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Xcel Energy Inc – ‘10-K’ for 12/31/02

On:  Monday, 3/31/03, at 5:10pm ET   ·   For:  12/31/02   ·   Accession #:  950134-3-5065   ·   File #:  1-03034

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 3/31/03  Xcel Energy Inc                   10-K       12/31/02   11:2.5M                                   RR Donnelley

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML   2.02M 
 2: EX-4.125    EX-4.125 Registration Rights Agreement                19     92K 
 3: EX-4.136    EX-4.136 Redemption Agreement                          9     46K 
 4: EX-4.137    EX-4.137 7.5 Percent Convertible Senior Notes         69    350K 
 5: EX-12.01    EX-12.01 Computation of Ratio of Earnings           HTML     23K 
 6: EX-21.01    EX-21.01 Subsidiaries of Xcel Energy Inc.           HTML     20K 
 7: EX-23.01    EX-23.01 Consent of Independent Accountants         HTML     12K 
 8: EX-23.02    EX-23.02 Consent of Independent Accountants         HTML     11K 
 9: EX-99.01    EX-99.01 Statement Pursuant to Private Securities   HTML     15K 
10: EX-99.02    EX-99.02 Description of Business of Nrg Energy Inc  HTML    116K 
11: EX-99.04    EX-99.04 Certification Pusuant to 18 Usc SEC. 1350  HTML     10K 


10-K   —   Annual Report
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Table of Contents
"Item l. Business
"Company Overview
"Utility Regulation
"Ratemaking Principles
"Fuel, Purchased Gas and Resource Adjustment Clauses
"Pending Regulatory Matters
"Electric Utility Operations
"Competition and Industry Restructuring
"Capacity and Demand
"Energy Sources
"Fuel Supply and Costs
"Trading Operations
"Nuclear Power Operations and Waste Disposal
"Electric Operating Statistics
"Gas Utility Operations
"Capability and Demand
"Gas Supply and Costs
"Gas Operating Statistics
"Nonregulated Subsidiaries
"NRG Energy, Inc
"E Prime, Inc
"Other Subsidiaries
"Environmental Matters
"Capital Spending and Financing
"Employees
"Executive Officers
"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
"Item 7A. Quantitative and Qualitative Disclosures about Market Risk
"Item 8. Financial Statements and Supplementary Data
"Part Iii
"Item 12 -- Security Ownership of Certain Beneficial Owners and Management
"Schedule Ii
"Signatures
"Certifications

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  e10vk  

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

     
(Mark One)
x   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

Commission File Number 1-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)
     
Minnesota
(State or Other Jurisdiction of Incorporation or Organization)
  41-0448030
(I.R.S. Employer Identification No.)
     
800 Nicollet Mall, Minneapolis, Minnesota
(Address of Principal Executive Offices)
  55402
(Zip Code)

Registrant’s Telephone Number, including Area Code (612) 330-5500

Securities registered pursuant to Section 12(b) of the Act:

         
Registrant   Title of Each Class   Name of Each Exchange on Which Registered

 
 
Xcel Energy Inc.   Common Stock, $2.50 par value per share   New York, Chicago, Pacific
Xcel Energy Inc.   Rights to Purchase Common Stock, $2.50 par value per share   New York, Chicago, Pacific
  Cumulative Preferred Stock, $100 par value:  
Xcel Energy Inc.   Preferred Stock $3.60 Cumulative   New York
Xcel Energy Inc.   Preferred Stock $4.08 Cumulative   New York
Xcel Energy Inc.   Preferred Stock $4.10 Cumulative   New York
Xcel Energy Inc.   Preferred Stock $4.11 Cumulative   New York
Xcel Energy Inc.   Preferred Stock $4.16 Cumulative   New York
Xcel Energy Inc.   Preferred Stock $4.56 Cumulative   New York

Securities registered pursuant to Section 12(g) of Act: None

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. x Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

As of June 28, 2002, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $6,649,735,234 and there were 396,940,044 shares of common stock outstanding.

As of March 15, 2003, there were 398,714,039 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2003 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

 



TABLE OF CONTENTS

Item l. Business
COMPANY OVERVIEW
UTILITY REGULATION
Ratemaking Principles
Fuel, Purchased Gas and Resource Adjustment Clauses
Pending Regulatory Matters
ELECTRIC UTILITY OPERATIONS
Competition and Industry Restructuring
Capacity and Demand
Energy Sources
Fuel Supply and Costs
Trading Operations
Nuclear Power Operations and Waste Disposal
Electric Operating Statistics
GAS UTILITY OPERATIONS
Competition and Industry Restructuring
Capability and Demand
Gas Supply and Costs
Gas Operating Statistics
NONREGULATED SUBSIDIARIES
NRG Energy, Inc.
e prime, inc.
Other Subsidiaries
ENVIRONMENTAL MATTERS
CAPITAL SPENDING AND FINANCING
EMPLOYEES
EXECUTIVE OFFICERS
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
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9 — Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
Item 10 — Directors and Executive Officers of the Registrant
Item 11 — Executive Compensation
Item 12 — Security Ownership of Certain Beneficial Owners and Management
Item 13 — Certain Relationships and Related Transactions
Item 14 — Controls and Procedures
Item 15 — Exhibits, Financial Statement Schedules and Reports on Form 8-K
SCHEDULE II
Signatures
CERTIFICATIONS
EX-4.125 Registration Rights Agreement
EX-4.136 Redemption Agreement
EX-4.137 7.5 percent Convertible Senior Notes
EX-12.01 Computation of Ratio of Earnings
EX-21.01 Subsidiaries of Xcel Energy Inc.
EX-23.01 Consent of Independent Accountants
EX-23.02 Consent of Independent Accountants
EX-99.01 Statement pursuant to Private Securities
EX-99.02 Description of Business of NRG Energy Inc
EX-99.04 Certification pusuant to 18 USC Sec. 1350


Table of Contents

Index

             
        Page No.
       
PART I
       
Item 1 - Business
    3  
 
COMPANY OVERVIEW
       
 
UTILITY REGULATION
       
   
Ratemaking Principles
    5  
   
Fuel, Purchased Gas and Resource Adjustment Clauses
    6  
   
Other Regulatory Mechanisms and Requirements
    7  
   
Pending Regulatory Matters
    8  
 
ELECTRIC UTILITY OPERATIONS
       
   
Competition and Industry Restructuring
    14  
   
Capacity and Demand
    18  
   
Energy Sources
    18  
   
Fuel Supply and Costs
    19  
   
Trading Operations
    21  
   
Nuclear Power Operations and Waste Disposal
    21  
   
Electric Operating Statistics
    24  
 
GAS UTILITY OPERATIONS
       
   
Competition and Industry Restructuring
    25  
   
Capability and Demand
    25  
   
Gas Supply and Costs
    26  
   
Gas Operating Statistics
    28  
 
NONREGULATED SUBSIDIARIES
       
   
NRG Energy, Inc.
    29  
   
e prime, inc.
    29  
        30  
 
ENVIRONMENTAL MATTERS
    30  
 
CAPITAL SPENDING AND FINANCING
    31  
 
EMPLOYEES
    31  
 
EXECUTIVE OFFICERS
    31  
Item 2 - Properties
    33  
Item 3 - Legal Proceedings
    39  
Item 4 - Submission of Matters to a Vote of Security Holders
    41  
PART II
       
Item 5 - Market for Registrant’s Common Equity and Related Stockholder Matters
    41  
Item 6 - Selected Financial Data
    42  
Item 7 - Management’s Discussion and Analysis
    43  
Item 7A - Quantitative and Qualitative Disclosures about Market Risk
    68  
Item 8 - Financial Statements and Supplementary Data
    69  
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    134  
PART III
       
Item 10 - Directors and Executive Officers of the Registrant
    134  
Item 11 - Executive Compensation
    134  
Item 12 - Security Ownership of Certain Beneficial Owners and Management
    134  
Item 13 - Certain Relationships and Related Transactions
    134  
Item 14 - Controls and Procedures
    134  
PART IV
       
Item 15 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
    135  
SIGNATURES
    149  
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
       

2



Table of Contents

Item 1. 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. 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. As a stock-for-stock exchange for shareholders of both companies, the merger was accounted for as a pooling-of-interests and, accordingly, amounts reported for periods prior to the merger have been restated for comparability with post-merger results.

Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. These six utility subsidiaries are 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); Southwestern Public Service Co., a New Mexico corporation (SPS); Black Mountain Gas Co., a Minnesota corporation (BMG), which has been sold pending regulatory approval; and Cheyenne Light, Fuel and Power Co., a Wyoming corporation (Cheyenne). Their service territories include portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. During 2002, Xcel Energy’s regulated businesses also included Viking Gas Transmission Co. (Viking) and its one-third interest in Guardian Pipeline, which was sold on Jan. 17, 2003, and WestGas InterState, Inc. (WGI), all interstate natural gas pipeline companies.

Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc., a Delaware corporation (NRG), an independent power producer. Xcel Energy owned 100 percent of NRG at the beginning of 2000. About 18 percent of NRG was sold to the public in an Initial Public Offering in the second quarter of 2000, leaving Xcel Energy with an 82-percent interest at Dec. 31, 2000. In March 2001, another 8 percent of NRG was sold to the public, leaving Xcel Energy with an interest of about 74 percent at Dec. 31, 2001. On June 3, 2002, Xcel Energy acquired the 26 percent of NRG held by the public so that it again held 100 percent ownership at Dec. 31, 2002. NRG is facing extreme financial difficulties and, among other things, has missed numerous scheduled payments of principal and interest on its outstanding bank loans and bonds. NRG may seek, in the near future, protection under the bankruptcy laws. See Notes 2, 3, 4 and 7 to the Financial Statements. Xcel Energy recently reached a tentative agreement with various NRG creditors that, if implemented, would require Xcel Energy to pay NRG up to $752 million. See Nonregulated Subsidiaries under Item 1 for a further discussion of this matter.

In addition to NRG, Xcel Energy’s nonregulated subsidiaries include Utility Engineering Corp. (engineering, construction and design), Seren Innovations, Inc. (broadband telecommunications services), e prime inc. (natural gas marketing and trading), Planergy International, Inc. (enterprise energy management solutions), Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits) and Xcel Energy International Inc. (an international independent power producer).

Xcel Energy was incorporated under the laws of Minnesota in 1909. Its executive offices are located at 800 Nicollet Mall, Minneapolis, Minn. 55402.

For information on the nonregulated subsidiaries of Xcel Energy, see Nonregulated Subsidiaries under Item 1. For information regarding Xcel Energy’s segments and foreign revenues, see Note 21 to the Consolidated Financial Statements.

Xcel Energy’s web site address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its web site, its annual report on form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC).

Regulated Subsidiaries

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 consolidated special purpose financing trust.

3



Table of Contents

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 primarily 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; P.S.R. Investments, Inc., which owns and manages permanent life insurance policies on certain employees; Green and Clear Lakes Company, which owns water rights; and PSCo Capital Trust I, a consolidated special purpose financing trust. PSCo also holds a controlling interest in several other relatively small ditch and water 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.

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 consolidated special purpose financing trust.

Other Regulated Subsidiaries

Cheyenne was incorporated in 1900 under the laws of Wyoming. Cheyenne is an operating utility engaged in the purchase, transmission, distribution and sale of electricity and natural gas, primarily serving approximately 37,000 electric customers and 30,000 natural gas customers in and around Cheyenne, Wyo.

BMG was incorporated in 1999 under the laws of Minnesota. BMG is a natural gas and propane distribution company, located in Cave Creek, Ariz., with approximately 9,300 customers. We have entered into an agreement to sell BMG. The sale is subject to the receipt of several regulatory approvals.

Viking Gas is an interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota. Viking operated exclusively as a transporter of natural gas for third-party shippers under authority granted by the Federal Energy Regulatory Commission (FERC). On Jan. 17, 2003, Xcel Energy completed the sale of its interest in Viking, including its ownership interest in Guardian Pipeline, LLC (Guardian).

WGI was incorporated in 1990 under the laws of Colorado. WGI is a natural gas transmission company engaged in transporting natural gas from Chalk Bluffs, Colo., to Cheyenne, Wyo.

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Table of Contents

UTILITY REGULATION

Ratemaking Principles

The Xcel Energy system is subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under PUHCA. The rules and regulations under PUHCA generally limit the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules require that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions. See additional discussion of PUHCA requirements under Factors Affecting Results of Operations and Liquidity and Capital Resources in Management’s Discussion and Analysis under Item 7.

The 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 Xcel Energy’s other activities, including regulation of retail rates and environmental matters.

Xcel Energy is unable to predict the impact on its operating results from the future regulatory activities of any of these agencies. Xcel Energy's utility subsidiaries 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 electric 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.

The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the two-year test 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.

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Table of Contents

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.

Cheyenne

Cheyenne is subject to the jurisdiction of the Wyoming Public Service Commission (WPSC) with respect to its facilities, rates, accounts, services and issuance of securities.

Other

Viking and WGI are subject to FERC jurisdiction and each holds a FERC certificate, which allows them to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas Act. BMG is subject to the regulation of the Arizona Corporation Commission (ACC).

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 latest 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 latest 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 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 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, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

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PSCo

PSCo currently has seven retail 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. 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 such costs prior to Jan. 1, 2003. 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 at least annually to coincide with changes in purchased gas costs. Purchased gas costs and revenues received to recover gas costs are compared on a monthly basis and differences are deferred. 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. 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 NMPRC authorized SPS to implement a monthly adjustment factor on an interim basis beginning with the February 2002 billing cycle.

Cheyenne

All electric demand and purchased power costs are recoverable through an energy adjustment clause. All purchased gas costs are recoverable through a gas cost adjustment clause. Differences in costs incurred from costs recovered in rates are deferred and recovered through prospective adjustments to rates. However, rate changes for cost recovery require WPSC approval before going into effect. Historically, customers have been provided carrying costs on over-collected costs, but Cheyenne has not been allowed to collect carrying charges for under-recovered costs.

Other Regulatory Mechanisms and Requirements

NSP-Minnesota

In December 2000, the NDPSC approved Xcel Energy’s “PLUS” performance-based regulation proposal 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. NSP — Minnesota’s performance determines the range of allowed return on equity

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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. See further discussion under Item 7, Management’s Discussion and Analysis.

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. 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

Xcel Energy

FERC Investigation Against All Wholesale Electric Sellers — 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 PSCo and NRG, 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 that may have violated market rules. On May 22, 2002, Xcel Energy and NRG 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 in that submission reported that at times during 2000 and 2001, PSCo 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 PSCo 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 such possible over-schedules. Subsequently, in the California Refund Proceeding, as discussed later, PSCo informed the FERC that evidence that was adduced by certain California litigants appears to indicate that the PSCo trader involved in these transactions did not believe that they involved overstated schedules, and that Xcel Energy accordingly may have over reported transactions in that submission.

