating authority for their nuclear plants to NMC, formally establishing NMC as an operating company. NMC manages the operations and maintenance at the plants, and is responsible for physical security. NMC’s responsibilities also include oversight of on-site dry storage facilities for used nuclear fuel at the Prairie Island nuclear plant. Utility plant owners, including Xcel Energy, continue to own the plants, control all energy produced by the plants, and retain responsibility for nuclear liability insurance and decommissioning costs. Existing personnel continue to provide day-to-day plant operations, with the additional benefit of sharing ideas and operating experience from all NMC-operated plants for improved safety, reliability and operational performance.

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      For further discussion of nuclear issues, see Notes 13 and 14 to the Consolidated Financial Statements.

Electric Operating Statistics (NSP-Minnesota)

                             
Year Ended December 31,

2002 2001 2000



Electric Sales (Millions of Kwh):
                       
 
Residential
    9,782       9,236       8,995  
 
Commercial and industrial
    23,818       23,697       23,535  
 
Public authorities and other
    274       282       280  
     
     
     
 
   
Total retail
    33,874       33,215       32,810  
 
Sales for resale
    4,945       6,100       6,764  
     
     
     
 
   
Total energy sold
    38,819       39,315       39,574  
     
     
     
 
Number of customers at end of period:
                       
 
Residential
    1,165,237       1,151,235       1,137,649  
 
Commercial and industrial
    139,779       137,267       134,216  
 
Public authorities and other
    5,740       5,577       5,408  
     
     
     
 
   
Total retail
    1,310,756       1,294,079       1,277,273  
 
Wholesale
    58       81       80  
     
     
     
 
   
Total customers
    1,310,814       1,294,160       1,277,353  
     
     
     
 
Electric revenues (Thousands of dollars):
                       
 
Residential
  $ 736,485     $ 735,683     $ 705,502  
 
Commercial and industrial
    1,204,371       1,288,679       1,245,267  
 
Public authorities and other
    30,442       32,759       27,218  
 
Regulatory accrual adjustment
    4,766       15,480        
     
     
     
 
   
Total retail
    1,976,064       2,072,601       1,977,987  
 
Wholesale
    109,147       163,147       179,770  
 
Sales to NSP-Wisconsin
    219,006       236,118       217,122  
 
Other electric revenues
    56,649       97,902       37,004  
     
     
     
 
   
Total electric revenues
  $ 2,360,866     $ 2,569,768     $ 2,411,883  
     
     
     
 
Kwh sales per retail customer
    25,843       25,667       25,688  
Revenue per retail customer
  $ 1,507.58     $ 1,601.60     $ 1,548.60  
Residential revenue per Kwh
    7.53¢       7.97¢       7.84¢  
Commercial and industrial revenue per Kwh
    5.06¢       5.44¢       5.29¢  
Wholesale revenue per Kwh
    2.21¢       2.67¢       2.66¢  

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Electric Operating Statistics (NSP-Wisconsin)

                             
Year Ended December 31,

2002 2001 2000



Electric sales (Millions of Kwh):
                       
 
Residential
    1,874       1,780       1,774  
 
Commercial and industrial
    3,846       3,755       3,786  
 
Public authorities and other
    40       39       40  
     
     
     
 
   
Total retail
    5,760       5,574       5,600  
 
Sales for resale
    564       527       473  
     
     
     
 
   
Total energy sold
    6,324       6,101       6,073  
     
     
     
 
Number of customers at end of period:
                       
 
Residential
    196,701       193,842       191,287  
 
Commercial and industrial
    34,224       33,627       33,075  
 
Public authorities and other
    1,107       1,092       1,047  
     
     
     
 
   
Total retail
    232,032       228,561       225,409  
 
Wholesale
    10       10       10  
     
     
     
 
   
Total customers
    232,042       228,571       225,419  
     
     
     
 
Electric revenues (Thousands of dollars):
                       
 
Residential
  $ 142,104     $ 135,351     $ 131,201  
 
Commercial and industrial
    207,979       202,699       195,298  
 
Public authorities and other
    5,387       4,576       4,450  
     
     
     
 
   
Total retail
    355,470       342,626       330,949  
 
Wholesale
    20,404       18,706       16,936  
 
Sales to NSP-Minnesota
    80,200       85,895       73,425  
 
Other electric revenues
    2,663       3,668       3,167  
     
     
     
 
   
Total electric revenues
  $ 458,737     $ 450,895     $ 424,477  
     
     
     
 
Kwh sales per retail customer
    24,824       24,387       24,843  
Revenue per retail customer
  $ 1,531.99     $ 1,499.06     $ 1,468.22  
Residential revenue per Kwh
    7.58¢       7.60¢       7.40¢  
Commercial and industrial revenue per Kwh
    5.41¢       5.40¢       5.16¢  
Wholesale revenue per Kwh
    3.62¢       3.55¢       3.58¢  

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Electric Operating Statistics (PSCo)

                             
Year Ended December 31,

2002 2001 2000



Electric sales (Millions of Kwh):
                       
 
Residential
    8,129       7,673       7,647  
 
Commercial and industrial
    17,408       17,223       17,033  
 
Public authorities and other
    277       229       252  
     
     
     
 
   
Total retail
    25,814       25,125       24,932  
 
Sales for resale
    8,701       11,110       9,148  
     
     
     
 
   
Total energy sold
    34,515       36,235       34,080  
     
     
     
 
Number of customers at end of period:
                       
 
Residential
    1,058,082       1,040,029       1,019,961  
 
Commercial and industrial
    139,573       136,671       133,947  
 
Public authorities and other(1)
    68,601       88,083       86,364  
     
     
     
 
   
Total retail
    1,266,256       1,264,783       1,240,272  
 
Wholesale
    171       159       96  
     
     
     
 
   
Total customers
    1,266,427       1,264,942       1,240,368  
     
     
     
 
Electric revenues (Thousands of dollars):
                       
 
Residential
  $ 585,035     $ 571,308     $ 558,153  
 
Commercial and industrial
    866,955       854,397       844,511  
 
Public authorities and other
    32,803       32,169       32,185  
     
     
     
 
   
Total retail
    1,484,793       1,457,874       1,434,849  
 
Wholesale
    355,713       896,805       577,226  
 
Other electric revenues
    38,364       (12,495 )     2,479  
     
     
     
 
   
Total electric revenues
  $ 1,878,870     $ 2,342,184     $ 2,014,554  
     
     
     
 
Kwh sales per retail customer
    20,386       19,865       20,102  
Revenue per retail customer
  $ 1,172.59     $ 1,152.67     $ 1,156.88  
Residential revenue per Kwh
    7.20¢       7.45¢       7.30¢  
Commercial and industrial revenue per Kwh
    4.98¢       4.96¢       4.96¢  
Wholesale revenue per Kwh
    4.09¢       8.07¢       6.31¢  


(1)  2001 and 2000 customers include 18,000 individual customers that subsequently became two incorporated municipalities in 2002.

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Electric Operating Statistics (SPS)

                             
Year Ended December 31,

2002 2001 2000



Electric sales (Millions of Kwh):
                       
 
Residential
    3,300       3,212       3,467  
 
Commercial and industrial
    12,044       12,404       12,383  
 
Public authorities and other
    549       549       608  
     
     
     
 
   
Total retail
    15,893       16,165       16,458  
 
Sales for resale
    9,045       8,367       9,898  
     
     
     
 
   
Total energy sold
    24,938       24,532       26,356  
     
     
     
 
Number of customers at end of period:
                       
 
Residential
    304,971       306,622       311,660  
 
Commercial and industrial
    75,676       74,761       74,343  
 
Public authorities and other
    5,615       5,786       5,705  
     
     
     
 
   
Total retail
    386,262       387,169       391,708  
 
Wholesale
    70       55       34  
     
     
     
 
   
Total customers
    386,332       387,224       391,742  
     
     
     
 
Electric revenues (Thousands of dollars):
                       
 
Residential
  $ 192,030     $ 236,931     $ 198,123  
 
Commercial and industrial
    462,556       595,788       458,719  
 
Public authorities and other
    29,104       21,318       30,275  
     
     
     
 
   
Total retail
    683,690       854,037       687,117  
 
Wholesale
    287,768       439,817       393,502  
 
Other electric revenues(1)
    53,720       91,604       (1,039 )
     
     
     
 
   
Total electric revenues
  $ 1,025,178     $ 1,385,458     $ 1,079,580  
     
     
     
 
Kwh sales per retail customer
    41,146       41,752       42,013  
Revenue per retail customer
  $ 1,770.02     $ 2,205.85     $ 1,754.16  
Residential revenue per Kwh
    5.82¢       7.38¢       5.72¢  
Commercial and industrial revenue per Kwh
    3.84¢       4.80¢       3.70¢  
Wholesale revenue per Kwh
    3.18¢       5.26¢       3.98¢  


(1)  Other electric revenues is negative in 2000 primarily due to an increased provision for rate refunds.

GAS UTILITY OPERATIONS

Competition and Industry Restructuring

      In the early 1990’s, the FERC issued Order No. 636, which mandated the unbundling of interstate natural gas pipeline services, including sales, transportation, storage and ancillary services. The implementation of Order No. 636 has resulted in additional pressure on all local distribution companies (LDCs) to keep gas supply and transmission prices for their large customers competitive. Customers have greater ability to buy gas directly from suppliers and arrange their own pipeline and LDC transportation service. Changes in regulatory policies and market forces have shifted the industry from traditional bundled gas sales service to an unbundled transportation and market-based commodity service.

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      The natural gas delivery/ transportation business has remained competitive as industrial and large commercial customers have the ability to bypass the local gas utility through the construction of interconnections directly with, and the purchase of gas from, interstate pipelines, thereby avoiding the delivery charges added by the local gas utility.

      As LDC’s, NSP-Minnesota, NSP-Wisconsin and PSCo provide transportation service to large customers. Transportation service does not have an adverse effect on earnings because the sales and transportation rates have been designed to produce the same profit margin. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDC’s distribution system.

      The Colorado Legislature passed legislation in 1999 that provides the CPUC the authority and responsibility to approve voluntary unbundling plans submitted by Colorado gas utilities in the future. PSCo has not filed a plan to further unbundle its gas service to all residential and commercial customers and continues to evaluate its business opportunities for doing so.

Capability and Demand

     NSP-Minnesota and NSP-Wisconsin

      Xcel Energy categorizes its gas supply requirements as firm or interruptible (customers with an alternate energy supply). The maximum daily send out (firm and interruptible) for the combined system of NSP-Minnesota and NSP-Wisconsin was 650,641 MMBtu for 2002, which occurred on Jan. 2, 2002.

      NSP-Minnesota and NSP-Wisconsin purchase gas from independent suppliers. The gas is delivered under gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 640,000 MMBtu/day. In addition, NSP-Minnesota and NSP-Wisconsin have contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 15 percent of winter season and 23 percent of peak daily, firm requirements of NSP-Minnesota and NSP-Wisconsin.

      NSP-Minnesota and NSP-Wisconsin also own and operate two liquefied natural gas (LNG) plants with a storage capacity of 2.5 Billion cubic feet (Bcf) equivalent and four propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 32 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days and can be used to minimize daily imbalance fees on interstate pipelines.

      NSP-Minnesota and NSP-Wisconsin are required to file for a change in gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or exchange one form of demand for another. In October 2001, the MPUC approved NSP’s 2000-2001 entitlement levels, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA. NSP-Minnesota’s 2001-2002 entitlement levels were approved on April 3, 2002. The 2002-2003 entitlement levels are pending MPUC action. NSP-Wisconsin’s winter 2002-2003 Supply Plan was approved by the PSCW in October 2002.

     PSCo

      PSCo projects peak day gas supply requirements for firm sales and backup transportation (transportation customers contracting for firm supply backup) to be approximately 1,756,000 MMBtu. In addition, firm transportation customers hold 451,000 MMBtu of capacity without supply backup. Total firm delivery obligation for PSCo is 2,206,870 MMBtu per day. The maximum daily delivery for 2002 (firm and interruptible services) was 1,652,459 MMBtu on Feb. 25, 2002.

      PSCo purchases gas from independent suppliers. The gas supplies are delivered to the respective delivery systems through a combination of transportation agreements, with interstate pipelines and deliveries by suppliers directly to each company. These agreements provide for firm deliverable pipeline capacity of

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approximately 1,220,000 MMBtu/day, which includes 797,000 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company owned underground storage facilities, which provide about 38,000 MMBtu of gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at the companies’ city gate meter stations and a small amount received directly from wellhead sources.

      PSCo has received approval to close one of its three storage facilities, Leyden Storage Field. The field’s 110,000 MMBtu peak day capacity was replaced with additional third-party storage and transportation capacity. See further discussion at Note 13 to the Consolidated Financial Statements.

      PSCo is required by CPUC regulations to file a gas purchase plan by June of each year projecting and describing the quantities of gas supplies, upstream services and the costs of those supplies and services for the period beginning July 1 through June 30 of the following year. PSCo is also required to file a gas purchase report by October of each year reporting actual quantities and costs incurred for gas supplies and upstream services for the 12-month period ending the previous June 30.

Gas Supply and Costs

      Xcel Energy’s utility subsidiaries actively seek gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources, with varied contract lengths.

      The following table summarizes the average cost per MMBtu of gas purchased for resale by Xcel Energy’s regulated retail gas distribution business:

                         
NSP-Minnesota NSP-Wisconsin PSCo



2002
  $ 3.98     $ 4.63     $ 3.17  
2001
  $ 5.83     $ 5.11     $ 4.99  
2000
  $ 4.56     $ 4.71     $ 4.48  

      The cost of gas supply, transportation service and storage service is recovered through various cost recovery adjustment mechanisms.

     NSP-Minnesota and NSP-Wisconsin

      NSP-Minnesota and NSP-Wisconsin have firm gas transportation contracts with several pipelines, which expire in various years from 2003 through 2014. Approximately 80 percent of NSP-Minnesota and NSP-Wisconsin’s retail gas customers needs are supplied from the Northern Natural pipeline system.

      NSP-Minnesota and NSP-Wisconsin have certain gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in lieu of delivery. At Dec. 31, 2002, NSP-Minnesota and NSP-Wisconsin were committed to approximately $267.7 million in such obligations under these contracts, which expire in various years from 2003 through 2014.

      NSP-Minnesota and NSP-Wisconsin purchase firm gas supply utilizing long-term and short-term agreements from approximately 37 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota and NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

     PSCo

      PSCo has certain gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in lieu of delivery. At Dec. 31, 2002, PSCo was committed to approximately $906.3 million in such obligations under these contracts, which expire in various years from 2003 through 2025.

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      PSCo has attempted to maintain low-cost, reliable natural gas supplies by optimizing a balance of long-term and short-term gas purchases, firm transportation and gas storage contracts. PSCo also utilizes a mixture of fixed-price purchases and index-related purchases to provide a less volatile, yet market sensitive, price to its customers. During 2002, PSCo purchased natural gas from approximately 44 suppliers.

Gas Operating Statistics (NSP-Minnesota)

                             
Year Ended December 31,

2002 2001 2000



Gas deliveries (Thousands of Dth):
                       
 
Residential
    38,407       36,880       38,461  
 
Commercial and industrial
    38,320       38,346       41,257  
 
Other
    1,286       2,058       1,225  
     
     
     
 
   
Total retail
    78,013       77,284       80,943  
 
Transportation and other
    8,559       11,204       9,510  
     
     
     
 
   
Total deliveries
    86,572       88,488       90,453  
     
     
     
 
Number of customers at end of period:
                       
 
Residential
    393,538       384,965       371,894  
 
Commercial and industrial
    37,445       36,311       35,381  
     
     
     
 
   
Total retail
    430,983       421,276       407,275  
 
Transportation and other
    42       74       51  
     
     
     
 
   
Total customers
    431,025       421,350       407,326  
     
     
     
 
Gas revenues (Thousands of dollars):
                       
 
Residential
  $ 263,178     $ 323,611     $ 285,868  
 
Commercial and industrial
    199,196       258,803       227,414  
 
Other
    1       166       1,569  
     
     
     
 
   
Total retail
    462,375       582,580       514,851  
 
Transportation and other
    27,197       42,926       21,849  
     
     
     
 
   
Total gas revenues
  $ 489,572     $ 625,506     $ 536,700  
     
     
     
 
Dth sales per retail customer
    181.01       183.45       198.74  
Revenue per retail customer
  $ 1,072.84     $ 1,382.89     $ 1,264.14  
Residential revenue per Dth
  $ 6.85     $ 8.77     $ 7.43  
Commercial and industrial revenue per Dth
  $ 5.20     $ 6.75     $ 5.51  
Transportation and other revenue per Dth
  $ 3.18     $ 3.83     $ 2.30  

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Gas Operating Statistics (NSP-Wisconsin)

                             
Year Ended December 31,

2002 2001 2000



Gas deliveries (Thousands of Dth):
                       
 
Residential
    6,720       5,554       6,281  
 
Commercial and industrial
    11,800       11,479       11,544  
 
Other
    722       1,415       868  
     
     
     
 
   
Total retail
    19,242       18,448       18,693  
 
Transportation and other
    1,413       1,399       1,353  
     
     
     
 
   
Total deliveries
    20,655       19,847       20,046  
     
     
     
 
Number of customers at end of period:
                       
 
Residential
    81,252       79,027       75,449  
 
Commercial and industrial
    11,140       11,002       10,626  
     
     
     
 
   
Total retail
    92,392       90,029       86,075  
 
Transportation and other
    5       5        
     
     
     
 
   
Total customers
    92,397       90,034       86,075  
     
     
     
 
Gas revenues (Thousands of dollars):
                       
 
Residential
  $ 49,426     $ 51,049     $ 49,156  
 
Commercial and industrial
    52,223       69,084       58,249  
 
Other
          2,102       1,946  
     
     
     
 
   
Total retail
    101,649       122,235       109,351  
 
Transportation and other
    494       818       672  
     
     
     
 
   
Total gas revenues
  $ 102,143     $ 123,053     $ 110,023  
     
     
     
 
Dth sales per retail customer
    208.27       204.91       217.17  
Revenue per retail customer
  $ 1,100.19     $ 1,357.73     $ 1,270.42  
Residential revenue per Dth
  $ 7.36     $ 9.19     $ 7.83  
Commercial and industrial revenue per Dth
  $ 4.43     $ 6.02     $ 5.05  
Transportation and other revenue per Dth
  $ 0.35     $ 0.58     $ 0.50  

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Gas Operating Statistics (PSCo)

                             
Year Ended December 31,

2002 2001 2000



Gas deliveries (Thousands of Dth):
                       
 
Residential
    95,882       91,389       90,270  
 
Commercial and industrial
    43,449       45,036       41,165  
     
     
     
 
   
Total retail
    139,331       136,425       131,435  
 
Transportation and other
    120,626       122,513       117,992  
     
     
     
 
   
Total deliveries
    259,957       258,938       249,427  
     
     
     
 
Number of customers at end of period:
                       
 
Residential
    1,063,378       1,032,529       1,001,951  
 
Commercial and industrial
    96,669       95,879       94,516  
     
     
     
 
   
Total retail
    1,160,047       1,128,408       1,096,467  
 
Transportation and other
    3,134       2,967       3,173  
     
     
     
 
   
Total customers
    1,163,181       1,131,375       1,099,640  
     
     
     
 
Gas revenues (Thousands of dollars):
                       
 
Residential
  $ 510,890     $ 832,320     $ 526,409  
 
Commercial and industrial
    192,419       366,048       208,589  
     
     
     
 
   
Total retail
    703,309       1,198,368       734,998  
Transportation and other
    46,046       53,173       52,112  
     
     
     
 
   
Total gas revenues
  $ 749,355     $ 1,251,541     $ 787,110  
     
     
     
 
Dth sales per retail customer
    120.11       120.90       119.87  
Revenue per retail customer
  $ 606.28     $ 1,060.20     $ 670.33  
Residential revenue per Dth
  $ 5.33     $ 9.11     $ 5.83  
Commercial and industrial revenue per Dth
  $ 4.43     $ 8.13     $ 5.07  
Transportation and other revenue per Dth
  $ 0.38     $ 0.43     $ 0.44  

ENVIRONMENTAL MATTERS

      Certain of Xcel Energy’s utility subsidiary facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy’s utility subsidiaries have received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

      Xcel Energy and its utility subsidiaries strive to comply with all environmental regulations applicable to their operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon their operations. For more information on environmental contingencies, see Note 13 to the Consolidated Financial Statements.

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EMPLOYEES

      The number of Xcel Energy utility subsidiary employees on Dec. 31, 2002 is presented in the following table. Of the employees listed in the table, 5,615 or 55 percent, are covered under collective bargaining agreements. See Note 9 to the Consolidated Financial Statements for further discussion. Xcel Energy Services, Inc. employees provide service to Xcel Energy’s utility subsidiaries.

         
NSP-Minnesota
    2,963  
NSP-Wisconsin
    550  
PSCo
    2,625  
SPS
    1,071  
Xcel Energy Services, Inc.
    2,965  

Item 2.     Properties

      Virtually all of the utility plant of NSP-Minnesota, NSP-Wisconsin, and PSCo is subject to the lien of their first mortgage bond indentures.

      Electric utility generating stations:

NSP-Minnesota

                     
Summer 2002
Net Dependable
Station, City and Unit Fuel Installed Capability (Mw)




 
Sherburne — Becker, Minn.
               
   
Unit 1
  Coal   1976     706  
   
Unit 2
  Coal   1977     689  
   
Unit 3(a)
  Coal   1987     507  
 
Prairie Island — Welch, Minn.
               
   
Unit 1
  Nuclear   1973     522  
   
Unit 2
  Nuclear   1974     522  
 
Monticello — Monticello, Minn
  Nuclear   1971     578  
 
King — Bayport, Minn
  Coal   1968     529  
 
Black Dog — Burnsville, Minn.
               
   
2 Units
  Coal/Natural Gas   1955 - 1960     278  
   
2 Units
  Natural Gas   2002     260  
 
High Bridge — St. Paul, Minn.
               
   
2 Units
  Coal   1956 - 1959     267  
 
Riverside — Minneapolis, Minn.
               
   
2 Units
  Coal   1964 - 1987     374  
 
Angus Anson — Sioux Falls, S.D.
               
   
2 Units
  Natural Gas   1994     217  
 
Inver Hills — Inver Grove Heights, Minn.
               
   
6 Units
  Natural Gas   1972     306  
 
Blue Lake — Shakopee, Minn.
               
   
4 Units
  Natural Gas   1974     160  
 
Other
  Various   Various     323  
             
 
Total     6,238  
     
 


(a)  Based on NSP-Minnesota’s ownership interest of 59 percent.

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NSP-Wisconsin

                       
Summer 2002
Net Dependable
Station, City and Unit Fuel Installed Capability (Mw)




 
Combustion Turbine:
               
   
Flambeau Station — Park Falls, Wis.
               
     
1 Unit
  Natural Gas/Oil   1969     12  
   
Wheaton — Eau Claire, Wis.
               
     
6 Units
  Natural Gas/Oil   1973     345  
   
French Island — La Crosse, Wis.
               
     
2 Units
  Oil   1974     142  
 
Steam:
               
   
Bay Front — Ashland, Wis.
               
     
3 Units
  Coal/Wood/Natural Gas   1945 - 1960     76  
   
French Island — La Crosse, Wis.
               
     
2 Units
  Wood/RDF*   1940 - 1948     27  
 
Hydro:
               
     
19 Plants
      Various     249  
             
 
Total     851  
     
 


RDF is refuse-derived fuel, made from municipal solid waste.

PSCo

                     
Summer 2002 Net
Dependable
Station, City and Unit Fuel Installed Capability (Mw)




Steam:
               
 
Arapahoe — Denver, Colo.
               
   
2 Units
  Coal   1950 - 1955     156  
 
Cameo — Grand Junction, Colo.
               
   
2 Units
  Coal   1957 - 1960     73  
 
Cherokee — Denver, Colo.
               
   
4 Units
  Coal   1957 - 1968     717  
 
Comanche — Pueblo, Colo.
               
   
2 Units
  Coal   1973 - 1975     660  
 
Craig — Craig, Colo.
               
   
2 Units
  Coal   1979 - 1980     83 (a)
 
Hayden — Hayden, Colo.
               
   
2 Units
  Coal   1965 - 1976     237 (b)
 
Pawnee — Brush, Colo.
  Coal   1981     505  
 
Valmont — Boulder, Colo.
  Coal   1964     186  
 
Zuni — Denver, Colo.
               
   
3 Units
  Natural Gas/Oil   1948 - 1954     107  

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Table of Contents

                       
Summer 2002 Net
Dependable
Station, City and Unit Fuel Installed Capability (Mw)




 
Combustion Turbines:
               
   
Fort St. Vrain — Platteville, Colo.
               
     
4 Units
  Natural Gas   1972 - 2001     690  
   
Various Locations
               
     
6 Units
  Natural Gas   Various     171  
 
Hydro:
               
   
Various Locations
               
     
12 Units
      Various     32  
   
Cabin Creek — Georgetown, Colo.
      1967     210  
     
Pumped Storage
               
 
Wind:
               
   
Ponnequin — Weld County, Colo.
      1999 - 2001      
 
Diesel Generators:
               
   
Cherokee — Denver, Colo.
               
     
2 Units
      1967     6  
             
 
Total     3,833  
     
 


(a)  Based on PSCo’s ownership interest of 9.72 percent.
 
(b)  Based on PSCo’s ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit 2.

SPS

                     
Summer 2002 Net
Dependable
Station, City and Unit Fuel Installed Capability (Mw)




Steam:
               
 
Harrington — Amarillo, Texas
               
   
3 Units
  Coal   1976 - 1980     1,066  
 
Tolk — Muleshoe, Texas
               
   
2 Units
  Coal   1982 - 1985     1,080  
 
Jones — Lubbock, Texas
               
   
2 Units
  Natural Gas   1971 - 1974     486  
 
Plant X — Earth, Texas
               
   
4 Units
  Natural Gas   1952 - 1964     442  
 
Nichols — Amarillo, Texas
               
   
3 Units
  Natural Gas   1960 - 1968     457  
 
Cunningham — Hobbs, N.M.
               
   
2 Units
  Natural Gas   1957 - 1965     267  
 
Maddox — Hobbs, N.M. 
  Natural Gas   1983     118  
 
CZ-2-Pampa, Texas
  Purchased Steam   1979     26  
 
Moore County — Amarillo, Texas
  Natural Gas   1954     48  

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Table of Contents

                       
Summer 2002 Net
Dependable
Station, City and Unit Fuel Installed Capability (Mw)




 
Gas Turbine:
               
     
Carlsbad — Carlsbad, N.M. 
  Natural Gas   1977     13  
     
CZ-1-Pampa, Texas
  Hot Nitrogen   1965     13  
     
Maddox — Hobbs, N.M. 
  Natural Gas   1983     65  
     
Riverview — Electric City, Texas
  Natural Gas   1973     23  
     
Cunningham — Hobbs, N.M. 
  Natural Gas   1998     220  
 
Diesel:
               
   
Tucumcari — N.M.
               
     
6 Units
      1941 - 1968      
             
 
Total     4,324  
     
 

      Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2002:

                                 
Conductor Miles NSP-Minnesota NSP-Wisconsin PSCo SPS





500 kilovolt (kv)
    2,919                    
345 kv
    5,653       1,312       529       2,735  
230 kv
    1,440             10,005       8,998  
161 kv
    298       1,331              
138 kv
                92        
115 kv
    6,162       1,528       4,789       8,837  
Less than 115 kv
    78,316       31,063       57,346       15,477  

      Electric utility transmission and distribution substations at Dec. 31, 2002:

                                 
Quantity NSP-Minnesota NSP-Wisconsin PSCo SPS





      360       205       209       492  

      Gas utility mains at Dec. 31, 2002:

                                 
Miles NSP-Minnesota NSP-Wisconsin PSCo SPS





Transmission
    115             2,263        
Distribution
    8,608       1,929       18,114        

Item 3. Legal Proceedings

      In the normal course of business, various lawsuits and claims have arisen against the utility subsidiaries of Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

     NSP-Minnesota

      Department of Energy Complaint — On June 8, 1998, NSP-Minnesota filed a complaint in the Court of Federal Claims against the DOE requesting damages in excess of $1 billion for the DOE’s partial breach of the Standard Contract. NSP-Minnesota requested damages consisting of the costs of storage of spent nuclear fuel at the Prairie Island nuclear generating plant, anticipated costs related to the Private Fuel Storage, LLC and costs relating to the 1994 state legislation limiting the number of casks that can be used to store spent nuclear fuel at Prairie Island. On April 6, 1999, the Court of Federal Claims dismissed NSP-Minnesota’s complaint. On May 20, 1999, NSP-Minnesota appealed to the Court of Appeals for the Federal Circuit. On Aug. 31, 2000, the Court of Appeals for the Federal Circuit reversed and remanded to the Court of Federal Claims. On Dec. 26, 2000, NSP-Minnesota filed a motion with the Court of Federal Claims to amend its

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complaint and renew its motion for summary judgment on the DOE’s liability. On July 31, 2001, the Court of Federal Claims granted NSP-Minnesota’s motion for summary judgment on liability. On Nov. 28, 2001, the DOE brought a motion of partial summary judgment on the schedule for acceptance of spent nuclear fuel and on Nov. 27, 2001 the DOE’s obligation to accept greater than Class C waste. These motions are pending. Limited discovery with respect to the schedule issues has been conducted. A trial in NSP-Minnesota’s suit against the DOE is not likely to occur before the second quarter of 2003.

      Light Rail Lawsuit — In February 2001, NSP-Minnesota filed a lawsuit in the federal district court in Minneapolis seeking reimbursement of costs for relocating electric utility lines to allow for construction of a light rail transit (LRT) line in downtown Minneapolis. In May 2001, the Minnesota Department of Transportation and the Metropolitan Council (Defendants) obtained a preliminary injunction requiring NSP-Minnesota to move certain facilities. NSP-Minnesota has complied with the preliminary injunction and utility line relocation has commenced. NSP-Minnesota is capitalizing its costs incurred as construction work in progress. In September 2002, the court granted Defendants’ motions for summary judgment and dismissed NSP-Minnesota’s claims. NSP-Minnesota reserves its right to appeal. In collateral matters regarding LRT construction, NSP-Minnesota commenced a mandamus action in state court seeking an order requiring Defendants to commence condemnation proceedings concerning an underground substation, access to which is blocked by LRT. In October 2002, the court dismissed NSP-Minnesota’s petition. NSP-Minnesota also has commenced an action in state court alleging that LRT construction violates the Minnesota Environmental Rights Act and a separate action in federal district court alleging that the Federal Transit Administration’s failure to evaluate certain environmental effects of LRT violates the National Environmental Policy Act.

      SchlumbergerSema, Inc. v. Xcel Energy Inc. (NSP-Minnesota) — Under a 1996 Data Services Agreement (DSA), SchlumbergerSema, Inc. (SLB) provides automated meter reading, distribution automation, and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB had committed events of default under the DSA, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration before the American Arbitration Association and asserted various claims against NSP-Minnesota totaling $24 million for NSP-Minnesota’s alleged breach of an expansion contract and a meter purchasing contract. In arbitration, NSP-Minnesota asserts counterclaims against SLB for SLB’s failure to meet performance criteria, improper billing, failure to pay for use of NSP-Minnesota owned property and failure to pay $7.4 million for NSP-Minnesota distribution automation assets. NSP-Minnesota also seeks a declaratory judgment from the arbitrator that will terminate SLB’s rights under the DSA. No arbitration date is set, but written discovery has commenced. The parties are scheduled to mediate their disputes on April 9, 2003.

     NSP-Wisconsin

      Stray Voltage and Related Lawsuits — On Sept. 25, 2000, NSP-Wisconsin was served with a complaint in Eau Claire County Circuit Court, Wisconsin, on behalf of Caron and Janice Stubrud. The complaint alleged that stray voltage from NSP-Wisconsin’s system harmed their dairy herd resulting in lost milk production, lost profits and income, property damage, and injury to their dairy herd. The complaint also alleged that NSP-Wisconsin acted willfully and wantonly, entitling plaintiffs to treble damages. The plaintiffs allege farm damages of approximately $3.8 million. In July 2002, NSP-Wisconsin filed for summary judgment, and trial has been adjourned to November 2003 to allow the court ample time to consider summary judgment issues.

      On Nov. 13, 2001, Ralph Schmidt, Karline Schmidt, August C. Heeg Jr., and Joanne Heeg filed a complaint in Clark County, Wisconsin against a subsidiary of Xcel Energy. NSP-Wisconsin has been substituted as the proper party defendant, and plaintiffs will be amending their complaints to separate the Schmidt and Heeg claims into separate lawsuits. Both sets of plaintiffs allege that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, property damage and injury to their dairy herd and seek compensatory, punitive and treble damages. The Heeg plaintiffs allege compensatory damages of $1.9 million and pre-verdict interest of $6.1 million, for total damages of $8.0 million. The Schmidt plaintiffs allege compensatory damages of $1.0 million and pre-verdict interest of $1.2 million, for total damages of $2.2 million. No trial date has been set.

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      On March 1, 2002, NSP-Wisconsin was served with a lawsuit commenced by James and Grace Gumz and Michael and Susan Gumz in Marathon County Circuit Court, Wisconsin, alleging that electricity supplied by NSP-Wisconsin harmed their dairy herd and caused them personal injury. The Gumz’s complaint alleges negligence, strict liability, nuisance, trespass, and statutory violations and seeks compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1.7 million and pre-verdict interest of $1.8 million for total damages of $3.5 million. Trial has been set for March 2004.