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 PSCo 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. In this transaction, PSCo agreed to buy from Reliant 15,000 megawatts per hour, during the off-peak hours of the months of November and December 1999. Collectively, these sales with Reliant consisted of approximately 10 million megawatt hours in 1999 and 1.8 million megawatt hours in 2000 and represented approximately 55 percent of PSCo's trading volumes for 1999 and approximately 15 percent of PSCo's trading volumes in 2000. The purpose of the non-profit transaction was in consideration of future for-profit transactions, such as those discussed above. PSCo engaged in these transactions, such as those discussed above with Reliant for the proper commercial objective of making a profit. It did not enter into these transactions to inflate volumes or revenues, and at the time the transactions occurred, the transactions were reported net in our financial statements.

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On March 26, 2003, the FERC at its open meeting discussed this investigation and stated its intent to issue show cause orders to thirty identified market participants, requesting that these entities explain why their conduct did not constitute impermissible gaming under applicable tariffs and why they should not have to disgorge unjust profits or be subjected to other remedies. PSCo was not identified as one of these market participants. However, it was indicated that NRG would be asked to show cause why its prices from May to October, 2000, did not constitute economic withholding and inflated bidding and why it should not be required to disgorge unjust profits or be subjected to other remedies.

Section 206 Investigation Against 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 jurisdictional electric suppliers making sales in interstate commerce at market-based rates. NSP-Minnesota, PSCo, SPS and certain NRG affiliates 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.

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.

California Refund Proceeding — A number of parties purchasing energy in markets operated by the California Independent System Operator (California ISO) or the California Power Exchange (PX) have asserted prices paid for such energy were unjust and unreasonable and that refunds should be made in connection with sales in those markets for the period Oct. 2, 2000 through June 20, 2001. PSCo and NRG supplied energy to these markets during the referenced period and have been an active participant in the proceedings. The FERC ordered an investigation into the California ISO and PX spot markets and concluded that the electric market structure and market rules for wholesale sales of energy in California were flawed and have caused unjust and unreasonable rates for short-term energy under certain conditions. The FERC ordered modifications to the market structure and rules in California and established an administrative law judge (ALJ) to make findings with respect to, among other things, the amount of refunds owed by each supplier based on the difference between what was charged and what would have been charged in a more functional market, i.e., the “market clearing price,” which in turn is based on the unit providing energy in an hour with the highest incremental cost. The initial proceeding related to California’s demand for $8.9 billion in refunds from power sellers. The ALJ subsequently stated that after assessing a refund of $1.8 billion for power prices, power suppliers were owed $1.2 billion because the State was holding funds owed to suppliers. Because of the low volume of sales that PSCo had into California after this date, PSCo’s exposure is estimated at approximately $1.2 million, which is offset by amounts owed by the California ISO to PSCo in excess of that amount. The purchasing parties have appealed this decision. They have also asserted that the refund effective date should be set at an earlier date. The FERC has allowed the purchasing parties to request additional information regarding the market participants’ uses of certain strategies and the effect those strategies may have had on the market. The purchasing parties have filed a pleading at the FERC in which they claim that use of these strategies justifies an earlier refund effective date. An earlier effective date could increase PSCo’s exposure to approximately $15 million.

On March 26, 2003, FERC at its open meeting discussed and voted on a draft order in this proceeding. Based on the discussion of the draft order, it would appear that the FERC is going to use different gas costs to determine the applicable market clearing prices for the refund period. The effect of this change will be to increase PSCo's and other sellers' refund exposure. However, it does not appear from the discussion that the FERC will move back the applicable refund effective date. It may be expected that California litigants will request rehearing of this aspect of the order after it is issued.

Commodity Futures Trading Commission Investigation — Pursuant to a formal order of investigation, on June 17, 2002 the Commodity Futures Trading Commission (CFTC) issued broad subpoenas to Xcel Energy on behalf of its affiliates, including NRG, calling for production, among other things, of “all documents related to natural gas and electricity trading” (the June 17, 2002 subpoenas”). Since that time, Xcel Energy has produced documents and other materials in response to numerous more specific requests under the June 17, 2002 subpoenas. Certain of these requests and Xcel Energy’s responses have concerned so-called “round-trip trades.” By a subpoena dated Jan. 29, 2003 and related letter requests (the Jan. 29, 2003 subpoena”), the CFTC has requested that Xcel Energy produce all documents related to all data submittals and documents provided to energy industry publications. Xcel Energy has produced documents and other materials in response to the Jan. 29, 2003 subpoena, including a report identifying instances where Xcel Energy’s e prime subsidiary reported natural gas transactions to an industry publication in a manner inconsistent with the publication’s instructions. Xcel Energy believes this reporting did not affect the financial accounting treatment of any transaction recorded in e prime’s books and records. Also beginning on Jan. 29, 2003, the CFTC has sought testimony from two employees, and has notified Xcel Energy of its intention to seek additional testimony from numerous other employees and executives, concerning the reporting of energy transactions to industry publications. Xcel Energy and NRG are cooperating in the CFTC investigation, but cannot predict the outcome of any investigation.

SEC Trading Investigation — Pursuant to a formal order of investigation, on June 26, 2002 the SEC issued a subpoena to Xcel Energy requesting all documents concerning any so-called “round trip trades” with Reliant Resources, Inc. Pursuant to a another formal order of investigation, on Oct. 3, 2002 the SEC issued a subpoena to Xcel Energy calling for additional information concerning certain energy trades between Xcel Energy on the one hand and Duke Energy Corporation and Mirant Corporation on the other, involving the same product, quantity and price executed on the same day. Xcel Energy has produced documents and has cooperated in these investigations, but cannot predict the outcome of any investigation.

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

PUHCA Regulation — See discussion of pending issues under PUHCA regulation at Management’s Discussion and Analysis — Liquidity and Capital Resources.

NSP-Minnesota

Minnesota 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 NSP-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. 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 (DOC) and the Office of the Attorney General (OAG) 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 DOC and OAG 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 separating 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. On March 10, 2003, the DOC and OAG submitted a progress report to the MPUC drafted by the state agencies auditor. The report documents alleged instances of record keeping inconsistencies and misstatements and concludes it would be nearly impossible to establish the magnitude of misstatements in the record keeping system. In submitting the progress report, the state agencies noted, however, that the total outage duration stated would need to increase by nearly 33 million minutes to violate state-imposed standards. NSP-Minnesota vigorously disputes the method, findings and conclusions of the report.

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 them when 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 DOC has supported deferred accounting to provide for recovery of prudent, otherwise

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unrecovered and appropriate costs, subject to a normal prudence review process. The OAG 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 applications requesting authorization of 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 March 11, 2003, the MPUC issued an order granting 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.

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 into 2004. Construction is expected to be complete in the spring of 2007.

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 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 of NSP-Wisconsin to 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, 2003, order. On Jan. 31, 2003, the MPSC granted the NSP-Wisconsin’s request for a 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.

PSCo

Incentive Cost Adjustment — PSCo’s 2001 calendar year energy costs under the ICA were approximately $19 per megawatt-hour, compared with 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 originally agreed in the merger stipulation and agreement to mitigate future cost deferrals and to recover the projected ICA energy costs of $148 million 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 ($12.78 through base electric rates and $2.10 through the ICA), 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 March 31, 2005. On March 5, 2003, PSCo filed to reduce the ICA rate to $2.07 per megawatt hour.

PSCo’s costs for 2002 were approximately $17 per megawatt-hour or approximately $56 million less than the energy costs for the 2001 test year. Under the ICA mechanism, retail customers and PSCo share this difference

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equally. A CPUC proceeding to review and approve the incurred and recoverable 2001 costs under the ICA is in process. A review of the 2002 recoverable ICA 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 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 power expense recovery revenue of $123 million predicated on calendar year 2003 forecasted retail sales for PSCo. 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 $63 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: a revision in ECA costs caused by a renegotiated purchased power contract; a revised 2003 sales forecast; an updated forecast of natural gas costs used as a fuel source in electric generating stations; and 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. See additional discussion under Item 7, Management’s Discussion and Analysis.

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 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.

Gas Rate Requests — 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.

In March 2003, PSCo filed a request with the CPUC for a $95.6 million increase in the natural gas cost component of rates in Colorado for the period March 21, 2003 through Sept. 30, 2003. The CPUC approved the requested increase by order issued March 20, 2003. The cost adjustment will not result in any additional gas margin for PSCo, as the increase reflects additional costs for purchasing natural gas on behalf of its customers. Natural gas costs are passed on to customers on a dollar-per-dollar basis.

PSCo Fuel Clause Investigation — Certain wholesale power customers of PSCo have filed complaints with the FERC alleging PSCo has been improperly collecting certain fuel and purchased energy costs through the wholesale fuel cost adjustment clause included in their rates. The FERC consolidated the complaints and set them for hearing and settlement judge procedures. In November 2002, the Chief Judge terminated settlement procedures after settlement was not reached. The investigation is currently in the discovery process and hearings are set for August 2003.

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 $13.6 million, including interest on behalf of all of PSCo’s gas extension applicants since Oct. 1, 1996. HBA also seeks recovery of its attorney’s fees.

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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 recommended 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.

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

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been an active participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling the FERC has allowed the parties to request additional evidence regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period parties have claimed the total amount of transactions with PSCo subject to refund are $34 million.

On March 26, 2003, the FERC at its open meeting discussed this proceeding. While the action that the FERC plans to take cannot be definitively ascertained from that discussion, it appears that the FERC may conduct further proceedings to determine whether spot-market bilateral sales in the Pacific Northwest should be subject to refund.

SPS

Texas Fuel Reconciliation, 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 filed testimony. Intervenors proposed that revenues from certain wholesale transactions be credited to Texas retail customers. SPS opposed this proposed revenue treatment. Hearings were scheduled for March 2003. On March 14, the parties submitted to the Administrative Law Judges a stipulation settling the proceeding. The stipulation resolves all issues regarding SPS’s fuel costs and wholesale trading activities through December 2001. SPS will withdraw, without prejudice, its request to share in 10 percent of margins from certain wholesale non-firm sales. SPS had proposed to recover $1.1 million from Texas customers for the proposed sharing of wholesale non-firm sales margins. The company had not recorded these proposed revenues pending the outcome in this proceeding. The parties agreed that SPS would reduce its December 2001 fuel under-recovery balances by $5.8 million. Taking into account the withdrawal of proposed margin sharing of wholesale non-firm sales, the net impacts to SPS’s deferred fuel expense balances, before tax, is $4.7 million. The stipulation will be considered by the PUCT during an open meeting in the next several months.

SPS has reported to the PUCT that it has under-collected its fuel costs under the current Texas retail fixed fuel factors. Taking into account the stipulation in the fuel cost reconciliation proceeding, SPS has under-collected through February 2003 by $16.2 million. In March 2003, SPS filed an application seeking to surcharge Texas retail customer bills from June 2003 through January 2004 to collect the $16.2 million in deferred expenses. SPS is in the process of preparing a filing with the PUCT to recover in customer rates current fuel costs under its fixed fuel cost recovery factors in accordance with state statutes and PUCT regulations. The filing is expected to be completed in May 2003. Recovery amounts would depend on future fuel rates once the filing is approved.

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 purchase 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.

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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 from customers.

Lamb County Electric Cooperative — 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. See further discussion under Item 3 — Legal Proceedings.

Cheyenne

Cheyenne Purchased Power Costs — On May 25, 2001, the WPSC approved a stipulation agreement between Cheyenne and intervenors in connection with a proposed increase in rates charged to Cheyenne’s retail customers to recover increased power costs.

The stipulation provides for an ECA rate structure with a fixed energy supply rate for Cheyenne’s customers through 2003; the continuation of the ECA with certain modifications, including the amortization through December 2005 of unrecovered costs incurred during 2001 up to the agreed-upon fixed supply rates; and an agreement that Cheyenne’s energy supply needs will be provided, in whole or in part, by PSCo in accordance with wholesale tariff rates to be approved by the FERC. The estimated retail rate increases under the stipulation provide recovery of an additional $18 million, compared with prior rate levels, through 2001 and a total of $28 million for each of the years 2002 and 2003. In 2004 and 2005, Cheyenne will return to requesting recovery of its actual costs incurred plus the outstanding balance of any deferral from earlier years.

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. Xcel Energy and its 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. For more information on the delay of restructuring for SPS in Texas and New Mexico, see Note 15 to the Consolidated Financial Statements.

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 electricity. 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 face 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 unbundle wholesale merchant and transmission

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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.

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

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 2001, 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.

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 approximately $9 million per year.

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, however in March 2003, the Midwest ISO and the SPP announced the have mutually agreed to terminate the consolidation of their two organizations.

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 initial applicants were: 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. In addition, in late 2002, several other companies stated their intent to join TRANSLink. They are Great River Energy power cooperative, Dairyland Electric Power Cooperative, Southern Minnesota Public Power Association and a group of 119 municipal utilities known as the Midwest Municipal Transmission Group. Rochester Public Utilities joined in early 2003. The participants believe TRANSLink is the most cost-effective option available to manage transmission and to comply with regulations issued by 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 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

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FERC approved the TRANSLink rate schedules to the Midwest ISO tariff subject to refund, and required TRANSLink to engage in settlement discussions on several items. TRANSLink anticipates resolving these issues during the second 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 Development Co. also identified its nine-member independent board of directors. The establishment of an independent board is required to satisfy Order 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 electric 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). 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. However, the Legislature, without recommendation from the EUC, modified the coal severance and coal conversion taxes primarily to improve the competitive status of 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 its 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. No similar filing is required in the South Dakota jurisdiction.

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. 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

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their customers’ energy needs. In 2002, the PSCW approved the first power plan 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 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, no 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 its 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. No similar filing is 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 of approximately $5.1 million 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.

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 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. An order was received from the PUCT in May 2002 that stipulates recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the order, 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 15 to the Consolidated Financial Statements.

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

Oklahoma Restructuring — 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.

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TRANSLink — In November and December 2002, SPS filed for PUCT and NMPRC approval to transfer functional control of its electric transmission system to the 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. No similar filings are required in the Kansas and Oklahoma jurisdictions.

Other

Wyoming Restructuring — There were no electric industry restructuring legislation proposals introduced in the Legislature during 2001 or 2002. No action with respect to electric restructuring is anticipated in 2003.

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 (in Megawatts)
   
Operating Company   2000   2001   2002   2003 Forecast

 
 
 
 
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 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. Purchased 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 electricity, 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:

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    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 and Monticello plants 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 issue of spent nuclear fuel storage limitation and its effect on the future of nuclear generation in Minnesota in the 2003 legislative session. See Nuclear Power Operations and Waste Disposal-High-Level Radioactive Waste Disposal under Item 1. The MPUC has suspended the procedure schedule pending the completion of the 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 to 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, which are retail and wholesale 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 Fuel
NSP System Generating Plants   Cost   Percent   Cost   Percent   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 Fuel
PSCo Generating Plants   Cost   Percent   Cost   Percent   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 Fuel
SPS Generating Plants   Cost   Percent   Cost   Percent   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  

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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 the spot market 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. NSP-Minnesota and NSP-Wisconsin use both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

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 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 coal 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.

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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 agreements.

Trading Operations

Xcel Energy and its utility subsidiaries conduct various trading operations, including the purchase and sale of electric energy. Participation in short-term wholesale energy markets also provides market intelligence and information that supports the energy management of each utility subsidiary. Xcel Energy and its utility subsidiaries reduce commodity price and credit risks by using physical and financial instruments to minimize commodity 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 the customers and the capturing of additional margins from non-traditional customers. Xcel Energy and its 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. See Pending Regulatory Matters under Item 1 for a discussion of investigations of trading activities.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 19 to the Consolidated Financial Statements.

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 Radioactive 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 lives, if off-site low-level disposal facilities were not available to NSP-Minnesota.

High-Level Radioactive 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 19 to the Consolidated Financial Statements for further discussion of this matter.

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NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. 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 temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. The NRC license review process includes formal evidentiary hearings before an Atomic Safety and Licensing Board (ASLB) and opportunities for public input. Evidentiary hearings were held in 2000 and 2002, Most of the issues raised by opponents of the project have been favorably resolved or dismissed. On March 10, 2003, the ASLB ruled that the likelihood of certain aircraft crashes into the proposed facility was sufficiently credible that it would have to be addressed before the facility could be licensed and set forth a potential process for addressing this concern. PFS is currently evaluating this decision and awaiting ASLB decisions on the remaining five major issues expected in a few weeks. Due to uncertainty regarding NRC and other 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 beyond 2007, 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.

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 steam 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 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

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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.

For further discussion of nuclear issues, see Notes 18 and 19 to the Consolidated Financial Statements.

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Electric Operating Statistics (Xcel Energy)

                         
    Year Ended December 31,
   
    2002   2001   2000
   
 
 
Electric Sales (millions of Kwh)
                       
Residential
    23,302       22,113       22,101  
Commercial and Industrial
    57,815       57,755       57,409  
Public Authorities and Other
    1,143       1,103       1,184  
 
   
     
     
 
Total Retail
    82,260       80,971       80,694  
Sales for Resale
    23,256       26,104       26,284  
 
   
     
     
 
Total Energy Sold
    105,516       107,075       106,978  
 
   
     
     
 
Number of Customers at End of Period
                       
Residential
    2,756,565       2,722,832       2,691,505  
Commercial and Industrial
    394,620       387,579       380,784  
Public Authorities and Other
    81,341       100,819       98,715  
 
   
     
     
 
Total Retail
    3,232,526       3,211,230       3,171,004  
Wholesale
    309       305       220  
 
   
     
     
 
Total Customers
    3,232,835       3,211,535       3,171,224  
 
   
     
     
 
Electric Revenues (thousands of dollars)
                       
Residential
  $ 1,677,231     $ 1,697,390     $ 1,607,655  
Commercial and Industrial
    2,791,550       2,979,730       2,772,550  
Public Authorities and Other
    98,394       91,438       94,653  
Regulatory Accrual Adjustment
    4,766       15,480        
 
   
     
     
 
Total Retail
    4,571,941       4,784,038       4,474,858  
Wholesale
    715,144       1,478,038       1,161,173  
Other Electric Revenues
    148,292       132,661       38,454  
 
   
     
     
 
Total Electric Revenues
  $ 5,435,377     $ 6,394,737     $ 5,674,485  
 
   
     
     
 
Kwh Sales per Retail Customer
    25,448       25,215       25,448  
Revenue per Retail Customer
  $ 1,414.36     $ 1,489.78     $ 1,411.18  
Residential Revenue per Kwh
    7.20¢       7.68¢       7.27¢  
Commercial and Industrial Revenue per Kwh
    4.83¢       5.16¢       4.83¢  
Wholesale Revenue per Kwh
    3.08¢       5.66¢       4.42¢  

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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.

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 LDCs, 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 LDCs 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, which are customers with an alternate energy supply. The maximum daily send-out of firm and interruptible for the combined system of NSP-Minnesota and NSP-Wisconsin was 650,641 million British thermal units (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 604,000 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 to exchange one form of demand for another. In October 2001, the MPUC approved NSP-Minnesota’s 2000-2001 entitlement levels. NSP-Minnesota’s 2001-2002 entitlement levels were approved on April 3, 2002, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA. 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 and Cheyenne

PSCo and Cheyenne project peak day gas supply requirements for firm sales and backup transportation, which include 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 and

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Cheyenne are 2,206,870 MMBtu per day. The maximum daily deliveries for both companies in 2002 for firm and interruptible services were 1,652,459 MMBtu on Feb. 25, 2002.

PSCo and Cheyenne purchase 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 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 is 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 18 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   Cheyenne
   
 
 
 
2002
  $ 3.98     $ 4.63     $ 3.17     $ 2.77  
2001
  $ 5.83     $ 5.11     $ 4.99     $ 5.03  
2000
  $ 4.56     $ 4.71     $ 4.48     $ 4.03  

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 Gas 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 and Cheyenne

PSCo and Cheyenne 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, PSCo and Cheyenne were

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committed to approximately $906.3 million in such obligations under these contracts, which expire in various years from 2003 through 2025.

PSCo and Cheyenne have 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 and Cheyenne also utilize 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 and Cheyenne purchased natural gas from approximately 44 suppliers.

Viking

On Nov. 7, 2002, Xcel Energy reached an agreement to sell Viking and Viking’s one-third share of Guardian Pipeline to Border Viking Company, whose ultimate parent is Northern Border Partners L. P. The sale was completed on Jan. 17, 2003, and Xcel Energy received net proceeds of $124 million.

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Gas Operating Statistics (Xcel Energy)

                         
    Year Ended December 31,
   
    2002   2001   2000
   
 
 
Gas Deliveries (thousands of Dth)
                       
Residential
    144,038       136,568       137,989  
Commercial and Industrial
    95,959       97,303       96,370  
 
   
     
     
 
Total Retail
    239,997       233,871       234,359  
Transportation and Other
    294,640       284,301       297,041  
 
   
     
     
 
Total Deliveries
    534,637       518,172       531,400  
 
   
     
     
 
Number of Customers at End of Period
                       
Residential
    1,574,489       1,531,589       1,483,114  
Commercial and Industrial
    148,383       146,266       143,568  
 
   
     
     
 
Total Retail
    1,722,872       1,677,855       1,626,682  
Transportation and Other
    3,189       3,054       3,233  
 
   
     
     
 
Total Customers
    1,726,061       1,680,909       1,629,915  
 
   
     
     
 
Gas Revenues (thousands of dollars)
                       
Residential
  $ 842,786     $ 1,233,205     $ 878,638  
Commercial and Industrial
    455,152       711,282       506,040  
 
   
     
     
 
Total Retail
    1,297,938       1,944,487       1,384,678  
Transportation and Other
    99,862       108,164       84,202  
 
   
     
     
 
Total Gas Revenues
  $ 1,397,800     $ 2,052,651     $ 1,468,880  
 
   
     
     
 
 
                       
Dth Sales per Retail Customer
    139.30       139.39       144.07  
Revenue per Retail Customer
  $ 753.36     $ 1,158.91     $ 851.23  
Residential Revenue per Dth
  $ 5.85     $ 9.03     $ 6.37  
Commercial and Industrial Revenue per Dth
  $ 4.74     $ 7.31     $ 5.25  
Transportation and Other Revenue per Dth
  $ 0.34     $ 0.38     $ 0.28  

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NONREGULATED SUBSIDIARIES

Through its non-utility subsidiaries, Xcel Energy invests in and operates several nonregulated businesses in a variety of industries. The following is an overview of the significant nonregulated businesses.

NRG Energy, Inc.

NRG is an energy company primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. For additional information see Item 1 of NRG’s Annual Report on Form 10-K, incorporated herein by reference at Exhibit 99.02.

Xcel Energy owned 100 percent of NRG Energy at the beginning of 2000. About 18 percent of NRG Energy was sold to the public in an initial public offering in the second quarter of 2000, leaving Xcel Energy with an 82-percent interest at Dec. 31, 2000. In March 2001, another 8 percent of NRG Energy was sold to the public, leaving Xcel Energy with an interest of about 74 percent at Dec. 31, 2001. On June 3, 2002, Xcel Energy purchased the 26 percent of NRG Energy held by the public so that it again held 100 percent ownership at Dec. 31, 2002. See Note 4 to the Consolidated Financial Statements for discussion of potential changes in NRG ownership.

Since the early 1990’s, NRG has pursued a strategy of rapid growth through acquisitions. Starting in 2000, NRG Energy added new construction to this strategy. This strategy required significant capital, much of which was satisfied primarily with debt. As of Dec. 31, 2002 NRG had approximately $9.4 billion of debt on its balance sheet at the corporate and project levels. Due to a number of reasons, including the overall downturn in the energy industry, NRG’s financial condition has deteriorated significantly and NRG is facing severe financial difficulties. NRG has failed to make scheduled payments of interest and principal on its outstanding bank loans and bonds. As a consequence, NRG may seek protection under the bankruptcy laws in the future. See Notes 2, 3, 4 and 7 to the Consolidated Financial Statements.

NRG is restructuring its operations to become a domestic-based owner-operator of a fuel-diverse portfolio of electric generation facilities engaged in the sale of energy, capacity and related products. NRG is working toward this goal by selective divestiture of non-core assets, realignment of management, reorganization of power marketing activities and an overall financial restructuring that will improve liquidity and reduce debt. NRG does not anticipate any new significant development, and, instead, will focus on operational performance and asset management. NRG has already made significant reductions in expenditures, business development activities and personnel. Power sales and fuel procurement will remain a key strategic element of NRG’s operations. NRG’s objective will be to optimize the fuel input and the energy output of its facilities within an appropriate risk and liquidity profile.

The entire independent power industry in the United States is in turmoil. Many of NRG’s competitors have announced plans to scale back their growth, sell assets, and restructure their finances. Bankruptcy filings are likely by several of NRG’s competitors. The results of the wholesale restructuring of the independent power industry are impossible to predict, but they may include consolidation within the industry, the sale or liquidation of certain competitors, the re-regulation of certain markets, and the long-term reduction in new investment into the industry. Under any scenario, however, NRG anticipates that it will continue to face competition from numerous companies in the industry, some of which may have more extensive operating experience, larger staffs, and greater financial resources than NRG presently possesses.

Many companies in the regulated utility industry, with which the independent power industry is closely linked, are also restructuring or reviewing their strategies. Several of these companies are discontinuing going forward with unregulated investments, seeking to divest of their unregulated subsidiaries or attempting to have their regulated subsidiaries acquire their unregulated subsidiaries. This may lead to an increased competition between the regulated utilities and the unregulated power producers within certain markets. In such instances, NRG may compete with regulated utilities in the influence of market designs and rulemaking.

On March 26, 2003, Xcel Energy’s board of directors approved a tentative settlement with holders of most of NRG’s long-term notes and the steering committee representing NRG’s bank lenders regarding alleged claims of such creditors against Xcel Energy, including claims related to the support and capital subscription agreement between Xcel Energy and NRG dated May 29, 2002 (the “Support Agreement”). The settlement is subject to a variety of conditions as set forth below, including definitive documentation. The principal terms of the settlement as of the date of this report were as follows:

Xcel Energy would pay up to $752 million to NRG to settle all claims of NRG, and the claims of NRG against Xcel Energy, including all claims under the Support Agreement.

$350 million would be paid at or shortly following the consummation of a restructuring of NRG’s debt through a bankruptcy proceeding. It is expected that this payment would be made prior to year-end 2003. $50 million would be paid on Jan. 1, 2004, and all or any part of such payment could be made, at Xcel Energy’s election, in Xcel Energy common stock. Up to $352 million would be paid on April 30, 2004, except to the extent that Xcel Energy had not received at such time tax refunds equal to $352 million associated with the loss on its investment in NRG. To the extent Xcel Energy had not received such refunds, the April 30 payment would be due on May 30, 2004.

$390 million of the Xcel Energy payments are contingent on receiving releases from NRG creditors. To the extent Xcel Energy does not receive a release from an NRG creditor. Xcel Energy’s obligation to make $390 million of the payments would be reduced based on the amount of the creditor’s claim against NRG. As noted below, however, the entire settlement is contingent upon Xcel Energy receiving releases from at least 85 percent of the claims in various NRG creditor groups. As a result, it is not expected that Xcel Energy’s payment obligations would be reduced by more than approximately $60 million. Any reduction would come from the Xcel Energy payment due on April 30, 2004.

Upon the consummation of NRG’s debt restructuring through a bankruptcy proceeding, Xcel Energy’s exposure on any guaranties or other credit support obligations incurred by Xcel Energy for the benefit of NRG or any subsidiary would be terminated and any cash collateral posted by Xcel Energy would be returned to it. The current amount of such cash collateral is approximately $11.5 million.

As part of the settlement with Xcel Energy, any intercompany claims of Xcel Energy against NRG or any subsidiary arising from the provision of intercompany goods or services or the honoring of any guaranty will be paid in full in cash in the ordinary course except that the agreed amount of such intercompany claims arising or accrued as of Jan. 31, 2003 will be reduced from approximately $55 million as asserted by Xcel Energy to $13 million. The $13 million agreed amount is to be paid upon the consummation of NRG’s debt restructuring with $3 million in cash and an unsecured promissory note of NRG on market terms in the principal amount of $10 million.

NRG and its direct and indirect subsidiaries would not be reconsolidated with Xcel Energy or any of its other affiliates for tax purposes at any time after their June 2002 re-affiliation or treated as a party to or otherwise entitled to the benefits of any tax sharing agreement with Xcel Energy. Likewise, NRG would not be entitled to any tax benefits associated with the tax loss Xcel Energy expects to incur in connection with the write down of its investment in NRG.

Xcel Energy’s obligations under the tentative settlement, including its obligations to make the payments set forth above, are contingent upon, among other things, the following:

     (1)      Definitive documentation, in form and substance satisfactory to the parties;
  (2)   Between 50 percent and 100 percent of the claims represented by various NRG facilities or creditor groups (the “NRG Credit Facilities”) having executed an agreement, in form and substance satisfactory to Xcel Energy, to support the settlement;
  (3)   Various stages of the implementation of the settlement occurring by dates currently being negotiated, with the consummation of the settlement to occur by Sept. 30, 2003;
  (4)   The receipt of releases in favor of Xcel Energy by at least 85 percent of the claims represented by the NRG Credit Facilities;
  (5)   The receipt by Xcel Energy of all necessary regulatory approvals; and
  (6)   No downgrade prior to consummation of the settlement of any Xcel Energy credit rating from the level of such rating as of March 25, 2003.

Since many of these conditions are not within Xcel Energy’s control, Xcel Energy cannot state with certainty that the settlement will be effectuated. Nevertheless, the Xcel Energy management is optimistic at this time that the settlement will be implemented.

Additional information regarding NRG’s operations is included in Item 1 of Part I of NRG’s Form 10-K for the year ended Dec. 31, 2002, which is incorporated as Exhibit 99.02 to this 10-K report and incorporated by reference herein.

e prime, inc.

e prime was incorporated in 1995 under the laws of Colorado. e prime provides energy related products and services, which include natural gas marketing and trading and energy consulting. In 1996, e prime received authorization from the FERC to act as a power marketer. Additionally, e prime owns Young Gas Storage Company, which owns a 47.5 percent general partnership interest in an underground gas storage facility in northeastern Colorado.