     SPS

      On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS. LCEC alleged that SPS had been unlawfully providing service to oil field customers and their facilities in LCEC’s singly-certificated area. SPS responded that it was lawfully entitled to serve oil field customers under “grandfather rights” granted it in the same order that granted LCEC its certificated area. Ultimately, the PUCT issued an order granting SPS’ motion for summary disposition, thus denying LCEC’s petition. LCEC appealed the PUCT’s order to the District Court, which upheld the order. LCEC then appealed to the Third Court of Appeals, which reversed the District Court judgment and remanded the case to the PUCT for an evidentiary hearing. The LCEC complaint was transferred to the State Office of Administrative Hearings (SOAH) for processing. A hearing on the merits was held in October 2002, and SPS is currently waiting for a Proposal for Decision from the SOAH administrative law judge. In related litigation, on Oct. 18, 1996, LCEC filed an action for damages based on its claim that SPS had been unlawfully providing service to oil field customers in its certified area. This case has remained dormant pending a final determination by the PUCT of the lawfulness of the service. Damages resulting from a decision adverse to SPS could be material.

     Other Matters

      For a discussion of other legal claims and environmental proceedings, see Note 13 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates, see Pending Regulatory Matters under Item 1, all incorporated by reference.

 
Item 4.      Submission of Matters to a Vote of Security Holders

      This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

PART II

Item 5.      Market for Registrant’s Common Equity and Related Stockholder Matters

      This is not applicable as NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS are wholly owned subsidiaries.

 
Item 6.      Selected Financial Data

      This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

 
Item 7.      Management’s Discussion and Analysis

      Discussion of financial condition and liquidity for the utility subsidiaries of Xcel Energy are omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

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Table of Contents

Forward Looking Information

      The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of Xcel Energy’s utility subsidiaries 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 to the Consolidated Financial 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,” “estimate,” “expect,” “objective,” “outlook,” “possible,” “potential” 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 their impact on capital expenditures;
 
  •  rating agency actions;
 
  •  business conditions in the energy industry;
 
  •  competitive factors;
 
  •  unusual weather;
 
  •  changes in federal or state legislation;
 
  •  regulation; and
 
  •  the other risk factors listed from time to time by the utility subsidiaries of Xcel Energy in reports filed with the SEC, including Exhibit 99.01 to this Report on Form 10-K for the year ended Dec. 31, 2002.

NSP-Minnesota’s Management’s Discussion and Analysis

Results of Operations

      NSP-Minnesota’s net income was approximately $200.2 million for 2002, compared with approximately $207.9 million for 2001.

      Conservation Incentive Recovery — Operating income, and income before taxes increased by $41 million in 2001 due to the reversal of a MPUC decision.

      In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 incentives associated with state mandated programs for electric energy conservation. NSP-Minnesota recorded a $35 million charge in 1999 based on this action. NSP-Minnesota appealed the MPUC decision and prevailed after several court actions.

      On June 28, 2001, the MPUC approved the plan to recover the incentives and issued an order to that effect shortly thereafter. As a result, the previously recorded liabilities of approximately $41 million (including carrying charges) for potential refunds to customers were no longer required. The plan approved by the MPUC increased revenue by approximately $34 million and increased allowance for funds used during construction (AFDC) by approximately $7 million for the second quarter of 2001.

      Based on the new MPUC policy and less uncertainty regarding conservation incentives to be approved, conservation incentives are being recorded on a current basis in 2001 and 2002.

      Electric Utility and Commodity Trading Margins — Electric fuel and purchased power expense tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers, most fluctuations in energy costs do not significantly affect electric utility margin.

      NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales for resale (excluding sales to retail and municipal customers), which are associated with energy produced from NSP-Minnesota’s generation assets or energy

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and capacity purchased to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Margins from electric commodity trading activity, conducted at NSP-Minnesota, is partially redistributed to PSCo and SPS pursuant to the Joint Operating Agreement (JOA) approved by the FERC. Trading margins, as discussed in Note 1 to the Consolidated Financial Statements, are reported net in the Consolidated Statements of Income. The following table details electric utility, short-term wholesale and electric commodity trading revenue and margin:
                                 
Electric
Electric Short-Term Commodity Consolidated
Utility Wholesale Trading Totals




(Millions of dollars)
2002
                               
Electric utility revenue
  $ 2,264     $ 97     $     $ 2,361  
Electric fuel and purchased power
    (721 )     (68 )           (789 )
Electric trading revenue
                30       30  
Electric trading costs
                (28 )     (28 )
     
     
     
     
 
Gross margin before operating expenses
  $ 1,543     $ 29     $ 2     $ 1,574  
     
     
     
     
 
Margin as a percentage of revenue
    68.2 %     29.9 %     6.7 %     65.8 %
2001
                               
Electric utility revenue
  $ 2,416     $ 154     $     $ 2,570  
Electric fuel and purchased power
    (870 )     (112 )           (982 )
Electric trading revenue
                12       12  
Electric trading costs
                (12 )     (12 )
     
     
     
     
 
Gross margin before operating expenses
  $ 1,546     $ 42     $     $ 1,588  
     
     
     
     
 
Margin as a percentage of revenue
    64.0 %     27.3 %     %     61.5 %

      Electric utility revenue decreased by approximately $152 million, or 6.3 percent, in 2002. Electric utility margin decreased by approximately $3 million, or 0.2 percent, in 2002. The decrease in revenue is due largely to lower purchased power costs recovered through electric rates, lower shared trading margins recorded through the JOA and the recovery of conservation incentives in 2001. As discussed previously, the reversal of the 1999 MPUC decision to deny NSP-Minnesota recovery of conservation incentives increased retail revenue and margin by $34 million in 2001. The decrease in margin reflects the lower shared trading margins recorded through the JOA and the recovery of conservation incentives in 2001. These decreases in revenue and margin were partially offset by sales growth and favorable weather in 2002 and the pass through in 2001 of a property tax refund. The margin decrease was further offset by lower capacity costs in 2002.

      Short-term wholesale margins decreased in 2002, compared with 2001, due to lower power prices and other market conditions.

      Gas Utility Margins — The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. However, due to purchased gas cost recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on gas margin.

                 
2002 2001


(Millions of
dollars)
Gas utility revenue
  $ 490     $ 626  
Cost of gas sold and transported
    (344 )     (477 )
     
     
 
Gas utility margin
  $ 146     $ 149  
     
     
 

      Gas revenue decreased by approximately $136 million, or 21.7 percent, in 2002, primarily due to decreases in the cost of natural gas, which are largely passed on to customers through various rate adjustment

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clauses. Gas margin decreased by $3 million, or 2.0 percent, compared with 2001, primarily due to lower margins from transportation services, lower conservation incentives and decreased late payment revenues. The revenue and margin decreases were partially offset by favorable weather in 2002.

      Other Revenue — Other revenue decreased in 2002, compared with 2001, due to the transfer of certain refuse-derived fuel operations to NRG Energy, Inc., a wholly owned subsidiary of Xcel Energy.

      Non-Fuel Operating Expense and Other Costs — Depreciation and amortization expense increased by approximately $14.6 million, or 4.3 percent, for 2002 compared with 2001, primarily due to capital additions to utility plant.

      Taxes (other than income taxes) decreased by approximately $6.5 million due to lower Minnesota property taxes resulting from legislation enacted in 2001.

      Special charges decreased by approximately $9.8 million in 2002. During 2001, NSP-Minnesota expensed pretax special charges of approximately $13.5 million for planned staff consolidation costs. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $3.7 million were expensed for the final costs of staff consolidations. The charges related to NSP-Minnesota’s allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. For more information, see Note 2 to the Consolidated Financial Statements.

      Other income (deductions) increased by approximately $21.4 million due to increased interest income from federal and state income tax settlements of approximately $11.3 million and a gain on the sale of nonutility property by a subsidiary of NSP-Minnesota, First Midwest Auto Park of $6.8 million, in March 2002.

      Interest expense increased by approximately $13.8 million, or 16.2 percent, for 2002, compared with 2001. The increase is attributed to the issuance of long-term debt in July and August 2002.

      Income taxes declined in 2002 due to lower pretax income levels and lower effective tax rates as shown in Note 8 to the Consolidated Financial Statements.

NSP-Wisconsin’s Management’s Discussion and Analysis

Results of Operations

      NSP-Wisconsin’s net income was $54.4 million for 2002, compared with $36.4 million for 2001.

      Electric Utility Margins — The following table details the change in electric revenue and margin. Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power. The fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction does not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.

                 
Total Electric
Utility

2002 2001


(Millions of
dollars)
Electric utility revenue
  $ 459     $ 451  
Electric fuel and purchased power
    (212 )     (233 )
     
     
 
Gross margin before operating expenses
  $ 247     $ 218  
     
     
 
Margin as a percentage of revenue
    53.8 %     48.3 %

      Electric revenue increased by approximately $8 million, or 1.7 percent, in 2002 primarily due to higher fuel cost recoveries through rates, sales growth, and more favorable weather conditions. Partially offsetting the

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revenue increases were lower Interchange Agreement billings to NSP-Minnesota for energy delivered and cost allocations. (For more information on the Interchange Agreement, see Note 17 to the Financial Statements.) Electric margin increased by approximately $29 million, or 13.4 percent, in 2002 due largely to higher fuel cost recoveries through rates, lower fuel and purchased power cost, sales growth, and more favorable weather conditions.

      Gas Utility Margins — The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. However, due to purchase gas cost recovery mechanisms for retail customers in Wisconsin and Michigan, fluctuations in the cost of gas have little effect on gas margin.

                 
2002 2001


(Millions of
dollars)
Gas utility revenue
  $ 102     $ 123  
Cost of gas sold and transported
    (72 )     (96 )
     
     
 
Gas utility margin
  $ 30     $ 27  
     
     
 

      Gas revenue decreased by approximately $21 million, or 17.0 percent, in 2002 compared with 2001, mostly due to decreases in the cost of natural gas, which is largely recovered through various purchased gas cost recovery mechanisms. Gas margin increased by $3 million, or 11.1 percent, in 2002 primarily due to sales growth and more favorable weather conditions.

      Non-Fuel Operating Expense and Other Costs — Other operating and maintenance expense for 2002 decreased by approximately $4.5 million or 4.2 percent, compared with 2001, largely due to reduced benefit costs and interchange expense from NSP-Minnesota. See further discussion of the interchange agreement at Note 17.

      Depreciation and amortization expense increased by approximately $2.8 million, or 6.8 percent, for 2002 compared with 2001, primarily due to capital additions to utility plant and remaining life changes to production plant and data processing equipment.

      Special charges decreased by $1.8 million in 2002. During 2001, NSP-Wisconsin expensed pretax special charges of approximately $2.5 million for planned staff consolidation costs. In the first quarter of 2002, the identification of affected employees was completed and additional pretax charges of $0.7 million were expensed for the final costs of staff consolidations. The charges related to NSP-Wisconsin’s allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. For more information, see Note 2.

      Interest expense increased by approximately $1.0 million, or 4.7 percent, for 2002 compared with 2001, largely due to regulatory amortization of an interest refund in 2001 that did not recur in 2002 and lower allowance for funds used during construction (related to lower construction expenditures).

      Income taxes increased in 2002 due mainly to higher pretax income levels.

PSCo’s Management’s Discussion and Analysis

Results Of Operations

      PSCo’s net income was approximately $264.7 million for 2002, compared with approximately $273.0 million for 2001.

      Electric Utility and Commodity Trading Margins — Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Electric margins reflect the impact of sharing energy costs and savings relative to a target cost per delivered kilowatt hour and certain trading margins under the ICA mechanism. In addition to the ICA, PSCo has other adjustment clauses, discussed previously, that allow certain costs to be recovered from retail customers. The

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fuel clause cost recovery does not allow for complete recovery of all variable production expenses and higher costs can adversely affect earnings.

      PSCo has two distinct forms of wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales for resale, which are associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Some electric commodity trading activity, conducted at PSCo, is partially redistributed to NSP-Minnesota and SPS pursuant to the JOA approved by the FERC. Trading margins reflect the impact of sharing certain trading margins under the ICA. Trading margins, as discussed in Note 1 to the Consolidated Financial Statements, are reported net in the Consolidated Statements of Income. The following table details electric utility, short-term wholesale and electric trading revenue and margin:

                                 
Electric
Electric Short-Term Commodity Consolidated
Utility Wholesale Trading Totals




(Millions of dollars)
2002
                               
Electric utility revenue
  $ 1,779     $ 100     $     $ 1,879  
Electric fuel and purchased power
    (794 )     (96 )           (890 )
Electric trading revenue
                1,498       1,498  
Electric trading costs
                (1,499 )     (1,499 )
     
     
     
     
 
Gross margin before operating expenses
  $ 985     $ 4     $ (1 )   $ 988  
     
     
     
     
 
Margin as a percentage of revenue
    55.4 %     4.0 %     (0.1 )%     29.3 %
2001
                               
Electric utility revenue
  $ 1,711     $ 631     $     $ 2,342  
Electric fuel and purchased power
    (855 )     (498 )           (1,353 )
Electric trading revenue
                1,279       1,279  
Electric trading costs
                (1,255 )     (1,255 )
     
     
     
     
 
Gross margin before operating expenses
  $ 856     $ 133     $ 24     $ 1,013  
     
     
     
     
 
Margin as a percentage of revenue
    50.0 %     21.1 %     1.9 %     28.0 %

      Electric utility revenue increased by $68 million, or 4.0 percent, in 2002 compared with 2001. Electric utility margin increased by approximately $129 million, or 15.1 percent, in 2002 compared with 2001. The higher electric margins reflect lower unrecovered costs, due in part to resetting the energy cost recovery through the ICA in January 2002. In 2001, PSCo’s allowed recovery was approximately $78 million less than its actual costs, while in 2002 its allowed recovery was approximately $29 million more than its actual cost. Electric revenues and margin also increased due to sales growth and more favorable temperatures.

      Short-term wholesale margins and electric commodity trading margins decreased substantially in 2002, compared with 2001. The decrease is due to lower power prices, lower revenues and other market conditions.

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      Gas Utility Margins — The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. PSCo has a GCA mechanism for natural gas sales, which recognizes the majority of the effects of changes in the cost of gas purchased for resale and adjusts customer billings to reflect such changes in costs on a timely basis. Therefore, fluctuations in the cost of gas have little effect on gas margin.

                 
2002 2001


(Millions of
Dollars)
Gas utility revenue
  $ 749     $ 1,252  
Cost of gas sold and transported
    (422 )     (931 )
     
     
 
Gas utility margin
  $ 327     $ 321  
     
     
 

      Gas revenue for 2002 decreased by approximately $502.2 million, or 40.1 percent, compared with 2001, largely due to lower gas costs passed through to customers through rate recovery mechanisms. Gas margin for 2002 increased by approximately $6.6 million, or 2.1 percent, compared with 2001, due in part to higher rates from a 2000 rate case, effective Feb. 1, 2001.

      Non-Fuel Operating Expense and Other Items — Other operating and maintenance expenses for 2002 decreased approximately $5.4 million, or 1.1 percent, compared with 2001. The change is largely due to reduced consulting expense and bad debt expense.

      Depreciation and amortization expense increased by approximately $8.3 million, or 3.4 percent, for 2002 compared with 2001, primarily due to increased amortization costs of software and increased depreciation resulting from capital additions to utility plant.

      Taxes (other than income taxes) increased by approximately $6.4 million, or 9.0 percent, for 2002 compared with 2001, primarily due to an $8 million property tax refund received in 2001 for calendar year 2000.

      Special charges decreased by $37.4 million in 2002 compared to 2001. During 2001, PSCo expensed pretax special charges of approximately $15 million for planned staff consolidation costs. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $0.6 million were expensed for the final costs of staff consolidations. The charges related to PSCo’s allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. Charges in 2001 also included special charges related to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of a regulatory asset related to deferred post employment benefit costs at PSCo. For more information see Note 2 to the Consolidated Financial Statements.

      Interest expense increased by approximately $11.5 million, or 9.9 percent, for 2002 compared with 2001, primarily due to the issuance of $600 million of 7.875 percent first collateral trust bonds in September 2002.

      Income taxes declined in 2002 due to lower pretax income levels.

SPS’ Management’s Discussion and Analysis

Results of Operations

      SPS’ net income was $73.9 million for 2002, compared with $130.1 million for 2001.

      Extraordinary Items — During early 2001, legislation in both Texas and New Mexico was passed that delayed the planned implementation of restructuring within SPS’ service territory for at least five years. Accordingly, in the second quarter of 2001, SPS reapplied the provisions of Statements of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” for its generation business. At that time, SPS did not restore any regulatory assets or other costs previously written off due to the uncertainty of various regulatory issues, including transition plans to address future rate recovery of SPS’ restructuring costs.

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      During the fourth quarter of 2001, SPS completed a $500 million medium-term debt financing with the proceeds used to reduce short-term borrowings that had resulted from the 2000 defeasance. In its regulatory filings and communications, SPS has proposed to amortize its defeasance costs over the five-year life of the refinancing, consistent with historical ratemaking, and has requested incremental rate recovery of $25 million of other restructuring costs. These non-financing restructuring costs have been deferred and will be amortized in the future consistent with rate recovery. Based on these events and the corresponding reduced uncertainty surrounding the financial impacts of the delay in restructuring, SPS restored in 2001 certain regulatory assets totaling $17.6 million as of Dec. 31, 2001, and reported related after-tax extraordinary income of $11.8 million. Regulatory assets previously written off in 2000 were restored only for items currently being recovered in rates and items where future rate recovery is considered probable.

      For more information on SPS’ restructuring developments, including the reapplication of regulatory accounting under SFAS No. 71, see Note 10 to the Consolidated Financial Statements.

      Electric Utility Margins — The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Fuel and purchased power costs are recoverable in SPS’ Texas jurisdiction through a fixed fuel factor, which is included in rates. In the New Mexico retail jurisdiction, fuel and purchased energy costs are adjusted through a fuel clause and a fixed annual factor. In all other jurisdictions, SPS currently recovers substantially all increases and refunds substantially all decreases in fuel and purchased power costs pursuant to monthly adjustment clauses. Due to these fuel clause cost recovery mechanisms for retail customers and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not significantly affect electric margin. However, the fuel clause cost recovery does not allow for complete recovery of all variable production expenses and, therefore, changes in costs can affect earnings.

                         
Electric Short-Term Consolidated
Utility Wholesale Totals



(Millions of dollars)
2002
                       
Electric utility revenue
  $ 1,019     $ 6     $ 1,025  
Electric fuel and purchased power
    (550 )     (5 )     (555 )
     
     
     
 
Gross margin before operating expenses
  $ 469     $ 1     $ 470  
     
     
     
 
Margin as a percentage of revenue
    46.0 %     16.7 %     45.9 %
2001
                       
Electric utility revenue
  $ 1,382     $ 3     $ 1,385  
Electric fuel and purchased power
    (862 )     (2 )     (864 )
     
     
     
 
Gross margin before operating expenses
  $ 520     $ 1     $ 521  
     
     
     
 
Margin as a percentage of revenue
    37.6 %     33.3 %     37.6 %

      Electric utility revenue decreased by approximately $363 million, or 26 percent, in 2002. Electric utility margin decreased by approximately $51 million, or 9.8 percent, in 2002. Electric revenues decreased for 2002, compared with 2001, largely due to decreased recovery of fuel and purchased power costs driven by declining fuel costs in 2002, and decreasing wholesale revenues. Electric margin declined due to an approximate $57 million decrease in capacity margins and lower shared trading margins recorded through the JOA, partially offset by growth in retail sales.

      Non-Fuel Operating Expense and Other Costs — Other operating and maintenance expenses for 2002 increased by approximately $2.5 million, or 1.6 percent, compared with 2001, largely due to increased insurance premiums.

      Depreciation and amortization expense increased by approximately $5.1 million, or 6.1 percent, for 2002 compared with 2001, primarily due to capital additions to utility plant.

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      Taxes (other than income taxes) increased by approximately by $5.7 million, or 11.8 percent, for 2002 compared with 2001, primarily due to higher property and franchise taxes.

      Special charges increased slightly in 2002. During 2001, SPS expensed pretax special charges of approximately $4.5 million for planned staff consolidation costs. The charges related to SPS’ allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. In 2002, special charges of $5.1 million were expensed due to a Texas regulatory recovery adjustment. For more information, see Note 2 to the Consolidated Financial Statements.

      Other income decreased by $5.8 million, or 49 percent, for 2002 compared with 2001, primarily due to SPS no longer receiving interest income on a note receivable that was paid off in 2001.

      Interest expense increased by approximately $1.0 million, or 2.1 percent, for 2002 compared with 2001. The change is primarily due to an increase in financing costs related to debt that was refinanced in late 2001.

Income taxes declined in 2002 due to lower pretax income levels.

Item 7A.     Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

      Business and Operational Risk — Xcel Energy’s utility subsidiaries are exposed to commodity price risk in their generation, retail distribution and energy trading operations. NSP-Minnesota and SPS recover purchased energy expenses on a dollar-for-dollar basis. NSP-Minnesota and PSCo recover natural gas costs on a dollar-for-dollar basis. However, NSP-Wisconsin and PSCo have limited exposure to market price risk for the purchase and sale of electric energy. In these jurisdictions, electric energy expenses are recovered based on fixed price limits or under established sharing mechanisms. NSP-Minnesota is authorized to recover certain financial instrument costs, incurred to mitigate wholesale electric and gas commodity price volatility in rates, through the fuel clause adjustment and purchased gas adjustment.

      NSP-Minnesota, PSCo and SPS manage commodity price risk by entering into purchase and sales commitments for electric power and natural gas, long-term contracts for coal supplies and fuel oil, and derivative financial instruments. Xcel Energy’s risk management policy allows the utility subsidiaries to manage the market price risk within each rate regulated operation to the extent such exposure exists. Management is limited under the policy to enter into only transactions that reduce market price risk where the rate regulation jurisdiction does not already provide for dollar-for-dollar recovery.

      Interest Rate Risk — Xcel Energy’s utility subsidiaries are exposed to fluctuations in interest rates where they enter into variable rate debt obligations to fund certain power projects being developed or purchased. Exposure to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. Xcel Energy’s risk management policy allows us to reduce interest rate exposure from variable rate debt obligations.

      The impacts on pretax income of a 100 basis point change in the benchmark rate on variable debt at December 31 are as follows:

                 
2002 2001


(Millions of
dollars)
NSP-Minnesota
  $ 2.9     $ 4.9  
PSCo.
  $ 4.3     $ 1.4  
SPS
  $ 0.3     $ 3.9  

      With the exception of short-term borrowings, NSP-Wisconsin does not have variable interest rates; therefore there is limited interest rate risk.

      See Note 11 to the Consolidated Financial Statements for a discussion of SPS’ interest rate swaps.

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      Trading Risk — NSP-Minnesota and PSCo conduct various trading operations, including the purchase and sale of electric capacity and energy. Xcel Energy’s risk management policy allows the utility subsidiaries to conduct the trading activity within guidelines and limitations as approved by our Risk Management Committee made up of management personnel not involved in the trading operations.

      Our 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 and various holding periods varying from two to five days.

      As of Dec. 31, 2002, the calculated VaRs were:

                                 
During 2002
Year Ended
Operations Dec. 31, 2002 Average High Low





(Millions of Dollars)
Electric Commodity Trading
    0.29       0.62       3.39       0.01  


      As of Dec. 31, 2001, the calculated VaRs were:

                                 
During 2001
Year Ended
Operations Dec. 31, 2001 Average High Low





(Millions of Dollars)
Electric Commodity Trading
    0.52       1.71       7.37       0.16  

      In 2001, Xcel Energy changed its holding period for measuring VaR from electricity trading activity from 21 days to two to five days. Xcel Energy’s revised holding periods are generally consistent with current industry standard practice.

      Credit Risk — In addition to the risks discussed previously, Xcel Energy’s utility subsidiaries are exposed to credit risk in our risk management activities. Credit risk relates to the risk of loss resulting from the non-performance by a counterparty of its contractual obligations. As Xcel Energy and its utility subsidiaries continue their trading activities, exposure to credit risk and counterparty default may increase. Xcel Energy’s utility subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

      Xcel Energy’s utility subsidiaries conduct 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.

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Item 8.     Financial Statements and Supplemental Data

INDEPENDENT AUDITORS’ REPORT

To Northern States Power Company-Minnesota:

      We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Northern States Power Company-Minnesota (a Minnesota corporation) and subsidiaries (the Company) as of December 31, 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive income and cash flows for the year then ended (which include the disclosures regarding Northern States Power Company-Minnesota included in the combined footnotes to the financial statements). Our audit also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

      The consolidated financial statements of Northern States Power Company-Minnesota for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion and included an explanatory paragraph related to the Company’s adoption of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity” on those consolidated financial statements and the financial schedules in their report dated February 21, 2002.

      We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company-Minnesota and its subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2003

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THE FOLLOWING REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — NSP-Minnesota

To Northern States Power Company-Minnesota:

      We have audited the accompanying consolidated balance sheets and statements of capitalization of Northern States Power Company-Minnesota (a Minnesota corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2001. These financial statements and the schedule referred to below are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

      We conducted our audits in accordance with auditing standards generally accepted in the 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, the financial statements referred to above present fairly, in all material respects, the financial position of Northern States Power Company - Minnesota and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

      As discussed in Note 12 to the consolidated financial statements, effective January 1, 2001 Northern States Power Company-Minnesota and its subsidiaries adopted Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activity,” which changed its method of accounting for certain commodity contracts and other derivatives.

      Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

/s/ ARTHUR ANDERSEN, LLP

ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota

February 21, 2002

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INDEPENDENT AUDITORS’ REPORT

To Northern States Power Company-Wisconsin:

      We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Northern States Power Company-Wisconsin (a Wisconsin corporation) and subsidiaries (the Company) as of December 31, 2002, and the related consolidated statements of income, stockholder’s equity and cash flows for the year then ended (which include the disclosures regarding Northern States Power Company-Wisconsin included in the combined footnotes to the financial statements). Our audit also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

      The consolidated financial statements of Northern States Power Company-Wisconsin for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statements and the financial statement schedules in their report dated February 21, 2002.

      We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company-Wisconsin and its subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2003

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THE FOLLOWING REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — NSP-Wisconsin

To Northern States Power Company-Wisconsin:

      We have audited the accompanying consolidated balance sheets and statements of capitalization of Northern States Power Company-Wisconsin (a Wisconsin corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2001. These financial statements and the schedule referred to below are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

      We conducted our audits in accordance with auditing standards generally accepted in the 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, the financial statements referred to above present fairly, in all material respects, the financial position of Northern States Power Company-Wisconsin and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

      Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

/s/ ARTHUR ANDERSEN, LLP

ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota

February 21, 2002

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INDEPENDENT AUDITORS’ REPORT

To Public Service Company of Colorado:

      We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Colorado (a Colorado corporation) and subsidiaries (the Company) as of December 31, 2002 and 2001, and the related consolidated statements of income, stockholder’s equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2002 (which include the disclosures regarding Public Service Company of Colorado included in the combined footnotes to the financial statements). Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

      We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 referred to above present fairly, in all material respects, the financial position of Public Service Company of Colorado and its subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

      As discussed in Note 12 to the consolidated financial statements, effective January 1, 2001 Public Service Company of Colorado adopted Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities, which changed its method of accounting for certain commodity contracts and other derivatives.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2003

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INDEPENDENT AUDITORS’ REPORT

To Southwestern Public Service Company:

      We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Southwestern Public Service Company (a New Mexico corporation) and subsidiaries (the Company) as of December 31, 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive income and cash flows for the year then ended (which include the disclosures regarding Southwestern Public Service Company included in the combined footnotes to the financial statements). Our audit also included the financial statement schedule listed in the Index at Item 15. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.

      The consolidated financial statements of Southwestern Public Service Company for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion and included an explanatory paragraph related to the Company’s adoption of Statement of Financial Accounting Standards No. 133 — “Accounting for Derivative Instruments and Hedging Activity” on those consolidated financial statements and the financial statement schedules in their report dated February 21, 2002.

      We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated 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 audit provides a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of Southwestern Public Service Company and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2003

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THE FOLLOWING REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — SPS

To Southwestern Public Service Company:

      We have audited the accompanying consolidated balance sheets and statements of capitalization of Southwestern Public Service Company (a New Mexico corporation) as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements and the schedule referred to below are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

      We conducted our audits in accordance with auditing standards generally accepted in the 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, the financial statements referred to above present fairly, in all material respects, the financial position of Southwestern Public Service Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

      As discussed in Note 12 to the consolidated financial statements, effective January 1, 2001 Southwestern Public Service Company adopted Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activity,” which changed its method of accounting for certain commodity contracts and other derivatives.

      Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth there in relation to the basic financial statements taken as a whole.

/s/ ARTHUR ANDERSEN, LLP


ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota

February 21, 2002

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NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF INCOME

                             
Year Ended December 31,

2002 2001 2000



(Thousands of dollars)
Operating revenues:
                       
 
Electric utility
  $ 2,360,866     $ 2,569,768     $ 2,411,883  
 
Gas utility
    489,572       625,506       536,700  
 
Electric trading margin
    1,806       385        
 
Other
    30,875       52,836       51,900  
     
     
     
 
   
Total operating revenues
    2,883,119       3,248,495       3,000,483  
Operating expenses:
                       
 
Electric fuel and purchased power
    789,379       981,506       869,421  
 
Cost of gas sold and transported
    343,700       476,528       382,596  
 
Operating and maintenance expenses
    825,451       824,416       798,666  
 
Depreciation and amortization
    354,157       339,509       323,935  
 
Taxes (other than income taxes)
    168,721       175,209       202,245  
 
Special charges (see Note 2)
    3,727       13,543       72,095  
     
     
     
 
   
Total operating expenses
    2,485,135       2,810,711       2,648,958  
     
     
     
 
Operating income
    397,984       437,784       351,525  
Other income (expenses) — net
    25,069       3,713       (5,725 )
Interest charges and financing costs:
                       
 
Interest charges — net of amounts capitalized; includes
other financing costs of $5,241, $4,489 and $5,158, respectively
    98,940       85,150       126,635  
 
Distributions on redeemable preferred securities of subsidiary trust
    15,750       15,750       15,750  
     
     
     
 
   
Total interest charges and financing costs
    114,690       100,900       142,385  
     
     
     
 
Income before income taxes
    308,363       340,597       203,415  
Income taxes
    108,141       132,732       92,191  
     
     
     
 
Net income
  $ 200,222     $ 207,865     $ 111,224  
     
     
     
 
 
See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

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NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CASH FLOWS

                               
Year Ended December 31,

2002 2001 2000



(Thousands of dollars)
Operating activities:
                       
 
Net income
  $ 200,222     $ 207,865     $ 111,224  
 
Adjustments to reconcile net income to cash provided by operating activities:
                       
   
Depreciation and amortization
    366,362       358,718       340,868  
   
Nuclear fuel amortization
    48,675       41,928       44,591  
   
Deferred income taxes
    (26,280 )     10,414       1,341  
   
Amortization of investment tax credits
    (7,490 )     (8,046 )     (9,017 )
   
Allowance for equity funds used during construction
    (5,491 )     (4,898 )     4,176  
   
Conservation incentive accrual adjustments
    (9,152 )     (49,271 )     19,248  
   
Special charges — not requiring cash
    1,567       12,888       14,932  
   
Gain on sale of nonutility property
    (6,785 )            
   
Change in accounts receivable
    1,649       72,775       16,016  
   
Change in inventories
    (4,296 )     (5,363 )     (2,447 )
   
Change in other current assets
    25,340       62,903       (64,324 )
   
Change in accounts payable
    (12,745 )     (64,722 )     123,059  
   
Change in other current liabilities
    54,404       (26,441 )     (42,460 )
   
Change in other assets and liabilities
    25,107       (45,996 )     (64,942 )
     
     
     
 
     
Net cash provided by operating activities
    651,087       562,754       492,265  
Investing activities:
                       
 
Utility capital/ construction expenditures
    (383,857 )     (483,936 )     (391,727 )
 
Allowance for equity funds used during construction
    5,491       4,898       (4,176 )
 
Proceeds from sale of property
    11,152              
 
Investments in external decommissioning fund
    (57,830 )     (54,996 )     (48,967 )
 
Restricted cash
    (23,000 )            
 
Other investments — net
    (4,939 )     (5,922 )     454  
     
     
     
 
   
Net cash used in investing activities
    (452,983 )     (539,956 )     (444,416 )
Financing activities:
                       
 
Short-term borrowings — net
    (381,115 )     21,995       (61,005 )
 
Proceeds from issuance of long-term debt
    624,892             76,127  
 
Repayment of long-term debt, including reacquisition premiums
    (4,876 )     (155,081 )     (180,730 )
 
Capital contributions from parent
    51,714       282,768       358,632  
 
Dividends and cash distributions paid to parent
    (195,550 )     (167,237 )     (240,291 )
     
     
     
 
   
Net cash provided by (used in) financing activities
    95,065       (17,555 )     (47,267 )
     
     
     
 
Net increase in cash and cash equivalents
    293,169       5,243       582  
Cash and cash equivalents at beginning of year
    17,169       11,926       11,344  
     
     
     
 
Cash and cash equivalents at end of year
  $ 310,338     $ 17,169     $ 11,926  
     
     
     
 
Supplemental disclosure of cash flow information:
                       
 
Cash paid for interest (net of amounts capitalized)
  $ 75,315     $ 84,789     $ 128,530  
 
Cash paid for income taxes (net of refunds received)
  $ 83,636     $ 84,957     $ 105,720  
 
See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

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NSP-MINNESOTA

CONSOLIDATED BALANCE SHEETS

                     
December 31, December 31,
2002 2001


(Thousands of dollars)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 310,338     $ 17,169  
 
Restricted cash
    23,000        
 
Accounts receivable — net of allowance for bad debts: $5,812 and $5,452, respectively
    231,996       227,007  
 
Accounts receivable from affiliates
    24,773       31,528  
 
Accrued unbilled revenues
    109,435       125,770  
 
Materials and supplies inventories
    106,037       103,934  
 
Fuel inventory
    34,875       31,945  
 
Gas inventory
    24,385       25,122  
 
Derivative instruments valuation — at market
    3,831       204  
 
Prepayments and other
    34,234       48,285  
     
     
 
   
Total current assets
    902,904       610,964  
     
     
 
Property, plant and equipment, at cost:
               
 
Electric utility plant
    6,855,807       6,582,337  
 
Gas utility plant
    716,844       695,338  
 
Construction work in progress
    313,931       316,468  
 
Other
    384,214       368,513  
     
     
 
   
Total property, plant and equipment
    8,270,796       7,962,656  
 
Less accumulated depreciation
    (4,624,988 )     (4,310,214 )
 
Nuclear fuel — net of accumulated amortization: $1,058,531 and $1,009,855, respectively
    74,139       96,315  
     
     
 
   
Net property, plant and equipment
    3,719,947       3,748,757  
     
     
 
Other assets:
               
 
Nuclear decommissioning fund investments
    617,048       596,113  
 
Other investments
    22,730       22,542  
 
Regulatory assets
    212,539       226,088  
 
Prepaid pension asset
    263,713       188,287  
 
Other
    72,144       64,278  
     
     
 
   
Total other assets
    1,188,174       1,097,308  
     
     
 
   
Total assets
  $ 5,811,025     $ 5,457,029  
     
     
 
LIABILITIES AND EQUITY
Current liabilities:
               
 
Current portion of long-term debt
  $ 226,462     $ 153,134  
 
Short-term debt
    69       381,184  
 
Accounts payable
    198,889       235,930  
 
Accounts payable to affiliates
    66,866       42,550  
 
Taxes accrued
    210,041       168,491  
 
Dividends payable to parent
    52,280       44,332  
 
Derivative instruments valuation — at market
    3,958        
 
Other
    83,464       76,004  
     
     
 
   
Total current liabilities
    842,029       1,101,625  
     
     
 
Deferred credits and other liabilities:
               
 
Deferred income taxes
    700,966       697,605  
 
Deferred investment tax credits
    74,577       82,598  
 
Regulatory liabilities
    486,035       468,051  
 
Benefit obligations and other
    136,452       133,771  
     
     
 
   
Total deferred credits and other liabilities
    1,398,030       1,382,025  
     
     
 
Long-term debt
    1,569,938       1,039,220  
Mandatorily redeemable preferred securities of subsidiary trust (see Note 6)
    200,000       200,000  
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares
    10       10  
Premium on common stock
    813,869       762,155  
Retained earnings
    987,158       990,435  
Leveraged ESOP
          (18,564 )
Accumulated other comprehensive (loss) income
    (9 )     123  
     
     
 
 
Total common stockholder’s equity
    1,801,028       1,734,159  
     
     
 
Commitments and contingencies (see Note 13)
               
Total liabilities and equity
  $ 5,811,025     $ 5,457,029  
     
     
 
 
See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

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NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY AND OTHER COMPREHENSIVE INCOME

                                                         
Accumulated
Common Stock Other

Premium on Retained Leveraged Comprehensive
Shares Amount Common Stock Earnings ESOP Income (Loss) Total







(Thousands of dollars, except share information)
Balance at Dec. 31, 1999
    1,000,000     $ 10     $ 145,603     $ 1,052,088     $ (11,606 )   $     $ 1,186,095  
Net income — comprehensive income
                            111,224                       111,224  
Contribution of capital to parent
                    (16,216 )     (210,423 )                     (226,639 )
Contribution of capital by parent
                    350,000                               350,000  
Loan to ESOP to purchase shares
                                    (20,000 )             (20,000 )
Repayment of ESOP loan(a)
                                    6,989               6,989  
     
     
     
     
     
     
     
 
Balance at Dec. 31, 2000
    1,000,000       10       479,387       952,889       (24,617 )           1,407,669  
Net income
                            207,865                       207,865  
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 12)
                                            121       121  
Unrealized gain — marketable securities
                                            2       2  
                                                     
 
Comprehensive income for 2001
                                                    207,988  
Common dividends declared to parent
                            (170,319 )                     (170,319 )
Contribution of capital by parent
                    282,768                               282,768  
Repayment of ESOP loan(a)
                                    6,053               6,053  
     
     
     
     
     
     
     
 
Balance at Dec. 31, 2001
    1,000,000       10       762,155       990,435       (18,564 )     123       1,734,159  
Net income
                            200,222                       200,222  
After-tax net unrealized losses related to derivatives accounted for as hedges (see Note 12)
                                            (121 )     (121 )
Unrealized loss — marketable securities
                                            (11 )     (11 )
                                                     
 
Comprehensive income for 2002
                                                    200,090  
Common dividends declared to parent
                            (203,499 )                     (203,499 )
Contribution of capital by parent
                    51,714                               51,714  
Repayment of ESOP loan(a)
                                    18,564               18,564  
     
     
     
     
     
     
     
 
Balance at Dec. 31, 2002
    1,000,000     $ 10     $ 813,869     $ 987,158     $     $ (9 )   $ 1,801,028  
     
     
     
     
     
     
     
 


(a)  Did not affect cash flows.

 
See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

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NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CAPITALIZATION

                     
December 31,

2002 2001


(Thousands of dollars)
Long-Term Debt
               
First Mortgage Bonds, Series due:
               
 
Dec. 1, 2003 — 2006, 3.75 — 4.1%
  $ 9,145 (a)   $ 11,225 (a)
 
March 1, 2003, 5.875%
    100,000       100,000  
 
April 1, 2003, 6.375%
    80,000       80,000  
 
Dec. 1, 2005, 6.125%
    70,000       70,000  
 
Aug. 28, 2012, 8%
    450,000        
 
March 1, 2011, variable rate, 6.265% at Dec. 31, 2002 and 1.8% at Dec. 31, 2001
    13,700 (b)     13,700 (b)
 
March 1, 2019, 8.5% at Dec. 31, 2002 and a variable rate of 2.04% at Dec. 31, 2001
    27,900 (b)     27,900 (b)
 
Sept. 1, 2019, 8.5% at Dec. 31, 2002 and a variable rate of 1.76% and 2.04% at Dec. 31, 2001
    100,000 (b)     100,000 (b)
 
July 1, 2025, 7.125%
    250,000       250,000  
 
March 1, 2028, 6.5%
    150,000       150,000  
 
April 1, 2030, 8.5% at Dec. 31, 2002 and 1.85% at Dec. 31, 2001
    69,000 (b)     69,000 (b)
 
Dec. 1, 2003 — 2008, 4.25% — 5%
    14,090 (a)     16,090 (a)
Guaranty Agreements, Series due: Feb. 1, 2003 — May 1, 2003, 5.375% — 7.4%
    28,450 (b)     29,200 (b)
Senior Notes due Aug. 1, 2009, 6.875%
    250,000       250,000  
Retail Notes due July 1, 2042, 8%
    185,000        
Employee Stock Ownership Plan Bank Loans, variable rate
          18,564  
Other
    8,046       11,690  
Unamortized discount
    (8,931 )     (5,015 )
     
     
 
   
Total
    1,796,400       1,192,354  
Less redeemable bonds classified as current (see Note 4)
    13,700       141,600  
Less current maturities
    212,762       11,534  
     
     
 
   
Total NSP-Minnesota long-term debt
  $ 1,569,938     $ 1,039,220  
     
     
 
Mandatorily Redeemable Preferred Securities of Subsidiary Trust
holding as its sole asset junior subordinated deferrable debentures of NSP-Minnesota (see Note 6)
  $ 200,000     $ 200,000  
     
     
 
Common Stockholder’s Equity
               
 
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares in 2002 and 2001
  $ 10     $ 10  
 
Premium on common stock
    813,869       762,155  
 
Retained earnings
    987,158       990,435  
 
Leveraged ESOP
          (18,564 )
 
Accumulated other comprehensive income (loss)
    (9 )     123  
     
     
 
   
Total common stockholder’s equity
  $ 1,801,028     $ 1,734,159  
     
     
 


(a)  Resource recovery financing
(b)  Pollution control financing

 
See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

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NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF INCOME

                               
Year Ended December 31,

2002 2001 2000



(Thousands of dollars)
Operating revenues:
                       
 
Electric utility
  $ 458,737     $ 450,895     $ 424,477  
 
Gas utility
    102,143       123,053       110,023  
 
Other
    761       692       670  
     
     
     
 
   
Total operating revenues
    561,641       574,640       535,170  
Operating expenses:
                       
 
Electric fuel and purchased power
    212,180       233,165       210,088  
 
Cost of gas sold and transported
    72,260       95,617       81,843  
 
Operating and maintenance expenses
    102,496       106,999       105,235  
 
Depreciation and amortization
    44,466       41,645       40,502  
 
Taxes (other than income taxes)
    16,066       15,944       15,350  
 
Special charges (see Note 2)
    675       2,488       12,848  
     
     
     
 
     
Total operating expenses
    448,143       495,858       465,866  
     
     
     
 
Operating income
    113,498       78,782       69,304  
Other income (expense) — net
    917       837       937  
Interest charges — net of amounts capitalized; includes other financing costs of $896, $896 and $840, respectively
    23,117       22,069       19,255  
Income before income taxes
    91,298       57,550       50,986  
Income taxes
    36,925       21,158       20,690  
     
     
     
 
Net income
  $ 54,373     $ 36,392     $ 30,296  
     
     
     
 
 
See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

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NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF CASH FLOWS

                               
Year Ended December 31,

2002 2001 2000



(Thousands of dollars)
Operating activities:
                       
 
Net income
  $ 54,373     $ 36,392     $ 30,296  
 
Adjustments to reconcile net income to cash provided by
operating activities:
                       
   
Depreciation and amortization
    45,641       42,724       41,473  
   
Deferred income taxes
    21,682       3,049       1,868  
   
Amortization of investment tax credits
    (808 )     (819 )     (827 )
   
Allowance for equity funds used during construction
    (641 )     (1,449 )     (200 )
   
Undistributed equity in earnings of unconsolidated affiliates
    (232 )     (553 )     (411 )
   
Special charges — not requiring cash
    171       2,427       2,459  
   
Changes in accounts receivable
    (14,473 )     13,696       (16,127 )
   
Change in inventories
    (1,213 )     (485 )     (31 )
   
Change in other current assets
    2,213       7,377       (10,235 )
   
Change in accounts payable
    15,889       (47,930 )     24,265  
   
Change in other current liabilities
    (2,923 )     1,645       2,162  
   
Change in other assets and liabilities
    (10,716 )     (8,363 )     (3,599 )
     
     
     
 
     
Net cash provided by operating activities
    108,963       47,711       71,093  
Investing activities:
                       
 
Utility capital/ construction expenditures
    (38,414 )     (62,010 )     (88,624 )
 
Allowance for equity funds used during construction
    641       1,449       200  
 
Other investments — net
    240       611       (161 )
     
     
     
 
     
Net cash used in investing activities
    (37,533 )     (59,950 )     (88,585 )
Financing activities:
                       
 
Short-term borrowings — net
    (27,420 )     18,400       (64,900 )
 
Proceeds from issuance of long-term debt
                79,399  
 
Repayment of long-term debt
    (34 )     (34 )      
 
Contribution of capital by parent
    3,210       26,353        
 
Issuance of common stock to parent
                29,977  
 
Dividends paid to parent
    (47,118 )     (32,481 )     (27,004 )
     
     
     
 
     
Net cash provided by (used in) financing activities
    (71,362 )     12,238       17,472  
     
     
     
 
 
Net increase (decrease) in cash and cash equivalents
    68       (1 )     (20 )
 
Cash and cash equivalents at beginning of year
    30       31       51  
     
     
     
 
 
Cash and cash equivalents at end of year
  $ 98     $ 30     $ 31  
     
     
     
 
Supplemental disclosure of cash flow information:
                       
 
Cash paid for interest (net of amounts capitalized)
  $ 21,399     $ 20,227     $ 17,175  
 
Cash paid for income taxes (net of refunds received)
  $ 13,456     $ 16,821     $ 22,665  
 
See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

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NSP-WISCONSIN

CONSOLIDATED BALANCE SHEETS

                     
December 31, December 31,
2002 2001


(Thousands of dollars)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 98     $ 30  
 
Accounts receivable — net of allowance for bad debts: $1,373 and $969, respectively
    47,890       31,870  
 
Accounts receivable from affiliates
    1,460       3,006  
 
Accrued unbilled revenues
    20,074       20,596  
 
Material and supplies inventories — at average cost
    5,994       5,885  
 
Fuel inventory — at average cost
    6,006       5,854  
 
Gas inventory — at average cost
    4,263       3,311  
 
Prepaid taxes
    13,735       13,157  
 
Prepayments and other
    1,681       3,949  
     
     
 
   
Total current assets
    101,201       87,658  
     
     
 
Property, plant and equipment, at cost:
               
 
Electric utility plant
    1,161,901       1,132,114  
 
Gas utility plant
    131,969       127,635  
 
Other
    113,936       115,435  
     
     
 
   
Total property, plant and equipment
    1,407,806       1,375,184  
 
Less accumulated depreciation
    (592,187 )     (553,467 )
     
     
 
   
Net property, plant and equipment
    815,619       821,717  
     
     
 
Other assets:
               
 
Other investments
    9,817       9,824  
 
Regulatory assets
    48,112       37,123  
 
Prepaid pension asset
    38,557       28,563  
 
Other
    7,577       7,373  
     
     
 
   
Total other assets
    104,063       82,883  
     
     
 
   
Total assets
  $ 1,020,883     $ 992,258  
     
     
 
LIABILITIES AND EQUITY
Current liabilities:
               
 
Current portion of long-term debt
  $ 40,034     $ 34  
 
Notes payable to affiliate
    6,880       34,300  
 
Accounts payable
    23,535       14,482  
 
Accounts payable to affiliates
    6,836        
 
Dividends payable to parent
    12,260       10,988  
 
Other
    20,225       22,515  
     
     
 
   
Total current liabilities
    109,770       82,319  
     
     
 
Deferred credits and other liabilities:
               
 
Deferred income taxes
    146,471       119,895  
 
Deferred investment tax credits
    14,820       15,628  
 
Regulatory liabilities
    11,950       16,891  
 
Benefit obligations and other
    46,026       34,925  
     
     
 
   
Total deferred credits and other liabilities
    219,267       187,339  
     
     
 
Long-term debt
    273,108       313,054  
Common stock — authorized 1,000,000 shares of $100 par value;
outstanding 933,000 shares
    93,300       93,300  
Premium on common stock
    62,981       59,771  
Retained earnings
    262,457       256,475  
     
     
 
   
Total common stockholder’s equity
    418,738       409,546  
Commitments and contingencies (see Note 13)
               
     
     
 
   
Total liabilities and equity
  $ 1,020,883     $ 992,258  
     
     
 
 
See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

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NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

                                         
Common Stock Premium on Total

Common Retained Stockholder’s
Shares Amount Stock Earnings Equity





(Thousands of dollars, except share information)
Balance at Dec. 31, 1999
    862,000     $ 86,200     $ 10,541     $ 260,259     $ 357,000  
Net income
                            30,296       30,296  
Common dividends declared to parent
                            (27,004 )     (27,004 )
Issuance of common stock to parent
    71,000       7,100       22,877               29,977  
     
     
     
     
     
 
Balance at Dec. 31, 2000
    933,000       93,300       33,418       263,551       390,269  
Net income
                            36,392       36,392  
Common dividends declared to parent
                            (43,468 )     (43,468 )
Contribution of capital by parent
                    26,353               26,353  
     
     
     
     
     
 
Balance at Dec. 31, 2001
    933,000       93,300       59,771       256,475       409,546  
Net income
                            54,373       54,373  
Common dividends declared to parent
                            (48,391 )     (48,391 )
Contribution of capital by parent
                    3,210               3,210  
     
     
     
     
     
 
Balance at Dec. 31, 2002
    933,000     $ 93,300     $ 62,981     $ 262,457     $ 418,738  
     
     
     
     
     
 
 
See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

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NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF CAPITALIZATION

                     
December 31,

2002 2001


(Thousands of dollars)
Long-Term Debt
               
First Mortgage Bonds Series due:
               
 
Oct. 1, 2003, 5.75%
  $ 40,000     $ 40,000  
 
March 1, 2023, 7.25%
    110,000       110,000  
 
Dec. 1, 2026, 7.375%
    65,000       65,000  
City of La Crosse Resource Recovery Bond — Series due Nov. 1, 2021, 6%
    18,600 (a)     18,600 (a)
Fort McCoy System Acquisition — due Oct. 31, 2030, 7%
    930       963  
Senior Notes due Oct. 1, 2008, 7.64%
    80,000       80,000  
Unamortized discount
    (1,388 )     (1,475 )
     
     
 
   
Total
    313,142       313,088  
Less current maturities
    40,034       34  
     
     
 
   
Total NSP-Wisconsin long-term debt
  $ 273,108     $ 313,054  
     
     
 
Common Stockholder’s Equity
               
 
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares in 2002 and 2001
  $ 93,300     $ 93,300  
Premium on common stock
    62,981       59,771  
Retained earnings
    262,457       256,475  
     
     
 
   
Total common stockholder’s equity
  $ 418,738     $ 409,546  
     
     
 


  (a)  Resource recovery financing

 
See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF INCOME

                             
Year Ended December 31,

2002 2001 2000



(Thousands of dollars)
Operating revenues:
                       
 
Electric utility
  $ 1,878,870     $ 2,342,184     $ 2,014,554  
 
Electric trading margin
    (677 )     23,655       25,100  
 
Gas utility
    749,355       1,251,541       787,110  
 
Steam and other
    24,365       32,465       26,751  
     
     
     
 
   
Total operating revenues
    2,651,913       3,649,845       2,853,515  
Operating expenses:
                       
 
Electric fuel and purchased power
    890,135       1,352,839       1,132,418  
 
Cost of gas sold and transported
    422,442       931,246       486,800  
 
Cost of sales — steam
    4,746       9,554       6,177  
 
Operating and maintenance expenses
    469,090       474,466       413,665  
 
Depreciation and amortization
    247,598       239,309       210,704  
 
Taxes (other than income taxes)
    77,042       70,680       77,885  
 
Special charges (see Note 2)
    622       38,033       78,779  
     
     
     
 
   
Total operating expenses
    2,111,675       3,116,127       2,406,428  
     
     
     
 
Operating income
    540,238       533,718       447,087  
Other income
    76,942       78,324       73,904  
Other expense
    (81,583 )     (73,746 )     (60,802 )
Interest charges and financing costs:
                       
 
Interest charges — net of amounts capitalized, includes other financing costs of $3,780, $3,691, and $4,741, respectively
    127,487       116,028       146,091  
 
Distributions on redeemable preferred securities of subsidiary trust
    14,744       15,200       15,200  
     
     
     
 
   
Total interest charges and financing costs
    142,231       131,228       161,291  
     
     
     
 
Income before income taxes and extraordinary item
    393,366       407,068       298,898  
Income taxes
    128,686       132,501       102,770  
     
     
     
 
Income before extraordinary item
    264,680       274,567       196,128  
Extraordinary item, net of income taxes of $940 (see Note 4)
          (1,534 )      
     
     
     
 
Net income
  $ 264,680     $ 273,033     $ 196,128  
     
     
     
 
 
See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CASH FLOWS

                               
Year Ended December 31,

2002 2001 2000



(Thousands of dollars)
Operating activities:
                       
 
Net income
  $ 264,680     $ 273,033     $ 196,128  
 
Adjustments to reconcile net income to cash provided by operating activities:
                       
   
Depreciation and amortization
    255,712       242,999       216,212  
   
Deferred income taxes
    108,721       (13,309 )     (8,582 )
   
Amortization of investment tax credits
    (4,665 )     (4,152 )     (5,481 )
   
Allowance for equity funds used during construction
    24       (393 )     (54 )
   
Special charges — not requiring cash
    267       37,699       2,333  
   
Extraordinary item — net of tax (see Note 4)
          1,534        
   
Change in accounts receivable
    24,763       19,044       (29,653 )
   
Change in accrued utility revenues
    65,198       99,851       (148,688 )
   
Change in recoverable purchased gas and electric energy costs
    (74,077 )     132,032       (106,098 )
   
Change in inventories
    (18,091 )     (35,216 )     36,480  
   
Change in prepayments and other current assets
    8,881       (6,166 )     26,788  
   
Change in accounts payable
    (61,134 )     (260,236 )     278,703  
   
Change in other current liabilities
    (56,964 )     9,441       (1,072 )
   
Change in other assets and liabilities
    (69 )     11,063       3,688  
     
     
     
 
     
Net cash provided by operating activities
    513,246       507,224       460,704  
Investing activities:
                       
 
Capital/ construction expenditures
    (443,176 )     (469,768 )     (373,566 )
 
Proceeds from disposition of property, plant and equipment
    17,322       11,074       10,514  
 
Allowance for equity funds used during construction
    (24 )     393       54  
 
Payment received for notes receivable from affiliate
                192,620  
 
Other investments — net
    (2,207 )     1,046       1,521  
     
     
     
 
     
Net cash used in investing activities
    (428,085 )     (457,255 )     (168,857 )
Financing activities:
                       
 
Short-term borrowings — net
    (488,161 )     436,177       (200,992 )
 
Proceeds from issuance of long-term debt-net
    593,599             101,020  
 
Repayment of long-term debt, including reacquisition premiums
    (18,674 )     (273,159 )     (207,124 )
 
Capital contribution from parent
    62,200       15,249       160,000  
 
Dividends paid to parent
    (230,867 )     (221,266 )     (180,786 )
     
     
     
 
     
Net cash used in financing activities
    (81,903 )     (42,999 )     (327,882 )
Net increase (decrease) in cash and cash equivalents
    3,258       6,970       (36,035 )
 
Cash and cash equivalents at beginning of year
    22,666       15,696       51,731  
     
     
     
 
 
Cash and cash equivalents at end of year
  $ 25,924     $ 22,666     $ 15,696  
     
     
     
 
Supplemental disclosure of cash flow information:
                       
 
Cash paid for interest (net of amounts capitalized)
  $ 112,179     $ 117,316     $ 162,823  
 
Cash paid for income taxes (net of refunds received)
  $ 15,255     $ 130,917     $ 104,349  
 
See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED BALANCE SHEETS

                     
December 31, December 31,
2002 2001


(Thousands of dollars)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 25,924     $ 22,666  
 
Accounts receivable — net of allowance for bad debts: $13,685 and $14,510, respectively
    165,743       209,913  
 
Accounts receivable from affiliates
    19,407        
 
Accrued unbilled revenues
    203,969       269,167  
 
Recoverable purchased gas and electric energy costs
    23,131       16,763  
 
Materials and supplies inventories
    49,579       40,893  
 
Fuel inventory
    25,366       22,135  
 
Gas inventories — replacement cost in excess of LIFO: $20,502 and $11,331, respectively
    85,679       79,505  
 
Derivative instruments valuation — at market
    2,735       3,855  
 
Prepayments and other
    13,257       56,001  
     
     
 
   
Total current assets
    614,790       720,898  
     
     
 
Property, plant and equipment, at cost:
               
 
Electric utility plant
    5,345,464       5,253,693  
 
Gas utility plant
    1,494,017       1,416,730  
 
Construction work in progress
    456,800       273,539  
 
Other
    624,764       586,261  
     
     
 
   
Total property, plant and equipment
    7,921,045       7,530,223  
 
Less accumulated depreciation
    (2,896,978 )     (2,746,687 )
     
     
 
   
Net property, plant and equipment
    5,024,067       4,783,536  
     
     
 
Other assets:
               
 
Other investments
    12,319       10,112  
 
Regulatory assets
    238,600       192,841  
 
Prepaid pension asset
          60,797  
 
Other
    35,150       72,694  
     
     
 
   
Total other assets
    286,069       336,444  
     
     
 
   
Total assets
  $ 5,924,926     $ 5,840,878  
     
     
 
LIABILITIES AND EQUITY
Current liabilities:
               
 
Current portion of long-term debt
  $ 282,097     $ 17,174  
 
Short-term debt
    88,074       562,812  
 
Note payable to affiliate
    15,142       28,565  
 
Accounts payable
    318,005       359,406  
 
Accounts payable to affiliates
    40,449       60,151  
 
Taxes accrued
    47,363       60,780  
 
Dividends payable to parent
    60,550       53,387  
 
Derivative instruments valuation — at market
    2,593       50,385  
 
Accrued interest
    44,391       32,717  
 
Other
    75,872       108,528  
     
     
 
   
Total current liabilities
    974,536       1,333,905  
     
     
 
Deferred credits and other liabilities:
               
 
Deferred income taxes
    553,006       564,268  
 
Deferred investment tax credits
    74,987       79,652  
 
Regulatory liabilities
    45,707       49,048  
 
Other deferred credits
    5,052       12,435  
 
Customers’ advances for construction
    142,992       85,582  
 
Minimum pension liability
    104,773        
 
Benefit obligations and other
    69,283       66,835  
     
     
 
   
Total deferred credits and other liabilities
    995,800       857,820  
     
     
 
Long-term debt
    1,782,128       1,465,055  
Mandatorily redeemable preferred securities of subsidiary trust (see Note 6)
    194,000       194,000  
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares
           
Premium on common stock
    1,652,284       1,590,084  
Retained earnings
    430,997       404,347  
Accumulated comprehensive income (loss)
    (104,819 )     (4,333 )
     
     
 
   
Total common stockholder’s equity
    1,978,462       1,990,098  
Commitments and contingencies (see Note 13)
               
   
Total liabilities and equity
  $ 5,924,926     $ 5,840,878  
     
     
 
 
See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND OTHER COMPREHENSIVE INCOME
                                                 
Accumulated
Common Stock Other Total

Premium on Retained Comprehensive Stockholder’s
Shares Amount Common Stock Earnings Income (Loss) Equity






(Thousands of dollars, except share information)
Balance at Dec. 31, 1999
    100     $     $ 1,414,835     $ 346,050     $     $ 1,760,885  
Net income and comprehensive income
                            196,128               196,128  
Common dividends declared to parent
                            (193,827 )             (193,827 )
Contribution of capital by parent
                    160,000                       160,000  
     
     
     
     
     
     
 
Balance at Dec. 31, 2000
    100             1,574,835       348,351             1,923,186  
Net income
                            273,033               273,033  
Net unrealized transition gain at adoption of SFAS No. 133, Jan. 1, 2001 (see Note 12)
                                    1,649       1,649  
After-tax net unrealized losses related to derivatives accounted for as hedges (see Note 12)
                                    (26,319 )     (26,319 )
After-tax net realized losses on derivative transactions reclassified into earnings (see Note 12)
                                    20,348       20,348  
Unrealized loss — marketable securities
                                    (11 )     (11 )
                                             
 
Comprehensive income for 2001
                                            268,700  
Common dividends declared to parent
                            (217,037 )             (217,037 )
Contribution of capital by parent
                    15,249                       15,249  
     
     
     
     
     
     
 
Balance at Dec. 31, 2001
    100             1,590,084       404,347       (4,333 )     1,990,098  
Net income
                            264,680               264,680  
Minimum pension liability recognized net of deferred tax of $64,600 (see Note 9)
                                    (105,358 )     (105,358 )
After-tax net unrealized losses related to derivatives accounted for as hedges (see Note 12)
                                    10,296       10,296  
After-tax net realized losses on derivative transactions reclassified into earnings (see Note 12)
                                    (4,985 )     (4,985 )
Unrealized loss — marketable securities
                                    (439 )     (439 )
                                             
 
Comprehensive income for 2002
                                            (100,486 )
Common dividends declared to parent
                            (238,030 )             (238,030 )
Contribution of capital by parent
                    62,200                       62,200  
     
     
     
     
     
     
 
Balance at Dec. 31, 2002
    100     $     $ 1,652,284     $ 430,997     $ (104,819 )   $ 1,978,462  
     
     
     
     
     
     
 
 
See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CAPITALIZATION

                     
December 31,

2002 2001


(Thousands of dollars)
Long-Term Debt
               
First Mortgage Bonds, Series due:
               
 
April 15, 2003, 6%
  $ 250,000     $ 250,000  
 
March 1, 2004, 8.125%
    100,000       100,000  
 
Nov. 1, 2005, 6.375%
    134,500       134,500  
 
June 1, 2006, 7.125%
    125,000       125,000  
 
April 1, 2008, 5.625%
    18,000 (b)     18,000 (b)
 
June 1, 2012, 5.5%
    50,000 (b)     50,000 (b)
 
Oct. 1, 2012, 7.875%
    600,000        
 
April 1, 2014, 5.875%
    61,500 (b)     61,500 (b)
 
Jan. 1, 2019, 5.1%
    48,750 (b)     48,750 (b)
 
March 1, 2022, 8.75%
    146,340       147,840  
 
Jan. 1, 2024, 7.25%
    110,000       110,000  
Unsecured Senior A Notes, due July 15, 2009, 6.875%
    200,000       200,000  
Secured Medium-Term Notes, due Nov. 25, 2003 — March 5, 2007, 6.45% — 7.11%
    175,000       190,000  
Unamortized discount
    (4,612 )     (5,282 )
Capital lease obligations, 11.2% due in installments through May 31, 2025
    49,747       51,921  
     
     
 
   
Total
    2,064,225       1,482,229  
Less current maturities
    282,097       17,174  
     
     
 
   
Total PSCo long-term debt
  $ 1,782,128     $ 1,465,055  
     
     
 
Mandatorily Redeemable Preferred Securities of Subsidiary Trust
               
 
Holding as its sole asset the junior subordinated deferrable debentures of PSCo (see Note 6):
  $ 194,000     $ 194,000  
     
     
 
Common Stockholder’s Equity
               
 
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in 2002 and 2001
  $     $  
 
Premium on common stock
    1,652,284       1,590,084  
 
Retained earnings
    430,997       404,347  
 
Accumulated other comprehensive income (loss)
    (104,819 )     (4,333 )
     
     
 
   
Total common stockholder’s equity
  $ 1,978,462     $ 1,990,098  
     
     
 


(b) Pollution control financing.