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e prime’s gas trading operations acquire assets and commodities and subsequently trade around those assets or commodity positions. e prime captures trading opportunities through price volatility driven by factors such as asset utilization, locational price differentials, weather, available supplies, credit and customer actions. Trading margins are captured through the utilization of transmission, transportation and storage assets, capture of regional price differences and other factors.

Other Subsidiaries

Although not individually reportable segments, Xcel Energy also has a number of nonregulated subsidiaries in various lines of business. The most significant are discussed below.

Xcel Energy International

Xcel Energy International (Xcel International) was formed in 1997 to manage the international operations of Xcel Energy, outside of NRG.

In August 2002, Xcel International sold a 5-percent interest in Yorkshire Power for $33 million to CE Electric UK. Xcel Energy and American Electric Power Co. each held a 50-percent interest in Yorkshire, a UK retail electricity and gas supplier and electric distributor, before selling 95 percent of Yorkshire to Innogy Holdings plc in April 2001.

Xcel Energy Argentina’s primary investment consists of the ownership and operation of three independent power production facilities in Argentina. At Dec. 31, 2002, Xcel Argentina had approximately $112 million invested in these facilities.

Utility Engineering Corp. (UE)

UE was incorporated in 1985 under the laws of Texas. UE is engaged in engineering, design, construction management and other miscellaneous services. UE currently has five wholly owned subsidiaries, including Universal Utility Services LLC, Precision Resource Co., Quixx Corp., Proto-Power Corp. and Applied Power Associates Inc.

Planergy International Inc.

Planergy provides energy management, consulting, on-site generation, load curtailment, demand-side management, energy conservation and optimization, distributed generation and power quality services, as well as information management solutions to industrial, commercial and utility customers.

Seren Innovations, Inc.

Seren is constructing a combination cable television, telephone and high-speed internet access system in two locations: St. Cloud, Minn., and Contra Costa County in the East Bay area of northern California. As of Dec. 31, 2002, Xcel Energy’s investment in Seren was approximately $255 million. Seren projects improvement in its operating results with positive cash flow anticipated in 2005, upon completion of its build-out program, and earnings contribution in 2008. See further discussion in Note 18 to the Consolidated Financial Statements.

Eloigne Company

Eloigne was established in 1993 and its principal business is the acquisition of rental housing projects that qualify for low-income housing tax credits under current federal tax law. As of Dec. 31, 2002, approximately $83 million had been invested in Eloigne projects, including approximately $23 million in wholly owned properties and approximately $60 million in equity interests in jointly owned projects. Completed and committed Eloigne projects as of Dec. 31, 2002, are expected to generate tax credits of $76 million over the time period of 2003 through 2011.

ENVIRONMENTAL MATTERS

Certain of Xcel Energy’s 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 has received all

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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 subsidiaries strive to comply with all environmental regulations applicable to its 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 Xcel Energy’s operations. For more information on environmental contingencies, see Notes 18 and 19 to the Consolidated Financial Statements and environmental matters in Management’s Discussion and Analysis under Item 7.

CAPITAL SPENDING AND FINANCING

For a discussion of expected capital expenditures and funding sources, see Management’s Discussion and Analysis under Item 7.

EMPLOYEES

The number of Xcel Energy employees at Dec. 31, 2002, is presented in the table below. Of the employees listed below, 7,449, or 51 percent, are covered under collective bargaining agreements.

           
NSP-Minnesota
    2,963  
NSP-Wisconsin
    550  
PSCo
    2,625  
SPS
    1,071  
Xcel Energy Services Inc.
    2,965  
NRG
    3,173  
    1,295  
 
   
 
 
Total
    14,642  
 
   
 

EXECUTIVE OFFICERS

Wayne H. Brunetti, 60, Chairman of the Board, August 2001 to present, President and Chief Executive Officer, August 2000 to present. Previously, Vice Chairman, President, Chief Operating Officer and Director of NCE since 1997 and President and Director of PSCo since 1994.

Paul J. Bonavia, 51, President — Energy Markets, Xcel Energy, August 2000 to present. Previously, Senior Vice President and General Counsel of NCE since 1997.

Benjamin G.S. Fowke III, 44, Vice President and Treasurer, Xcel Energy, November 2002 to present. Previously, Vice President and Chief Financial Officer - Energy Markets, Xcel Energy from August 2000 to November 2002, Vice President - Retail Services and Energy Markets, NCE from January 1999 to July 2000 and Vice President — Finance/Accounting, e prime from May 1997 to December 1998.

Raymond E. Gogel, 52, Vice President and CIO, Xcel Energy, April 2002 to present. Previously, Vice President and Senior Client Services Principal for IBM Global Services since June 2001 and Senior Project Executive for IBM Global Services since January 1998.

Cathy J. Hart, 53, Vice President and Corporate Secretary, Xcel Energy, August 2000 to present. Previously, Secretary of NCE since 1998 and Manager of Corporate Communications of PSCo from 1993 to 1996. From June 1996 to June 1998, Cathy J. Hart was not employed. For family reasons, she resigned as Manager of Corporate Communications at PSCo in June 1996 to move to Australia. She was re-employed by NCE as Corporate Secretary in June 1998.

Gary R. Johnson, 56, Vice President and General Counsel, Xcel Energy, August 2000 to present. Previously, Vice President and General Counsel of NSP since 1991.

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Richard C. Kelly, 56, Vice President and Chief Financial Officer, Xcel Energy, August 2002 to present. Previously, President — Enterprises, Xcel Energy, since August 2000, Executive Vice President and Chief Financial Officer for NCE from 1997 to August 2000 and Senior Vice President of PSCo from 1990 to 1997.

Cynthia L. Lesher, 54, Chief Administrative Officer, Xcel Energy, August 2000 to present. Chief Human Resources Officer, Xcel Energy, July 2001 to present. Previously, President of NSP-Gas since July 1997 and prior was Vice President-Human Resources of NSP.

Tom Petillo, 58, President — Delivery, Xcel Energy, March 2001 to present. Previously, President — Delivery, Xcel Energy from August 2000 to March 2001, Executive Vice President of New Century Services from 1998 to August 2000 and President and Director of New Century International from 1997 to 1998.

David E. Ripka, 54, Vice President and Controller, Xcel Energy, August 2000 to present. Previously, Vice President and Controller of NRG from June 1999 to August 2000, Controller of NRG from March 1997 to June 1999 and prior was Assistant Controller for NSP from June 1992 to March 1997.

Patricia K. Vincent, 44, President — Retail, Xcel Energy, March 2001 to present. Previously, Vice President of Marketing and Sales of Xcel Energy from August 2000 to March 2001, Vice President of Marketing & Sales of NCE from January 1999 to August 2000 and Manager, Director and Vice President of Marketing and Sales at Arizona Public Service Company from 1992 to January 1999.

David M. Wilks, 56, President — Energy Supply, Xcel Energy, August 2000 to present. Previously, Executive Vice President and Director of PSCo and New Century Services from 1997 to August 2000 and President, Chief Operating Officer and Director of SPS from 1995 to August 2000.

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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.
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.

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Table of Contents

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  
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.

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Table of Contents

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
  Natural Gas            
   
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  
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   Cheyenne   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
    113       6,162       1,528       4,789       8,837  
Less than 115 kv
    2,781       78,316       31,063       57,346       15,477  

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

                                         
Quantity of                                        
Substations   Cheyenne   NSP-Minnesota   NSP-Wisconsin   PSCo   SPS

 
 
 
 
 
 
    5       360       205       209       492  

Gas utility mains at Dec. 31, 2002:

                                                         
Miles   Black Mtn Gas   Cheyenne   NSP-Minnesota   NSP-Wisconsin   PSCo   Viking   WGI

 
 
 
 
 
 
 
Transmission
                115             2,263       623       12  
Distribution
    415       673       8,608       1,929       18,114              

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Table of Contents

Listed below are descriptions of NRG’s interests in facilities, operations and/or projects as of Dec. 31, 2002.

Independent Power Production and Cogeneration Facilities

                 
        Net   NRG’s    
        Owned   Percentage    
        Capacity   Ownership    
Name and Location of Facility   Purchaser/Power Market   (MW)   Interest   Fuel Type

 
 
 
 
Eastern Region:                
                 
Oswego, New York
Huntley, New York
Dunkirk, New York
Arthur Kill, New York
Astoria Gas Turbines, New York
Ilion, New York
Somerset, Massachusetts
Middletown, Connecticut
Montville, Connecticut
Devon, Connecticut
Norwalk Harbor, Connecticut
Connecticut Jet Power, Connecticut
Other — 6 projects
  Niagara Mohawk/NYISO
Niagara Mohawk/NYISO
Niagara Mohawk/NYISO
NYISO
NYISO
NYISO
Eastern Utilities Associates
ISO-NE
ISO-NE
ISO-NE
ISO-NE
ISO-NE
Various
  1,700
760
600
842
614
57
160
856
498
401
353
127
68
  100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
Various
  Oil/Gas
Coal
Coal
Gas/Oil
Gas/Oil
Gas/Oil
Coal/Oil/Jet
Oil/Gas/Jet
Oil/Gas
Gas/Oil/Jet
Oil
Jet
Various
Indian River, Delaware
Dover, Delaware
Vienna, Maryland
Conemaugh, Pennsylvania
Keystone, Pennsylvania
Paxton Creek Cogeneration,
  Delmarva/PJM
PJM
Delmarva/PJM
PJM
PJM
  784
106
170
64
63
  100% 100% 100% 3.72% 3.70%   Coal/Oil
Gas/Coal
Oil
Coal/Oil
Coal/Oil
Pennsylvania
Commonwealth Atlantic
James River
  Virginia Electric & Power
PJM
PJM
  12
188
55
  100%
50%
50%
  Gas
Gas/Oil
Coal
                 
Central Region:                
                 
Big Cajun II, Louisiana
Big Cajun I, Louisiana
Bayou Cove, Louisiana
Sterlington, Louisiana
Batesville, Mississippi
McClain, Oklahoma
Mustang, Texas
Other — 3 projects
  Cooperatives/SERC-Entergy
Cooperatives/SERC-Entergy
SERC-Entergy
Louisiana Generating
SERC-TVA
SPP-Southern
Golden Spread Electric Coop
Various
  1,489
458
320
202
837
400
122
45
  86.04% 100% 100% 100% 100% 77% 25% Various   Coal
Gas
Gas
Gas
Gas
Gas
Gas
Various
Kendall, Illinois
Rockford I, Illinois
Rockford II, Illinois
Rocky Road Power, Illinois
Audrain, Missouri
Other — 2 projects
  MAIN
MAIN
MAIN
MAIN
MAIN/SERC-Entergy
Various
  1,168
342
171
175
640
42
  100%
100%
100%
50%
100%
Various
  Gas
Gas
Gas
Gas
Gas
Various
                 
West Coast Region:                
                 
El Segundo Power, California
Encina, California
Long Beach Generating, California
San Diego Combustion Turbines,
Saguaro Power Co., Nevada
  California DWR
California DWR
California DWR
Cal ISO
Nevada Power
  335
483
265
93
50
  50%
50%
50%
50%
50%
  Gas
Gas/Oil
Gas
Gas/Oil
Gas/Oil
                 

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Table of Contents

                 
        Net   NRG’s    
        Owned   Percentage    
        Capacity   Ownership    
Name and Location of Facility   Purchaser/Power Market   (MW)   Interest   Fuel Type

 
 
 
 
Other North America:
NEO Corporation, Various
Energy Investors Funds, Various
International Projects:
  Various
Various
  197
11
  71.49% 0.73%   Various
Various
Asia-Pacific:                
Lanco Kondapalli Power, India
Hsin Yu, Taiwan
Australia:
  APTRANSCO
Industrials
  107
102
  30%
60%
  Gas/Oil (3)
Gas (3)
Flinders, South Australia
Gladstone Power Station, Queensland
Loy Yang Power A, Victoria
Europe:
  South Australian Pool
Enertrade/Boyne Smelters
Victorian Pool
  760
630
507
  100% 37.50% 25.37%   Coal
Coal
Coal
Killingholme Power A, UK
Enfield Energy Centre, UK
Schkopau Power Station, Germany
MIBRAG mbH, Germany
  UK Electricity Grid
UK Electricity Grid
VEAG/Industrials
ENVIA/MIBRAG Mines
  680
99
400
119
  100% 25% 41.67% 50%   Gas (3)
Gas/Oil
Coal
Coal
                 
ECK Generating, Czech Republic
CEEP Fund, Poland
Other Americas:
  STE/Industrials
Industrials
  166
4.5
  44.5% 7.56%   Coal/Gas/Oil (3)
Gas/Coal
TermoRio, Brazil
Itiquira Energetica, Brazil
COBEE, Bolivia
Energia Pacasmayo, Peru
Cahua, Peru
Latin Power, Various
  Petrobras
COPEL/Tradener
Electropaz/ELF
Electroperu/Peruvian Grid
Quimpac/Industrials
Various
  520
154
219
66
45
52
  50% 93.3% 100% 100% 100% 6.75%   Gas/Oil
Hydro
Hydro/Gas
Hydro/Oil
Hydro
Various

Thermal Energy Production And Transmission Facilities
And Resource Recovery Facilities

                 
            NRG’s    
            Percentage   Thermal Energy
    Date of       Ownership   Purchaser/MSW
Name and Location of Facility   Acquisition   Net Owned Capacity(1)   Interest   Supplier

 
 
 
 
NRG Energy Center — Minneapolis,                
Minnesota   1993   Steam: 1,403 mmBtu/hr. (411 MWt) Chilled water: 42,450 tons (149 MWt)   100%   Approximately 100 steam customers and 40 chilled water customers
                 
NRG Energy Center — San Francisco,                
California   1999   Steam: 490 mmBtu/hr. (144 MWt)   100%   Approximately 185 steam
customers
                 
NRG Energy Center — Harrisburg,                
Pennsylvania   2000   Steam: 490 mmBtu/hr. (144 MWt) Chilled water: 1,800 tons (8 MWt)   100%   Approximately 295 steam customers and 2 chilled water customers

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Table of Contents

                 
            NRG’s    
            Percentage   Thermal Energy
    Date of       Ownership   Purchaser/MSW
Name and Location of Facility   Acquisition   Net Owned Capacity(1)   Interest   Supplier

 
 
 
 
NRG Energy Center — Pittsburgh,
Pennsylvania
  1999   Steam: 260 mmBtu/hr.
(76 MWt)
Chilled water: 12,580
tons (44 MWt)
  100%   Approximately 30 steam
and 30 chilled water
customers
                 
NRG Energy Center — San Diego,
California
  1997   Chilled water: 8,000
tons (28 MWt)
  100%   Approximately 20 chilled
water customers
                 
                 
NRG Energy Center Rock-Tenn,
Minnesota
  1992   Steam: 430 mmBtu/hr.
(126 MWt)
  100%   Rock-Tenn Company
                 
Camas Power Boiler,
Washington
  1997   Steam: 200 mmBtu/hr.
(59 MWt)
  100%   Georgia-Pacific Corp.
                 