 
See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF INCOME

                             
Year Ended December 31,

2002 2001 2000



(Thousands of dollars)
Operating revenues
  $ 1,025,178     $ 1,385,458     $ 1,079,580  
Operating expenses:
                       
 
Electric fuel and purchased power
    554,874       863,624       582,013  
 
Operating and maintenance expenses
    156,880       154,410       149,036  
 
Depreciation and amortization
    89,087       83,972       78,526  
 
Taxes (other than income taxes)
    54,105       48,383       47,407  
 
Special charges (see Note 2)
    5,114       4,512       24,345  
     
     
     
 
   
Total operating expenses
    860,060       1,154,901       881,327  
     
     
     
 
Operating income
    165,118       230,557       198,253  
Other income (expense) — net
    6,025       11,814       11,468  
Interest charges and financing costs:
                       
 
Interest charges — net of amounts capitalized; includes other financing costs of $6,138, $1,614 and $1,720 respectively
    46,048       45,067       54,643  
 
Distributions on redeemable preferred securities of subsidiary trust
    7,850       7,850       7,850  
     
     
     
 
   
Total interest charges and financing costs
    53,898       52,917       62,493  
     
     
     
 
Income before income taxes and extraordinary items
    117,245       189,454       147,228  
Income taxes
    43,363       71,175       58,776  
     
     
     
 
Income before extraordinary items
    73,882       118,279       88,452  
Extraordinary items, net of income taxes of $0, $5,747 and $(8,549), respectively (see Note 10)
          11,821       (18,960 )
     
     
     
 
Net income
  $ 73,882     $ 130,100     $ 69,492  
     
     
     
 
 
See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

                               
Year Ended December 31,

2002 2001 2000



(Thousands of dollars)
Operating activities:
                       
 
Net income
  $ 73,882     $ 130,100     $ 69,492  
 
Adjustments to reconcile net income to net cash provided by operating activities:
                       
   
Depreciation and amortization
    97,595       88,183       82,617  
   
Deferred income taxes
    29,885       3,609       45,871  
   
Amortization of investment tax credits
    (250 )     (250 )     (250 )
   
Allowance for equity funds used during construction
                11  
   
Special charges — not requiring cash
    5,321       4,377        
   
Deferred energy costs
    (56,322 )     104,249       (102,300 )
   
Extraordinary items (see Note 10)
          (11,821 )     18,960  
   
Change in accounts receivable
    (10,559 )     17,191       5,049  
   
Change in inventories
    (4,575 )     583       5,766  
   
Change in other current assets
    27,036       (8,641 )     (44,625 )
   
Change in accounts payable
    9,045       (68,056 )     55,118  
   
Change in other current liabilities
    (19,311 )     50,270       (3,056 )
   
Change in other assets and liabilities
    (14,214 )     (47,012 )     (45,485 )
     
     
     
 
     
Net cash provided by operating activities
    137,533       262,782       87,168  
Investing activities:
                       
 
Capital/ construction expenditures
    (57,116 )     (117,431 )     (103,915 )
 
Allowance for equity funds used during construction
                (11 )
 
Proceeds from (cost of) disposition of property, plant and equipment
    5,393       (3,592 )     (3,433 )
 
Other investments — net
    (3,037 )     119,986       (6,349 )
     
     
     
 
     
Net cash used in investing activities
    (54,760 )     (1,037 )     (113,708 )
Financing activities:
                       
 
Short-term borrowings — net
          (674,579 )     496,834  
 
Proceeds from issuance of long-term debt — net
          500,168        
 
Repayment of long-term debt, including reacquisition premiums
                (383,145 )
 
Capital contribution by parent
    5,793       52,437        
 
Dividends paid to parent
    (93,365 )     (85,098 )     (77,855 )
     
     
     
 
     
Net cash provided by (used in) financing activities
    (87,572 )     (207,072 )     35,834  
     
     
     
 
 
Net increase (decrease) in cash and cash equivalents
    (4,799 )     54,673       9,294  
 
Cash and cash equivalents at beginning of year
    65,499       10,826       1,532  
     
     
     
 
 
Cash and cash equivalents at end of year
  $ 60,700     $ 65,499     $ 10,826  
     
     
     
 
Supplemental disclosure of cash flow information:
                       
 
Cash paid for interest (net of amounts capitalized)
  $ 37,870     $ 45,001     $ 70,857  
 
Cash paid for income taxes (net of refunds received)
  $ 37,112     $ 83,715     $ 17,490  
 
See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED BALANCE SHEETS

                     
December 31, December 31,
2002 2001


(Thousands of dollars)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 60,700     $ 65,499  
 
Accounts receivable — net of allowance for bad debts: $1,559 and $1,785, respectively
    49,460       61,688  
 
Accounts receivable from affiliates
    22,787        
 
Accrued unbilled revenues
    52,999       75,924  
 
Recoverable electric energy costs
    16,439        
 
Materials and supplies inventories — at average cost
    17,231       12,588  
 
Fuel and gas inventories — at average cost
    1,322       1,390  
 
Current portion of accumulated deferred income taxes
          10,068  
 
Prepayments and other
    6,059       10,170  
     
     
 
   
Total current assets
    226,997       237,327  
     
     
 
Property, plant and equipment, at cost:
               
 
Electric utility plant
    3,076,970       3,056,459  
 
Other and construction work in progress
    64,908       55,436  
     
     
 
   
Total property, plant and equipment
    3,141,878       3,111,895  
 
Less accumulated depreciation
    (1,338,340 )     (1,275,501 )
     
     
 
   
Net property, plant and equipment
    1,803,538       1,836,394  
     
     
 
Other assets:
               
 
Other investments
    14,382       11,345  
 
Regulatory assets
    105,404       96,613  
 
Prepaid pension asset
    105,044       82,503  
 
Deferred charges and other
    9,979       36,598  
     
     
 
   
Total other assets
    234,809       227,059  
     
     
 
   
Total assets
  $ 2,265,344     $ 2,300,780  
     
     
 
LIABILITIES AND EQUITY
Current liabilities:
               
 
Accounts payable
  $ 73,536     $ 72,204  
 
Accounts payable to affiliates
    9,604       1,891  
 
Taxes accrued
    24,107       35,274  
 
Accrued interest
    7,630       9,696  
 
Dividends payable to parent
    24,427       20,969  
 
Current portion of accumulated deferred income taxes
    13,034        
 
Recovered electric energy costs
          39,883  
 
Derivative instruments valuation — at market
    1,176       1,131  
 
Other
    22,473       28,222  
     
     
 
   
Total current liabilities
    175,987       209,270  
     
     
 
Deferred credits and other liabilities:
               
 
Deferred income taxes
    399,800       392,907  
 
Deferred investment tax credits
    4,217       4,467  
 
Regulatory liabilities
    2,363       1,117  
 
Derivative instruments valuation-at market
    6,008       5,809  
 
Benefit obligations and other
    22,597       15,815  
     
     
 
   
Total deferred credits and other liabilities
    434,985       420,115  
     
     
 
Long-term debt
    725,662       725,375  
Mandatorily redeemable preferred securities of subsidiary trust (see Note 6)
    100,000       100,000  
Common stock — authorized 200 shares of $1.00 par value; outstanding 100 shares
           
Premium on common stock
    411,329       405,536  
Retained earnings
    421,976       444,917  
Accumulated comprehensive income (loss)
    (4,595 )     (4,433 )
     
     
 
   
Total common stockholder’s equity
    828,710       846,020  
Commitments and contingencies (see Notes 10 and 13)
               
     
     
 
   
Total liabilities and equity
  $ 2,265,344     $ 2,300,780  
     
     
 
 
See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY AND

OTHER COMPREHENSIVE INCOME
                                                 
Accumulated
Common Stock Other

Premium on Retained Comprehensive
Shares Amount Common Stock Earnings Income (Loss) Total






(Thousands of dollars, except share information)
Balance at Dec. 31, 1999
    100     $     $ 353,099     $ 408,284     $     $ 761,383  
Net income and comprehensive income
                            69,492               69,492  
Common dividends declared to parent
                            (79,246 )             (79,246 )
     
     
     
     
     
     
 
Balance at Dec. 31, 2000
    100             353,099       398,530             751,629  
Net income
                            130,100               130,100  
Net unrealized transition loss at adoption of SFAS No. 133, Jan. 1, 2001. see Note 12
                                    (2,626 )     (2,626 )
After-tax net unrealized losses related to derivatives accounted for as hedges. see Note 12
                                    (2,394 )     (2,394 )
After-tax net realized losses on derivatives transactions reclassified into earnings. see Note 12
                                    587       587  
                                             
 
Comprehensive income for 2001
                                            125,667  
Common dividends declared to parent
                            (83,713 )             (83,713 )
Contribution of capital by parent
                    52,437                       52,437  
     
     
     
     
     
     
 
Balance at Dec. 31, 2001
    100             405,536       444,917       (4,433 )     846,020  
Net income
                            73,882               73,882  
After-tax net unrealized gains related to derivatives accounted for as hedges. see Note 12
                                    303       303  
After-tax net realized loss on derivatives transactions reclassified into earnings. see Note 12
                                    (465 )     (465 )
                                             
 
Comprehensive income for 2002
                                            73,720  
Common dividends declared to parent
                            (96,823 )             (96,823 )
Contribution of capital by parent
                    5,793                       5,793  
     
     
     
     
     
     
 
Balance at Dec. 31, 2002
    100     $     $ 411,329     $ 421,976     $ (4,595 )   $ 828,710  
     
     
     
     
     
     
 
 
See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF CAPITALIZATION

                     
December 31,

2002 2001


(Thousands of dollars)
Long-Term Debt
               
Unsecured senior A Notes, due March 1, 2009, 6.2%
  $ 100,000     $ 100,000  
Unsecured senior B Notes, due Nov. 1, 2006, 5.125%
    500,000       500,000  
Pollution control obligations, securing pollution control revenue bonds,
Not collateralized by First Mortgage Bonds due:
               
 
July 1, 2011, 5.2%
    44,500       44,500  
 
July 1, 2016, 1.6% at Dec. 31, 2002 and 1.7% at Dec. 31, 2001
    25,000       25,000  
 
Sept. 1, 2016, 5.75%
    57,300       57,300  
Unamortized discount
    (1,138 )     (1,425 )
     
     
 
   
Total SPS long-term debt
  $ 725,662     $ 725,375  
     
     
 
Mandatorily Redeemable Preferred Securities of Subsidiary Trust
               
 
Holding as its sole asset junior subordinated deferrable debentures of SPS
(see Note 6)
  $ 100,000     $ 100,000  
     
     
 
Common Stockholder’s Equity
               
 
Common stock — authorized 200 shares of $1 par value;
Outstanding 100 shares
  $     $  
 
Premium on common stock
    411,329       405,536  
 
Retained earnings
    421,976       444,917  
 
Accumulated other comprehensive income (loss)
    (4,595 )     (4,433 )
     
     
 
   
Total common stockholder’s equity
  $ 828,710     $ 846,020  
     
     
 
 
See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
1. Summary of Significant Accounting Policies (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      Merger and Basis of Presentation — On Aug. 18, 2000, Northern States Power Co. (NSP) and New Century Energy, Inc. (NCE) merged and formed Xcel Energy, Inc. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. Cash was paid in lieu of any fractional shares of Xcel Energy common stock. The merger was structured as a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares) and accounted for as a pooling-of-interests. At the time of the merger, Xcel Energy registered as a holding company under the PUHCA.

      Pursuant to the merger agreement, NCE was merged with and into NSP. NSP, as the surviving legal corporation, changed its name to Xcel Energy. Also, as part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed wholly owned subsidiary of Xcel Energy, which was renamed NSP-Minnesota.

      Consistent with pooling accounting requirements, results and disclosures for all periods prior to the merger have been restated for consistent reporting with post-merger organization and operations.

      Business and System of Accounts — This report reflects Xcel Energy’s four largest domestic utility subsidiaries, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, which 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 are 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 aspects.

      Principles of Consolidation — NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have subsidiaries, which have been consolidated. In the consolidation process, we eliminate all significant intercompany transactions and balances.

      NSP-Minnesota and NSP-Wisconsin have subsidiaries for which they use the equity method of accounting for their investments and record their portion of earnings from such investments after subtracting income taxes.

      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 of 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 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 amount collected under the clauses and the recoverable costs incurred.

      PSCo’s electric rates in Colorado are adjusted under the ICA mechanism (for fuel and purchased energy expense incurred prior to Jan. 1, 2003), which takes into account changes in energy costs and certain trading margins that are shared with the customer. For fuel and purchased energy expense incurred beginning Jan. 1, 2003, the recovery mechanism shall be determined by the CPUC in the PSCo 2002 general rate case. In the interim, 2003 fuel and purchased energy expense is recovered through an Interim Adjustment Clause. In Colorado, PSCo operates under an electric Performance-Based Regulatory Plan, which results in an annual earnings test. NSP-Minnesota and PSCo’s rates include monthly adjustments for the recovery of conservation and energy management program costs, which are reviewed annually.

      SPS’ rates in Texas have fixed fuel factor and periodic fuel filing, reconciling and reporting requirements, which provide cost recovery. In New Mexico, SPS has recently reinstituted a monthly fuel and purchased power cost recovery factor.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      NSP-Wisconsin’s rates include a cost-of-energy adjustment clause for purchased natural gas, but not for purchased electricity or electric fuel. NSP-Wisconsin can request recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, and an interim fuel-cost hearing process.

      Trading Operations — In June 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached a partial consensus on Issue No. 02-03 “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” under EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF No. 02-03). The EITF concluded that all gains and losses related to energy trading activities within the scope of EITF No. 98-10 (whether or not settled physically) must be shown net in the statement of income, effective for periods ending after July 15, 2002. NSP-Minnesota and PSCo have reclassified revenue from trading activities for all comparable prior periods reported. Such energy trading activities originally recorded as a component of Electric Trading Costs have been reclassified to offset Electric Trading Revenues to present Electric Trading Margin on a net basis as indicated in the table below. These reclassifications had no impact on operating income or reported net income.

                         
2002 2001 2000



(Millions of dollars)
NSP-Minnesota
  $ 28     $ 12     $  
PSCo.
  $ 1,499     $ 1,255     $ 788  

      Electric commodity trading activity is conducted at NSP-Minnesota and PSCo. Pursuant to a Joint Operating Agreement (JOA), approved by the FERC as a part of the merger, the activity is then apportioned to the other operating utilities of Xcel Energy. NSP-Minnesota’s and PSCo’s trading revenues and costs do not include the revenue and production costs associated with energy produced from generation assets; however, trading results at PSCo include the impacts of the ICA rate-sharing mechanism. In addition, trading results at NSP-Minnesota and PSCo are recorded using mark-to-market accounting. For more information, see Notes 11 and 12 to the Consolidated Financial Statements.

      Property, Plant, 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, plus net removal cost is charged to accumulated depreciation and amortization. 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.

      Xcel Energy’s utility subsidiaries determine the depreciation of their plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense for Xcel Energy’s utility subsidiaries, expressed as a percentage of average depreciable property, for the years ended December 31, is listed in the following table:

                         
2002 2001 2000



NSP-Minnesota
    3.7 %     4.2 %     3.7 %
NSP-Wisconsin
    3.3 %     3.1 %     3.3 %
PSCo.
    2.5 %     3.0 %     2.8 %
SPS
    2.8 %     2.8 %     2.7 %

      PSCo’s property, plant and equipment includes approximately $18 million and $25 million, respectively, for costs associated with the engineering design of the future Pawnee 2 generating station and certain water rights obtained for a future generating station in Colorado. PSCo is earning a return on these investments based on its weighted average cost of debt in accordance with a Colorado Public Utilities Commission (CPUC) rate order.

      Allowance for Funds Used During Construction (AFDC) and Capitalized Interest — AFDC, a noncash item, represents the cost of capital used to finance utility construction activity. AFDC is computed by applying

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income and deductions (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in Xcel Energy’s utility subsidiaries 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. Interest capitalized as AFDC for Xcel Energy’s utility subsidiaries is listed in the following table:

                         
2002 2001 2000



(Millions of dollars)
NSP-Minnesota
  $ 8.5     $ 11.9     $ 3.8  
NSP-Wisconsin
  $ 0.4     $ 1.1     $ 2.3  
PSCo.
  $ 8.0     $ 12.1     $ 9.4  
SPS
  $ 1.0     $ 4.4     $ 4.5  

      Decommissioning — NSP-Minnesota accounts for the future cost of decommissioning — or permanently retiring — its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. Our 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. For more information on nuclear decommissioning, see Note 14 to the Consolidated Financial Statements.

      PSCo also previously operated a nuclear generating plant, which has been decommissioned and re-powered using natural gas. PSCo’s costs associated with decommissioning were deferred and are being amortized consistent with the CPUC regulatory recovery.

      Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of nuclear 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 U.S. Department of Energy (DOE) and NSP-Minnesota’s portion of the cost of decommissioning or shutting down the DOE’s fuel enrichment facility.

      Environmental Costs — We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset based on our expectation that we will recover these costs from customers in future rates. Otherwise, we expense the costs. If an environmental expense is related to facilities we currently use, such as pollution-control equipment, we capitalize and depreciate the costs over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

      We record estimated remediation costs, excluding inflationary increases and possible reductions for insurance coverage and rate recovery. The estimates are based on our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, we estimate and record only our share of the cost. We treat any future costs of restoring sites where operation may extend indefinitely as a capitalized cost of plant retirement. The depreciation expense levels we can recover in rates include a provision for these estimated removal costs.

      Income Taxes — Xcel Energy and its utility subsidiaries file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss. 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 taxable income of each company in the consolidated federal or combined state returns. Xcel Energy’s utility subsidiaries defer income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. We use the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, we account for the reversal of some temporary differences as current income tax expense. We defer investment tax credits and spread their benefits over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which we summarize in Note 15 to the Consolidated Financial Statements. For more information on income taxes, see Note 8 to the Consolidated Financial Statements.

      Derivative Financial Instruments — Xcel Energy’s utility subsidiaries utilize a variety of derivatives, including interest rate swaps and locks, to reduce exposure to interest rate risk and energy contracts to reduce exposure to commodity price risk. The energy contracts are both financial- and commodity-based in the energy trading and energy nontrading operations. These contracts consist mainly of commodity futures and options, index or fixed price swaps and basis swaps.

      On Jan. 1, 2001, Xcel Energy’s utility subsidiaries adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activity,” as amended by SFAS No. 137 and SFAS No. 138 (collectively referred to as SFAS No. 133). For more information on the impact of SFAS No. 133, see Notes 11 and 12 to the Consolidated Financial Statements.

      Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy’s utility subsidiaries use estimates based on the best information available. We use estimates for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we get better information or when we can determine actual amounts. Those revisions can affect operating results. Each year we also review the depreciable lives of certain plant assets and revise them, if appropriate.

      Cash Items — Xcel Energy’s utility subsidiaries consider investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Those instruments are primarily commercial paper and money market funds. Restricted cash at NSP-Minnesota consists of cash collateral for letters of credit and funds held in a collateral trust account to satisfy the requirements of certain debt agreements. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.

      Inventory — All inventories are recorded at average cost, with the exception of natural gas in storage at PSCo, which is recorded using last-in-first-out pricing.

      Regulatory Accounting — Xcel Energy’s utility subsidiaries account for certain income and expense items using SFAS No. 71. Under SFAS No. 71:

  •  we defer certain costs, which would otherwise be charged to expense, as regulatory assets based on our expected ability to recover them in future rates; and
 
  •  we defer certain credits, which would otherwise be reflected as income, as regulatory liabilities based on our expectation they will be returned to customers in future rates.

      We base our estimates of recovering deferred costs and returning deferred credits on specific ratemaking decisions or precedent for each item. We amortize regulatory assets and liabilities consistent with the period of expected regulatory treatment.

      Intangible Assets and Deferred Financing Costs — Effective Jan. 1, 2002, the utility subsidiaries of Xcel Energy implemented SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires different accounting for intangible assets as compared to goodwill. Intangible assets are amortized over their economic useful life and reviewed for impairment in accordance with SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.” Goodwill is no longer amortized after adoption of SFAS No. 142. Non-amortized intangible assets and goodwill are tested for impairment annually and on an interim basis if an event or circumstance occurs between annual tests that might reduce the fair value of that asset.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have immaterial amounts of unamortized intangible assets and no amounts of goodwill as of Dec. 31, 2002 and 2001.

      Other assets include deferred financing costs, which we are amortizing over the remaining maturity periods of the related debt. Xcel Energy’s utility subsidiaries’ deferred financing costs, net of amortization at Dec. 31, are listed in the following table:

                         
2002 2001 2000



(Millions of dollars)
NSP-Minnesota
  $ 21.1     $ 12.4     $ 13.4  
NSP-Wisconsin
  $ 1.7     $ 1.9     $ 2.1  
PSCo.
  $ 18.9     $ 14.2     $ 16.6  
SPS
  $ 8.4     $ 9.2     $ 6.8  

2.     Special Charges (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      2002 — Regulatory Recovery Adjustment — In late 2001, SPS filed an application requesting recovery of costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 2002, SPS entered into a settlement agreement with intervenors regarding the recovery of restructuring costs in Texas, subject to approval by the state regulatory commission. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million.

      2002 and 2001 — Restaffing — During the fourth quarter of 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. Approximately $36 million of these restaffing costs were allocated to Xcel Energy’s utility subsidiaries consistent with service company cost allocation methodologies utilized under the requirements of the PUHCA. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of staff consolidations. Approximately $6 million of these restaffing costs were allocated to Xcel Energy’s utility subsidiaries. All 564 of accrued staff terminations have occurred. See the summary of costs by utility subsidiary below.

      2001 — Postemployment Benefits — PSCo adopted accrual accounting for postemployment benefits under SFAS No. 112, “Employers Accounting for Postemployment Benefits” in 1994. The costs of these benefits had been recorded on a pay-as-you-go basis and, accordingly, PSCo recorded a regulatory asset in anticipation of obtaining future rate recovery of these transition costs. PSCo recovered its FERC jurisdictional portion of these costs. PSCo requested approval to recover its Colorado retail natural gas jurisdictional portion in a 1996 retail rate case and its retail electric jurisdictional portion in the electric earnings test filing for 1997. In the 1996 rate case, the CPUC allowed recovery of postemployment benefit costs on an accrual basis, but denied PSCo’s request to amortize the transition costs regulatory asset. Following various appeals, which proved unsuccessful, PSCo wrote off $23 million pretax of regulatory assets related to deferred postemployment benefit costs as of June 30, 2001.

      2000 — Merger Costs — Upon consummation of the merger in 2000, Xcel Energy expensed pretax special charges related to its regulated operations totaling $199 million. During 2000, an allocation of approximately $188 million of merger costs was made to Xcel Energy’s utility subsidiaries consistent with prior regulatory filings, in proportion to expected merger savings by the Company and consistent with service company cost allocation methodologies utilized under the requirements of the PUHCA. These costs are reported on the accompanying consolidated financial statements as special charges.

      Of the total pretax special charges recorded by Xcel Energy that related to its regulated operations, $159 million was recorded during the third quarter of 2000 and $40 million was recorded during the fourth quarter of 2000. See Note 18 to the Consolidated Financial Statements for the quarterly impacts on Xcel Energy’s utility subsidiaries.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The total pretax charges included $52 million related to one-time transaction related costs incurred in connection with the merger of NSP and NCE. These transaction costs included investment banker fees, legal and regulatory approval costs, and expenses for support of and assistance with planning and completing the merger transaction.

      Also included in the total were $147 million of pretax charges pertaining to incremental costs of transition and integration activities associated with merging operations. These transition costs included approximately $77 million for severance and related expenses associated with staff reductions. All 721 of accrued staff terminations have occurred. The staff reductions were non-bargaining positions mainly in corporate and operations support areas. Other transition and integration costs included amounts incurred for facility consolidation, systems integration, regulatory transition, merger communications and operations integration assistance.

      Accrued Special Charges — The following table summarizes activity related to accrued special charges in 2002 and 2001:

                                                           
Dec. 31, Dec. 31, Dec. 31,
2000 Expensed Payments 2001 Expensed Payments 2002
Liability* 2001 2001 Liability* 2002 2002 Liability*







(Millions of dollars)
Special charge activities for utility subsidiaries:
                                                       
 
NSP-Minnesota
  $ 19     $ 14     $ (28 )   $ 5     $ 4     $ (7 )   $ 2  
 
NSP-Wisconsin
    3       2       (3 )     2       1       (3 )      
 
PSCo.
    2       15       (15 )     2       1       (3 )      
 
SPS
    1       5       (5 )     1             (1 )      


Reported on the balance sheets in other current liabilities.

 
3. Short-Term Borrowings (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      Notes Payable and Commercial Paper — Information regarding notes payable and commercial paper for the years ended Dec. 31, 2002 and 2001 is:

                   
2002 2001


(Thousands of dollars,
except interest rates)
NSP — Minnesota
               
 
Notes payable to banks
  $ 69     $ 184  
 
Commercial paper
          381,000  
     
     
 
 
Total short-term debt
  $ 69     $ 381,184  
     
     
 
 
Weighted average interest rate at year end
    4.40 %     2.16 %
PSCo
               
 
Notes payable to banks
  $ 88,074     $  
 
Commercial paper
          562,812  
     
     
 
 
Total short-term debt
  $ 88,074     $ 562,812  
     
     
 
 
Weighted average interest rate at year end
    2.42 %     2.76 %
SPS
               
 
Notes payable to banks
  $     $  
 
Commercial paper
           
     
     
 
 
Total short-term debt
  $     $  
     
     
 
 
Weighted average interest rate at year end
    n/a       n/a  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      NSP-Wisconsin has an intercompany borrowing arrangement with NSP-Minnesota, with interest charged at NSP-Minnesota’s short-term borrowing rate. At Dec. 31, 2002 and 2001, NSP-Wisconsin had $6.9 million and $34.3 million, respectively, in short-term borrowings. The weighted average interest rate for NSP-Wisconsin was 4.40 percent at Dec. 31, 2002 and 2.16 percent at Dec. 31, 2001.

      Bank Lines of Credit — At Dec. 31, 2002, NSP-Minnesota, PSCo and SPS had credit facilities with several banks. They paid for these lines of credit with fee payments.

                         
Period Beginning Period Amount



(Millions of dollars)
NSP-Minnesota
    August 2002       364  days     $ 300  
PSCo.
    June 2002       364  days     $ 530  
SPS
    February 2002       364  days     $ 250  

      The SPS $250 million facility expired on Feb. 18, 2003 and was replaced on that date with a $100 million unsecured, 364-day credit agreement. The facilities provide short-term financing in the form of bank loans and letters of credit.

      The credit facilities of NSP-Minnesota and PSCo are secured by first mortgage bonds and first collateral trust bonds, respectively.

4.                Long-Term Debt (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      Except for SPS and other minor exclusions, all property of Xcel Energy’s utility subsidiaries is subject to the liens of their first mortgage indentures, which are contracts between the companies and their bondholders. In addition, certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.

      The utility subsidiaries’ first mortgage bond indentures provide for the ability to have sinking fund requirements. These annual sinking fund requirements are 1 percent of the highest principal amount of the series of first mortgage bond at any time outstanding. Sinking fund requirements at NSP-Wisconsin and PSCo are $2.6 million and are for one series of first mortgage bonds for each. Such sinking fund obligations may be satisfied with property additions or cash. NSP-Minnesota and SPS have no sinking fund requirements.

      NSP-Minnesota’s 2011 series bonds are redeemable upon seven days notice at the option of the bondholder. Because of the terms that allow the holders to redeem these bonds on short notice, we include them in the current portion of long-term debt reported under current liabilities on the Consolidated Balance Sheet.

      In addition, NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $825 million in additional cash dividends on common stock at Dec. 31, 2002.

      Maturities and sinking fund requirements for long-term debt for our utility subsidiaries are listed in the following table:

                                 
NSP-Minnesota NSP-Wisconsin PSCo SPS




(Millions of dollars)
2003
  $ 226     $ 41     $ 284     $  
2004
    4       1       149        
2005
    75       1       138        
2006
    5       1       129       500  
2007
    3       1       104        

      Extraordinary Item — During the fourth quarter of 2001, PSCo’s subsidiary, 1480 Welton, Inc., redeemed its long-term debt and in doing so incurred redemption premiums and other costs of $2.5 million. These costs are reported as an Extraordinary Item on PSCo’s Consolidated Statements of Income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.     Preferred Stock (PSCo and SPS)

      SPS and PSCo have authorized the issue of preferred shares.

                         
Preferred Shares Preferred Shares
Authorized Par Value Outstanding



SPS
    10,000,000     $ 1.00       none  
PSCo.
    10,000,000     $ 0.01       none  
 
6. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts (NSP-Minnesota, PSCo and SPS)

      NSP Financing I, a wholly owned, special-purpose subsidiary trust of NSP-Minnesota, has $200 million of 7.875 percent trust preferred securities issued and outstanding that mature in 2037. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments on debentures issued by NSP-Minnesota and held by the subsidiary trust, which are eliminated in consolidation. The preferred securities are redeemable at the option of NSP-Minnesota at $25 per share. Distributions and redemption payments are guaranteed by NSP-Minnesota.

      PSCo Capital Trust I, a wholly owned, special-purpose subsidiary trust of PSCo, has $194 million of 7.60 percent trust preferred securities issued and outstanding that mature in 2038. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments on debentures issued by PSCo and held by the subsidiary trust, which are eliminated in consolidation. The securities are redeemable at the option of PSCo after May 2003, at 100 percent of the principal amount outstanding plus accrued interest. Distributions and redemption payments are guaranteed by PSCo.

      SPS Capital I, a wholly owned, special-purpose subsidiary trust of SPS, has $100 million of 7.85 percent trust preferred securities issued and outstanding that mature in 2036. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments on debentures issued by SPS and held by the subsidiary trust, which are eliminated in consolidation. The securities are redeemable at the option of SPS, at 100 percent of the principal amount plus accrued interest. Distributions and redemption payments are guaranteed by SPS.

      Distributions paid to preferred security holders are reflected as a financing cost in the accompanying Consolidated Statements of Income along with interest expense.

 
7. Joint Plant Ownership (NSP-Minnesota and PSCo)

      The investments by Xcel Energy’s utility subsidiaries in jointly owned plants as of Dec. 31, 2002 are:

                                   
Construction
Plant in Accumulated Work in
Service Depreciation Progress Ownership %




(Thousands of dollars)
NSP-Minnesota-Sherco Unit 3
  $ 612,643     $ 291,754     $ 943       59.0  
PSCo:
                               
 
Hayden Unit 1
    84,486       38,429       446       75.5  
 
Hayden Unit 2
    79,882       42,291       6       37.4  
 
Hayden Common Facilities
    27,339       3,300       250       53.1  
 
Craig Units 1 and 2
    59,636       31,963       258       9.7  
 
Craig Common Facilities, Units 1, 2 and 3
    18,473       9,029       3,409       6.5 - 9.7  
 
Transmission Facilities, including Substations
    89,254       29,365       1,208       42.0 - 73.0  
     
     
     
         
Total PSCo.
  $ 359,070     $ 154,377     $ 5,577          
     
     
     
         

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      NSP-Minnesota is part owner of Sherco 3, an 860-megawatt coal-fired electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. The PSCo assets include approximately 320 megawatts of jointly owned generating capacity. Both NSP-Minnesota and PSCo’s share of operating expenses and construction expenditures are included in utility operating expenses. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs.

 
8. Income Taxes (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

     NSP-Minnesota

      Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

                           
2002 2001 2000



Federal statutory rate
    35.0 %     35.0 %     35.0 %
Increases (decreases) in tax from:
                       
 
State income taxes, net of federal income tax benefit
    5.6 %     5.9 %     7.2 %
 
Life insurance policies
    (0.3 )%     (0.3 )%     (0.3 )%
 
Tax credits recognized
    (3.8 )%     (2.4 )%     (4.5 )%
 
Regulatory differences — utility plant items
    (0.3 )%     2.3 %     3.8 %
 
Non-deductibility of merger costs
                4.5 %
 
Other — net
    (1.1 )%     (1.5 )%     (0.4 )%
     
     
     
 
Effective income tax rate
    35.1 %     39.0 %     45.3 %
     
     
     
 

      Income taxes comprise the following expense (benefit) items (Thousands of dollars):

                           
2002 2001 2000



Current federal tax expense
  $ 114,222     $ 113,670     $ 80,085  
Current state tax expense
    31,740       16,791       19,980  
Current federal tax credits
    (636 )     (628 )     (799 )
Deferred federal tax credits
    (20,973 )     (3,740 )     (1,206 )
Deferred state tax expense (credits)
    (5,308 )     14,154       2,546  
Deferred investment tax credits
    (10,904 )     (7,515 )     (8,415 )
     
     
     
 
 
Total income tax expense
  $ 108,141     $ 132,732     $ 92,191  
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

                     
2002 2001


(Thousands of dollars)
Deferred tax liabilities:
               
 
Differences between book and tax bases of property
  $ 706,256     $ 724,096  
 
Regulatory assets
    73,890       69,851  
 
Tax benefit transfer leases
    10,964       14,724  
 
Other
    11,029       22,536  
     
     
 
   
Total deferred tax liabilities
  $ 802,139     $ 831,207  
     
     
 
Deferred tax assets:
               
 
Regulatory liabilities
  $ 25,113     $ 39,892  
 
Employee benefits and other accrued liabilities
    42,633       45,229  
 
Deferred investment tax credits
    30,088       33,168  
 
Other
    8,235       8,072  
     
     
 
   
Total deferred tax assets
  $ 106,069     $ 126,361  
     
     
 
   
Net deferred tax liability
  $ 696,070     $ 704,846  
     
     
 

     NSP-Wisconsin

      Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

                           
2002 2001 2000



Federal statutory rate
    35.0 %     35.0 %     35.0 %
Increases (decreases) in tax from:
                       
 
State income taxes, net of federal income tax benefit
    5.7 %     4.4 %     5.2 %
 
Life insurance policies
    (0.1 )%            
 
Tax credits recognized
    (0.9 )%     (1.4 )%     (1.6 )%
 
Equity income from unconsolidated affiliates
    (0.1 )%     (0.4 )%     (0.4 )%
 
Regulatory differences — utility plant items
    0.6 %     (1.1 )%     (1.0 )%
 
Non-deductibility of merger costs
                3.2 %
 
Other — net
    0.2 %     0.3 %     0.2 %
     
     
     
 
Effective income tax rate
    40.4 %     36.8 %     40.6 %
     
     
     
 

      Income taxes comprise the following expense (benefit) items (Thousands of dollars):

                           
2002 2001 2000



Current federal tax expense
  $ 13,143     $ 15,691     $ 14,924  
Current state tax expense
    2,907       3,237       3,500  
Deferred federal tax expense
    16,569       2,462       2,487  
Deferred state tax expense
    5,113       587       606  
Deferred investment tax credits
    (807 )     (819 )     (827 )
     
     
     
 
 
Total income tax expense
  $ 36,925     $ 21,158     $ 20,690  
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

                     
2002 2001


(Thousands of dollars)
Deferred tax liabilities:
               
 
Differences between book and tax bases of property
  $ 132,044     $ 113,039  
 
Regulatory assets
    21,744       17,583  
 
Other
    20,048       14,777  
     
     
 
   
Total deferred tax liabilities
  $ 173,836     $ 145,399  
     
     
 
Deferred tax assets:
               
 
Regulatory liabilities
  $ 5,040     $ 6,877  
 
Deferred investment tax credits
    6,019       6,284  
 
Employee benefits and other accrued liabilities
    12,773       8,786  
 
Other
    680       1,183  
     
     
 
   
Total deferred tax assets
  $ 24,512     $ 23,130  
     
     
 
   
Net deferred tax liability
  $ 149,324     $ 122,269  
     
     
 

     PSCo

      Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

                           
2002 2001 2000



Federal statutory rate
    35.0 %     35.0 %     35.0 %
Increases (decreases) in tax from:
                       
 
State income taxes, net of federal income tax benefit
    2.7 %     3.3 %     1.9 %
 
Life insurance policies
    (6.2 )%     (5.1 )%     (6.8 )%
 
Tax credits recognized
    (3.0 )%     (1.4 )%     (3.1 )%
 
Regulatory differences — utility plant items
    2.6 %     2.4 %     2.7 %
 
Non-deductibility of merger costs
                3.3 %
 
Extraordinary item
          (0.1 )%      
 
Other — net
    1.6 %     (1.6 )%     1.4 %
     
     
     
 
Effective income tax rate including extraordinary items
    32.7 %     32.5 %     34.4 %
 
Extraordinary items
          0.1 %      
     
     
     
 
Effective income tax rate excluding extraordinary items
    32.7 %     32.6 %     34.4 %
     
     
     
 

      Income taxes comprise the following expense (benefit) items (Thousands of dollars):

                           
2002 2001 2000



Current federal tax expense
  $ 20,833     $ 116,173     $ 91,281  
Current state tax expense
    2,338       20,687       7,037  
Current tax credits
    (7,087 )     (1,523 )     (3,699 )
Deferred federal tax expense
    103,108       1,371       11,835  
Deferred state tax expense
    14,159       (55 )     1,797  
Deferred investment tax credits
    (4,665 )     (4,152 )     (5,481 )
     
     
     
 
 
Income tax expense excluding extraordinary items
  $ 128,686     $ 132,501     $ 102,770  
Tax expense (benefit) on extraordinary item
          (940 )      
     
     
     
 
 
Total income tax expense
  $ 128,686     $ 131,561     $ 102,770  
     
     
     
 

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      The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

                     
2002 2001


(Thousands of dollars)
Deferred tax liabilities:
               
 
Differences between book and tax bases of property
  $ 567,817     $ 504,694  
 
Employee benefits and other accrued liabilities
    56,840       52,132  
 
Regulatory assets
    36,469       39,069  
 
Other
    35,745       33,556  
     
     
 
   
Total deferred tax liabilities
  $ 696,871     $ 629,451  
     
     
 
Deferred tax assets:
               
 
Deferred investment tax credits
  $ 28,501     $ 30,403  
 
Regulatory liabilities
    17,375       18,646  
 
Other comprehensive income
    64,329       621  
 
Other
    11,362       49,375  
     
     
 
   
Total deferred tax assets
  $ 121,567     $ 99,045  
     
     
 
   
Net deferred tax liability
  $ 575,304     $ 530,406  
     
     
 

     SPS

      Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

                           
2002 2001 2000



Federal statutory rate
    35.0 %     35.0 %     35.0 %
Increases (decreases) in tax from:
                       
 
State income taxes, net of federal income tax benefit
    (0.3 )%     1.5 %     0.9 %
 
Life insurance policies
                (0.1 )%
 
Tax credits recognized
    (0.2 )%     (0.2 )%     (0.2 )%
 
Regulatory differences — utility plant items
    1.9 %     1.8 %     2.9 %
 
Non-deductibility of merger costs
                2.1 %
 
Extraordinary item
          (0.4 )%     5.8 %
 
Other — net
    0.6 %     (0.5 )%     (0.7 )%
     
     
     
 
Effective income tax rate including extraordinary items
    37.0 %     37.2 %     45.7 %
 
Extraordinary items
          0.4 %     (5.8 )%
     
     
     
 
Effective income tax rate excluding extraordinary items
    37.0 %     37.6 %     39.9 %
     
     
     
 

      Income taxes comprise the following expense (benefit) items (Thousands of dollars):

                           
Current federal tax expense
  $ 15,913     $ 95,648     $ 13,063  
Current state tax expense
    (2,185 )     5,221       815  
Deferred federal tax expense
    28,298       (28,493 )     43,729  
Deferred state tax expense
    1,587       (951 )     1,419  
Deferred investment tax credits
    (250 )     (250 )     (250 )
     
     
     
 
 
Income tax expense excluding extraordinary items
    43,363       71,175       58,776  
Tax expense (benefit) on extraordinary items
          5,747       (8,549 )
     
     
     
 
 
Total income tax expense
  $ 43,363     $ 76,922     $ 50,227  
     
     
     
 

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      The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

                     
2002 2001


(Thousands of dollars)
Deferred tax liabilities:
               
 
Differences between book and tax bases of property
  $ 357,874     $ 330,601  
 
Regulatory assets
    27,617       28,586  
 
Employee benefits and other accrued liabilities
    32,719       24,645  
 
Other
    13,034       18,669  
     
     
 
   
Total deferred tax liabilities
  $ 431,244     $ 402,501  
     
     
 
Deferred tax assets:
               
 
Deferred investment tax credits
  $ 1,519     $ 1,609  
 
Regulatory liabilities
    844       895  
 
Other
    16,048       17,158  
     
     
 
   
Total deferred tax assets
  $ 18,411     $ 19,662  
     
     
 
   
Net deferred tax liability
  $ 412,833     $ 382,839  
     
     
 
 
9. Benefit Plans and Other Postretirement Benefits (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      Xcel Energy offers various benefit plans to its benefit employees. Approximately 51 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2002, NSP-Minnesota had 2,246 and NSP-Wisconsin had 419 union employees covered under a collective bargaining agreement, which expires at the end of 2004. PSCo had 2,193 union employees covered under a collective bargaining agreement, which expires in May 2003. SPS had 757 union employees covered under a collective bargaining agreement, which expires in October 2005.

      Pension Benefits — Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all utility 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. Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities.

      A comparison of the actuarially computed pension benefit obligation and plan assets for Xcel Energy plans which benefit utility subsidiary employees, on a combined basis, is presented in the following table:

                 
2002 2001


(Thousands of dollars)
Change in Benefit Obligation
               
Obligation at January 1
  $ 2,409,186     $ 2,254,138  
Service cost
    65,649       57,521  
Interest cost
    172,377       172,159  
Acquisitions
    7,848        
Plan amendments
    3,903       2,284  
Actuarial loss
    65,763       108,754  
Settlements
    (994 )      
Special termination benefits
    4,445        
Benefit payments
    (222,601 )     (185,670 )
     
     
 
Obligation at December 31
  $ 2,505,576     $ 2,409,186  
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                 
2002 2001


(Thousands of dollars)
Change in Fair Value of Plan Assets
               
Fair value of plan assets at January 1
  $ 3,267,586     $ 3,689,157  
Actual return on plan assets
    (404,940 )     (235,901 )
Employer contributions — acquisitions
    912        
Settlements
    (994 )      
Benefit payments
    (222,601 )     (185,670 )
     
     
 
Fair value of plan assets at December 31
  $ 2,639,963     $ 3,267,586  
     
     
 
Funded Status of Plans at December 31
               
Net asset
  $ 134,387     $ 858,400  
Unrecognized transition asset
    (2,003 )     (9,317 )
Unrecognized prior service cost
    224,651       242,313  
Unrecognized (gain) loss
    165,927       (712,571 )
     
     
 
Xcel Energy net pension amounts recognized on balance sheet
  $ 522,962     $ 378,825  
     
     
 
NSP-Minnesota prepaid pension asset recorded
  $ 263,713     $ 188,287  
     
     
 
NSP-Wisconsin prepaid pension asset recorded
    38,557       28,563  
     
     
 
PSCo prepaid pension asset recorded
          60,797  
     
     
 
PSCo intangible asset recorded — prior service costs
    6,874        
     
     
 
PSCo accrued benefit liability recorded
    (3,182 )      
     
     
 
PSCo minimum pension liability
    (104,773 )      
     
     
 
PSCo accumulated other comprehensive income recorded — pretax
    169,958        
     
     
 
SPS prepaid pension asset recorded
    105,044       82,503  
     
     
 
Significant Assumptions
               
Discount rate for year end valuation
    6.75 %     7.25 %
Expected average long term increase in compensation level
    4.00 %     4.50 %
Expected average long term rate of return on assets
    9.50 %     9.50 %

      During 2002, one of Xcel Energy’s pension plans which provides benefits to employees of PSCo became underfunded, with projected benefit obligations of $590 million exceeding plan assets of $452 million on Dec. 31, 2002. All other Xcel Energy plans, which provide benefits to employees of the utility subsidiaries, in the aggregate had plan assets of $2,188 million and projected benefit obligations of $1,916 million on Dec. 31, 2002. A minimum pension liability of $105 million was recorded by PSCo related to the underfunded plan as of that date. A corresponding reduction in Accumulated Other Comprehensive Income (a component of Common Stockholder’s Equity) was also recorded by PSCo 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 Stockholder’s Equity of PSCo was reduced by $105 million at Dec. 31, 2002.

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      The components of net periodic pension cost (credit) for Xcel Energy plans which benefit employees of its utility subsidiaries are:

                         
Xcel Energy 2002 2001 2000




(Thousands of dollars)
Service cost
  $ 65,649     $ 57,521     $ 59,066  
Interest cost
    172,377       172,159       172,063  
Expected return on plan assets
    (339,932 )     (325,635 )     (292,580 )
Curtailment
          1,121        
Amortization of transition asset
    (7,314 )     (7,314 )     (7,314 )
Amortization of prior service cost
    22,663       20,835       19,197  
Amortization of net gain
    (69,264 )     (72,413 )     (60,676 )
     
     
     
 
Net periodic pension credit under SFAS No. 87
  $ (155,821 )   $ (153,726 )   $ (110,244 )
     
     
     
 
NSP-Minnesota
                       
Net periodic pension credit under SFAS No. 87
  $ (71,928 )   $ (76,509 )   $ (56,182 )
Credits not recognized due to effects of regulation
    71,928       76,509       56,182  
     
     
     
 
Net benefit cost (credit) recognized for financial reporting
  $     $     $  
     
     
     
 
NSP-Wisconsin
                       
Net SFAS No. 87 benefit credit recognized for reporting
  $ (9,994 )   $ (10,002 )   $ (6,369 )
     
     
     
 
PSCo
                       
Net SFAS No. 87 benefit credit recognized for reporting
  $ (14,747 )   $ (17,311 )   $ (16,825 )
     
     
     
 
SPS
                       
Net SFAS No. 87 benefit credit recognized for reporting
  $ (22,235 )   $ (21,131 )   $ (21,352 )
     
     
     
 

      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.

      Defined Contribution Plans — Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total contributions to these plans, which benefit employees of the utility subsidiaries, were approximately $19 million in 2002, $23 million in 2001, and $24 million in 2000. The contribution for 2002 included $3.1 million for NSP-Minnesota, $0.7 million for NSP-Wisconsin, $5.9 million for PSCo and $1.9 million for SPS.

      Until May 6, 2002 Xcel Energy had a leveraged employee stock ownership plan (ESOP) that covered substantially all employees of NSP-Minnesota and NSP-Wisconsin. Xcel Energy made contributions to this noncontributory, defined contribution plan to the extent it realized tax savings from dividends paid on certain ESOP shares. ESOP contributions had no material effect on Xcel Energy earnings because the contributions were essentially offset by the tax savings provided by the dividends paid on ESOP shares. Xcel Energy allocated leveraged ESOP shares to participants when it repaid ESOP loans with dividends on stock held by the ESOP.

      In May 2002 the ESOP was merged into the Xcel Retirement Savings 401(k) Plan. Starting with the 2003 plan year, the ESOP component of the 401(k) will no longer be leveraged.

      Xcel Energy’s leveraged ESOP held no shares of Xcel Energy common stock at the end of 2002, 10.7 million shares of Xcel Energy common stock at May 6, 2002, 10.5 million shares of Xcel Energy common stock at the end of 2001, and 12.0 million shares of Xcel Energy common stock at the end of 2000. Xcel Energy excluded the following average number of uncommitted leveraged ESOP shares from earnings per share calculations: 0.7 million in 2002, 0.9 million in 2001, and 0.7 million in 2000. On Nov. 19, 2002, Xcel Energy paid off all of the ESOP loans. All uncommitted ESOP shares were released and will be used by Xcel Energy for its employer matching contribution to its 401(k) plan.

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      Postretirement Health Care Benefits — Xcel Energy has contributory health and welfare benefit plans that provide 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. However, employees of the former NCE who retired in 2002 continue to receive employer subsidized health care benefits. Employees of the former NSP who retired after 1998 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. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. 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.

      Certain state agencies, which regulate Xcel Energy’s utility subsidiaries, have also 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. Minnesota and Wisconsin retail regulators required external funding of accrued SFAS No. 106 costs to the extent such funding is tax advantaged. Plan assets held in external funding trusts principally consist of investments in equity mutual funds, fixed-income securities and cash equivalents.

      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:

                 
2002 2001


(Thousands of dollars)
Change in Benefit Obligation
               
Obligation at January 1
  $ 662,853     $ 558,994  
Service cost
    5,967       5,258  
Interest cost
    48,304       45,177  
Acquisitions
    773        
Plan amendments
           
Plan participants’ contributions
    5,755       3,517  
Actuarial loss
    57,175       98,655  
Special termination benefits
    (173 )      
Benefit payments
    (44,263 )     (48,748 )
     
     
 
Obligation at December 31
  $ 736,391     $ 662,853  
     
     
 
Change in Fair Value of Plan Assets
               
Fair value of plan assets at January 1
  $ 242,803     $ 223,266  
Actual return on plan assets
    (13,632 )     (3,701 )
Plan participants’ contributions
    5,755       3,517  
Employer contributions
    60,320       68,469  
Benefit payments
    (44,263 )     (48,748 )
     
     
 
Fair value of plan assets at December 31
  $ 250,983     $ 242,803  
     
     
 

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2002 2001


(Thousands of dollars)
Funded Status of Plan at December 31
               
Net obligation
  $ 485,408     $ 420,050  
Unrecognized transition asset (obligation)
    (169,328 )     (186,099 )
Unrecognized prior service cost
    10,675       12,559  
Unrecognized gain (loss)
    (200,634 )     (132,354 )
     
     
 
Total accrued benefit liability recorded
  $ 126,121     $ 114,156  
     
     
 
NSP-Minnesota accrued benefit liability recorded
  $ 58,660     $ 59,462  
     
     
 
NSP-Wisconsin accrued benefit liability recorded
  $ 4,899     $ 5,052  
     
     
 
PSCo accrued benefit liability recorded
  $ 44,876     $ 36,350  
     
     
 
SPS accrued benefit liability recorded
  $ 9,772     $ 6,656  
     
     
 
Significant Assumptions
               
Discount rate for year end valuation
    6.75 %     7.25 %
Expected average long term rate of return on assets
    8.0 - 9.0 %     9.0 %

      The assumed health care cost trend rate for 2002 is approximately 8 percent, decreasing gradually to 5.5 percent in 2007 and remaining level thereafter. A 1 percent change in the assumed health care cost trend rate would have the following effects:

                                         
Xcel Energy NSP-Minnesota NSP-Wisconsin PSCo SPS





(Thousands of dollars)
Effect of changes in the assumed health care cost trend rate
                                       
1 percent increase in APBO components at Dec. 31, 2002
  $ 79,028     $ 12,848     $ 2,181     $ 45,934     $ 8,115  
1 percent decrease in APBO components at Dec. 31, 2002
    (65,755 )     (11,123 )     (1,889 )     (37,770 )     (6,672 )
1 percent increase in service and interest components of the net periodic cost
    6,285       833       142       3,668       674  
1 percent decrease in service and interest components of the net periodic cost
    (5,181 )     (724 )     (124 )     (2,985 )     (549 )

      The components of net periodic postretirement benefit cost of Xcel Energy’s plans are:

                         
2002 2001 2000



(Thousands of dollars)
Xcel Energy
                       
Service cost
  $ 5,967     $ 6,160     $ 5,679  
Interest cost
    48,304       46,579       43,477  
Expected return on plan assets
    (21,011 )     (18,920 )     (17,902 )
Amortization of transition obligation
    16,771       16,771       16,773  
Amortization of prior service credit
    (1,130 )     (1,235 )     (1,211 )
Amortization of net loss
    5,380       1,457       915  
     
     
     
 
Net periodic postretirement benefit cost under SFAS No. 106
    54,281       50,812       47,731  
Additional cost recognized due to effects of regulation
    4,043       3,738       6,641  
     
     
     
 
Net cost recognized for financial reporting
  $ 58,324     $ 54,550     $ 54,372  
     
     
     
 

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2002 2001 2000



(Thousands of dollars)
NSP-Minnesota
                       
Net periodic postretirement benefit cost recognized — SFAS No. 106
  $ 12,667     $ 11,124     $ 10,718  
     
     
     
 
NSP-Wisconsin
                       
Net periodic postretirement benefit cost recognized — SFAS No. 106
  $ 1,531     $ 1,155     $ 852  
     
     
     
 
PSCo
                       
Net periodic postretirement benefit cost recognized — SFAS No. 106
  $ 30,619     $ 29,910     $ 28,323  
Additional cost recognized due to effects of regulation
    3,890       3,890       3,890  
     
     
     
 
Net cost recognized for financial reporting
  $ 34,509     $ 33,800     $ 32,213  
     
     
     
 
SPS
                       
Net periodic postretirement benefit cost recognized — SFAS No. 106
  $ 5,542     $ 3,254     $ 3,696  
Additional cost (credit) recognized due to effects of regulation
    153       (152 )     2,751  
     
     
     
 
Net cost recognized for financial reporting
  $ 5,695     $ 3,102     $ 6,447  
     
     
     
 

10.     Extraordinary Items (SPS)

      In the second quarter of 2000, SPS discontinued regulatory accounting under SFAS No. 71 for the generation portion of its business due to the issuance of a written order by the PUCT in May 2000, addressing the implementation of electric utility restructuring. SPS’ transmission and distribution business continued to meet the requirements of SFAS No. 71, as that business was expected to remain regulated. During the second quarter of 2000, SPS wrote off its generation related regulatory assets and other deferred costs totaling approximately $19.3 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million. During the third quarter of 2000, SPS recorded an extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer and defeasance of first mortgage bonds. The first mortgage bonds were defeased to facilitate the legal separation of generation, transmission and distribution assets, which was expected to eventually occur in 2001 under restructuring requirements in effect in 2000.

      In March 2001, the state of New Mexico enacted legislation that amended its Electric Utility Restructuring Act of 1999 and delayed customer choice until 2007. SPS has requested recovery of its costs incurred to prepare for customer choice in New Mexico. A decision on this and other matters is pending before the NMPRC. SPS expects to receive future regulatory recovery of these costs.

      In June 2001, the Governor of Texas signed legislation postponing the deregulation and restructuring of SPS until at least 2007. This legislation amended the 1999 legislation, SB-7, which provided for retail electric competition beginning January 2002. Under the amended legislation, prior PUCT orders issued in connection with the restructuring of SPS are considered null and void. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7.

      As a result of these legislative developments, SPS reapplied the provisions of SFAS No. 71 for its generation business during the second quarter of 2001. More than 95 percent of SPS’ retail electric revenues are from operations in Texas and New Mexico. Because of the delays to electric restructuring passed by Texas and New Mexico, SPS’ previous plans to implement restructuring, including the divestiture of generation assets, have been abandoned. Accordingly, SPS will continue to be subject to rate regulation under traditional

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

cost-of-service regulation, consistent with its past accounting and ratemaking practices for the foreseeable future (at least until 2007).

      During the fourth quarter of 2001, SPS completed a $500 million medium-term debt financing with the proceeds used to reduce short-term borrowings that had resulted from the 2000 defeasance. In its regulatory filings and communications, SPS proposed to amortize its defeasance costs over the five-year life of the refinancing, consistent with historical ratemaking, and requested incremental rate recovery of $25 million of other restructuring costs in Texas and New Mexico. These nonfinancing restructuring costs have been deferred and are being amortized consistent with rate recovery. Management believes it will be allowed full recovery of its prudently incurred costs. Based on these 2001 events and the corresponding reduced uncertainty surrounding the financial impacts of the delay in restructuring, SPS restored certain regulatory assets totaling $17.6 million as of Dec. 31, 2001, and reported related after-tax extraordinary income of $11.8 million. Regulatory assets previously written off in 2000 were restored only for items being recovered in current rates and for items where future rate recovery is considered probable.

      See Note 2 for discussion of special charges related to SPS restructuring in 2002.

11.                 Financial Instruments (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Fair Values

      The estimated December 31 fair values of Xcel Energy’s utility subsidiaries’ recorded financial instruments were as follows:

                                 
2002 2001


Carrying Carrying
Amount Fair Value Amount Fair Value




(Thousands of dollars)
NSP-Minnesota
                               
Mandatorily redeemable preferred securities of subsidiary trust
  $ 200,000     $ 188,080     $ 200,000     $ 200,800  
Long-term investments
    619,502       619,452       596,196       596,196  
Long-term debt, including current portion
    1,796,400       1,884,050       1,192,354       1,190,175  
                                 
2002 2001


Carrying Carrying
Amount Fair Value Amount Fair Value




(Thousands of dollars)
NSP-Wisconsin
                               
Long-term investments
  $ 10     $ 10     $ 9     $ 9  
Long-term debt, including current portion
    313,142       320,884       313,088       317,490  
                                 
2002 2001


Carrying Carrying
Amount Fair Value Amount Fair Value




(Thousands of dollars)
PSCo
                               
Mandatorily redeemable preferred securities of subsidiary trust
  $ 194,000     $ 178,868     $ 194,000     $ 189,732  
Long-term investments
    6,598       6,598       4,727       4,727  
Long-term debt, including current portion
    2,064,225       2,147,775       1,482,229       1,523,735  

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2002 2001


Carrying Carrying
Amount Fair Value Amount Fair Value




(Thousands of dollars)
SPS
                               
Mandatorily redeemable preferred securities of subsidiary trust
  $ 100,000     $ 96,400     $ 100,000     $ 100,200  
Long-term investments
    9,622       8,098       6,017       6,744  
Long-term debt, including current portion
    725,662       748,666       725,375       708,586  

      The carrying amount of cash, cash equivalents, short-term investments and other financial instruments approximates fair value because of the short maturity of those instruments. The fair values of Xcel Energy’s utility subsidiaries’ long-term investments, mainly debt securities in an external nuclear decommissioning fund held by NSP-Minnesota, are estimated based on quoted market prices for those or similar investments. The fair value of Xcel Energy’s utility subsidiaries’ long-term debt and the mandatorily redeemable preferred securities are 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, 2002 and 2001. These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date and current estimates of fair values may differ significantly from the amounts presented herein.

Guarantees

      Xcel Energy’s utility subsidiaries had the following guarantees outstanding on Dec. 31, 2002:

 
Guarantor SPS
 
Guarantee amount $17.7 million
 
Exposure under guarantee $11.0 million
 
Nature of guarantee Guarantee for certain obligations of a customer in connection with an agreement for the sale of electric power. These obligations relate to the construction of certain utility property that, in the event of default by the customer, would revert to SPS.
 
Term of guarantee Expires September 2003.
 
Triggering events or circumstances requiring performance under the guarantee In the event the customer should default on their obligation to pay the receivables, SPS would be responsible for the payment of the remaining receivables.
 
Current carrying amount of the liability n/a
 
Nature of any recourse provisions SPS would hold title to the collateral and would not be required to transfer the ownership of the additional transmission related facilities to the customer. SPS would also have access to the customer sinking fund account, which is approximately $6.7 million.
 
Any assets held as collateral Electric transmission system.
 
Guarantor NSP-Minnesota
 
Guarantee amount $6.2 million
 
Exposure under guarantee $0.6 million

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Nature of guarantee NSP-Minnesota sold a portion of its receivables (consisting of customer loans to local and state government entities for energy efficiency improvements) to a third party. Under the sales agreements, NSP-Minnesota is required to guarantee repayment to the third party of the remaining loan balances. Based on prior collection experience of these loans, losses under the loan guarantees, if any, are not believed to have a material impact on the results of operations.
 
Term of guarantee Latest expiration in 2007.
 
Triggering events or circumstances requiring performance under the guarantee Non-payment by the government entity on the underlying debt.
 
Current carrying amount of the liability n/a
 
Nature of any recourse provisions None
 
Any assets held as collateral Security interest in the underlying loan agreements, contracts and arrangements between NSP-Minnesota and the government entities.
 
Guarantor NSP-Wisconsin
 
Guarantee amount $1.4 million
 
Exposure under guarantee $0.1 million
 
Nature of guarantee NSP-Wisconsin guarantees customer loans to encourage business growth and expansion.
 
Term of guarantee Latest expiration in 2006.
 
Triggering events or circumstances requiring performance under the guarantee Non-timely payment of the obligations or at the time the Debtor becomes the subject of bankruptcy or other insolvency proceedings.
 
Current carrying amount of the liability n/a
 
Nature of any recourse provisions None
 
Any assets held as collateral None
 
Guarantor NSP-Minnesota
 
Guarantee amount $0.2 million
 
Exposure under guarantee $0.0 million
 
Nature of guarantee Primarily bonds to guarantee restoration of sites that have been disturbed to access utility equipment.
 
Term of guarantee 2003 through 2004.
 
Triggering events or circumstances requiring performance under the guarantee Failure of NSP-Minnesota to perform under the agreement which is the subject of the relevant bond. In addition, per the indemnity agreement between NSP-Minnesota and the various surety compa-

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  nies, the surety companies have the discretion to demand collateral be posted.
 
Current carrying amount of the liability n/a
 
Nature of any recourse provisions None
 
Any assets held as collateral None
 
Guarantor PSCo
 
Guarantee amount $0.5 million
 
Exposure under guarantee $0.1 million
 
Nature of guarantee Primarily bonds to guarantee restoration of sites that have been disturbed to access utility equipment.
 
Term of guarantee August 2003
 
Triggering events or circumstances requiring performance under the guarantee Failure of PSCo to perform under the agreement which is the subject of the relevant bond. In addition, per the indemnity agreement between PSCo and the various surety companies, the surety companies have the discretion to demand collateral be posted.
 
Current carrying amount of the liability n/a
 
Nature of any recourse provisions None
 
Any assets held as collateral None

Fair Value of Derivative Instruments

      The discussion below briefly describes the derivatives of Xcel Energy’s utility subsidiaries and discloses the respective fair values at Dec. 31, 2002. For more detailed information regarding derivative financial instruments and the related risks, see Note 12 to the Consolidated Financial Statements.

      Interest Rate Swaps — On both Dec. 31, 2002 and 2001, SPS had an interest rate swap, converting variable-rate debt to fixed-rate debt, with a notional amount of $25 million. The fair value of the swap on both Dec. 31, 2002 and 2001 was a liability of approximately $7 million.

      Electric Trading Operations — PSCo and NSP-Minnesota participate in the trading of electricity as a commodity. This trading includes the use of forward contracts, futures and options. PSCo and NSP-Minnesota make purchases and sales at existing market points or combine purchases with available transmission to make sales at other market points. Options and hedges are used to either minimize the risks associated with market prices, or to profit from price volatility related to our purchase and sale commitments.

      As discussed in Note 1, beginning with the third quarter of 2002, PSCo and NSP-Minnesota have presented the results of their electric trading activity net in operating revenue. The Consolidated Statements of Income for 2001 and 2000 have been reclassified to be consistent. In earlier presentations trading activities were presented gross. All financial derivative contracts and contracts that do not include physical delivery are recorded at the amount of the gain or loss received from the contract. The mark-to-market adjustments for these transactions are appropriately reported in the Consolidated Statement of Income in Electric Trading Revenues.

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      The fair value of PSCo’s and NSP-Minnesota’s trading contracts on Dec. 31, 2002 were:

                 
Total Fair Value

PSCo NSP-Minnesota


(Millions of dollars)
Fair value of trading contracts outstanding at Jan. 1, 2002
  $ 7.4     $  
Contracts realized or settled during 2002
    (3.9 )     (4.1 )
Fair value of trading contract additions and changes during the year
    (3.4 )     3.9  
     
     
 
Fair value of contracts outstanding at Dec. 31, 2002*
  $ 0.1     $ (0.2 )
     
     
 


Does not include the impact of ratepayer sharing in Colorado

      The future maturities of PSCo’s and NSP-Minnesota’s trading contracts were:

                         
Maturity less Maturity Total Fair
Source of Fair Value than 1 year 1 to 3 years Value




(Millions of dollars)
Prices actively quoted
  $ (0.1 )   $ 0.0     $ (0.1 )
Prices based on models and other valuation methods (including prices quoted from external sources)
    0.0       0.0       0.0  

      Xcel Energy’s utility subsidiaries’ energy marketing operations use a combination of energy and gas purchased for resale futures and forward contracts, along with physical supply to hedge market risks in the energy market. At December 31, the notional value and fair value of these contracts for the respective years were:

                                 
2002 2001


NSP-Minnesota PSCo NSP-Minnesota PSCo




(Millions of dollars)
Notional value
  $ 34.0     $ (28.3 )   $ 71.8     $ 12.0  
Fair value (liability) asset
    10.6       22.7       (15.1 )     (8.9 )

Letters of Credit

      Xcel Energy’s utility subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. The following table details the letters of credit outstanding for Xcel Energy’s utility subsidiaries at Dec. 31, 2002. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined by the market.

                         
NSP-Minnesota PSCo SPS



(Millions of dollars)
Letters of credit outstanding
  $ 16.8     $ 0.0     $ 9.5  

12.     Derivative Valuation and Financial Impacts (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Use of Derivatives to Manage Risk

      Business and Operational Risk — Xcel Energy’s utility subsidiaries are exposed to commodity price risk in their generation, retail distribution and energy trading operations. NSP-Minnesota and SPS recover purchased energy expenses on a dollar-for-dollar basis. NSP-Minnesota and PSCo recover natural gas costs on a dollar-for-dollar basis. However, NSP-Wisconsin and PSCo have limited exposure to market price risk for the purchase and sale of electric energy. In these jurisdictions, electric energy expenses are recovered based on fixed price limits or under established sharing mechanisms. NSP-Minnesota is authorized to recover certain financial instrument costs, incurred to mitigate wholesale electric and gas commodity price volatility in rates, through the fuel clause adjustment and purchased gas adjustment.

      NSP-Minnesota, PSCo and SPS manage commodity price risk by entering into purchase and sales commitments for electric power and natural gas, long-term contracts for coal supplies and fuel oil, and

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derivative financial instruments. Xcel Energy’s risk management policy allows the utility subsidiaries to manage the market price risk within each rate regulated operation to the extent such exposure exists. Management is limited under the policy to enter into only transactions that reduce market price risk where the rate regulation jurisdiction does not already provide for dollar-for-dollar recovery.

      Interest Rate Risk — Xcel Energy’s utility subsidiaries are exposed to fluctuations in interest rates where they enter into variable rate debt obligations to fund certain power projects being developed or purchased. Exposure to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. Xcel Energy’s risk management policy allows the utility subsidiaries to reduce interest rate exposure from variable rate debt obligations.

      With the exception of short-term borrowings, NSP-Wisconsin does not have variable interest rates; therefore there is limited interest rate risk.

      See Note 11 to the Consolidated Financial Statements for a discussion of SPS’ interest rate swaps.

      Trading Risk — NSP-Minnesota and PSCo conduct various trading operations, including the purchase and sale of electric capacity and energy. Xcel Energy’s risk management policy allows the utility subsidiaries to conduct the trading activity within approved guidelines and limitations as approved by our Risk Management Committee made up of management personnel not involved in trading operations.

Derivatives as Hedges

      2001 Accounting Change — On Jan. 1, 2001, Xcel Energy and its utility subsidiaries adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This statement requires that all derivative instruments as defined by SFAS No. 133 be recorded on the balance sheet at fair value unless exempted. Changes in a derivative instrument’s fair value must be recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the income statement, to the extent effective. SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

      A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be 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 gain or loss on the hedged item to offset the gain or loss on the derivative instrument in the same period. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be 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 currently in earnings.

      Xcel Energy’s utility subsidiaries formally document hedge relationships, including, among other things, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedged transaction. Derivatives are recorded in the balance sheet at fair value. Xcel Energy’s utility subsidiaries also formally assess, both at inception and at least quarterly thereafter, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

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Financial Impacts of Derivatives

      The components of SFAS No. 133 impacts on Other Comprehensive Income for 2002 and 2001, included in Stockholder’s Equity, are detailed in the following table (Millions of dollars).

                         
NSP-Minnesota PSCo SPS



Net unrealized gain (loss) - Jan. 1, 2002
  $ 0.1     $ (4.3 )   $ (4.4 )
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges
    0.0       10.3       0.3  
After-tax net realized (gains) losses on derivative transactions reclassified into earnings
    (0.1 )     (5.0 )     (0.5 )
     
     
     
 
Accumulated other comprehensive income (loss) related to SFAS No 133 at Dec. 31, 2002
  $ 0.0     $ 1.0     $ (4.6 )
     
     
     
 
Net unrealized transition gain (loss) at adoption, Jan. 1, 2001
  $     $ 1.6     $ (2.6 )
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges
    0.1       (26.3 )     (2.4 )
After-tax net realized losses on derivative transactions reclassified into earnings
          20.4       0.6  
     
     
     
 
Accumulated other comprehensive income (loss) related to SFAS No. 133 at Dec. 31, 2001
  $ 0.1     $ (4.3 )   $ (4.4 )
     
     
     
 

      NSP-Minnesota, PSCo and SPS did not realize any material impact to earnings related to ineffective hedges during 2002 and 2001.

      Xcel Energy’s utility subsidiaries record the fair value of derivative instruments in the Consolidated Balance Sheets as separate line items noted as “Derivative Instruments Valuation’ for assets and liabilities, as well as current and non-current.

      Cash Flow Hedges — NSP-Minnesota and PSCo enter into derivative instruments to manage exposure to changes in commodity prices. These derivative instruments take the form of fixed price, floating price or index sales, or purchases and options, such as puts, calls and swaps. These derivative instruments are designated as cash flow hedges for accounting purposes and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At Dec. 31, 2002, NSP-Minnesota and PSCo had various commodity related contracts through April 2003 and January 2009, respectively. Earnings on these cash flow hedges are recorded as the hedged purchase or sales transaction is completed. This could include the physical sale of electric energy or the usage of natural gas to generate electric energy. For the year ended Dec. 31, 2002, NSP-Minnesota reclassified approximately $0.1 million of net after-tax gains from Other Comprehensive Income into earnings. For the year ended Dec. 31, 2002, PSCo reclassified approximately $5.0 million of net after-tax losses from Other Comprehensive Income into earnings.

      SPS enters 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 and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. SPS reclassified into earnings during 2002 net after-tax gains from Other Comprehensive Income of approximately $0.5 million.

      Hedge effectiveness is recorded based on the nature of the item being hedged. Hedging transactions for the sales of electric energy are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, and hedging transactions for interest rate swaps are recorded as a component of interest expense.

      Derivatives Not Qualifying for Hedge Accounting — NSP-Minnesota and PSCo have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market

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basis in the Consolidated Statements of Income. All financial derivative instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the Consolidated Statements of Income.

      Normal Purchases or Normal Sales — Xcel Energy’s utility subsidiaries enter into fixed price contracts for the purchase and sale of various commodities for use in its business operations. SFAS No. 133 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 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. Contracts that meet the requirements of normal are documented as normal and exempted from the accounting and reporting requirements of SFAS No. 133.

      Xcel Energy’s utility subsidiaries evaluate all of their contracts when such contracts are entered into to determine if they are derivatives and if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the trading operations are considered normal.

      Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.

      Pending Accounting Change — On Oct. 25, 2002, the EITF rescinded EITF No. 98-10. With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment. The utility subsidiaries have not yet evaluated the effect of adopting this decision when required in 2003.

13.     Commitments and Contingent Liabilities (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      Legislative Resource Commitments (NSP-Minnesota) — In 1994, NSP-Minnesota received Minnesota legislative approval for additional on-site temporary spent fuel storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. Seventeen dry cask containers were approved. As of Dec. 31, 2002, NSP-Minnesota has loaded 17 of the containers.

      The Minnesota Legislature established several energy resource and other commitments for NSP-Minnesota to obtain the Prairie Island temporary nuclear fuel storage facility approval. These commitments can be met by building, purchasing, or in the case of biomass, converting generation resources.