NRG Energy Center — Dover,
Delaware
  2000   Steam: 190 mmBtu/hr.
(56 MWt)
  100%   Kraft Foods Inc.
                 
NRG Energy Center Washco,
Minnesota
  1992   Steam: 160 mmBtu/hr.
(47 MWt)
  100%   Andersen Corporation,
Minnesota Correctional
Facility
Energy Center Kladno, Czech
Republic
  1994   227 mmBtu/hr. (67 MWt)   44.40%   City of Kladno (2)(3)
                 
                 
Resource Recovery Facilities                
Newport, Minnesota   1993   MSW: 1,500 tons/day   100%   Ramsey and Washington Counties
                 
Elk River, Minnesota   2001   MSW: 1,275 tons/day   85%   Anoka, Hennepin, and
Sherburne Counties;
Tri-County Solid Waste
Management Commission
                 
Penobscot Energy Recovery,
Maine
  1997   MSW: 590 tons/day   50%   Bangor Hydroelectric
Company

(1)   Thermal production and transmission capacity is based on 1,000 Btus per pound of steam production or transmission capacity. The unit mmBtu is equal to one million Btus.
 
(2)   Kladno also is included in the Independent Power Production and Cogeneration Facilities table on the preceding page, under the name ECK Generating.
 
(3)   Facilities held for sale.

The debt associated with many of the NRG facilities listed above is in default and could be subject to foreclosure by the lenders to such facilities. See Notes 2, 3, 4 and 7 to the Consolidated Financial Statements.

Other Properties

In addition to the above, NRG leases its corporate offices at 901 Marquette, Suite 2300, Minneapolis, Minn. 55402 and various other office spaces. NRG also owns interests in other construction projects in various stages of construction, the development of which has been terminated due to NRG's liquidity situation, as well as other properties not used for operational purposes.

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Table of Contents

Item 3. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy in addition to the regulatory matters discussed in Item 1. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Legal Contingencies

California Ancillary Services — On March 11, 2002, the Attorney General of California filed in federal court, United States District Court for the Northern District of California, a civil complaint against NRG, certain NRG affiliates, Xcel Energy, Dynegy, Inc. and Dynegy Power Marketing, Inc., alleging antitrust violations in the ancillary services market. The complaint alleges that the defendants repeatedly sold electricity generating capacity to the California ISO in state court in California. Similar actions have been brought against other parties in the California market for use as a reserve and subsequently, and impermissibly, sold the same capacity into the “spot” market for wholesale power, unlawfully collecting millions of dollars. Similar complaints were filed against other power generators. The plaintiff seeks an injunction against further similar acts by the defendants, and also seeks restitution, disgorgement of all proceeds, including profits, gained from these sales, and certain civil penalties. On April 17, 2002, the defendants in these various cases removed all of them to the federal district court, which denied the Attorney General’s motion to remand the cases to state court. That decision is on appeal to the Ninth Circuit Court. Meanwhile, the defendants’ motion to dismiss all the cases based on federal preemption and the filed rate doctrine is pending in the district court. A notice of bankruptcy filing regarding NRG has also been filed in this action, providing notice of the involuntary petition. On March 25, 2003, the federal district court dismissed the Attorney General's actions against NRG, certain NRG affiliates, Dynegy, Inc. and Dynegy Power Marketing, Inc. without prejudice.

Connecticut Light & Power Company — Connecticut Light & Power Company (CL&P) filed a claim in United States District Court for the District of Connecticut for recovery of amounts it claims is owing for congestion charges under the terms of a contract with a subsidiary of NRG. CL&P has served and filed its motion for summary judgment and NRG has yet to respond. CL&P has offset approximately $30 million from amounts owed to NRG, claiming that it has the right to offset those amounts under the contract. NRG has counterclaimed seeking to recover those amounts, arguing that CL&P has no rights under the contract to offset them. NRG cannot estimate at this time the likelihood of an unfavorable outcome in this matter, or the overall exposure for congestion charges for the full term of the contract. CL&P has also sought joinder in the involuntary bankruptcy of NRG in Minnesota.

Department of Energy (DOE) 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 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 motions for partial summary judgment on the schedule for acceptance of spent nuclear fuel and 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.

Fortistar Litigation — In July 1999, Fortistar Capital, Inc., a Delaware corporation, filed a complaint in State Court in Minnesota against NRG asserting claims for injunctive relief and for damages as a result of NRG’s alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility in New York. NRG disputed Fortistar’s allegations and asserted numerous counterclaims. In October 1999, NRG, through a wholly owned subsidiary, closed on the acquisition of the Oswego facility. On May 8, 2002, the parties resolved the litigation with respect to the Oswego facility as well as litigation between the parties with respect to Minnesota Methane LLC. At the end of August 2002, NRG asserted that conditions for consummation of the settlement had not been met, while Fortistar moved the court to enter judgment against NRG to enforce the settlement seeking damages in excess of $35 million plus interest and attorney’s fees. NRG is opposing Fortistar’s motion on the grounds that conditions to contract performance have not been satisfied. No decision has been made on the pending motion, and NRG cannot predict the outcome of this dispute. See discussion of additional Fortistar litigation at Note 18 to the Consolidated Financial Statements.

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Table of Contents

Lamb County Electric Cooperative - 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. On March 6, 2003, an ALJ issued a proposal for decision recommending that the cooperative’s petition for a cease and desist order be denied on the basis that SPS is duly certificated to provide the service in the disputed oil fields. The PUCT will receive proposed exceptions to the judge’s proposal for decision and is expected to decide the case in April 2003. 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 Xcel Energy could be material.

Environmental Contingencies

French Island — 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 October 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, on March 29, 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 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.

NRG Opacity Consent Order — NRG became part of a consent order as a result of acquiring its Huntley, Dunkirk and Oswego plants from Niagara Mohawk. At the time of financial close on these assets, a consent order was being negotiated between Niagara Mohawk and the NYDEC. The order required Niagara Mohawk to pay a stipulated penalty for each opacity event at these facilities. An opacity event is an event in time, usually six minutes or 20 minutes, when a plant’s emissions do not meet minimum levels of air transparency. On Jan. 14, 2002, the NYDEC issued NRG NOVs for opacity events, which had occurred since the time NRG assumed ownership of Huntley, Dunkirk and Oswego generating stations. The NYDEC proposed a penalty associated with the NOVs at $900,000. Subsequently, the NYDEC has indicated that a consent order, not yet received by NRG, will seek a penalty in excess of that previously proposed. NRG expects to continue negotiations with NYDEC regarding the proposed consent orders, but cannot predict the outcome of those negotiations.

Additional Information

For a discussion of other legal claims and environmental proceedings, see Note 18 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates and other regulatory matters, see Pending Regulatory Matters under Item 1, and Management’s Discussion and Analysis under Item 7, all incorporated by reference.

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

No issues were submitted for a vote during the fourth quarter of 2002.

PART II

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

Quarterly Stock Data

Xcel Energy’s common stock is listed on the New York Stock Exchange (NYSE), the Chicago Stock Exchange and the Pacific Stock Exchange. The trading symbol is XEL. The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2002 and 2001 and the dividends declared per share during those quarters.

                         
2002   High   Low   Dividends

 
 
 
First Quarter
  $ 28.49     $ 22.26     $ 0.3750  
Second Quarter
  $ 26.49     $ 13.91     $ 0.3750  
Third Quarter
  $ 17.20     $ 5.12     $ 0.1875  
Fourth Quarter
  $ 11.60     $ 7.40     $ 0.1875  
                         
2001   High   Low   Dividends

 
 
 
First Quarter
  $ 30.35     $ 24.19     $ 0.3750  
Second Quarter
  $ 31.85     $ 27.39     $ 0.3750  
Third Quarter
  $ 29.51     $ 25.00     $ 0.3750  
Fourth Quarter
  $ 29.77     $ 25.30     $ 0.3750  

Book value per share at Dec. 31, 2002, was $11.70. Shareholders of record as of Dec. 31, 2002, were 128,002.

Xcel Energy’s Restated Articles of Incorporation and First Mortgage Bond Trust Indenture provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 2002, the payment of cash dividends on common stock was not restricted except as described below.

Under PUHCA, unless there is an order from the SEC, a holding company or any subsidiary may only declare and pay dividends out of retained earnings. Due to 2002 losses incurred by NRG, retained earnings of Xcel Energy were a deficit of $101 million at Dec. 31, 2002 and, accordingly, dividends cannot be declared until earnings in 2003 are sufficient to eliminate this deficit or Xcel Energy is granted relief under the PUHCA. Xcel Energy has requested authorization from the SEC to pay dividends out of paid-in capital up to $260 million until Sept. 30, 2003. It is not known when or if the SEC will act on this request. See Common Stock Dividends under Item 7 for a discussion of factors affecting Xcel Energy’s payment of dividends.

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Item 6. Selected Financial Data

                                         
(Millions of dollars,                                        
except share and per share data)   2002   2001(d)   2000(d)   1999   1998

 
 
 
 
 
Operating revenues(a)
  $ 9,524     $ 11,333     $ 9,223     $ 6,883     $ 6,606  
Operating expenses(a)
  $ 10,957     $ 9,475     $ 7,744     $ 5,679     $ 5,412  
Income (loss) from continuing operations
  $ (1,661 )   $ 738     $ 514     $ 571     $ 620  
Net income (loss)
  $ (2,218 )   $ 795     $ 527     $ 571     $ 624  
Earnings available for common stock
  $ (2,222 )   $ 791     $ 523     $ 566     $ 619  
Average number of common shares outstanding (000’s)
    382,051       342,952       337,832       331,943       323,883  
Average number of common and potentially dilutive shares outstanding (000’s)
    382,051       343,742       338,111       332,054       324,355  
Earnings per share from continuing operations
  $ (4.36 )   $ 2.14     $ 1.51     $ 1.70     $ 1.91  
Earnings per share-basic
  $ (5.82 )   $ 2.31     $ 1.54     $ 1.70     $ 1.91  
Earnings per share-diluted
  $ (5.82 )   $ 2.30     $ 1.54     $ 1.70     $ 1.91  
Dividends declared per share(b)
  $ 1.13     $ 1.50     $ 1.45     $ 1.47     $ 1.46  
Total assets
  $ 27,258     $ 28,754     $ 21,769     $ 18,070     $ 15,055  
Long-term debt(e)
  $ 6,550     $ 11,556     $ 7,011     $ 5,582     $ 4,057  
Book value per share
  $ 11.70     $ 17.91     $ 16.32     $ 15.78     $ 15.44  
Return on average common equity
    (41.0 )%     13.5 %     9.6 %     10.9 %     12.6 %
Ratio of earnings (deficiency) to fixed charges(c)(f)
    (1.8 )     2.1       1.9       2.4       3.0  

(a)   Operating revenues and expenses for 1998 through 2001 include reclassifications to conform to the 2002 presentation. These reclassifications related to reporting electric and natural gas trading revenues and costs on a net basis, and to presenting the results of discontinued operations separately. These reclassifications had no effect on net income or earnings per share.
 
(b)   Amounts include pro forma adjustments to restate periods before the merger to create Xcel Energy, for historically consistent reporting. Dividends in 2000 reflect dividends paid by predecessor companies before, and Xcel Energy after, the Xcel Energy merger in August 2000.
 
(c)   Excludes undistributed equity income and includes allowance for funds used during construction.
 
(d)   Earnings in 2001 were increased by 3 cents per share for extraordinary items. Earnings in 2000 were reduced by 52 cents per share for special charges related to the Xcel Energy merger, as discussed in Note 2 to the Consolidated Financial Statements. In addition, earnings in 2000 were reduced by 6 cents per share for extraordinary items related to electric utility restructuring in Texas and New Mexico, as discussed in Note 15 to the Consolidated Financial Statements.
 
(e)   Long term debt for 1998 through 2001 include reclassifications to present the long-term debt of discontinued operations separately, and adjustments related to those reclassifications.
 
(f)   The fixed charges exceeded earnings, as defined for this ratio, by $2.9 billion in 2002.

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Item 7. Management’s Discussion and Analysis

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 (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. 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. As a stock-for-stock exchange for shareholders of both companies, the merger was accounted for as a pooling-of-interests and, accordingly, amounts reported for periods prior to the merger have been restated for comparability with post-merger results.

Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. These six utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); Southwestern Public Service Co. (SPS); Black Mountain Gas Co. (BMG), which is in the process of being sold pending regulatory approval; and Cheyenne Light, Fuel and Power Co. (Cheyenne). They serve customers in portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. During 2002, Xcel Energy’s regulated businesses also included Viking Gas Transmission Co. (Viking), which was sold on Jan. 17, 2003, and WestGas InterState Inc. (WGI), both interstate natural gas pipeline companies.

Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc. (NRG), an independent power producer. Xcel Energy owned 100 percent of NRG at the beginning of 2000. About 18 percent of NRG was sold to the public in an initial public offering in the second quarter of 2000, leaving Xcel Energy with an 82-percent interest at Dec. 31, 2000. In March 2001, another 8 percent of NRG was sold to the public, leaving Xcel Energy with an interest of about 74 percent at Dec. 31, 2001. On June 3, 2002, Xcel acquired the 26 percent of NRG held by the public so that it again held 100 percent ownership at Dec. 31, 2002. NRG is facing extreme financial difficulties. There is substantial doubt as to NRG’s ability to continue as a going concern absent a restructuring through bankruptcy, and NRG will likely be the subject of a bankruptcy proceeding. See Note 2, 3, 4 and 7 to the Consolidated Financial Statements.

In addition to NRG, Xcel Energy’s nonregulated subsidiaries include Utility Engineering Corp. (engineering, construction and design), Seren Innovations, Inc. (broadband telecommunications services), e prime inc. (natural gas marketing and trading), Planergy International, Inc. (enterprise energy management solutions), Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits) and Xcel Energy International Inc. (an international independent power producer).

FINANCIAL REVIEW

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying Consolidated Financial Statements and Notes. All Note references refer to the Notes to Consolidated Financial Statements.

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,” “project,” “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 and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership; structures that affect the speed and degree to which competition enters the electric and gas markets; the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses; currency translation and transaction adjustments; risks associated with the California power market; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2002.

RESULTS OF OPERATIONS

Xcel Energy’s earnings per share for the past three years were as follows:

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        Contribution to earnings per share
       
        2002   2001   2000
       
 
 
Continuing Operations Before Extraordinary Items:
                       
 
Regulated utility
  $ 1.59     $ 1.90     $ 1.20  
 
NRG (including impairments and restructuring
charges)
    (7.58 )     0.44       0.37  
 
Other nonregulated and holding company
(including tax benefits related to investment in
NRG in 2002)
    1.63       (0.21 )     (0.06 )
 
 
   
     
     
 
   
Income (loss) from continuing operations
    (4.36 )     2.13       1.51  
Discontinued operations – NRG (see Note 3)
    (1.46 )     0.14       0.09  
Extraordinary items – Regulated utility (see Note 15)
          0.03       (0.06 )
 
 
   
     
     
 
Total earnings (loss) per share – diluted
  $ (5.82 )   $ 2.30     $ 1.54  
 
 
   
     
     
 

Additional information on earnings contributions by operating segments are as follows:

                             
        Contribution to earnings per share
       
        2002   2001   2000
       
 
 
Regulated utility (including extraordinary items):
                       
 
Electric utility
  $ 1.33     $ 1.66     $ 1.03  
 
Gas utility
    0.26       0.24       0.17  
 
 
   
     
     
 
   
Total regulated utility
    1.59       1.90       1.20  
NRG (including discontinued operations) – (see Note 3)
    (9.04 )     0.58       0.46  
Other nonregulated and holding company:
                       
 
Tax benefit related to investment in NRG
    1.85       0.00       0.00  
 
Other (see Note 21 for components)
    (0.22 )     (0.18 )     (0.12 )
 
 
   
     
     
 
Total earnings (loss) per share – diluted
  $ (5.82 )   $ 2.30     $ 1.54  
 
 
   
     
     
 

For more information on significant factors that had an impact on earnings, see below.