      Other commitments established by the Legislature included a discount for low-income electric customers, required conservation improvement expenditures and various study and reporting requirements to a legislative electric energy task force. NSP-Minnesota has implemented programs to meet the legislative commitments. NSP-Minnesota’s capital commitments include the known effects of the Prairie Island legislation. The continuing impact of meeting legislative requirements on future power purchase commitments and other operating expenses is not determinable.

      Tax Matters (PSCo) — The IRS issued a Notice of Proposed Adjustment proposing to disallow interest expense deductions taken in tax years 1993 through 1997 related to corporate-owned life insurance (COLI) policy loans of PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. Late in 2001, PSCo received a technical advice memorandum from the IRS National Office, which communicated a position adverse to PSRI. Consequently, the IRS examination division has disallowed the interest expense deductions for the tax years 1993 through 1997.

      After consultation with tax counsel, it is PSCo’s position that the IRS determination is not supported by the tax law. Based upon this assessment, management continues to believe that the tax deduction of interest expense on the COLI policy loans is in full compliance with the tax law. Therefore, PSCo intends to challenge the IRS determination, which could require several years to reach final resolution. Although the ultimate

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resolution of this matter is uncertain, management continues to believe it will successfully resolve this matter without a material adverse impact on PSCo’s results of operations. For this reason, PSRI has not recorded any provision for income tax or interest expense related to this matter and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. However, defense of PSCo’s position may require significant cash outlays on a temporary basis.

      The total disallowance of interest expense deductions for the period of 1993 through 1997 is approximately $175 million. Additional interest expense deductions for the period 1998 through 2002 are estimated to total approximately $317 million. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2002, would reduce earnings by an estimated $214 million (after tax).

      Leases — Xcel Energy’s utility subsidiaries lease a variety of equipment and facilities used in the normal course of business. Some of these leases qualify as capital leases and are accounted for accordingly. The capital leases expire in 2024 and 2025. The net book value of property under capital leases was approximately $50 million and $52 million at Dec. 31, 2002 and 2001, respectively. Assets acquired under capital leases are recorded as property at the lower of fair-market value or the present value of future lease payments and are amortized over their actual contract term in accordance with practices allowed by regulators. The related obligation is classified as long-term debt. Executory costs are excluded from the minimum lease payments.

      The remainder of the leases, primarily leases of coal-hauling railcars, trucks, cars and power-operated equipment are accounted for as operating leases. The amounts paid under operating leases during 2002 for Xcel Energy’s utility subsidiaries are listed in the following table:

      Rental expense under operating leases was:

                         
2002 2001 2000



(Millions of dollars)
NSP-Minnesota
  $ 31.0     $ 30.7     $ 34.3  
NSP-Wisconsin
    4.8       4.7       3.4  
PSCo.
    22.6       2.6       9.6  
SPS
    4.6       0.1       2.2  

      Future commitments under operating leases are:

                                         
2003 2004 2005 2006 2007





(Millions of dollars)
NSP-Minnesota
  $ 21.5     $ 20.1     $ 19.2     $ 19.1     $ 19.1  
NSP-Wisconsin
    3.7       3.7       3.7       3.7       3.7  
PSCo.
    7.6       7.5       7.4       6.9       6.2  
SPS
    2.1       2.2       2.2       2.1       2.1  

      Future commitments under PSCo’s two capital leases are:

           
(Millions of dollars)

2003
  $ 8  
2004
    7  
2005
    7  
2006
    7  
2007
    7  
Thereafter
    78  
     
 
 
Total minimum obligation
    114  
Interest
    64  
     
 
 
Present value of minimum obligation
  $ 50  
     
 

      Nuclear Insurance — NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $9.4 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-

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Minnesota has secured $200 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $9.2 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 $88 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 $10 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 $1.5 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 $7.5 million for business interruption insurance and $21.6 million for property damage insurance if losses exceed accumulated reserve funds.

      Fuel Contracts — The utility subsidiaries of Xcel Energy have contracts providing for the purchase and delivery of a significant portion of their current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2003 and 2025. In addition, the utility subsidiaries of Xcel Energy are required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss for the utility subsidiaries of Xcel Energy, in the form of increased costs, from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking process, which provides for recovery of most fuel costs.

      The minimum purchase for each utility subsidiary of Xcel Energy is as follows:

                                 
Gas Storage &
Coal Nuclear Fuel Natural Gas Transportation




(Millions of dollars)
NSP-Minnesota and NSP-Wisconsin (combined)
  $ 219     $ 122     $ 284     $ 268  
PSCo
  $ 670     $     $ 1,264     $ 906  
SPS
  $ 1,442     $     $ 5     $  

      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 expiration dates through the year 2050. 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. Most of the capacity and energy costs are recovered through base rates and other cost recovery mechanisms.

      NSP-Minnesota has a 500-megawatt participation power purchase commitment with the Manitoba Hydro Electric Board, which expires in April 2005. The current cost of this agreement is based on 80 percent of the costs of owning and operating NSP-Minnesota’s Sherco 3 generating plant, adjusted to 1993 dollars. This agreement was extended during 2002 to include the period starting May 2005 through April 2015. The cost of the agreement for this extended period is based on a base price, which was established from May 2001 through April 2002 and will be escalated by the change in the United States Gross National Product to reflect the current year. In addition, NSP-Minnesota and Manitoba Hydro have seasonal diversity exchange agreements, and there are no capacity payments for the diversity exchanges. These commitments represent about 17 percent of Manitoba Hydro’s system capacity and account for approximately 9 percent of NSP-Minnesota’s 2002 electric system capability. The risk of loss from nonperformance by Manitoba Hydro is not

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considered significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments.

      At Dec. 31, 2002, 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):

                           
NSP-Minnesota* PSCo SPS



2003
  $ 133,688     $ 373,082     $ 17,320  
2004
    129,578       387,583       17,663  
2005
    108,828       408,961       17,946  
2006
    108,129       400,473       17,853  
2007 and thereafter
    1,442,140       3,201,726       326,310  
     
     
     
 
 
Total
  $ 1,922,363     $ 4,771,825     $ 397,092  
     
     
     
 


Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Environmental Contingencies

      We are subject to regulations covering air and water quality, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. We continuously assess our compliance. Regulations, interpretations and enforcement policies can change, which may impact the cost of building and operating our facilities.

      Site Remediation — We must pay all or a portion of the cost to remediate sites where past activities of our subsidiaries and some other parties have caused environmental contamination. At Dec. 31, 2002 there were three categories of sites:

  •  third party sites, such as landfills, to which we are alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes,
 
  •  the site of a former federal uranium enrichment facility, and
 
  •  sites of former manufactured gas plants (MGP’s) operated by our subsidiaries or predecessors.

      We record a liability when we have enough information to develop an estimate of the cost of remediating a site and revise the estimate as information is received. The estimated remediation cost may vary materially.

      To estimate the cost to remediate these sites, we may have to make assumptions where facts are not fully known. For instance, we might make assumptions 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.

      We revise our estimates as facts become known, but at Dec. 31, 2002 our estimated liability for the cost of remediating sites was:

                 
Current Portion
Total Liability of Liability


(Millions of dollars)
NSP-Minnesota
  $ 19.0     $ 5.1  
NSP-Wisconsin
    23.1       2.0  
PSCo
    2.8       0.4  
SPS
           

      Some of the cost of remediation may be recovered from:

  •  insurance coverage;
 
  •  other parties that have contributed to the contamination; and

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  •  customers.

      Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. We have recorded estimates of our share of future costs for these sites. We are not aware of any other parties’ inability to pay, nor do we know if responsibility for any of the sites is in dispute.

      Federal Uranium Enrichment Facility — Approximately $13 million of the long-term liability and $4 million of the current liability for NSP-Minnesota, and approximately $2 million of the long-term liability for PSCo, relate to a DOE assessment 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 14 to Consolidated Financial Statements for further discussion of nuclear obligations.

      Asbestos Removal — Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Since we intend to operate most of these facilities indefinitely, we cannot estimate the amount or timing of payments for its final removal. 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.

NSP-Minnesota

      MGP Sites — NSP-Minnesota has investigated and remediated MGP sites in Minnesota and North Dakota. The MPUC allowed NSP-Minnesota to defer, rather than immediately expense, certain remediation costs of four active remediation sites in 1994. This deferral accounting treatment may be used to accumulate costs that regulators might allow us to recover from our customers. The costs are deferred as a regulatory asset until recovery is approved, and then the regulatory asset is expensed over the same period as the regulators have allowed us to collect the related revenue from our customers. In September 1998, the MPUC allowed the recovery of a portion of these MGP site remediation costs in natural gas rates. Accordingly, NSP-Minnesota has been amortizing the related deferred remediation costs to expense. In 2001, the North Dakota Public Service Commission allowed the recovery of part of the cost of remediating another former MGP site in Grand Forks, N.D. The recoverable cost of remediating that site, $2.9 million, was accumulated in a regulatory asset that is now being expensed evenly over eight years. NSP-Minnesota may request recovery of costs to remediate other sites following the completion of preliminary investigations.

      Plant Emissions — On Dec. 10, 2001, the Minnesota Pollution Control Agency issued a notice of violation to NSP-Minnesota alleging air quality violations related to the replacement of a coal conveyor and violations of an opacity limitation at the A.S. King generating plant. NSP-Minnesota has responded to the notice of violation and is working to resolve its allegations.

      NSP-Minnesota New Source Review (NSR) Information Request — As discussed in more detail below, on Nov. 3, 1999 the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act’s NSR requirements related to alleged modifications of electric generating stations located in the South and Midwest. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to EPA’s initial information requests related to NSP-Minnesota plants in Minnesota. On May 22, 2002, EPA issued a follow-up information request to Xcel Energy seeking additional information regarding NSR compliance at its plants in Minnesota. Xcel Energy has completed its response to the follow-up information request.

NSP-Wisconsin

      Ashland MGP Site — NSP-Wisconsin was named as one of three PRPs for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin and

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two other properties: an adjacent city lakeshore park area and a small area of Lake Superior’s Chequemegon Bay adjoining the park.

      The Wisconsin Department of Natural Resources (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 Environmental Protection Agency (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 all operable units at the site and determine the level of responsibility of each PRP, we are not able to accurately determine our share of the ultimate cost of remediating the Ashland site.

      In the interim, NSP-Wisconsin has recorded a liability for an estimate of its share of the cost of remediating the portion of the Ashland site that it owns, estimated using information available to date and using reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the remediation costs accrued for the Ashland site because we expect that the Public Service Commission of Wisconsin (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.

      We proposed, and the EPA and WDNR have approved, an interim action (a coal tar removal/ groundwater treatment system) for one operable unit 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 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 EPA in determining which sites require further investigation. Resolution of Ashland remediation issues is not expected until 2004 or 2005.

      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.

      Plant Emissions — NSP-Wisconsin’s French Island plant generates electricity by burning a mixture of wood waste and refuse derived fuel. The fuel is derived from municipal solid waste furnished under a contract with La Crosse County, Wisconsin. In late 2000, the EPA reversed a prior decision and found that the plant was subject to the federal large combustor regulations. Those regulations became effective on Dec. 19, 2000. NSP-Wisconsin did not have adequate time to install the emission controls necessary to come into compliance with the large combustor regulations by the compliance date. As a result, in early 2001, the EPA issued a finding of violation to NSP-Wisconsin. NSP-Wisconsin is engaged in ongoing settlement discussions with the EPA regarding the finding of violation. In April 2001, a conservation group sent NSP-Wisconsin a notice of intent to sue under the citizen suit provisions of the Clean Air Act. NSP-Wisconsin could be fined up to $27,500 per day for each violation.

      In July 2001, the state of Wisconsin filed a lawsuit against NSP-Wisconsin in the Wisconsin Circuit Court for La Crosse County, contending that NSP-Wisconsin exceeded dioxin emission limits on numerous occasions between July 1995 and December 2000 at French Island. In September 2002, the Court approved a settlement in the case requiring NSP-Wisconsin to pay penalties of $167,579 and contribute $300,000 in installments through 2005 to help fund a household hazardous waste project in the La Crosse area.

      In August 2001, NSP-Wisconsin received a Certificate of Authority to install control equipment necessary to bring the French Island plant into compliance with both the federal large combustor regulations

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and state dioxin standard. NSP-Wisconsin began construction of the new air quality equipment in late 2001 and completed construction in 2002. NSP-Wisconsin has reached an agreement with La Crosse County through which La Crosse County will pay for the extra emissions equipment required to comply with the regulations.

     PSCo

      Leyden Gas Storage Facility — In February 2001, the CPUC granted PSCo’s application 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. Since late 2001, PSCo has operated the facility to withdraw the recoverable gas in inventory. Beginning in 2003, PSCo will start to flood 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. As of Dec. 31, 2002, PSCo has deferred approximately $4.5 million of costs associated with engineering buffer studies, damage claims paid to landowners and other closure costs. PSCo expects to incur an additional $6 million to $8 million of costs through 2005 to complete the decommissioning and closure of the facility. PSCo believes that these costs will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

      PSCo Notice of Violation — As discussed above, on Nov. 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the NSR requirements related to alleged modifications of electric generating stations located in the South and Midwest. Subsequently, the United States Environmental Protection Agency (EPA) also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to EPA’s initial information requests related to PSCo plants in Colorado.

      On July 1, 2002, Xcel Energy received a Notice of Violation (NOV) from the EPA alleging violations of the NSR requirements of the Clean Air Act at the Comanche and Pawnee Stations 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. Xcel Energy believes it acted in full compliance with the Clean Air Act 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. Xcel Energy also believes that the projects would be expressly authorized under the EPA’s NSR policy announced by the EPA administrator on June 22, 2002 and proposed in the Federal Register on Dec. 31, 2002. Xcel Energy disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the Clean Air Act, the EPA met with Xcel Energy in a conference in September 2002 to discuss the NOV.

      If the EPA is successful in any subsequent litigation regarding the issues set forth in the NOV or any matter arising as a result of its information requests, it could require Xcel Energy to install additional emission control equipment at the facilities and pay civil penalties. Civil penalties are limited to not more than $25,000 to $27,500 per day for each violation, commencing from the date the violation began. The ultimate financial impact to Xcel Energy is not determinable at this time.

Legal Contingencies

      In the normal course of business, Xcel Energy’s utility subsidiaries are party to routine claims and litigation arising from prior and current operations. Xcel Energy’s utility subsidiaries are actively defending these matters and have recorded an estimate of the probable cost of settlement or other disposition.

     NSP-Minnesota

      On Dec. 11, 1998, a natural gas explosion in St. Cloud, Minn., killed four people, including two NSP-Minnesota employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors Inc. (CCI) was installing fiber optic cable for Seren Innovations, Inc.

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Seren, CCI and Sirti, an architecture/ engineering firm retained by Seren, are named as defendants in 24 lawsuits relating to the explosion. NSP-Minnesota, Seren’s parent company at the time, is a defendant in 21 of the lawsuits. In addition to compensatory damages, plaintiffs are seeking punitive damages against CCI and Seren. NSP-Minnesota and Seren deny any liability for this accident. On July 11, 2000, the National Transportation Safety Board issued a report, which determined that CCI’s inadequate installation procedures and delay in reporting the natural gas hit were the proximate cause of the accident. NSP-Minnesota has a self-insured retention deductible of $2 million with general liability coverage limits of $185 million. Seren’s primary insurance coverage is $1 million and its secondary insurance coverage is $185 million. The ultimate cost to Xcel Energy, NSP-Minnesota and Seren, if any, is presently unknown.

     NSP-Wisconsin

      NSP-Wisconsin is the defendant in suits claiming electricity and/or stray voltage from NSP-Wisconsin’s system has harmed plaintiffs’ dairy herds and caused other damage and injuries. Total damages claimed in these proceedings are approximately $17.5 million. The ultimate outcome of these claims is not determinable at this time, and NSP-Wisconsin has recorded an estimate of costs necessary to settle or otherwise resolve these matters.

     SPS

      An electric cooperative in Lamb County, Texas filed a complaint with the PUCT regarding SPS’ alleged unlawful provision of service to oil-field customers and the cooperative’s facilities in the cooperative’s certified service area. SPS is awaiting a decision on this matter from a state administrative law judge. In addition, pending a final administrative determination on the lawfulness of SPS’ service, the cooperative has also commenced related litigation against SPS for damages. Damages resulting from decisions on these legal matters that are adverse to SPS could be material. However, SPS does not consider an adverse outcome probable at this time and consequently no costs have been accrued for this matter.

Other Contingencies

     NSP-Minnesota

      Operating Contingency — As discussed in Note 14, NSP-Minnesota is experiencing uncertainty regarding its ability to store used nuclear fuel from its Prairie Island and Monticello nuclear generating facilities. These facilities store used nuclear fuel in a storage pool or dry cask storage on the plant site, pending the availability of a DOE high-level radioactive substance storage or permanent disposal facility, or a private interim storage facility.

      The Prairie Island plant is licensed by the federal Nuclear Regulatory Commission (NRC) to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota legislature adopted a limit on dry cask storage of 17 casks for the entire state. The 17 casks, which stand outside the Prairie Island plant, are now full, and under the current configuration the storage pool within the plant would be full by 2007. Prairie Island cannot operate beyond 2007 unless the existing spent fuel is moved or the storage capacity is increased. Because the 17-cask limit is a statewide limit, the Monticello plant cannot, under current state law, store spent fuel in dry casks. Monticello’s on-site storage pool is expected to be full in 2010. Monticello cannot operate beyond 2010 unless the existing spent fuel is moved or the storage capacity is increased. Capitalized costs for Prairie Island and Monticello are being depreciated over these available storage periods, and no unamortized plant investment is expected to remain if the plants must shut down in 2007 and 2010, respectively.

      Due to the investment decisions required to be made in conjunction with the continued efficient operation of the nuclear plants, as well as the time and cost involved to develop alternatives to the existing nuclear power generation, NSP-Minnesota believes a decision is necessary in 2003 by the Minnesota legislature whether the state will allow the continued use of nuclear power in the future. Prairie Island will only be able to continue operating beyond 2007 with legislative authorization of additional storage space. If additional storage space for continued operations is not authorized, and interim storage is not available, legislation may be required to

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ensure expedited siting and permitting of new generation or transmission facilities in time to replace the power supply currently provided from NSP-Minnesota’s nuclear plants.

      NSP-Minnesota has developed replacement power options, including purchasing new coal or natural gas generation sources. The feasibility of supplementing new generation sources with additional wind turbines has been reviewed. These options will be presented to the 2003 Minnesota legislature. Each option involves a balance of cost, environmental impacts and production efficiencies. Based on the review of these options, NSP-Minnesota believes the most reliable, lowest cost, emissions-free method to provide the needed 1,700 megawatts of energy is to continue to operate the nuclear power plants at Prairie Island and Monticello, which is possible only with the additional approved storage capacity for spent fuel, either on-site or in a private facility. We cannot predict at this time what resource decisions the Minnesota Legislature or MPUC may make regarding the continued use of NSP-Minnesota’s Prairie Island and Monticello nuclear plants. If decisions are not made which allow the plants’ use beyond the storage capacity period, additional costs may need to be incurred to provide replacement power, either from new generating plants or from purchased power. The amount of such additional costs, and the level of corresponding rate recovery provided, are not determinable at this time but may be material.

     PSCo

      The Home Builders Association of Metropolitan Denver (HBA) filed a formal complaint against PSCo with the CPUC in February 2001, requesting an award of reparations for excessive charges related to construction payments under PSCo’s gas extension tariff as a result of PSCo’s alleged failure to file revisions to its published construction allowances since 1996. HBA seeks an award of reparations on behalf of all of PSCo’s gas extension applicants since Oct. 1, 1996, in the amount of $13.6 million, including interest, plus recovery of its attorney’s fees. A state administrative law judge has dismissed HBA’s complaint and denied recovery of attorney’s fees. However, the CPUC has considered exceptions filed by the HBA and has remanded the case back to the administrative law judge for a determination of whether and to what extent due reparations should be awarded, considering certain enumerated issues. PSCo does not consider an adverse outcome probable at this time and consequently no costs have been accrued for this matter.

      PSCo’s costs recoverable under the ICA for 2002 were approximately $17 per megawatt hour, or approximately $56 million less than the allowed energy recovery rate that was based on the 2001 test year. Under the ICA mechanism, retail customers and PSCo share this difference equally. A CPUC proceeding to review and approve the incurred and recoverable 2001 costs under the ICA is in process. In 2003, PSCo will file for recovery of its 2002 costs, and a review of these 2002 costs will be conducted in a separate future rate proceeding. The results of these rate proceedings could impact the cost recovery and sharing amounts recorded under the ICA for 2001 and 2002. At this time, PSCo believes its deferred energy costs of $122 million which are subject to future review are recoverable in future rates.

     SPS

      In 2001, Golden Spread filed a complaint against SPS and a request for investigation before the FERC. Golden Spread alleges SPS has violated provisions of an agreement pursuant to which SPS conducts joint dispatch of SPS and Golden Spread resources. Golden Spread seeks damages in excess of $10 million. SPS denies all of Golden Spread’s allegations, and has filed a counter-complaint against Golden Spread in which it has alleged that Golden Spread has failed to adhere to certain requirements of the agreement. Both complaints are presently pending before the FERC and settlement procedures have been ordered by the Commission. Settlement discussions are ongoing. Even if SPS is required to pay more to Golden Spread for power purchased under this agreement, we believe that the amounts are likely to be recoverable from customers under SPS’ various fuel clause mechanisms.

      In the normal course of business, SPS made a filing to facilitate the PUCT’s review of electric generation and fuel management activities, totaling approximately $608 million, for the period from January 2000 through December 2001. This proceeding is ongoing, and intervenor and PUCT staff testimony is being reviewed. Intervenors have proposed that revenues from certain wholesale transactions be credited to Texas

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retail customers. SPS is opposing this proposed revenue treatment, and believes all deferred costs under review are recoverable in future rates.

 
14. Nuclear Obligations (NSP-Minnesota)

      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 $13 million in 2002, $11 million in 2001 and $12 million in 2000. In total, NSP-Minnesota had paid approximately $312 million to the DOE through Dec. 31, 2002. However, we cannot determine 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. With the dry cask storage facilities approved in 1994, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least 2007. The Monticello nuclear plant has storage capacity to continue operations until 2010. Storage availability to permit operation beyond these dates is not assured at this time. We are investigating all of the alternatives for spent fuel storage 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. If on-site temporary storage at Prairie Island reaches approved capacity, we could seek interim storage at this or another contracted private facility, if available.

      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 2002 was $4 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, we deferred the unamortized assessment of $21 million at Dec. 31, 2002, as a regulatory asset.

      Plant Decommissioning — Decommissioning of NSP-Minnesota’s nuclear facilities is planned for the years 2010 through 2022, using the prompt dismantlement method. Through 2002, NSP-Minnesota followed industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in Accumulated Depreciation. Consequently, as of Dec. 31, 2002 the total decommissioning cost obligation and corresponding assets were not recorded in NSP-Minnesota’s financial statements.

      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. Funding presumes that current costs will escalate in the future at a rate of 4.35 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. Unrealized gains on nuclear decommissioning investments are deferred as Regulatory Liabilities based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

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      The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in April 2000, using 1999 cost data. A new filing was submitted to the MPUC in October 2002 and requests continuation of the current accrual. Since the timeframe is getting short on the recovery of the Prairie Island costs, less than five years at the start of 2003, NSP-Minnesota has recommended that the next filing be submitted in October 2003. The Department of Commerce has recommended that the internal fund, which is currently being transferred to the external funds, be transferred over a shorter period of time. This proposal would increase the fund cash contribution by approximately $13 million in 2003, but may not have an income statement impact. Although we expect to operate Prairie Island through the end of each unit’s licensed life, the approved capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2007. This is about seven years earlier than each unit’s licensed life. The approved recovery period for Prairie Island has been reduced because of the uncertainty regarding spent-fuel storage. We believe 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, 2002, 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. We plan to reinvest matured securities until decommissioning begins.

      At Dec. 31, 2002, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $662 million. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation at Dec. 31, 2002:

         
2002

(Thousands
of dollars)
Estimated decommissioning cost obligation from most recently approved study (1999 dollars)
  $ 958,266  
Effect of escalating costs to 2002 dollars (at 4.35 percent per year)
    130,573  
     
 
Estimated decommissioning cost obligation in current dollars
    1,088,839  
Effect of escalating costs to payment date (at 4.35 percent per year)
    805,435  
     
 
Estimated future decommissioning costs (undiscounted)
    1,894,274  
Effect of discounting obligation (using risk-free interest rate)
    (828,087 )
     
 
Discounted decommissioning cost obligation
    1,066,187  
Assets held in external decommissioning trust
    617,048  
     
 
Discounted decommissioning obligation in excess of assets currently held in external trust
  $ 449,139  
     
 

      Decommissioning expenses recognized include the following components:

                           
2002 2001 2000



(Thousands of dollars)
Annual decommissioning cost accrual reported as depreciation expense:
                       
 
Externally funded
  $ 51,433     $ 51,433     $ 51,433  
 
Internally funded (including interest costs)
    (18,797 )     (17,396 )     (16,111 )
Interest cost on externally funded decommissioning obligation
    (32 )     4,535       5,151  
Earnings from external trust funds
    32       (4,535 )     (5,151 )
     
     
     
 
Net decommissioning accruals recorded
  $ 32,636     $ 34,037     $ 35,322  
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Decommissioning and interest accruals are included with Accumulated Depreciation on the balance sheet. Interest costs and trust earnings associated with externally funded obligations are reported in Other Nonoperating Income on the Consolidated Statements of Income.

      Negative accruals for internally funded portions in 2000, 2001 and 2002 reflect the impacts of the 1999 decommissioning study, which has approved an assumption of 100 percent external funding of future costs. Previous studies assumed a portion was funded internally; beginning in 2000, accruals are reversing the previously accrued internal portion and increasing the external portion prospectively.

      Pending Accounting Change — SFAS No. 143 — In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement will require NSP-Minnesota to record its future nuclear plant decommissioning obligations as a liability at fair value with a corresponding increase to the carrying value of the related long-lived asset. The liability will be increased to its present value each period, and the capitalized cost will be depreciated over the useful life of the related long-lived asset. If at the end of the asset’s life the recorded liability differs from the actual obligations paid, SFAS No. 143 requires that a gain or loss be recognized at that time. However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for such treatment are met.

      NSP-Minnesota currently follows industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in accumulated depreciation. At Dec. 31, 2002, NSP-Minnesota recorded and recovered in rates $662 million of decommissioning obligations and had estimated discounted decommissioning cost obligations of $1.1 billion based on approvals from the various state commissions, which used a single scenario. However with the adoption of SFAS No. 143, a probabilistic view of several decommissioning scenarios were used resulting in an estimated discounted decommissioning cost obligation of $1.6 billion.

      NSP-Minnesota expects to adopt SFAS No. 143 as required on Jan. 1, 2003. In current estimates for adoption, the initial value of the liability, including cumulative accretion expense through that date, would be approximately $869 million. This liability would be established by reclassifying accumulated depreciation of $573 million and by recording two long-term assets totaling $296 million. A gross capitalized asset of $130 million would be recorded and would be offset by accumulated depreciation of $89 million. In addition, a regulatory asset of approximately $166 million would be recorded for the cumulative effect adjustment related to unrecognized depreciation and accretion under the new standard. Management expects that the entire transition amount would be recoverable in rates over time and, therefore, would support this regulatory asset upon adoption of SFAS No. 143.

15.     Regulatory Assets and Liabilities (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      Our regulated businesses prepare their 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 allow us to collect from, or require us to pay back to, customers in future electric and natural gas rates.

      Any portion of our business that is not rate regulated cannot use SFAS No. 71 accounting. Efforts to restructure and deregulate the utility industry may further reduce or end our ability to apply SFAS No. 71 in the future. Write-offs and material changes to our balance sheet, income and cash flows may result in such circumstances.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of unamortized regulatory assets and liabilities on the balance sheets of Xcel Energy’s utility subsidiaries are:

 
NSP-Minnesota
                               
December 31,
Remaining
Note Ref. Amortization Period 2002 2001




(Thousands of dollars)
AFDC recorded in plant(a)
          Plant lives   $ 82,697     $ 88,005  
Conservation programs(a)
          Up to five years     25,259       35,573  
Losses on reacquired debt
    1     Term of related debt     33,817       36,631  
Environmental costs
    13,14     To be determined     4,140       5,366  
Unrecovered gas costs(b)
    1     One to two years     12,296       10,324  
Nuclear decommissioning costs(c)
          Up to five years     20,769       24,696  
Renewable resource costs
          To be determined     26,000       17,500  
State commission accounting adjustments(a)
          Plant lives     4,732       4,860  
Other
          Various     2,829       3,133  
                 
     
 
 
Total regulatory assets
              $ 212,539     $ 226,088  
                 
     
 
Investment tax credit deferrals
              $ 50,836     $ 56,018  
Unrealized gains on decommissioning investments
    14           112,145       149,041  
Pension costs-regulatory differences
    9           287,615       215,687  
Deferred income tax adjustments
                27,687       46,157  
Fuel costs, refunds and other
                1,786       1,148  
Interest on income tax refunds
                5,966        
                 
     
 
 
Total regulatory liabilities
              $ 486,035     $ 468,051  
                 
     
 


(a)  Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.
 
(b)  Excludes current portion with expected rate recovery within 12 months of $12 million for 2002 and $22 million for 2001.
 
(c)  These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to assessments to pay for the decommissioning of a federal uranium enrichment facility.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NSP-Wisconsin
                               
December 31,
Remaining
Note Ref. Amortization Period 2002 2001




(Thousands of dollars)
AFDC recorded in plant(d)
          Plant lives   $ 7,290     $ 7,391  
Conservation programs(d)
          Through 2003     1,296       1,597  
Losses on reacquired debt
    1     Term of Related Debt     9,328       9,968  
Environmental costs
    13     To be determined     26,833       14,803  
State commission accounting adjustments(d)
          Plant lives     2,858       2,718  
Other
          Various     507       646  
                 
     
 
 
Total regulatory assets
              $ 48,112     $ 37,123  
                 
     
 
Investment tax credit deferrals
              $ 10,134     $ 10,510  
Interest on income tax refunds
                603        
Deferred income tax adjustments
                474       5,572  
Fuel costs, refunds and other
                739       809  
                 
     
 
 
Total regulatory liabilities
              $ 11,950     $ 16,891  
                 
     
 


(d)  Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

 
      PSCo
                               
December 31,
Remaining
Note Ref. Amortization Period 2002 2001




(Thousands of dollars)
AFDC recorded in plant(e)
          Plant lives   $ 36,469     $ 39,069  
Conservation programs(e)
          Up to five years     13,520       15,643  
Losses on reacquired debt
    1     Term of Related Debt     13,853       15,047  
Unrecovered energy costs(f)
          27 months     67,709        
Deferred income tax adjustments
    1     Mainly plant lives     23,058       34,556  
Nuclear decommissioning costs
          Three years     32,798       43,788  
Employees’ postretirement benefits other than pension
    9     Ten years     38,899       42,790  
Other
          Various     12,294       1,948  
                 
     
 
 
Total regulatory assets
              $ 238,600     $ 192,841  
                 
     
 
Investment tax credit deferrals
              $ 45,707     $ 49,048  
                 
     
 
 
Total regulatory liabilities
              $ 45,707     $ 49,048  
                 
     
 


(e)  Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

(f)  Excludes current portion with expected rate recovery within 12 months of $54 million for 2002 and $17 million for 2001.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     SPS

                               
December 31,
Remaining
Note Ref. Amortization Period 2002 2001




(Thousands of dollars)
AFDC recorded in plant(g)
          Plant lives   $ 27,617     $ $15,027  
Conservation programs(g)
          Up to five years     13,784       13,012  
Losses on reacquired debt
    1     Term of related debt     28,426       33,260  
Deferred income tax adjustments
    1     Mainly plant lives     24,010       35,162  
New Mexico restructuring costs.
          To be determined     5,147        
Texas restructuring costs
          Five years     6,420        
Other
                      152  
                 
     
 
 
Total regulatory assets
              $ 105,404     $ 96,613  
                 
     
 
Investment tax credit deferrals
              $ 2,363     $ 1,117  
                 
     
 
 
Total regulatory liabilities
              $ 2,363     $ 1,117  
                 
     
 


(g)  Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.
 
     This table excludes deferred energy charges expected to be recovered within the next 12 months of $16 million for 2002, and energy cost recovery expected to be returned to customers within the next 12 months of $40 million for 2001.

      The adoption of SFAS No. 143 in 2003 will also affect Xcel Energy’s accrued plant removal costs for other generation, transmission and distribution facilities for its utility subsidiaries. Although SFAS No. 143 does not recognize the future accrual of removal costs as a Generally Accepted Accounting Principles liability, 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, we have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the estimated amounts of future removal costs, which are considered regulatory liabilities under SFAS No. 143 that are accrued in accumulated depreciation, are as follows at Dec. 31, 2002:

         
(Millions of Dollars)

NSP-Minnesota
  $ 304  
NSP-Wisconsin
    70  
PSCo
    329  
SPS
    97  

16.     Segment and Related Information (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      Xcel Energy’s utility subsidiaries have two reportable segments: Electric Utility and Gas Utility.

  •  Xcel Energy’s Electric Utility generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, New Mexico, Wyoming, Kansas and Oklahoma. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Electric Utility also includes NSP-Minnesota’s and PSCo’s electric trading operations.
 
  •  Xcel Energy’s Gas Utility transmits, transports, stores and distributes natural gas and propane primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      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 (PSCo), appliance repair services (NSP-Minnesota and PSCo), nonutility real estate activities (NSP-Minnesota), parking ramp operations (NSP-Minnesota) and revenues associated with processing solid waste into refuse-derived fuel (NSP-Minnesota).

      To report net income for electric and 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; or
 
  •  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. Xcel Energy evaluates performance by each legal entity based on profit or loss.

Business Segments

 
NSP-Minnesota
                                           
Electric Gas All Reconciling Consolidated
Utility Utility Other Eliminations Total





(Thousands of dollars)
2002
                                       
Operating revenues from external customers
  $ 2,362,070     $ 485,473     $ 30,875     $     $ 2,878,418  
Intersegment revenues
    602       4,099                   4,701  
     
     
     
     
     
 
 
Total revenues
    2,362,672       489,572       30,875             2,883,119  
Depreciation and amortization
    325,595       27,640       922             354,157  
Financing costs, mainly interest expense
    100,888       13,196       17,415       (16,809 )     114,690  
Income tax expense
    101,981       4,983       1,177             108,141  
     
     
     
     
     
 
Segment net income
  $ 178,191     $ 15,011     $ 7,020     $     $ 200,222  
     
     
     
     
     
 
                                           
Electric Gas All Reconciling Consolidated
Utility Utility Other Eliminations Total





(Thousands of dollars)
2001
                                       
Operating revenues from external customers
  $ 2,569,431     $ 625,340     $ 52,836     $     $ 3,247,607  
Intersegment revenues
    722       166                   888  
     
     
     
     
     
 
 
Total revenues
    2,570,153       625,506       52,836             3,248,495  
Depreciation and amortization
    312,686       26,347       476             339,509  
Financing costs, mainly interest expense
    88,809       11,816       17,000       (16,725 )     100,900  
Income tax expense
    129,521       10,260       (7,049 )           132,732  
     
     
     
     
     
 
Segment net income
  $ 192,046     $ 13,790     $ 2,029     $     $ 207,865  
     
     
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                                           
Electric Gas All Reconciling Consolidated
Utility Utility Other Eliminations Total





(Thousands of dollars)
2000
                                       
Operating revenues from external customers
  $ 2,411,197     $ 535,131     $ 51,900     $     $ 2,998,228  
Intersegment revenues
    686       1,569                   2,255  
     
     
     
     
     
 
 
Total revenues
    2,411,883       536,700       51,900             3,000,483  
Depreciation and amortization
    300,961       22,945       29             323,935  
Financing costs, mainly interest expense
    129,298       12,918       16,894       (16,725 )     142,385  
Income tax expense
    83,718       8,364       109             92,191  
     
     
     
     
     
 
Segment net income
  $ 90,363     $ 19,538     $ 1,323     $     $ 111,224  
     
     
     
     
     
 

     NSP-Wisconsin

                                           
Electric Gas All Reconciling Consolidated
Utility Utility Other Eliminations Total





(Thousands of dollars)
2002
                                       
Operating revenues from external customers
  $ 458,571     $ 101,335     $ 761     $     $ 560,667  
Intersegment revenues
    166       808                   974  
     
     
     
     
     
 
 
Total revenues
    458,737       102,143       761             561,641  
Depreciation and amortization
    39,026       5,390       50             44,466  
Financing costs, mainly interest expense
    20,770       2,333       14             23,117  
Income tax expense
    36,792       970       (837 )           36,925  
     
     
     
     
     
 
Segment net income
  $ 46,215     $ 7,798     $ 360     $     $ 54,373  
     
     
     
     
     
 
                                           
Electric Gas All Reconciling Consolidated
Utility Utility Other Eliminations Total





(Thousands of dollars)
2001
                                       
Operating revenues from external customers
  $ 450,723     $ 120,951     $ 692     $     $ 572,366  
Intersegment revenues
    172       2,102                   2,274  
     
     
     
     
     
 
 
Total revenues
    450,895       123,053       692             574,640  
Depreciation and amortization
    36,713       4,932                   41,645  
Financing costs, mainly interest expense
    19,871       2,198                   22,069  
Income tax expense
    20,475       683                   21,158  
     
     
     
     
     
 
Segment net income
  $ 32,258     $ 4,134     $     $     $ 36,392  
     
     
     
     
     
 
                                           
Electric Gas All Reconciling Consolidated
Utility Utility Other Eliminations Total





(Thousands of dollars)
2000
                                       
Operating revenues from external customers
  $ 424,312     $ 108,077     $ 670     $     $ 533,059  
Intersegment revenues
    165       1,946                   2,111  
     
     
     
     
     
 
 
Total revenues
    424,477       110,023       670             535,170  
Depreciation and amortization
    35,103       5,399                   40,502  
Financing costs, mainly interest expense
    17,019       2,236                   19,255  
Income tax expense
    18,287       2,403                   20,690  
     
     
     
     
     
 
Segment net income
  $ 26,723     $ 3,573     $     $     $ 30,296  
     
     
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     PSCo

                                           
Electric Reconciling Consolidated
Utility Gas Utility All Other Eliminations Total





(Thousands of dollars)
2002
                                       
Operating revenues from external customers
  $ 1,877,974     $ 749,314     $ 24,365     $     $ 2,651,653  
Intersegment revenues
    219       41                   260  
     
     
     
     
     
 
 
Total revenues
    1,878,193       749,355       24,365             2,651,913  
Depreciation and amortization
    190,845       53,044       3,709             247,598  
Financing costs, mainly interest expense
    109,398       32,829       16,054       (16,050 )     142,231  
Income tax expense (credit)
    121,244       37,832       (30,390 )           128,686  
     
     
     
     
     
 
Segment net income
  $ 178,404     $ 64,303     $ 21,973     $     $ 264,680  
     
     
     
     
     
 
                                           
Electric Reconciling Consolidated
Utility Gas Utility All Other Eliminations Total





(Thousands of dollars)
2001
                                       
Operating revenues from external customers
  $ 2,365,714     $ 1,249,308     $ 32,465     $     $ 3,647,487  
Intersegment revenues
    125       2,233                   2,358  
     
     
     
     
     
 
 
Total revenues
    2,365,839       1,251,541       32,465             3,649,845  
Depreciation and amortization
    182,288       55,499       1,522             239,309  
Financing costs, mainly interest expense
    103,083       30,693       14,909       (17,457 )     131,228  
Income tax expense (credit)
    129,773       26,384       (23,656 )           132,501  
     
     
     
     
     
 
Segment income before extraordinary items
  $ 175,393     $ 48,436     $ 50,738     $     $ 274,567  
Extraordinary items, net of tax
                (1,534 )           (1,534 )
     
     
     
     
     
 
Segment net income
  $ 175,393     $ 48,436     $ 49,204     $     $ 273,033  
     
     
     
     
     
 
                                           
Electric Reconciling Consolidated
Utility Gas Utility All Other Eliminations Total





(Thousands of dollars)
2000
                                       
Operating revenues from external customers
  $ 2,039,654     $ 787,110     $ 26,751     $     $ 2,853,515  
Intersegment revenues
                             
     
     
     
     
     
 
 
Total revenues
    2,039,654       787,110       26,751             2,853,515  
Depreciation and amortization
    156,896       51,636       2,172             210,704  
Financing costs, mainly interest expense
    122,859       40,448       20,808       (22,824 )     161,291  
Income tax expense (credit)
    100,679       22,313       (20,222 )           102,770  
     
     
     
     
     
 
Segment net income
  $ 134,425     $ 28,795     $ 32,908     $     $ 196,128  
     
     
     
     
     
 

     SPS

      SPS has only one reportable segment. SPS operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $1,025.2 million, $1,385.5 million and $1,079.6 million for the years ended Dec. 31, 2002, 2001 and 2000, respectively.

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17.     Related Party Transactions (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      NSP-Minnesota, NSP-Wisconsin, PSCo and SPS receive various administrative, management, environmental and other support services from Xcel Energy Services Inc., which began operations in August 2000. Prior to this, all of these support services resided in former NSP for NSP-Minnesota and NSP-Wisconsin and were allocated to the former NSP subsidiaries, as appropriate. New Century Services provided these support services to PSCo and SPS before the merger to form Xcel Energy.

     NSP-Minnesota and NSP-Wisconsin

      Viking Gas Transmission Co. (Viking), a subsidiary of Xcel Energy through 2002, transports gas purchased by NSP-Minnesota from various suppliers. NSP-Minnesota incurred transportation costs of $4.6 million, $5.8 million and $5.5 million in 2002, 2001, and 2000, respectively, for gas transportation purchased from Viking. NSP Wisconsin purchased $1.6 million of transportation service from Viking during 2002.

      NSP-Minnesota purchased gas from e prime, another subsidiary of Xcel Energy, for $2.7 million in 2002 and $3.5 million in 2001. In addition NSP-Minnesota sold transportation services to e prime for $0.1 million in 2002 and $0.4 million in 2001 for gas delivered into the Minnesota operating area.

      Utility Engineering Corp., an additional Xcel Energy subsidiary, provided construction services to NSP-Minnesota, for which it was paid $7.0 million in 2002 and $6.7 million in 2001.

      The electric production and transmission costs of the entire NSP system are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement (Interchange Agreement) between the two companies provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Billings under the Interchange Agreement, which are included in the Consolidated Statements of Income, are as follows:

                           
2002 2001 2000



(Thousands of dollars)
NSP-Minnesota
                       
Operating revenues:
                       
Electric
                       
 
Production related
  $ 205,203     $ 218,385     $ 200,522  
 
Transmission
    15,471       17,733       16,600  
 
Gas
    363       468       220  
Operating expenses:
                       
 
Purchased and interchange power
    43,511       50,083       45,294  
 
Gas purchased for resale
                608  
 
Other operations*
    309,514       325,151       571,144  


Other operations expense includes $272,825, $289,339, and $543,013 paid to Xcel Energy Services Inc. in 2002, 2001 and 2000.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                           
2002 2001 2000



(Thousands of dollars)
NSP-Wisconsin
                       
Operating revenues:
                       
 
Electric
  $ 80,200     $ 85,895     $ 73,425  
Operating expenses:
                       
 
Purchased and interchange power
    205,174       218,534       199,730  
 
Gas purchased for resale
    95       244       220  
 
Other operations*
    50,449       46,371       42,330  


Other operations expense includes $36,695, $28,816, and $42,509 paid to Xcel Energy Services Inc. in 2002, 2001 and 2000.

      NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota’s average daily interest rate, including the cost of NSP-Minnesota’s compensating balance requirements. Corresponding interest charges on NSP-Wisconsin’s statement of income and other income on NSP-Minnesota’s statement of income include $0.2 million, $0.4 million, and $3.4 million for 2002, 2001, and 2000.

      NSP-Minnesota’s receivables from affiliates include amounts receivable from NSP-Wisconsin for the Interchange Agreement and short-term borrowings. NSP-Minnesota’s payable to affiliates primarily represents amounts payable to Xcel Energy Services Inc. for NSP-Minnesota’s allocation of support services from Xcel Energy Services Inc.

      NSP-Wisconsin’s receivable from affiliates primarily represents amounts receivable from NSP-Minnesota for the Interchange Agreement. NSP-Wisconsin’s notes payable to affiliates represents amounts payable to NSP-Minnesota.

     PSCo and SPS

      For 37 years Cheyenne Light, Fuel and Power (Cheyenne), an Xcel Energy subsidiary, had purchased all of its electricity from PacifiCorp, but the contract expired in early 2001. Cheyenne was unable to execute a new agreement with PacifiCorp and consequently PSCo began supplying Cheyenne’s power requirements in February 2001.

      SPS purchases gas from e prime to fuel electric generation plants.

      PSCo sells firm and interruptible transportation services to e prime for gas delivered into the Denver/ Pueblo operating area. PSCo also purchases gas from e prime for its gas utility system supply.

      PSCo and SPS receive construction services from Utility Engineering. In addition, PSCo and SPS pay interest expense on any short-term borrowings from Xcel Energy.

      In 2000, PSCo received interest income from Xcel Energy International Inc., another Xcel Energy subsidiary, on the note receivable related to the sale of New Century International. In 2000, SPS received interest income from Xcel Energy’s Wholesale Energy Group Inc. subsidiary on the note receivable related to the sale of Utility Engineering and its affiliate, Quixx, as part of the PSCo/SPS Merger.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

                         
2002 2001 2000



(Thousands of dollars)
PSCo
                       
Electric utility revenues
  $ 57,464     $ 40,457     $  
Gas utility revenues
    311       513       8,750  
Cost of gas sold
          1,644       3,483  
Operating expenses*
    208,402       232,902       500,954  
Interest income
                10,377  
Interest expense
    1,648       2,311       3,952  
Construction services — capitalized in plant
    70,784       69,316       67,893  


Operating expense includes $208,402, $232,902, and $500,954 paid to Xcel Energy Services Inc. in 2002, 2001 and 2000.

                         
2002 2001 2000



(Thousands of dollars)
SPS
                       
Electric fuel and purchased power expense
  $ 15,158     $ 24,342     $ 45,900  
Operating expenses*
    68,045       72,259       210,174  
Interest income
                8,640  
Interest expense
    147       253       850  
Construction services — capitalized in plant
    13,524       8,141       7,397  


Operating expense includes $68,045, $72,259, and $210,174 paid to Xcel Energy Services Inc. in 2002, 2001 and 2000.

 
18. Summarized Quarterly Financial Data (Unaudited) (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

     NSP-Minnesota

                                 
Quarter Ended

March 31, 2002(a) June 30, 2002 Sept. 30, 2002 Dec. 31, 2002




(Thousands of dollars)
Revenue(c)
  $ 735,251     $ 656,973     $ 752,136     $ 738,759  
Operating income
    67,370       86,279       169,418       74,917  
Net income
    33,033       42,424       82,992       41,773  
                                 
Quarter Ended

March 31, 2001 June 30, 2001(b) Sept. 30, 2001 Dec. 31, 2001(b)




(Thousands of dollars)
Revenue(c)
  $ 982,073     $ 759,215     $ 826,706     $ 680,501  
Operating income
    99,830       112,113       155,691       70,150  
Net income
    42,172       56,401       76,090       33,202  


(a)  2002 results include special charges as discussed in Note 2 to the Financial Statements. First quarter results were decreased by $4 million for a pretax special charge related to final employee restaffing costs.
 
(b)  2001 results include special charges and unusual items in the second and fourth quarters as discussed in Notes 2 and 15 to the Financial Statements. Second quarter results were increased by $41 million for conservation incentive adjustments. Fourth quarter results were decreased by $14 million for a pretax special charge related to employee restaffing costs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(c)  Certain items in the 2001 and 2002 quarterly income statements have been reclassified to conform to the 2002 annual presentation. These reclassifications, related to items formerly presented as electric trading revenues and costs, had no effect on net income.

     NSP-Wisconsin

                                 
Quarter Ended

March 31, 2002 June 30, 2002 Sept. 30, 2002 Dec. 31, 2002




(Thousands of dollars)
Revenue
  $ 157,402     $ 129,059     $ 130,232     $ 144,948  
Operating income
    34,682       24,917       27,562       26,337  
Net income
    17,951       12,418       12,496       11,508  
                                 
Quarter Ended

March 31, 2001 June 30, 2001 Sept. 30, 2001 Dec. 31, 2001(a)




(Thousands of dollars)
Revenue
  $ 183,567     $ 122,005     $ 132,111     $ 136,957  
Operating income
    26,565       9,928       19,431       22,858  
Net income
    13,092       3,414       8,627       11,259  


(a)  2001 results include special charges as discussed in Note 2 to the Financial Statements. Fourth quarter results were decreased by $2 million for a pretax special charge related to employee restaffing costs.

     PSCo

                                 
Quarter Ended

March 31, 2002 June 30, 2002 Sept. 30, 2002 Dec. 31, 2002




(Thousands of dollars)
Revenue(b)
    $758,680     $ 573,939     $ 594,126     $ 725,168  
Operating income
    132,858       134,033       134,716       138,631  
Income before extraordinary items
    66,691       62,361       66,967       68,661  
Extraordinary items
                       
Net income
    66,691       62,361       66,967       68,661  
                                 
Quarter Ended

March 31, 2001 June 30, 2001(a) Sept. 30, 2001 Dec. 31, 2001(a)




(Thousands of dollars)
Revenue(b)
  $ 1,171,056     $ 910,487     $ 791,876     $ 776,426  
Operating income
    194,293       129,508       100,070       109,847  
Income before extraordinary items
    107,390       66,302       47,947       52,928  
Extraordinary items
                      (1,534 )
Net income
    107,390       66,302       47,947       51,394  


(a)  2001 results include special charges as discussed in Note 2 to the Financial Statements. Second quarter results were decreased by $23 million for a pretax special charge related to postemployment benefits. Fourth quarter results were decreased by $15 million for a pretax special charge related to employee restaffing costs.
 
(b)  Certain items in the 2001 and 2002 quarterly income statements have been reclassified to conform to the 2002 annual presentation. These reclassifications, related to items formerly presented as electric trading revenues and costs, had no effect on net income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     SPS

                                 
Quarter Ended

March 31, 2002(a) June 30, 2002 Sept. 30, 2002 Dec. 31, 2002




(Thousands of dollars)
Revenue
  $ 211,692     $ 266,917     $ 291,857     $ 254,712  
Operating income
    35,117       34,642       62,388       32,971  
Income before extraordinary items
    14,748       13,429       31,741       13,964  
Extraordinary items
                       
Net income
    14,748       13,429       31,741       13,964  
                                 
Quarter Ended

March 31, 2001 June 30, 2001 Sept. 30, 2001 Dec. 31, 2001(b)




(Thousands of dollars)
Revenue
  $ 329,273     $ 371,681     $ 387,219     $ 297,285  
Operating income
    53,713       42,384       85,679       48,781  
Income before extraordinary items
    26,049       20,302       47,709       24,219  
Extraordinary items
                      11,821  
Net income
    26,049       20,302       47,709       36,040  


(a)  2002 results include special charges as discussed in Note 2 to the Financial Statements. First quarter results were decreased by $5 million for a pretax special charge related to restructuring costs.
 
(b)  2001 results include special charges as discussed in Note 2 to the Financial Statements. Fourth quarter results were decreased by $5 million for a pretax special charge related to employee restaffing costs.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      During 2001 and 2002, there were no disagreements with the independent public accountants for NSP-Minnesota, NSP-Wisconsin, PSCo or SPS on accounting principles or practices, financial statement disclosures, or auditing scope or procedures. Further, during 2001 and 2002, there have been no reportable events (as defined in Securities and Exchange Commission Regulation S-K, Item 304 (a)(1)(v)).

      On March 27, 2002, the Audit Committee of Xcel Energy’s Board of Directors recommended, and the Xcel Energy Board approved, the decision to engage Deloitte & Touche LLP as its new principal independent accountants for Xcel Energy for 2002.

      Accordingly, on March 27, 2002, Xcel Energy’s management informed Arthur Andersen LLP that the firm would no longer be engaged as principal independent accountants for Xcel Energy and its utility subsidiaries after the completion of their 2001 audit work for those companies. The reports of Arthur Andersen LLP on the financial statements of the utility subsidiaries for the years ended December 31, 2001 and 2000 did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles.

      On April 30, 2002, each respective Board of Directors of the Xcel Energy registrant subsidiaries approved the decision to engage Deloitte & Touche LLP as their new principal independent accountant for the year ending Dec. 31, 2002. On May 28, 2002 it was determined that all reports relating to the year ended Dec. 31, 2001 had been issued. Accordingly as of May 28, 2002 Arthur Andersen LLP ceased to be the principal independent auditor of the Xcel Energy registrant subsidiaries

      The utility subsidiaries requested that Arthur Andersen LLP furnish them with a letter addressed to the Securities and Exchange Commission stating whether or not it agrees with the above statements. Arthur Andersen LLP’s letter dated April 3, 2002 is incorporated herein by reference to Exhibit 16.01 to Form 8-K, dated May 28, 2002.

PART III

      Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for Xcel Energy’s utility subsidiaries in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

 
Item 10. Directors and Executive Officers of the Registrant (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
 
Item 11. Executive Compensation (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
 
Item 12. Security Ownership of Certain Beneficial Owners and Management (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
 
Item 13. Certain Relationships and Related Transactions (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
 
Item 14. Controls and Procedures

      Xcel Energy’s Utility Subsidiaries maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Within the 90-day period prior to the filing of this report, an evaluation was carried out under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of our disclosure controls and procedures. Based on that evaluation, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

      Subsequent to the date of their evaluation, there have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls.

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PART IV

 
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

NSP-Minnesota

             
Page

(a)1.
  Financial Statements and Schedules        
    Reports of Independent Auditors for the years ended Dec. 31, 2002, 2001 and 2000     48  
    Statements of Income for the three years ended Dec. 31, 2002     55  
    Statements of Cash Flows for the three years ended Dec. 31, 2002     56  
    Balance Sheets, Dec. 31, 2002 and 2001     57  
    Notes to Financial Statements     75  
    Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2002, 2001 and 2000        

   2.       Exhibits

         
   *     Indicates incorporation by reference.
  2.01*     Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Company and New Century Energies, Inc. (Incorporated by reference to Exhibit 2.1 to the Report on Form 8-K (File No. 1-12907) of New Century Energies, Inc. dated March 24, 1999).
  3.01*     Articles of Incorporation and Amendments of the Company.
  3.02*     By-Laws of the Company.
  4.01*     Trust Indenture, dated Feb. 1, 1937, from NSP to Harris Trust and Savings Bank, as Trustee. (Exhibit B-7 to File No. 2-5290).
  4.02*     Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K of NSP for the year 1988, File No. 1-3034). Supplemental Indenture between NSP and said Trustee, supplemental to Exhibit 4.03, dated as follows:
  4.03*     June 1, 1942 (Exhibit B-8 to File No. 2-97667).
  4.04*     Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290).
  4.05*     Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924).
  4.06*     July 1, 1948 (Exhibit 7.05 to File No. 2-7549).
  4.07*     Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047).
  4.08*     June 1, 1952 (Exhibit 4.08 to File No. 2-9631).
  4.09*     Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216).
  4.10*     Sept. 1, 1956 (Exhibit 2.09 to File No. 2-13463).
  4.11*     Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156).
  4.12*     July 1, 1958 (Exhibit 4.12 to File No. 2-15220).
  4.13*     Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355).
  4.14*     Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282).
  4.15*     June 1, 1962 (Exhibit 2.14 to File No. 2-21601).
  4.16*     Sept. 1, 1963 (Exhibit 4.16 to File No. 2-22476).
  4.17*     Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338).
  4.18*     June 1, 1967 (Exhibit 2.17 to File No. 2-27117).
  4.19*     Oct. 1, 1967 (Exhibit 2.01R to File No. 2-28447).
  4.20*     May 1, 1968 (Exhibit 2.01S to File No. 2-34250).
  4.21*     Oct. 1, 1969 (Exhibit 2.01T to File No. 2-36693).
  4.22*     Feb. 1, 1971 (Exhibit 2.01U to File No. 2-39144).
  4.23*     May 1, 1971 (Exhibit 2.01V to File No. 2-39815).
  4.24*     Feb. 1, 1972 (Exhibit 2.01W to File No. 2-42598).

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  4.25*     Jan. 1, 1973 (Exhibit 2.01X to File No. 2-46434).
  4.26*     Jan. 1, 1974 (Exhibit 2.01Y to File No. 2-53235).
  4.27*     Sept. 1, 1974 (Exhibit 2.01Z to File No. 2-53235).
  4.28*     April 1, 1975 (Exhibit 4.01AA to File No. 2-71259).
  4.29*     May 1, 1975 (Exhibit 4.01BB to File No. 2-71259).
  4.30*     March 1, 1976 (Exhibit 4.01CC to File No. 2-71259).
  4.31*     June 1, 1981 (Exhibit 4.01DD to File No. 2-71259).
  4.32*     Dec. 1, 1981 (Exhibit 4.01EE to File No. 2-83364).
  4.33*     May 1, 1983 (Exhibit 4.01FF to File No. 2-97667).
  4.34*     Dec. 1, 1983 (Exhibit 4.01GG to File No. 2-97667).
  4.35*     Sept. 1, 1984 (Exhibit 4.01HH to File No. 2-97667).
  4.36*     Dec. 1, 1984 (Exhibit 4.01II to File No. 2-97667).
  4.37*     May 1, 1985 (Exhibit 4.36 to Form 10-K for the year 1985, File No. 1-3034).
  4.38*     Sept. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985, File No. 1-3034).
  4.39*     July 1, 1989 (Exhibit 4.01 to Form 8-K dated July 7, 1989, File No. 1-3034).
  4.40*     June 1, 1990 (Exhibit 4.01 to Form 8-K dated June 1, 1990, File No. 1-3034).
  4.41*     Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated Oct. 13, 1992, File No. 1-3034).
  4.42*     April 1, 1993 (Exhibit 4.01 to Form 8-K dated March 30, 1993, File No. 1-3034).
  4.43*     Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated Dec. 7, 1993, File No. 1-3034).
  4.44*     Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated Feb. 10, 1994, File No. 1-3034).
  4.45*     Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated Oct. 5, 1994, File No. 1-3034).
  4.46*     June 1, 1995 (Exhibit 4.01 to Form 8-K dated June 28, 1995, File No. 1-3034).
  4.47*     April 1, 1997 (Exhibit 4.47 to Form 10-K for the year 1997, File No. 1-3034).
  4.48*     March 1, 1998 (Exhibit 4.01 to Form 8-K dated March 11, 1998, File No. 1-3034).
  4.49*     May 1, 1999 (Exhibit 4.49 to Form 10 of NSP-Minnesota, File No. 000-31709).
  4.50*     June 1, 2000 (Exhibit 4.50 to Form 10 of NSP-Minnesota, File No. 000-31709).
  4.51*     Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to Form 10 of NSP-Minnesota, File No. 000-31709).
  4.52*     Subordinated Debt Securities Indenture, dated as of Jan. 30, 1997, between Xcel Energy and Norwest Bank Minnesota, National Association, as trustee. (Exhibit 4.02 to Form 8-K dated Jan. 28, 1997, File No. 001-03034).
  4.53*     Preferred Securities Guarantee Agreement, dated as of Jan. 31, 1997, between Xcel Energy and Wilmington Trust Company, as Trustee. (Exhibit 4.05 to Form 8-K dated Jan. 28, 1997, File No. 001-03034).
  4.54*     Preferred Securities Guarantee Agreement, dated as of Aug. 18, 2000, between Northern States Power Company and Wilmington Trust Company, as Trustee. (Exhibit 4.54 to Form 10 of NSP-Minnesota, File No. 000-31709).
  4.55*     Amended and Restated Declaration of Trust of NSP Financing I, dated as of Jan. 31, 1997, including form of Preferred Security. (Exhibit 4.10 to Form 8-K dated Jan. 28, 1997, File No. 001-03034).
  4.56*     Supplemental Indenture, dated as of Jan. 31, 1997, between Xcel Energy and Norwest Bank Minnesota, National Association, as trustee, including form of Junior Subordinated Debenture. (Exhibit 4.12 to Form 8-K dated Jan. 28, 1997, File No. 001-03034).
  4.57*     Supplemental Trust Indenture dated Aug. 18, 2000 between Xcel Energy, Northern States Power Company and Wells Fargo Bank Minnesota, National Association, as Trustee (Exhibit 4.57 to Form 10 of NSP-Minnesota, File No. 000-31709).
  4.58*     Common Securities Guarantee Agreement dated as of Jan. 31, 1997, between Xcel Energy and Wilmington Trust Company, as Trustee. (Exhibit 4.13 to Form 8-K dated Jan. 28, 1997, File No. 001-03034).

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  4.59*     Common Securities Guarantee Agreement dated as of Aug. 18, 2000, between NSP and Wilmington Trust Company, as Trustee. (Exhibit 4.59 to Form 10 of NSP-Minnesota, File No. 000-31709).
  4.60*     Subscription Agreement dated as of Jan. 28, 1997, between NSP Financing I and NSP. (Exhibit 4.14 to Form 8-K dated Jan. 28, 1997, File No. 001-03034).
  4.61*     Trust Indenture, dated July 1, 1999, between NSP and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K dated July 21, 1999, File No. 1-03034).
  4.62*     Supplemental Trust Indenture dated July 15, 1999, between NSP and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to Form 8-K dated July 21, 1999, File No. 1-03034).
  4.63*     Supplemental Trust Indenture dated Aug. 18, 2000, among Xcel Energy, Northern States Power Company and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to Form 10 of NSP-Minnesota, File No. 000-31709).
  4.64*     Supplemental Trust Indenture dated June 1, 2002, between Northern States Power Company and BNY Midwest Trust Company, as successor trustee. (Exhibit 4.05 to Form 10-Q, dated Sept. 30, 2002, File No. 000-31709).
  4.65*     Supplemental Trust Indenture dated July 1, 2002, between Northern States Power Company and BNY Midwest Trust Company, as successor trustee. (Exhibit 4.06 to Form 10-Q, dated Sept. 30, 2002, File No. 000-31709).
  4.66*     Supplemental Trust Indenture dated July 1, 2002, between Northern States Power Company and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K, dated July 8, 2002, File No. 000-31709).
  4.67*     Supplemental Trust Indenture dated Aug. 1, 2002, between Northern States Power Company and BNY Midwest Trust Company, as Trustee. (Exhibit 4.01 to Form 8-K, dated Aug. 22, 2002, file No. 000-31709).
  4.68*     Registration Rights Agreement dated Aug. 29, 2002, between Northern States Power Company and Initial Bond Purchasers. (Exhibit 4.1 to Form S-4, File No. 333-101531).
  10.01*     Facilities Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (kv) line. (Exhibit 5.06I to File No. 2-54310).
  10.02*     Transactions Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06J to File No. 2-54310).
  10.03*     Coordinating Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06K to File No. 2-54310).
  10.04*     Ownership and Operating Agreement, dated March 11, 1982, between NSP, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034).
  10.05*     Transmission Agreement, dated April 27, 1982, and Supplement No. 1, dated July 20, 1982, between NSP and Southern Minnesota Municipal Power Agency. (Exhibit 10.02 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034).
  10.06*     Power Agreement, dated June 14, 1984, between NSP and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034).
  10.07*     Power Agreement, dated August 1988, between NSP and Minnkota Power Company. (Exhibit 10.08 to Form 10-K for the year 1988, File No. 1-3034).
  10.08*     Assignment and Assumption Agreement, dated Aug. 18, 2000 between Northern States Power Company and Xcel Energy Inc. (Exhibit 10.08 to Form 10 of NSP-Minnesota, File No. 000-31709)
  10.09*     Copy of Interchange Agreement dated Sept. 17, 1984, and Settlement Agreement dated May 31, 1985, between NSP-Wisconsin, the NSP-Minnesota Company and LSDP. (Filed as Exhibit 10.10 to Form 10-K Report 10-3140 for the year 1985).
  12.01     Statement of Computation of Ratio of Earnings to Fixed Charges.
  16.01*     Letter regarding change in accountant (Exhibit 16.01 to Form 8-K, dated May 28, 2002, File No. 001-3034)

126


Table of Contents

         
  23.01     Consent of Independent Accountants.
  99.01     Statement pursuant to Private Securities Litigation Reform Act of 1995.
  99.02*     Exhibit regarding the use of Arthur Andersen Audit Firm (Exhibit 99.02 to Form 10-K, File No. 001-3034)
  99.03     Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2002, or between Dec. 31, 2002 and the date of this report.

None

NSP-Wisconsin

             
Page

(a)1.
  Financial Statements and Schedules        
    Reports of Independent Auditors for the years ended Dec. 31, 2002, 2001 and 2000     50  
    Statements of Income for the three years ended Dec. 31, 2002     60  
    Statements of Cash Flows for the three years ended Dec. 31, 2002     61  
    Balance Sheets, Dec. 31, 2002 and 2001     62  
    Notes to Financial Statements     75  
    Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2002, 2001 and 2000        

   2.       Exhibits

         
   *     Indicates incorporation by reference.
  3.01*     Restated Articles of Incorporation as of Dec. 23, 1987. (Filed as Exhibit 3.01 to Form 10-K Report 10-3140 for the year 1987).
  3.02*     Copy of the By-Laws of NSP-Wisconsin as amended Feb. 2, 2000. (Filed as Exhibit 3.01 to Form 10-K Report 10-3140 for the year 1987).
  4.01*     Copy of Trust Indenture, dated April 1, 1947, From NSP-Wisconsin to Firstar Trust Company (formerly First Wisconsin Trust Company). (Filed as Exhibit 7.01 to Registration Statement 2-6982)
  4.02*     Copy of Supplemental Trust Indenture, dated March 1, 1949. (Filed as Exhibit 7.02 to Registration Statement 2-7825)
  4.03*     Copy of Supplemental Trust Indenture, dated June 1, 1957. (Filed as Exhibit 2.13 to Registration Statement 2-13463)
  4.04*     Copy of Supplemental Trust Indenture, dated Aug. 1, 1964. (Filed as Exhibit 4.20 to Registration Statement 2-23726)
  4.05*     Copy of Supplemental Trust Indenture, dated Dec. 1, 1969. (Filed as Exhibit 2.03E to Registration Statement 2-36693).
  4.06*     Copy of Supplemental Trust Indenture, dated Sept. 1, 1973. (Filed as Exhibit 2.03F to Registration Statement 2-49757).
  4.07*     Copy of Supplemental Trust Indenture, dated Feb. 1, 1982. (Filed as Exhibit 4.01G to Registration Statement 2-76146).
  4.08*     Copy of Supplemental Trust Indenture, dated March 1, 1982. (Filed as Exhibit 4.08 to form 10-K Report 10-3140 for the year 1982).
  4.09*     Copy of Supplemental Trust Indenture, dated June 1, 1986. (Filed as Exhibit 4.09 to Form 10-K Report 10-3140 for the year 1986).
  4.10*     Copy of Supplemental Trust Indenture, dated March 1, 1988. (Filed as Exhibit 4.10 to Form 10-K Report 10-3140 for the year 1988).
  4.11*     Copy of Supplemental and Restated Trust Indenture, dated March 1, 1991. (Filed as Exhibit 4.01K to Registration Statement 33-39831).