Significant Factors that Impacted 2002 Results

Special Charges — Regulated Utility — Regulated utility earnings from continuing operations were reduced by approximately 2 cents per share in 2002 due to a $5-million regulatory recovery adjustment for SPS and $9 million in employee separation costs associated with a restaffing initiative early in the year for utility and service company operations. See Note 2 to the Consolidated Financial Statements for further discussion of these items, which are reported as Special Charges in operating expenses.

Impairment and Financial Restructuring Charges — NRG — NRG’s losses from both continuing and discontinued operations were affected by charges recorded in 2002. Continuing operations included losses of approximately $7.07 per share in 2002 for asset impairment and disposal losses, and for other charges related mainly to its financial restructuring. These costs are reported as Special Charges and Writedowns and Disposal Losses from Investments in operating expenses, and are discussed further in Note 2 to the Financial Statements. In addition, discontinued operations included losses of approximately $1.56 per share for asset impairments and disposal losses, and are discussed further in Note 3 to the Consolidated Financial Statements.

During 2002, NRG experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events led to impairment reviews of a number of NRG assets, which resulted in material write-downs in 2002. In addition to impairments of projects operating or under development, certain NRG projects were determined to be held for sale, and estimated losses on disposal for such projects were also recorded. These impairment charges, some of which related to equity investments, have reduced Xcel Energy’s earnings for 2002 as follows: $6.29 of Special Charges in continuing operations, $0.51 of Losses on Disposal of Investments in continuing operations, and $1.57 of impairment charges included in discontinued operations. As reported previously, there is substantial doubt as to NRG’s ability to continue as a going concern, and NRG will likely be the subject of a bankruptcy proceeding.

NRG also expensed approximately $111 million in 2002 for incremental costs related to its financial restructuring and business realignment. These costs, which reduced 2002 earnings by 27 cents per share, include expenses for financial and legal advisors, contract termination costs, employee separation and other incremental costs incurred during the financial restructuring period. These costs also include a charge related to NRG’s NEO landfill gas generation operations for the estimated impact of a dispute settlement with NRG’s partner on the NEO project, Fortistar. Most of these costs were paid in 2002. See Note 2 to the Consolidated Financial Statements for discussion of accrued financial restructuring cost activity related to NRG.

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Tax Benefit — NRG Investment — As discussed in Note 11, it was determined in 2002 that NRG was no longer likely to be included in Xcel Energy’s consolidated income tax group. Approximately $706 million has been recognized at one of Xcel Energy’s nonregulated intermediate holding companies for the estimated tax benefits related to Xcel Energy’s investment in NRG, based on the difference between book and tax bases of such investment. This estimated tax benefit increased 2002 annual results by $1.85 per share.

Other Nonregulated & Holding Companies — Nonregulated and holding company earnings for 2002 were reduced by losses of approximately 6 cents per share for the combined effects of unusual items that occurred during the year. As discussed later, Xcel International recorded impairment losses for Argentina assets of 3 cents per share and disposal losses for Yorkshire Power of 2 cents per share, Planergy recorded gains from contract sales of 2 cents per share, losses were incurred on holding company debt of 2 cents per share, and incremental costs related to NRG financial restructuring activities of 1 cent per share were incurred at the holding company level.

Significant Factors that Impacted 2001 Results

Regulated utility earnings were reduced by a net 1 cent per share from the combined effects of four unusual items that occurred during the year. Three of the items affected continuing operations, reducing earnings by 4 cents per share. The remaining item increased income from extraordinary items by 3 cents per share.

Conservation Incentive Recovery — Regulated utility earnings from continuing operations in 2001 were increased by 7 cents per share due to a Minnesota Public Utilities Commission (MPUC) decision. In June 2001, the MPUC approved a plan allowing recovery of 1998 incentives associated with state-mandated programs for energy conservation. 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 by approximately $7 million, increasing earnings by 7 cents per share 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 beginning in 2001.

Special Charges — Postemployment Benefits and Restaffing Costs — Regulated utility earnings from continuing operations in 2001 were decreased by 4 cents per share due to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of a regulatory asset related to deferred postemployment benefit costs at PSCo.

Also, regulated utility earnings from continuing operations were reduced by approximately 7 cents per share in 2001 due to $39 million of employee separation costs associated with a restaffing initiative late in the year for utility and service company operations. See Note 2 to the Financial Statements for further discussion of these items, which are reported as Special Charges in operating expenses.

Extraordinary Items — Electric Utility Restructuring — In 2001, extraordinary income of $18 million before tax, or 3 cents per share, was recorded related to the regulated utility business to reflect the impacts of industry restructuring developments for SPS. This represents a reversal of a portion of the 2000 extraordinary loss discussed later. For more information on SPS extraordinary items, see Note 15 to the Consolidated Financial Statements.

Significant Factors that Impacted 2000 Results

Special Charges — Merger Costs — During 2000, Xcel Energy expensed pretax special charges of $241 million, or 52 cents per share, for costs related to the merger between NSP and NCE. Of these special charges, approximately 44 cents per share were associated with the costs of merging regulated utility operations and 8 cents per share were associated with merger impacts on nonregulated and holding company activities other than NRG. See Note 2 to the Consolidated Financial Statements for more information on these merger-related costs reported as Special Charges.

Extraordinary Items — Electric Utility RestructuringIn 2000, extraordinary losses of approximately $28 million before tax, or 6 cents per share, were recorded related to the regulated utility business for the expected discontinuation of regulatory accounting for SPS’ generation business. For more information on SPS extraordinary items, see Note 15 to the Consolidated Financial Statements.

Statement of Operations

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

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electric utility margin. However, the fuel clause cost recovery in Colorado does not allow for complete recovery of all variable production expense, and cost changes can affect earnings. Electric utility 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 incentive cost adjustment (ICA) ratemaking mechanism in Colorado. In addition to the ICA, Colorado has other adjustment clauses that allow certain costs to be recovered from retail customers.

Xcel Energy has three distinct forms of wholesale sales: short-term wholesale, electric commodity trading and natural gas commodity trading. Short-term wholesale refers to electric sales for resale, which are associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Electric and natural gas commodity trading refers to the sales for resale activity of purchasing and reselling electric and natural gas energy to the wholesale market.

Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota (electric), PSCo (electric) and e prime (natural gas). Margins from electric trading activity, conducted at NSP-Minnesota and PSCo, are partially redistributed to other operating utilities of Xcel Energy, pursuant to a joint operating agreement (JOA) approved by the Federal Energy Regulatory Commission (FERC). Trading margins reflect the impact of sharing certain trading margins under the ICA. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net (i.e., margins) in the Consolidated Statements of Operations. Trading revenue and costs associated with NRG’s operations are included in nonregulated margins. The following table details the revenue and margin for base electric utility, short-term wholesale and electric and natural gas trading activities.

                                                 
    Base           Electric   Natural Gas                
    Electric   Short-Term   Commodity   Commodity   Intercompany   Consolidated
(Millions of dollars)   Utility   Wholesale   Trading   Trading   Eliminations   Totals

 
 
 
 
 
 
2002
                                               
Electric utility revenue
  $ 5,232     $ 203     $     $     $     $ 5,435  
Electric fuel and purchased power-utility
    (2,029 )     (170 )                       (2,199 )
Electric and natural gas trading revenue-gross
                1,529       1,898       (71 )     3,356  
Electric and natural gas trading costs
                (1,527 )     (1,892 )     71       (3,348 )
 
   
     
     
     
     
     
 
Gross margin before operating expenses
  $ 3,203     $ 33     $ 2     $ 6     $     $ 3,244  
 
   
     
     
     
     
     
 
Margin as a percentage of revenue
    61.2 %     16.3 %     0.1 %     0.3 %           36.9 %
 
                                               
2001
                                               
Electric utility revenue
  $ 5,607     $ 788     $     $     $     $ 6,395  
Electric fuel and purchased power-utility
    (2,559 )     (613 )                       (3,172 )
Electric and natural gas trading revenue-gross
                1,337       1,938       (88 )     3,187  
Electric and natural gas trading costs
                (1,268 )     (1,918 )     88       (3,098 )
 
   
     
     
     
     
     
 
Gross margin before operating expenses
  $ 3,048     $ 175     $ 69     $ 20     $     $ 3,312  
 
   
     
     
     
     
     
 
Margin as a percentage of revenue
    54.4 %     22.2 %     5.2 %     1.0 %           34.6 %
 
                                               
2000
                                               
Electric utility revenue
  $ 5,107     $ 567     $     $     $     $ 5,674  
Electric fuel and purchased power-utility
    (2,106 )     (475 )                       (2,581 )
Electric and natural gas trading revenue-gross
                819       1,297       (54 )     2,062  
Electric and natural gas trading costs
                (788 )     (1,287 )     54       (2,021 )
 
   
     
     
     
     
     
 
Gross margin before operating expenses
  $ 3,001     $ 92     $ 31     $ 10     $     $ 3,134  
 
   
     
     
     
     
     
 
Margin as a percentage of revenue
    58.8 %     16.2 %     3.8 %     0.8 %     %     40.5 %

2002 Comparison to 2001 — Base electric utility revenue decreased $375 million, while electric utility margins, primarily retail, increased approximately $155 million in 2002, compared with 2001. Base electric revenues decreased largely due to decreased recovery of fuel and purchased power costs driven by declining fuel costs in 2002. The higher base electric margins in the year reflect lower unrecovered costs, due in part to resetting the base-cost recovery at PSCo 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. For the year, higher accrued conservation revenues, sales growth and more favorable temperatures also contributed to the

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higher electric margins and partially offset the lower base electric revenue. Lower wholesale capacity sales in Texas, as well as the impact of the conservation incentive adjustment in Minnesota in 2001, as discussed previously, partially offset the increased margins and contributed to the lower revenues.

Short-term wholesale margins consist of asset-based trading activity. Electric and natural gas commodity trading activity margins consist of non-asset-based trading activity. Short-term wholesale and electric and natural gas commodity trading sales margins decreased an aggregate of approximately $223 million in 2002, compared with 2001. The decrease in short-term wholesale and electric commodity trading margin reflects lower power prices and less favorable market conditions. The decrease in natural gas commodity trading margin reflects reduced market opportunities.

2001 Comparison to 2000 — Base electric utility revenue increased by approximately $500 million, or 9.8 percent, in 2001. Base electric utility margin increased by approximately $47 million, or 1.6 percent, in 2001. These revenue and margin increases were due to sales growth, weather conditions in 2001 and the recovery of conservation incentives in Minnesota. Increased conservation incentives, including the resolution of the 1998 dispute, as discussed previously, and accrued 2001 incentives, increased revenue and margin by $49 million. More favorable weather during 2001 increased revenue by approximately $23 million and margin by approximately $13 million. These increases were partially offset by increases in fuel and purchased power costs, which are not completely recoverable from customers in Colorado due to various cost-sharing mechanisms. Revenue and margin also were reduced in 2001 by approximately $30 million due to rate reductions in various jurisdictions agreed to as part of the merger approval process, compared with $10 million in 2000.

Short-term wholesale revenue increased by approximately $221 million, or 39.0 percent, in 2001. Short-term wholesale margin increased $83 million, or 90.2 percent, in 2001. These increases are due to the expansion of Xcel Energy’s wholesale marketing operations and favorable market conditions for the first six months of 2001, including strong prices in the western markets, particularly before the establishment of price caps and other market changes.

Electric and natural gas commodity trading margins, including proprietary electric trading (i.e., not in electricity produced by Xcel Energy’s own generating plants) and natural gas trading, increased approximately $48 million for the year ended Dec. 31, 2001, compared with the same period in 2000. The increase reflects an expansion of Xcel Energy’s trading operations and favorable market conditions, including strong prices in the western markets, particularly before the establishment of pricing caps and other market changes.

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

                           
(Millions of dollars)   2002   2001   2000

 
 
 
Natural gas utility revenue
  $ 1,398     $ 2,053     $ 1,469  
Cost of natural gas purchased and transported
    (852 )     (1,518 )     (948 )
 
   
     
     
 
 
Gas utility margin
  $ 546     $ 535     $ 521  

2002 Comparison to 2001 — Natural gas utility revenue decreased by $655 million, while natural gas margins increased by $11 million. Natural gas revenue decreased largely due to decreases in the cost of natural gas, which are generally passed through to customers. Natural utility gas margin increased due primarily to more favorable temperatures and sales growth.

2001 Comparison to 2000 — Natural gas utility revenue increased by approximately $584 million, or 39.8 percent, for 2001, primarily due to increases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in most of the jurisdictions in which Xcel Energy operates. Natural gas utility margin increased by approximately $14 million, or 2.7 percent, for 2001 due to sales growth and a rate increase in Colorado. These natural gas revenue and margin increases were partially offset by the impact of warmer temperatures in 2001, which decreased natural gas revenue by approximately $38 million and natural gas margin by approximately $16 million.

Nonregulated Operating Margins — The following table details the changes in nonregulated revenue and margin included in continuing operations.

                           
(Millions of dollars)   2002   2001   2000

 
 
 
Nonregulated and other revenue
  $ 2,611     $ 2,580     $ 1,856  
Earnings from equity investments
    72       217       183  
Nonregulated cost of goods sold
    (1,361 )     (1,319 )     (877 )
 
   
     
     
 
 
Nonregulated margin
  $ 1,322     $ 1,478     $ 1,162  

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2002 Comparison to 2001 — Nonregulated revenue from continuing operations increased slightly in 2002, reflecting growth from the full-year impact of NRG’s 2001 generating facility acquisitions but partially offset by lower market prices. Nonregulated margin from continuing operations decreased in 2002, due to decreased equity earnings. Earnings from equity investments for 2002 decreased compared with 2001, primarily due to decreased equity earnings from NRG’s West Coast Power project, which experienced less favorable long-term contracts and higher uncollectible receivables.

2001 Comparison to 2000 — Nonregulated revenue and margin from continuing operations increased in 2001, largely due to NRG’s acquisition of generating facilities, increased demand for electricity, market dynamics, strong performance from existing assets and higher market prices for electricity. Earnings from equity investments for 2001 increased compared with 2000, primarily due to increased equity earnings from NRG projects, which offset lower equity earnings from Yorkshire Power. As a result of a sales agreement to sell most of its investment in Yorkshire Power, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001.