127


Table of Contents

         
  4.12*     Copy of Supplemental Trust Indenture, dated April 1, 1991. (Filed as Exhibit 4.01 to Form 10-Q Report 10-3140 for the quarter ended March 31, 1991).
  4.13*     Copy of Supplemental Trust Indenture, dated March 1, 1993. (Filed as Exhibit to Form 8-K Report dated March 3, 1993).
  4.14*     Copy of Supplemental Trust Indenture, dated Oct. 1, 1993. (Filed as Exhibit 4.01 to Form 8-K Report dated Sept. 21, 1993).
  4.15*     Copy of Supplemental Trust Indenture, dated Dec. 1, 1996. (Filed as Exhibit 4.01 to Form 8-K Report dated Dec. 12, 1996).
  10.01*     Copy of Interchange Agreement dated Sept. 17, 1984, and Settlement Agreement dated May 31, 1985, between NSP-Wisconsin, the Minnesota Company and LSDP. (Filed as Exhibit 10.10 to Form 10-K Report 10-3140 for the year 1985).
  12.01     Statement of Computation of Ratio of Earnings to Fixed Charge.
  16.01*     Letter regarding change in accountant (Exhibit 16.01 to Form 8-K, dated May 28, 2002, File No. 001-3140).
  99.01     Statement pursuant to Private Securities Litigation Reform Act of 1995.
  99.02*     Exhibit regarding the use of Arthur Andersen Audit Firm (Exhibit 99.02 to Form 10-K, File No. 001-3140).
  99.03     Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


(b) Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2002, or between Dec. 31, 2002 and the date of this report.

        None

PSCo

             
Page

(a)1.
  Financial Statements and Schedules        
    Reports of Independent Auditors for the years ended Dec. 31, 2002, 2001 and 2000.      52  
    Statements of Income for the three years ended Dec. 31, 2002.      65  
    Statements of Cash Flows for the three years ended Dec. 31, 2002.      66  
    Balance Sheets, Dec. 31, 2002 and 2001.      67  
    Notes to Financial Statements.      75  
    Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2002, 2001 and 2000        
     
2.
  Exhibits
*
  Indicates incorporation by reference
2.01*
  Merger Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, dated Aug. 22, 1995, File No. 1-3280 — Exhibit 2).
3.01*
  Amended and Restated Articles of Incorporation dated July 10, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*
  By-laws dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
4.01*
  Indenture, dated as of Dec. 1, 1939, providing for the issuance of First Mortgage Bonds (Form 10 for 1946- Exhibit (B-1)).
4.02*
  Indentures supplemental to Indenture dated as of Dec. 1, 1939:
                                         
Previous Filing: Previous Filing:
Form; Date or Exhibit Form; Date or Exhibit
Dated as of File No. No. Dated as of File No. No.






Mar. 14, 1941
    10, 1946       B-2       Sept. 1, 1970       8-K, Sept. 1970       2  
May 14, 1941
    10, 1946       B-3       Feb. 1, 1971       8-K, Feb. 1971       2  
Apr. 28, 1942
    10, 1946       B-4       Aug. 1, 1972       8-K, Aug. 1972       2  
Apr. 14, 1943
    10, 1946       B-5       June 1, 1973       8-K, June 1973       1  

128


Table of Contents

                                         
Previous Filing: Previous Filing:
Form; Date or Exhibit Form; Date or Exhibit
Dated as of File No. No. Dated as of File No. No.






Apr. 27, 1944
    10, 1946       B-6       Mar. 1, 1974       8-K, Apr. 1974       2  
Apr. 18, 1945
    10, 1946       B-7       Dec. 1, 1974       8-K, Dec. 1974       1  
Apr. 23, 1946
    10-K, 1946       B-8       Oct. 1, 1975       S-7, (2-60082)       2(b)(3)  
Apr. 9, 1947
    10-K, 1946       B-9       Apr. 28, 1976       S-7, (2-60082)       2(b)(4)  
June 1, 1947
    S-1, (2-7075)       7(b)       Apr. 28, 1977       S-7, (2-60082)       2(b)(5)  
Apr. 1, 1948
    S-1, (2-7671)       7(b)(1)       Nov. 1, 1977       S-7, (2-62415)       2(b)(3)  
May 20, 1948
    S-1, (2-7671)       7(b)(2)       Apr. 28, 1978       S-7, (2-62415)       2(b)(4)  
Oct. 1, 1948
    10-K, 1948       4       Oct. 1, 1978       10-K, 1978       D(1)  
Apr. 20, 1949
    10-K, 1949       1       Oct. 1, 1979       S-7, (2-66484)       2(b)(3)  
Apr. 24, 1950
    8-K, Apr. 1950       1       Mar. 1, 1980       10-K, 1980       4(c)  
Apr. 18, 1951
    8-K, Apr. 1951       1       Apr. 28, 1981       S-16, (2-74923)       4(c)  
Oct. 1, 1951
    8-K, Nov. 1951       1       Nov. 1, 1981       S-16, (2-74923)       4(d)  
Apr. 21, 1952
    8-K, Apr. 1952       1       Dec. 1, 1981       10-K, 1981       4(c)  
Dec. 1, 1952
    S-9, (2-11120)       2(b)(9)       Apr. 29, 1982       10-K, 1982       4(c)  
Apr. 15, 1953
    8-K, Apr. 1953       2       May 1, 1983       10-K, 1983       4(c)  
Apr. 19, 1954
    8-K, Apr. 1954       1       Apr. 30, 1984       S-3, (2-95814)       4(c)  
Oct. 1, 1954
    8-K, Oct. 1954       1       Mar. 1, 1985       10-K, 1985       4(c)  
Apr. 18, 1955
    8-K, Apr. 1955       1       Nov. 1, 1986       10-K, 1986       4(c)  
Apr. 24, 1956
    10-K, 1956       1       May 1, 1987       10-K, 1987       4(c)  
May 1, 1957
    S-9, (2-13260)       2(b)(15)       July 1, 1990       S-3, (33-37431)       4(c)  
Apr. 10, 1958
    8-K, Apr. 1958       1       Dec. 1, 1990       10-K, 1990       4(c)  
May 1, 1959
    8-K, May 1959       2       Mar. 1, 1992       10-K, 1992       4(d)  
Apr. 18, 1960
    8-K, Apr. 1960       1       Apr. 1, 1993       10-Q, June 30, 1993       4(a)  
Apr. 19, 1961
    8-K, Apr. 1961       1       June 1, 1993       10-Q, June 30, 1993       4(b)  
Oct. 1, 1961
    8-K, Oct. 1961       2       Nov. 1, 1993       S-3, (33-51167)       4(a)(3)  
Mar. 1, 1962
    8-K, Mar. 1962       3(a)       Jan. 1, 1994       10-K, 1993       4(a)(3)  
June 1, 1964
    8-K, June 1964       1       Sept. 2, 1994       8-K, Sept. 1994       4(a)  
May 1, 1966
    8-K, May 1966       2       May 1, 1996       10Q, June 30, 1996       4(a)  
July 1, 1967
    8-K, July 1967       2       Nov. 1, 1996       10-K, 1996       4(a)(3)  
July 1, 1968
    8-K, July 1968       2       Feb. 1, 1997       10-Q, Mar. 31, 1997       4(a)  
Apr. 25, 1969
    8-K, Apr. 1969       1       April 1, 1998       10-Q, Mar. 31, 1998       4(a)  
Apr. 21, 1970
    8-K, Apr. 1970       1       Aug. 15, 2002       10-Q, Sept. 30, 2002       4.01  
                      Sept. 15, 2002       10-Q, Sept. 30, 2002       4.02  
                      Sept. 18, 2002       8-K, Sept. 18, 2002       4.02  

129


Table of Contents

     
4.03*
  Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
4.04*
  Indentures supplemental to Indenture dated as of Oct. 1, 1993:
                 
Previous Filing:
Form; Date or Exhibit
Dated as of File No. No.



Nov. 1, 1993
    S-3, (33-51167)       4(b)(2)  
Jan. 1, 1994
    10-K, 1993       4(b)(3)  
Sept. 2, 1994
    8-K, Sept. 1994       4(b)  
May 1, 1996
    10-Q, June 30, 1996       4(b)  
Nov. 1, 1996
    10-K, 1996       4(b)(3)  
Feb. 1, 1997
    10-Q, Mar. 31, 1997       4(b)  
April 1, 1998
    10-Q, Mar. 31, 1998       4(b)  
Aug. 15, 2002
    10-Q, Sept. 30, 2002       4.03  
Sept. 1, 2002
    8-K, Sept. 18, 2002       4.01  
Sept. 15, 2002
    10-Q, Sept. 30, 2002       4.04  
         
  4.05*     Indenture date May 1, 1998, between PSCo and The Bank of New York, providing for the issuance of Subordinated Debt Securities (Form 8-K, May 6, 1998 — Exhibit 4.2).
  4.06*     Supplemental Indenture dated May 11, 1998, between PSCo and The Bank of New York, (Form 8-K, May 6, 1998 — Exhibit 4.3).
  4.07*     Preferred Securities Guarantee Agreement dated May 11, 1998, between PSCo and The Bank of New York, (Form 8-K, May 6, 1998 — Exhibit 4.4).
  4.08*     Amended and Restated Declaration of Trust of PSCo Capital and Trust I date May 11, 1998, (Form 8-K, May 6, 1998 — Exhibit 4.1).
  4.09*     Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities (Form 8-K, July 13, 1999, Exhibit 4.1) and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Form 8-K, July 13, 1999, Exhibit 4.2).
  4.10*     Registration Rights Agreement dated Sept. 26, 2002, between Public Service Company of Colorado and Initial Bond Purchasers. (Exhibit 4.1 to Form S-4, File No. 333-101913).
  10.01*     Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between the Registrant and Amax Inc. on behalf of its division, Amax Coal Company (Form 10-K, Dec. 31, 1984 — Exhibit 10(c)(1)).
  10.02*     First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between the Registrant and Amax Coal Company (Form 10-K, Dec. 31, 1988 — Exhibit 10(c)(2).
  10.03*     Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (Form 10-K, Dec. 31, 1991 — Exhibit 10(e)(2)).
  10.04*     Executive Savings Plan (Form 10-K, Dec. 31, 1991 — Exhibit 10(e)(5)).
  10.05*     Form of Key Executive Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Form 10-K, Dec. 31, 1995 — Exhibit 10(3)(4)).
  12.01     Statement of Computation of Ratio of Earnings to Fixed Charge.
  16.01*     Letter regarding change in accountant (Exhibit 16.01 to Form 8-K, dated May 28, 2002, File No. 001-3280).
  23.01     Consent of Independent Accountants.

130


Table of Contents

         
  99.01     Statement pursuant to Private Securities Litigation Reform Act of 1995.
  99.02*     Exhibit regarding the use of Arthur Andersen Audit Firm (Exhibit 99.02 to Form 10-K, File No. 001-3280).
  99.03     Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


(b) Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2002, or between Dec. 31, 2002 and the date of this report.

           None

SPS

             
Page

(a)1.
  Financial Statements and Schedules        
    Reports of Independent Auditors for the years ended Dec. 31, 2002, 2001 and 2000.      53  
    Statements of Income for the three years ended Dec. 31, 2002.      70  
    Statements of Cash Flows for the three years ended Dec. 31, 2002.      71  
    Balance Sheets, Dec. 31, 2002 and 2001.      72  
    Notes to Financial Statements.      75  
    Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2002, 2001 and 2000        
     
2.
  Exhibits
*
  indicates incorporation by reference
2.01*
  Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, Exhibit 2, dated Aug. 22, 1995).
3.01*
  Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(a)(2)).
3.02*
  By-laws dated Sept. 29, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(2)).
4.01*
  Indenture, dated as of Aug. 1, 1946, providing for the issuance of First Mortgage Bonds (Registration No. 2-6910, Exhibit 7-A).
4.02*
  Indentures supplemental to Indenture dated as of Aug. 1, 1946:
         
Previous Filing:
Form; Date or Exhibit
Dated as of File No. No.



Feb. 1, 1967
  2-25983   2-S
Oct. 1, 1970
  2-38566   2-T
Feb. 9, 1977
  2-58209   2-Y
March 1, 1979
  2-64022   b(28)
April 1, 1983 (two)
  10-Q, May 1983   4(a)
Feb. 1, 1985
  10-K, Aug. 1985   4(c)
July 15, 1992 (two)
  10-K, Aug. 1992   4(a)
Dec. 1, 1992 (two)
  10-Q, Feb. 1993   4
Feb. 15, 1995
  10-Q, May 1995   4
March 1, 1996
  333-05199   4(c)
         
  4.03*     Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Form 8-K, Feb. 25, 1999, Exhibit B).
  4.04*     Supplemental Indenture dated March 1, 1999, between SPS and The Chase Manhattan Bank (Form 8-K, Feb. 25, 1999, Exhibit C).
  4.05*     Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 — Exhibit 4(b)).

131


Table of Contents

         
  4.06*     Indenture dated Oct. 21, 1996, between SPS and Wilmington Trust Company, (Form 10-Q, Nov. 30, 1996 — Exhibit 4(a)).
  4.07*     Supplemental Indenture dated Oct. 21, 1996, between SPS and Wilmington Trust Co., (Form 10-Q, Nov. 30, 1996 — Exhibit 4(b)).
  4.08*     Guarantee Agreement dated Oct. 21, 1996, between SPS and Wilmington Trust Co., (Form 10-Q, Nov. 30, 1996 — Exhibit 4(c)).
  4.09*     Amended and Restated Trust Agreement dated Oct. 21, 1996, among SPS, David M. Wilks, as initial depositor, Wilmington Trust Co. and the administrative trustees named therein (Form 10-Q, Nov. 30, 1996 — Exhibit 4(d)).
  4.10*     Agreement as to Expenses dated Oct. 21, 1996, between SPS and Southwestern Public Service Capital I, (Form 10-K, Dec. 31, 1996 — Exhibit F).
  10.01*     Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K, May 14, 1979 — Exhibit 3).
  10.02*     Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, May 14, 1979 — Exhibit 5(A)).
  10.03*     Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, May 14, 1979 — Exhibit 5(B)).
  10.04*     Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, Feb. 28, 1982 — Exhibit 10(b)).
  10.05*     Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, Feb. 28, 1982 — Exhibit 10(c)).
  10.06*     Incentive Compensation Plan (an Executive Management Plan) as amended July 23, 1996 (Form 10-K, Aug. 31, 1996 — Exhibit 10(a)).
  10.07*     1989 Stock Incentive Plan as amended April 23, 1996 (Form 10-K, Aug. 31, 1996 — Exhibit 10(b)).
  10.08*     Director’s Deferred Compensation Plan as amended Jan. 10, 1990 (Form 10-K, Aug. 31, 1996 — Exhibit 10(c)).
  10.09*     Supplemental Retirement Income Plan as amended July 23, 1991 (Form 10-K, Aug. 31, 1996 — Exhibit 10(e)).
  10.10*     EPS Performance Unit Plan dated Oct. 27, 1992 (Form 10-K, Aug. 31, 1996 — Exhibit 10(a)).
  12.01     Statement of Computation of Ratio of Earnings to Fixed Charge.
  16.01*     Letter regarding change in accountant (Exhibit 16.01 to Form 8-K, dated May 28, 2002, File No. 001-3789).
  99.01     Statement pursuant to Private Securities Litigation Reform Act of 1995.
  99.02*     Exhibit regarding the use of Arthur Andersen Audit Firm (Exhibit 99.02 to Form 10-K, File No. 001-3789).
  99.03     Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


(b)  Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2002, or between Dec. 31, 2002 and the date of this report.

None

132


Table of Contents

SCHEDULE II

UTILITY SUBSIDIARIES OF XCEL ENERGY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Years Ended Dec. 31, 2002, 2001 and 2000
                                             
Additions

Balance at Charged Charged Deductions Balance
beginning to costs & to other from at end
of period expenses accounts reserves(1) of period





(Thousands of dollars)
NSP-Minnesota
                                       
Reserve deducted from related assets:
                                       
 
Provision for uncollectible accounts:
                                       
   
2002
  $ 5,452     $ 8,028     $ 4,197     $ 11,865     $ 5,812  
     
     
     
     
     
 
   
2001
  $ 4,952     $ 6,664     $ 3,697     $ 9,861     $ 5,452  
     
     
     
     
     
 
   
2000
  $ 5,503     $ 5,642     $ 3,929     $ 10,122     $ 4,952  
     
     
     
     
     
 
NSP-Wisconsin
                                       
Reserve deducted from related assets:
                                       
 
Provision for uncollectible accounts:
                                       
   
2002
  $ 969     $ 2,036     $ 1,083     $ 2,715     $ 1,373  
     
     
     
     
     
 
   
2001
  $ 798     $ 1,710     $ 3,321     $ 4,860     $ 969  
     
     
     
     
     
 
   
2000
  $ 943     $ 2,269     $ 1,006     $ 3,420     $ 798  
     
     
     
     
     
 
PSCo
                                       
Reserve deducted from related assets:
                                       
 
Provision for uncollectible accounts:
                                       
   
2002
  $ 14,510     $ 10,736     $ 3,608     $ 15,169     $ 13,685  
     
     
     
     
     
 
   
2001
  $ 11,352     $ 12,749     $ 37     $ 9,628     $ 14,510  
     
     
     
     
     
 
   
2000
  $ 2,533     $ 15,011     $ 37     $ 6,229     $ 11,352  
     
     
     
     
     
 
SPS
                                       
Reserve deducted from related assets:
                                       
 
Provision for uncollectible accounts:
                                       
   
2002
  $ 1,785     $ 2,576     $ 802     $ 3,604     $ 1,559  
     
     
     
     
     
 
   
2001
  $ 845     $ 3,057     $     $ 2,117     $ 1,785  
     
     
     
     
     
 
   
2000
  $ 682     $ 1,475     $     $ 1,312     $ 845  
     
     
     
     
     
 


(1)  Uncollectible accounts written off or transferred to other parties.

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NSP-MINNESOTA

 
SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

  NSP-MINNESOTA
 
  /s/ RICHARD C. KELLY
 
  Richard C. Kelly
  Vice President and Chief Financial Officer
  (Principal Financial Officer)

February 25, 2003

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

     
 
/s/ WAYNE H. BRUNETTI   /s/ GARY R. JOHNSON

 
Wayne H. Brunetti
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
  Gary R. Johnson
Director
 
/s/ DAVID E. RIPKA   /s/ RICHARD C. KELLY

 
David E. Ripka
Vice President and Controller
(Principal Accounting Officer)
  Richard C. Kelly
Director

134


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NSP-MINNESOTA

CERTIFICATIONS

I, Wayne H. Brunetti, certify that:

      1. I have reviewed this annual report on Form 10-K of Northern States Power Co. (A Minnesota Corporation);

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

      3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
 
        b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
 
        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

      6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

  /s/ WAYNE H. BRUNETTI
 
  Wayne H. Brunetti
  Chairman, President and Chief Executive Officer

Date: Feb. 25, 2003

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I, Richard C. Kelly, certify that:

      1. I have reviewed this annual report on Form 10-K of Northern States Power Co. (A Minnesota Corporation);

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

      3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
 
        b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
 
        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

      6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

  /s/ RICHARD C. KELLY
 
  Richard C. Kelly
  Vice President and Chief Financial Officer

Date: Feb. 25, 2003

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NSP-WISCONSIN

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

  NSP-WISCONSIN
 
  /s/ RICHARD C. KELLY
 
  Richard C. Kelly
  Vice President and Chief Financial Officer
  (Principal Financial Officer)

February 25, 2003

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

     
 
/s/ MICHAEL L. SWENSON   /s/ WAYNE H. BRUNETTI

 
Michael L. Swenson
President and Chief Executive Officer
(Principal Executive Officer)
  Wayne H. Brunetti
Chairman
 
/s/ DAVID E. RIPKA   /s/ GARY R. JOHNSON

 
David E. Ripka
Vice President and Controller
(Principal Accounting Officer)
  Gary R. Johnson
Director
 
/s/ RICHARD C. KELLY

Richard C. Kelly
Director
   

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NSP-WISCONSIN

CERTIFICATIONS

I, Michael L. Swenson, certify that:

      1. I have reviewed this annual report on Form 10-K of Northern States Power Co. (A Wisconsin Corporation);

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

      3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
 
        b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
 
        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

      6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

  /s/ MICHAEL L. SWENSON
 
  Michael L. Swenson
  President and Chief Executive Officer

Date: Feb. 25, 2003

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I, Richard C. Kelly, certify that:

      1. I have reviewed this annual report on Form 10-K of Northern States Power Co. (A Wisconsin Corporation);

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

      3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
 
        b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
 
        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

      6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

  /s/ RICHARD C. KELLY
 
  Richard C. Kelly
  Vice President and Chief Financial Officer

Date: Feb. 25, 2003

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PSCo

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

  PUBLIC SERVICE COMPANY OF COLORADO
 
  /s/ RICHARD C. KELLY
 
  Richard C. Kelly
  Vice President and Chief Financial Officer
  (Principal Finance Officer)

February 25, 2003

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

     
 
/s/ WAYNE H. BRUNETTI   /s/ GARY R. JOHNSON

 
Wayne H. Brunetti
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
  Gary R. Johnson
Director
 
/s/ DAVID E. RIPKA   /s/ RICHARD C. KELLY

 
David E. Ripka
Vice President and Controller
(Principal Accounting Officer)
  Richard C. Kelly
Director

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Table of Contents

PSCo

CERTIFICATIONS

I, Wayne H. Brunetti, certify that:

      1. I have reviewed this annual report on Form 10-K of Public Service Company of Colorado;

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

      3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
 
        b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
 
        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

      6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

  /s/ WAYNE H. BRUNETTI
 
  Wayne H. Brunetti
  Chairman, President and Chief Executive Officer

Date: Feb. 25, 2003

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I, Richard C. Kelly, certify that:

      1. I have reviewed this annual report on Form 10-K of Public Service Company of Colorado;

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

      3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
 
        b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
 
        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

      6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

  /s/ RICHARD C. KELLY
 
  Richard C. Kelly
  Vice President and Chief Financial Officer

Date: Feb. 25, 2003

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SPS

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

  SOUTHWESTERN PUBLIC SERVICE CO.
 
  /s/ RICHARD C. KELLY
 
  Vice President and Chief Financial Officer
  (Principal Financial Officer)

February 25, 2003

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

     
 
/s/ GARY L. GIBSON   /s/ WAYNE H. BRUNETTI

 
Gary L. Gibson
President and Chief Executive Officer
(Principal Executive Officer)
  Wayne H. Brunetti
Chairman
 
/s/ DAVID E. RIPKA   /s/ GARY R. JOHNSON

 
David E. Ripka
Vice President and Controller
(Principal Accounting Officer)
  Gary R. Johnson
Director
 
/s/ RICHARD C. KELLY

Richard C. Kelly
Director
   

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SPS

CERTIFICATIONS

I, Gary L. Gibson, certify that:

      1. I have reviewed this annual report on Form 10-K of Southwestern Public Service;

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

      3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
 
        b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
 
        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

      6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

  /s/ GARY L. GIBSON
 
  Gary L. Gibson
  President and Chief Executive Officer

Date: Feb. 25, 2003

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I, Richard C. Kelly, certify that:

      1. I have reviewed this annual report on Form 10-K of Southwestern Public Service;

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

      3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

        a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
 
        b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
 
        c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

      5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

        a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
        b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

      6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

  /s/ RICHARD C. KELLY
 
  Richard C. Kelly
  Vice President and Chief Financial Officer

Date: Feb. 25, 2003

145 EX-12.01 3 c75034exv12w01.htm EX-12.01 COMPUTATION OF RATIO OF EARNINGS exv12w01

 

Exhibit 12.01

EXHIBIT 12(a)

NORTHERN STATES POWER COMPANY — MINNESOTA
AND SUBSIDIARIES

COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS
TO CONSOLIDATED FIXED CHARGES

(not covered by Report of Independent Auditor)

                                             
        Year Ended December 31,
       
        2002   2001   2000   1999   1998
       
 
 
 
 
                (in thousands, except ratios)        
Earnings:
                                       
 
Net income
  $ 200,222     $ 207,865     $ 111,224     $ 158,980     $ 210,206  
 
Provisions for Federal and state taxes on income
    108,141       132,732       92,191       97,431       124,713  
 
Fixed charges as below
    123,220       112,780       146,192       125,431       113,160  
 
Less: Undistributed equity in earnings of unconsolidated affiliates
                             
 
   
     
     
     
     
 
   
Total
  $ 431,583     $ 453,377     $ 349,607     $ 381,842     $ 448,079  
 
   
     
     
     
     
 
Fixed Charges:
                                       
 
Interest charges, excluding AFC — debt
  $ 107,470     $ 97,030     $ 130,442     $ 109,681     $ 97,410  
 
Distributions on redeemable preferred securities of subsidiary trust
    15,750       15,750       15,750       15,750       15,750  
 
   
     
     
     
     
 
   
Total
  $ 123,220     $ 112,780     $ 146,192     $ 125,431     $ 113,160  
 
   
     
     
     
     
 
Ratio of earnings to fixed charges
    3.5       4.0       2.4       3.0       4.0  
 
   
     
     
     
     
 

 


 

EXHIBIT 12(b)

NORTHERN STATES POWER COMPANY — WISCONSIN

COMPUTATION OF RATIO OF EARNINGS
TO FIXED CHARGES

(not covered by Report of Independent Auditor)

                                             
        Year Ended December 31,
       
        2002   2001   2000   1999   1998
       
 
 
 
 
                (in thousands, except ratios)        
Earnings:
                                       
 
Net income
  $ 54,373     $ 36,392     $ 30,296     $ 36,366     $ 32,195  
 
Provisions for Federal and state taxes on income
    36,925       21,158       20,690       25,302       20,468  
 
Fixed charges as below
    23,467       23,139       21,557       19,627       19,189  
 
Less: Undistributed equity in earnings of unconsolidated affiliates
    232       553       411       409       3  
 
   
     
     
     
     
 
   
Total
  $ 114,533     $ 80,136     $ 72,132     $ 80,886     $ 71,849  
 
   
     
     
     
     
 
Fixed Charges:
                                       
 
Interest charges, excluding AFC — debt
  $ 23,467     $ 23,139     $ 21,557     $ 19,627     $ 19,189  
 
Distributions on redeemable preferred securities of subsidiary trust
                             
 
   
     
     
     
     
 
   
Total
  $ 23,467     $ 23,139     $ 21,557     $ 19,627     $ 19,189  
 
   
     
     
     
     
 
Ratio of earnings to fixed charges
    4.9       3.5       3.3       4.1       3.7  
 
   
     
     
     
     
 

 


 

EXHIBIT 12(c)

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES

COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS
TO CONSOLIDATED FIXED CHARGES

(not covered by Report of Independent Auditor)

                                             
        Year Ended December 31,
       
        2002   2001   2000   1999   1998
       
 
 
 
 
                (in thousands, except ratios)        
Earnings:
                                       
 
Net income
  $ 264,680     $ 273,033     $ 196,128     $ 204,265     $ 200,103  
 
Provisions for Federal and state taxes on income
    128,686       132,501       102,770       96,574       101,494  
 
Fixed charges as below
    237,765       226,651       244,952       234,544       210,539  
 
Less: Undistributed equity in earnings of unconsolidated affiliates
                             
 
   
     
     
     
     
 
   
Total
  $ 631,131     $ 632,185     $ 543,850     $ 535,383     $ 512,136  
 
   
     
     
     
     
 
Fixed Charges:
                                       
 
Interest charges, excluding AFC — debt
  $ 223,021     $ 211,451     $ 229,752     $ 219,344     $ 200,828  
 
Distributions on redeemable preferred securities of subsidiary trust
    14,744       15,200       15,200       15,200       9,711  
 
   
     
     
     
     
 
   
Total
  $ 237,765     $ 226,651     $ 244,952     $ 234,544     $ 210,539  
 
   
     
     
     
     
 
Ratio of earnings to fixed charges
    2.7       2.8       2.2       2.3       2.4  
 
   
     
     
     
     
 

 


 

EXHIBIT 12(d)

SOUTHWESTERN PUBLIC SERVICE COMPANY
AND SUBSIDIARIES

COMPUTATION OF RATIO OF EARNINGS
TO FIXED CHARGES

(not covered by Report of Independent Auditor)

                                             
        Year Ended December 31,
       
        2002   2001   2000   1999   1998
       
 
 
 
 
                (in thousands, except ratios)        
Earnings:
                                       
 
Net income
  $ 73,882     $ 130,100     $ 69,492     $ 102,709     $ 114,987  
 
Provisions for Federal and state taxes on income
    43,363       71,175       58,776       59,399       65,696  
 
Fixed charges as below
    54,913       57,276       67,713       64,888       64,052  
 
Less: Undistributed equity in earnings of unconsolidated affiliates
                             
 
   
     
     
     
     
 
   
Total
  $ 172,158     $ 258,551     $ 195,981     $ 226,996     $ 244,735  
 
   
     
     
     
     
 
Fixed Charges:
                                       
 
Interest charges, excluding AFC — debt
  $ 47,063     $ 49,426     $ 59,863     $ 57,038     $ 56,202  
 
Distributions on redeemable preferred securities of subsidiary trust
    7,850       7,850       7,850       7,850       7,850  
 
   
     
     
     
     
 
   
Total
  $ 54,913     $ 57,276     $ 67,713     $ 64,888     $ 64,052  
 
   
     
     
     
     
 
Ratio of earnings to fixed charges
    3.1       4.5       2.9       3.5       3.8  
 
   
     
     
     
     
 

  EX-23.01 4 c75034exv23w01.htm EX-23.01 CONSENT OF INDEPENDENT ACCOUNTANTS exv23w01

 

EXHIBIT 23.01

INDEPENDENT AUDITORS’ CONSENT

We consent to the incorporation by reference in Registration Statements No. 333-59098 and 333-101531 of Northern States Power Company — Minnesota on Form S-3 and S-4 of our report dated February 24, 2003, appearing in this Annual Report on Form 10-K of Northern States Power Company — Minnesota for the year ended December 31, 2002.

DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 24, 2003

 


 

EXHIBIT 23.01

INDEPENDENT AUDITORS’ CONSENT

We consent to the incorporation by reference in Registration Statements No. 333-81791 and 333-101913 of Public Service Company of Colorado on Forms S-3 and S-4 of our report dated February 24, 2003, appearing in this Annual Report on Form 10-K of Public Service Company of Colorado for the year ended December 31, 2002.

DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 24, 2003

  EX-99.01 5 c75034exv99w01.htm EX-99.01 STATEMENT PURSUANT TO SECURITIES ACT exv99w01

 

Exhibit 99.01

Utility Subsidiaries of Xcel Energy Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of the Utility Subsidiaries of Xcel Energy. These statements are based on management’s beliefs as well as assumptions and information currently available to management. When used in the Utility Subsidiaries of Xcel Energy’s documents or oral presentations, the words “anticipate,” “estimate,” “expect,” “projected,” objective,” “outlook,” “forecast,” “possible,” “potential” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Utility Subsidiaries of Xcel Energy’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

  Economic conditions, including their impact on capital expenditures and the ability of the Utility Subsidiaries of Xcel Energy to obtain financing on favorable terms, inflation rates and monetary fluctuations;
 
  Business conditions in the energy business;
 
  Demand for electricity in the nonregulated marketplace;
 
  Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where the Utility Subsidiaries of Xcel Energy have a financial interest;
 
  Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;
 
  Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;
 
  Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, Xcel Energy or any of its subsidiaries; or security ratings;
 
  Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; or electric transmission or gas pipeline constraints;
 
  Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;
 
  Increased competition in the utility industry;
 
  State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates; structures and affect the speed and degree to which competition enters the electric and gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;
 
  Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;
 
  Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;
 
  Social attitudes regarding the utility and power industries;
 
  Risks associated with the California power market;
 
  Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;
 
  Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;
 
  Significant slowdown in growth or decline in the U.S. economy, delay in growth or recovery of the U.S. economy or increased cost for insurance premiums, security and other items as a consequence of the Sept. 11, 2001 terrorist attacks;
 
  Factors associated with nonregulated investments, including conditions of final legal closing, foreign government actions, foreign economic and currency risks, political instability in foreign countries, partnership actions, competition, operating risks, dependence on certain suppliers and customers, domestic and foreign environmental and energy regulations; and

 


 

  Other business or investment considerations that may be disclosed from time to time in the Utility Subsidiaries of Xcel Energy’s SEC filings or in other publicly disseminated written documents.

The Utility Subsidiaries of Xcel Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exhaustive.

  EX-99.03 6 c75034exv99w03.htm EX-99.03 CERTIFICATION PURSUANT TO 18 USC SEC 1350 exv99w03

 

Exhibit 99.03 — Officer Certification

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of NSP-Minnesota on Form 10-K for 2002, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the NSP-Minnesota certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

  (1)   The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of NSP-Minnesota as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 25, 2003

 
/s/ WAYNE H. BRUNETTI

Wayne H. Brunetti
Chairman, President and Chief Executive Officer
 
/s/ RICHARD C. KELLY

Richard C. Kelly
Vice President and Chief Financial Officer

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

1


 

Exhibit 99.03 — Officer Certification

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of NSP-Wisconsin on Form 10-K for the year 2002, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the NSP-Wisconsin certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

  (1)   The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of NSP-Wisconsin as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 25, 2003

 
/s/ Michael L. Swenson

Wayne H. Brunetti
President and Chief Executive Officer
 
/s/ RICHARD C. KELLY

Richard C. Kelly
Vice President and Chief Financial Officer

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

2


 

Exhibit 99.03 — Officer Certification

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of PSCo on Form 10-K for the year 2002, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the PSCo certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

  (1)   The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of PSCo as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 25, 2003

 
/s/ WAYNE H. BRUNETTI

Wayne H. Brunetti
Chairman, President and Chief Executive Officer
 
/s/ RICHARD C. KELLY

Richard C. Kelly
Vice President and Chief Financial Officer

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

3


 

Exhibit 99.03 — Officer Certification

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of SPS on Form 10-K for the year 2002, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the SPS certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

  (1)   The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of SPS as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 25, 2003

 
/s/ GARY L. GIBSON

Gary L. Gibson
President and Chairman
 
/s/ RICHARD C. KELLY

Richard C. Kelly
Vice President and Chief Financial Officer

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

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