Non-Fuel Operating Expense and Other Items Other utility operating and maintenance expense for 2002 decreased by approximately $4 million, or 0.3 percent. The decreased costs reflect lower incentive compensation and other employee benefit costs, as well as lower staffing levels in corporate areas. These decreases were substantially offset by higher plant outage and property insurance costs, in addition to inflationary factors such as market wage increases.

Other utility operating and maintenance expense for 2001 increased by approximately $60 million, or 4.1 percent, compared with 2000. The change is largely due to increased plant outages, higher nuclear operating costs, bad debt reserves reflecting higher energy prices, increased costs due to customer growth and higher performance-based incentive costs.

Other nonregulated operating and maintenance expenses for continuing operations increased $111 million in 2002 and increased $143 million in 2001. These expenses are included in the results for each nonregulated subsidiary, as discussed later.

Depreciation and amortization expense increased $131 million, or 14.5 percent, in 2002 and $140 million, or 18.2 percent, in 2001, primarily due to acquisitions of generating facilities by NRG and additions to utility plant. Higher NRG depreciation expense accounted for $87 million of the increase in 2002.

Interest income was higher in 2002 and 2001 due to higher cash balances at NRG in both years and to interest on affiliate loans in 2001.

Other income was higher in 2002 and 2001 due mainly to a gain on the sale of nonregulated property and PSCo assets.

Other expense increased in 2002 due largely to variations in currency exchange losses at NRG.

Interest expense increased $152 million, or 20.8 percent, in 2002 and $114 million, or 18.5 percent, in 2001, primarily due to increased debt of NRG. In addition, long-term debt was refinanced at higher interest rates during 2002. Higher NRG interest expense accounted for $105 million of the increase in 2002.

Income tax expense decreased by approximately $959 million in 2002, compared with 2001. Nearly all of this decrease relates to NRG’s 2002 losses and the change in tax filing status for NRG effective in the third quarter of 2002, as discussed in Note 11 to the Consolidated Financial Statements. NRG is now in a tax operating loss carryforward position and is no longer assumed to be part of Xcel Energy’s consolidated tax group. The effective tax rate for continuing operations, excluding minority interest and before extraordinary items, was 27.3 percent for the year ended Dec. 31, 2002, and 28.8 percent for the same period in 2001. The decrease in the effective rate between years reflects a nominal tax rate at NRG, due to their loss carryforward position. Partially offsetting the NRG tax rate decrease is the impact of a one-time adjustment to recognize tax benefits from Xcel Energy’s investment in NRG, as discussed in Note 11 to the Consolidated Financial Statements. The effective tax rate for the regulated utility business and operations other than NRG was significantly lower in 2002, compared with 2001, due to the benefit recorded on the investment in NRG and the changes in the items listed in the rate reconciliation in Note 11.

Weather — Xcel Energy’s earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase expenses, which may not be fully recoverable. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce expenses, which affects overall results. The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from historical averages:

  weather in 2002 increased earnings by an estimated 6 cents per share;
 
  weather in 2001 had minimal impact on earnings per share; and
 
  weather in 2000 increased earnings by an estimated 1 cent per share.

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NRG Results

                               
          Contribution to Xcel Energy’s earnings per share
         
          2002   2001   2000
         
 
 
Continuing NRG operations:
                       
 
Operations before tax credits, special charges and disposal losses
  $ (0.54 )   $ 0.49     $ 0.35  
 
Tax credits
          0.14       0.10  
 
Special charges-asset impairments (Note 2)
(6.29 )            
 
Special charges-financial restructuring and NEO (Note 2)
(0.27 )            
 
Write-downs and disposal losses from equity investments
(Note 2)
(0.51 )            
 
 
   
     
     
 
   
Income (loss) from continuing NRG operations
    (7.61 )     0.63       0.45  
Discontinued NRG operations (Note 3)
    (1.46 )     0.14       0.09  
 
 
   
     
     
 
     
Total NRG earnings (loss) per share
  (9.07 )   0.77     0.54  
     
Minority shareholder interest
  0.03     (0.19 )     (0.08 )
 
 
   
     
     
 
     
NRG contribution to Xcel Energy
  $ (9.04 )   $ 0.58     $ 0.46  
 
 
   
     
     
 

NRG Continuing Operations and Tax Credits — As previously stated, NRG is facing extreme financial difficulties, and there is substantial doubt as to NRG’s ability to continue as a going concern. During 2002, NRG’s continuing operations, excluding impacts of asset impairments and disposals and restructuring costs, experienced significant losses compared with 2001. The 2002 losses are primarily attributable to NRG’s North American operations, which experienced significant reductions in domestic energy and capacity sales and an overall decrease in power pool prices and related spark spreads. During 2002, an additional reserve for uncollectible receivables in California was established by West Coast Power, which reduced NRG’s equity earnings by approximately $29 million, after tax. West Coast Power’s 2002 income was also lower than 2001 due to less-favorable contracts and reductions in sales of energy and capacity. In addition, increased administrative costs, depreciation and interest expense from completed construction costs also contributed to the less-than-favorable results for NRG in 2002. Partially off-setting these earnings reductions was the recognition, in the fourth quarter of 2002, of approximately $51 million of additional revenues related to the contractual termination related to NRG’s Indian River project.

On a stand-alone basis, NRG does not have the ability to recognize all tax benefits that may ultimately accrue from its losses incurred in 2002, thus increasing the overall loss from continuing operations. In addition to losing the ability to recognize all tax benefits for operating losses, NRG in 2002 also lost the ability to utilize tax credits generated by its energy projects. These lower tax credits account for a portion of the decreased earnings contribution of NRG compared with results in 2001 and 2000, which included income related to recognition of tax credits.

NRG’s earnings for 2001 increased primarily due to new acquisitions in Europe and North America, as well as a full year of operation in 2001 of acquisitions made in the fourth quarter of 2000. In addition, NRG’s 2001 earnings reflected a reduction in the overall effective tax rate and mark-to-market gains related to SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activity.” The overall reduction in tax rates in 2001 was primarily due to higher energy credits, the implementation of state tax planning strategies and a higher percentage of NRG’s overall earnings derived from foreign projects in lower tax jurisdictions.

NRG Special Charges — Impairments and Financial Restructuring — As discussed previously, both the continuing and discontinued operations of NRG in 2002 included material losses for asset impairments and estimated disposal losses. Also, NRG recorded other special charges in 2002, mainly for incremental costs related to its financial restructuring and business realignment. See Notes 2 and 3 to the Consolidated Financial Statements for further discussion of NRG’s special charges and discontinued operations, respectively.

Other Nonregulated Subsidiaries and Holding Company Results

                           
      Contribution to Xcel Energy’s earnings per share
     
      2002   2001   2000
     
 
 
Xcel International
  $ (0.05 )   $ (0.02 )   $ 0.09
Eloigne Company
    0.02       0.03       0.02
Seren Innovations
    (0.07 )     (0.08 )     (0.07 )
Planergy International
    0.00       (0.04 )     (0.08 )
e prime
    0.00       0.02       (0.02 )
Financing costs and preferred dividends
    (0.11 )     (0.11 )     (0.07 )
Other nonregulated/holding company results
    (0.01 )     0.02       0.01  
 
   
     
     
 
 
Subtotal – nonregulated/holding co. excluding
tax benefit
    (0.22 )     (0.18 )     (0.12 )
Tax benefit from investment in NRG (Note 11)
    1.85              
 
   
     
     
 
 
Total nonregulated/holding company earnings per share
  $ 1.63     $ (0.18 )   $ (0.12 )
 
   
     
     
 

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Xcel International — Xcel International is currently comprised primarily of power generation projects in Argentina, and previously included an investment in Yorkshire Power.

In December 2002, a subsidiary of Xcel Argentina decided it would no longer fund one of its power projects in Argentina and defaulted on its loan agreements. The default is not material to Xcel Energy. However, this decision resulted in the shutdown of the Argentina plant facility, pending financing of a necessary maintenance outage. Updated cash flow projections for the plant were insufficient to provide recovery of Xcel International’s investment. An impairment write-down of approximately $13 million, or 3 cents per share, was recorded in 2002.

In August 2002, Xcel Energy announced it had sold its 5.25-percent interest in Yorkshire Power Group Limited for $33 million to CE Electric UK. The sale of the 5.25-percent interest resulted in an after-tax loss of $8.3 million, or 2 cents per share, in 2002. The loss is included in write-downs and disposal losses from investments on the Consolidated Statements of Operations. Xcel Energy and American Electric Power Co. initially each held a 50-percent interest in Yorkshire, a UK retail electricity and natural gas supplier and electricity distributor, before selling 94.75 percent of Yorkshire to Innogy Holdings plc in April 2001. As a result of this sales agreement, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001. For more information, see Note 3 to the Consolidated Financial Statements.

Eloigne Company — Eloigne invests in affordable housing that qualifies for Internal Revenue Service tax credits. Eloigne’s earnings contribution declined slightly in 2002 as tax credits on mature affordable housing projects began to decline. The actual decline in Eloigne’s net income in 2002, compared with 2001, was only $716,000, with 2002 earnings representing 2.1 cents per share and 2001 earnings representing 2.5 cents per share.

Seren Innovations — Seren operates a combination cable television, telephone and high-speed Internet access system in St. Cloud, Minn., and Contra Costa County, California. Operation of its broadband communications network has resulted in losses. Seren projects improvement in its operating results with positive cash flow anticipated in 2005, upon completion of its build-out phase, and a positive earnings contribution anticipated in 2008.

Planergy International — Planergy, a wholly owned subsidiary of Xcel Energy, provides energy management services. Planergy’s results for 2002 improved, largely due to gains from the sale of a portfolio of energy management contracts, which increased earnings by nearly 2 cents per share.

Planergy’s results for 2000 were reduced by special charges of 4 cents per share for the write-offs of goodwill and project development costs.

e prime e prime’s results for the year ended Dec. 31, 2001, reflect the favorable structure of its contractual portfolio, including natural gas storage and transportation positions, structured products and proprietary trading in natural gas markets. e prime’s earnings were lower in 2002, and higher in 2001, due to varying natural gas commodity trading margins, as discussed previously.

e prime’s results for 2000 were reduced by special charges of 2 cents per share for contractual obligations and other costs associated with post-merger changes in the strategic operations and related revaluations of e prime’s energy marketing business.

Financing Costs and Preferred Dividends — Nonregulated results include interest expense and preferred dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual subsidiaries.

In November 2002, the Xcel Energy holding company issued temporary financing, which included detachable options for the purchase of Xcel Energy notes, which are convertible to Xcel Energy common stock. This temporary financing was replaced with longer-term holding company financing in late November 2002. Costs incurred to redeem the temporary financing included a redemption premium of $7.4 million, $5.2 million of debt discount associated with the detachable option and other issuance costs, which increased financing costs and reduced 2002 earnings by 2 cents per share.

Other — Certain costs related to NRG’s restructuring are being incurred at the holding company level. Approximately $5 million of such costs were incurred in 2002, which reduced earnings by approximately 1 cent per share.

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Other nonregulated results for 2000, which include the activity of several nonregulated subsidiaries, were reduced by merger-related special charges of 2 cents per share. These special charges include $10 million in asset write-downs and losses resulting from various other nonregulated business ventures that are no longer being pursued after the Xcel Energy merger.

Factors Affecting Results of Operations

Xcel Energy’s utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions. In addition, Xcel Energy’s nonregulated businesses have adversely affected Xcel Energy’s earnings in 2002. The historical and future trends of Xcel Energy’s operating results have been, and are expected to be, affected by the following factors:

Impact of NRG Financial Difficulties - NRG is experiencing severe financial difficulties, resulting primarily from declining credit ratings and lower prices for power. These financial difficulties have caused NRG to miss several scheduled payments of interest and principal on its bonds and incur approximately $3.1 billion in asset impairment charges. In addition, as a result of being downgraded, NRG was required to post cash collateral ranging from $1.1 billion to $1.3 billion. NRG has been unable to post this cash collateral and, as a result, is in default on various obligations. Furthermore, in November 2002, lenders to NRG accelerated approximately $1.1 billion of NRG’s debt, rendering the debt immediately due and payable. In February 2003, lenders to NRG accelerated an additional $1 billion of debt. NRG does not contemplate making any principal or interest payments on its corporate-level debt pending the restructuring of its obligations and is in default under various debt instruments. As a consequence of the defaults, the lenders are able to seek to enforce their remedies, if they so choose, and that would likely lead to a bankruptcy filing by NRG. NRG continues to work with its lenders and bondholders on a comprehensive financial restructuring plan. See further discussion of potential NRG bankruptcy and financial restructuring under Liquidity and Capital Resources and in Notes 4 and 18 to the Consolidated Financial Statements.

Subsequent to its credit downgrade in July 2002, NRG experienced losses as follows in 2002:

                   
(Millions of dollars)   Third Quarter   Fourth Quarter

 
 
Net losses from NRG:
               
Special Charges – asset impairments
  $ (2,466 )   $ (79 )
Special Charges – financial restructuring and other costs
    (34 )     (21 )
Write-downs and losses on equity method investments
    (118 )     (74 )
Other income (loss) from continuing operations, including income tax effects
  140   (176 )
 
   
     
 
 
NRG loss from continuing operations
  (2,478 )   (350 )
Discontinued operations – asset impairments
    (600 )      
Discontinued operations – other
  23   9
 
   
     
 
 
Net NRG loss for period
  $ (3,055 )   $ (341 )
 
   
     
 

These NRG losses have reduced Xcel Energy’s retained earnings to a deficit as of Dec. 31, 2002. NRG is expected to continue to experience material losses into 2003, pending a successful financial restructuring and increased power prices. NRG’s losses in 2003 may include further asset impairments, losses from asset disposals, and financial restructuring costs as NRG continues its financial restructuring and decisions are made to realign NRG’s business operations and divest operating assets. In addition, the impact of any settlement with NRG’s creditors regarding the financial restructuring of NRG may also impact Xcel Energy’s operating results and retained earnings, by material amounts which will not be determinable until settlement terms are reached. See Note 4 to the Financial Statements for a discussion of a preliminary settlement with NRG’s creditors. As discussed later, Xcel Energy is unable without SEC approval under PUHCA to declare dividends on its common stock until consolidated retained earnings are positive, and continuing NRG financial impacts may continue to limit the ability of Xcel Energy to declare and pay dividends.

In the event that NRG’s financial situation ultimately results in a bankruptcy filing, there may be additional impacts on Xcel Energy’s financial condition and results of operations. See the “Xcel Energy Impacts” under the “Other Liquidity and Capital Resource Considerations” section later in Management’s Discussion and Analysis, and Note 4 to the Financial Statements, for further discussion of the possible effects of an NRG bankruptcy filing on Xcel Energy.

General Economic Conditions - The slower United States economy, and the global economy to a lesser extent, may have a significant impact on Xcel Energy’s operating results. Current economic conditions have resulted in a decline in the forward price curve for energy and decreased commodity-trading margins. In addition, certain operating costs, such as insurance and security, have increased due to the economy, terrorist activity and the threat of war. Management cannot predict the impact of a continued economic slowdown, fluctuating energy prices, war or the threat of war.

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However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to raise capital from a weakened economy or war.

Sales Growth — In addition to weather impacts, customer sales levels in Xcel Energy’s regulated utility businesses can vary with economic conditions, customer usage patterns and other factors. Weather-normalized sales growth for retail electric utility customers was estimated to be 1.8 percent in 2002 compared with 2001, and 1.0 percent in 2001 compared with 2000. Weather-normalized sales growth for firm gas utility customers was estimated to be approximately the same in 2002 compared with 2001, and 2.6 percent in 2001 compared with 2000. We are projecting that 2003 weather-normalized sales growth in 2003 compared with 2002 will be 1.5 to 2.0 percent for retail electric utility customers and 2.5 to 3.0 percent for firm gas utility customers.

Utility Industry Changes — The structure of the electric and natural gas utility industry has been subject 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 nondiscriminatory access to the use of their transmission systems.

In December 2001, the FERC approved Midwest Independent Transmission System Operator, Inc. (MISO) as the Midwest independent system operator responsible for operating the wholesale electric transmission system. Accordingly, in compliance with the FERC’s Order No. 2000, Xcel Energy turned over operational control of its transmission system to the MISO in January 2002.

Some states had begun to allow retail customers to choose their electricity supplier, and many other states were 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 indefinite delays in most industry restructuring.

Xcel Energy cannot predict the outcome of restructuring proceedings in the electric utility jurisdictions it serves at this time. The resolution of these matters may have a significant impact on the financial position, results of operations and cash flows of Xcel Energy.

California Power Market — NRG operates in the wholesale power market in California. See Note 18 to the Consolidated Financial Statements for a description of lawsuits against NRG and other power producers and marketers involving the California electricity markets. Xcel Energy and NRG have fully reserved for its uncollected receivables related to the California power market.

Critical Accounting Policies — Preparation of Consolidated Financial Statements and related disclosures in compliance with generally accepted accounting principles (GAAP) requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the Consolidated Financial Statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the Consolidated Financial Statements and related disclosures, even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies that are most significant to the portrayal of Xcel Energy’s financial condition and results, and that require management’s most difficult, subjective or complex judgments. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.

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Accounting Policy   Judgments/Uncertainties Affecting Application   See Additional Discussion At

 
 
Asset Valuation     Regional economic conditions   Management’s Discussion and Analysis:
• NRG
• Seren
• Argentina
    affecting asset operation, market prices
and related cash flows
Foreign currency valuation changes
  Results of Operations
Management’s Discussion and Analysis:Factors Affecting Results of Operations
   

  Regulatory and political environments
and requirements
Levels of future market penetration
and customer growth
 
  Impacts of NRG Financial Difficulties
Impact of Other Nonregulated Investments
            Notes to Consolidated Financial Statements
              Notes 2, 3 and 18
NRG Financial Restructuring     Terms negotiated to settle NRG’s
obligations to its creditors
  Management’s Discussion and Analysis:
Liquidity and Capital Resources
   


  Ownership interest in and control of
NRG, and related ability to continue
consolidating NRG as a subsidiary
 
  NRG Financial Issues
Xcel Energy Impacts
      Impacts of court decisions in future   Notes to Consolidated Financial Statements
   

  bankruptcy proceedings, including any
obligations of Xcel Energy
    Notes 4 and 18
Income Tax Accruals     Application of tax statutes and
regulations to transactions
  Management’s Discussion and Analysis:
Factors Affecting Results of Operations
   

  Anticipated future decisions of tax
authorities
    Tax Matters
      Ability of tax authority   Notes to Consolidated Financial Statements
   

  decisions/positions to withstand legal
challenges and appeals
Ability to realize tax benefits through
carrybacks to prior periods or
carryovers to future periods
    Notes 1, 11 and 18
Benefit Plan Accounting     Future rate of return on pension and
other plan assets, including impacts of
  Management’s Discussion and Analysis:
Factors Affecting Results of Operations
        any changes to investment portfolio     Pension Plan Costs and Assumptions
        composition   Notes to Consolidated Financial Statements
   

  Interest rates used in valuing benefit
obligation
Actuarial period selected to recognize
deferred investment gains and losses
    Notes 1 and 13
Regulatory Mechanisms and Cost Recovery     External regulator decisions,
requirements and regulatory
environment
  Management’s Discussion and Analysis:
Factors Affecting Results of Operations
      Anticipated future regulatory decisions
and their impact
    Utility Industry Changes and Restructuring
      Impact of deregulation and competition
on ratemaking process and ability to
 
Notes to Consolidated Financial Statements
      recover costs   Notes 1, 18 and 20
Environmental Issues  
  Approved methods for cleanup
Responsible party determination
  Management’s Discussion and Analysis:Factors Affecting Results of Operations
      Governmental regulations and
standards
    Environmental Matters

      Results of ongoing research and
development regarding environmental
impacts
  Notes to Consolidated Financial Statements
Notes 1 and 18
Uncollectible Receivables     Economic conditions affecting
customers, suppliers and market prices
  Management’s Discussion and Analysis:
Factors Affecting Results of Operations
   
  Regulatory environment and impact of
cost recovery constraints on customer
    California Power Market
        financial condition
  Notes to Consolidated Financial Statements
      Outcome of litigation and regulatory
proceedings
    Notes 1 and 18
Nuclear Plant     Costs of future decommissioning   Notes to Consolidated Financial Statements
Decommissioning and Cost Recovery  




  Availability of facilities for waste disposal
Approved methods for waste disposal
Useful lives of nuclear power plants
Future recovery of plant investment
and decommissioning costs
    Notes 1, 18 and 19

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Pension Plan Costs and Assumptions — Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future, and the interest rate used to discount future pension benefit payments to a present value obligation for financial reporting. In addition, the actuarial calculation uses an asset smoothing methodology to reduce volatility of varying investment performance over time. Note 13 to the Consolidated Financial Statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying financial statements.

Pension costs have been increasing in recent years, and are expected to increase further over the next several years, due to lower than expected investment returns experienced and decreases in interest rates used to discount benefit obligations. Investment returns in 2000 and 2001 were below the assumed level of 9.5 percent, and interest rates have declined from the 7.5 percent to 8 percent levels used in 1999 and 2000 cost determinations to 7.25 percent used in 2002. Xcel Energy continually reviews its pension assumptions, and in 2003 expects to change the investment return assumption to 9.25 percent and the discount rate assumption to 6.75 percent.

Xcel Energy bases its investment return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. These include equity investments, such as corporate common stocks; fixed-income investments, such as corporate bonds and U.S. Treasury securities and non-traditional investments, such as timber or real estate partnerships. In reaching a return assumption, Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts in the marketplace. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 12.6 percent, in excess of the current assumption level. The pension cost determinations assume the continued current mix of investment types over the long-term. The target and 2002 mix of assets among these portfolio components is discussed in Note 13 to the Consolidated Financial Statements. The Xcel Energy portfolio is heavily weighted toward equity securities, and includes non-traditional investments that can provide a higher than average return. However, as is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year. Xcel Energy lowered the 2003 pension investment return assumptions to reflect changing expectations of investment experts in the marketplace.

The investment gains or losses resulting from the difference between the expected pension returns assumed on smoothed or “market-related” asset levels and actual returns earned is deferred in the year the difference arises and recognized over the subsequent five-year period. This gain or loss recognition occurs by using a five-year moving-average value of pension assets to measure expected asset returns in the cost determination process, and by amortizing deferred investment gains or losses over the subsequent five-year period. Based on the use of average market-related asset values, and considering the expected recognition of past investment gains and losses over the next five years, achieving the assumed rate of asset return of 9.25 percent in each future year and holding other assumptions constant, we currently project that the pension costs recognized by Xcel Energy for financial reporting purposes will increase from a credit, or negative expense, of $84 million in 2002 to a credit of $45 million in 2003, a credit of $20 million in 2004, and a net expense of $20 million in 2005. Pension costs are currently a credit due to the recognized investment asset returns exceeding the other pension cost components, such as benefits earned for current service and interest costs for the effects of the passage of time on discounted obligations.

Xcel Energy bases its discount rate assumption on benchmark interest rates quoted by an established credit rating agency, Moody’s Investors Service (Moody’s), and have consistently benchmarked the interest rate used to derive the discount rate to the movements in long-term corporate bond indices for bonds rated AAA through BAA by Moody's, which have a period to maturity comparable to our projected benefit obligations. At Dec. 31, 2002, the annualized Moody’s Aa index rate, roughly in the middle of the AAA and BAA range, was 6.63 percent, which when rounded to the nearest quarter-percent rate, as is our policy, resulted in our 6.75 percent pension discount rate at year-end 2002. This rate was used to value the actuarial benefit obligations at that date, and will be used in 2003 pension cost determinations.

If Xcel Energy were to use alternative assumptions for pension cost determinations, a 1 percent change would result in the following impacts on the estimated pension costs recognized by Xcel Energy for financial reporting purposes:

  a 1 percent higher rate of return, 10.25 percent, would decrease 2003 pension costs by $22 million
 
  a 1 percent lower rate of return, 8.25 percent, would increase 2003 pension costs by $22 million
 
  a 1 percent higher discount rate, 7.75 percent, would decrease 2003 pension costs by $8 million
 
  a 1 percent lower discount rate, 5.75 percent, would increase 2003 pension costs by $12 million

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Alternative assumptions would also change the expected future cash funding requirements for the pension plans. Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in recent years for Xcel Energy’s pension plans, and do not require funding in 2003. Assuming future asset return levels equal the actuarial assumption of 9.25 percent for the years 2003-2005, then under current funding regulations we project that no cash funding would be required for 2004, $35 million in funding would be required for 2005, and $54 million in funding would be required for 2006. Actual performance can affect these funding requirements significantly. If the actual return level is 0 percent in 2003 and 2004, which assumes a continued downturn in the financial markets, and 9.25 percent in 2005 then the 2004 cash-funding requirement would still be zero. However, the 2005 funding requirement would increase to $60 million, and 2006 funding required would be $70 million. Current funding regulations are under legislative review in 2003, and if not retained in their current form, could change these funding requirements materially.

Regulation — Xcel Energy is a registered holding company under the PUHCA. As a result, Xcel Energy, its utility subsidiaries and certain of its nonutility subsidiaries are subject to extensive regulation by the SEC under the PUHCA 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 of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. See further discussion of financing restrictions under Liquidity and Capital Resources.

The electric and natural gas rates charged to customers of Xcel Energy’s utility subsidiaries are approved by the FERC and the regulatory commissions in the states in which they operate. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy requests changes in rates for utility services through filings with the governing commissions. Because comprehensive rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy’s financial results. In addition to changes in operating costs, other factors affecting rate filings are sales growth, conservation and demand-side management efforts and the cost of capital.

Most of the retail rate schedules for Xcel Energy’s utility subsidiaries provide for periodic adjustments to billings and revenues to allow for recovery of changes in the cost of fuel for electric generation, purchased energy, purchased natural gas and, in Minnesota and Colorado, conservation and energy management program costs. In Minnesota and Colorado, changes in electric capacity costs are not recovered through these rate adjustment mechanisms. For Wisconsin electric operations, where automatic cost-of-energy adjustment clauses are not allowed, the biennial retail rate review process and an interim fuel-cost hearing process provide the opportunity for rate recovery of changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment clause. In Colorado, PSCo has an ICA mechanism that allows for an equal sharing among customers and shareholders of certain fuel and energy costs and certain gains and losses on trading margins.

Regulated public utilities are allowed to record as regulatory assets certain costs that are expected to be recovered from customers in future periods and to record as regulatory liabilities certain income items that are expected to be refunded to customers in future periods. In contrast, nonregulated enterprises would expense these costs and recognize the income in the current period. If restructuring or other changes in the regulatory environment occur, Xcel Energy may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material adverse effect on Xcel Energy’s results of operations in the period the write-off is recorded.

At Dec. 31, 2002, Xcel Energy reported on its balance sheet regulatory assets of approximately $404 million and regulatory liabilities of approximately $297 million that would be recognized in the statement of operations in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain stranded costs not recoverable under market pricing. Xcel Energy currently does not expect to write off any stranded costs unless market price levels change or cost levels increase above market price levels. See Notes 1 and 20 to the Consolidated Financial Statements for further discussion of regulatory deferrals.

Merger Rate Agreements — As part of the merger approval process, Xcel Energy agreed to reduce its rates in several jurisdictions. The discussion below summarizes the rate reductions in Colorado, Minnesota, Texas and New Mexico.

As part of the merger approval process in Colorado, PSCo agreed to:

  reduce its retail electric rates by an annual rate of $11 million for the period of August 2000 through July 2002;
 
  file a combined electric and natural gas rate case in 2002, with new rates effective January 2003;
 
  cap merger costs associated with the electric operations at $30 million and amortize the merger costs for ratemaking purposes through 2002;
 
  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 2001 actual costs;

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  continue the electric performance-based regulatory plan (PBRP) and the electric quality service plan (QSP) currently in effect through 2006, with modifications to cap electric earnings at a 10.5-percent return on equity for 2002, to reflect no earnings sharing in 2003 since new base rates would have recently been established, and to increase potential bill credits if quality standards are not met; and
 
  develop a QSP for the natural gas operations to be effective for calendar years 2002 through 2007.

As part of the 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.

As part of the 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 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 nonfuel operating and maintenance savings equally among retail customers and shareholders;
 
  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.

PSCo Performance-Based Regulatory Plan — The Colorado Public Utilities Commission (CPUC) established an electric 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:

    all earnings above 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 set in the 2002 rate case for 2004 through 2006

  an electric 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 kilowatt-hour generated or purchased. According to the terms of the merger rate agreement in Colorado, the annual baseline cost will be reset in 2002, based on a 2001 test year. Pursuant to a stipulation approved by the CPUC, the ICA remains in effect through March 31, 2005, to recover allowed ICA costs from 2001 and 2002. The recovery of fuel and purchased energy expense beginning Jan. 1, 2003, will be decided in the PSCo 2002 general rate case. In the interim period until the conclusion of the general rate case, 2003 fuel and purchased energy expense is recovered through the interim adjustment clause (IAC).

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. PSCo has estimated no customer refund obligation for 2001 under the earnings test. The 2001 earnings test filing has not been approved. A hearing is scheduled for May 2003.

PSCo 2002 General Rate Case — In May 2002, PSCo filed a combined general retail electric, natural 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 qualifying facilities capacity cost adjustment (QFCCA), new depreciation rates and recovery of additional plant investment. PSCo 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

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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 natural 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. PSCo filed a joint motion on March 14, 2003 extending the filing date of the settlement agreement until April 1, 2003. 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.

Tax Matters — As discussed further in Note 18, the Internal Revenue Service (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, Xcel Energy 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 Xcel Energy’s position that the tax law does not support the IRS determination. Although the ultimate resolution of this matter is uncertain, management continues to believe it will successfully resolve this matter without a material adverse impact on Xcel Energy’s results of operations. However, defense of PSCo’s position may require significant cash outlays on a temporary basis, if refund litigation is pursued in United States District Court.

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. If COLI interest expense deductions were no longer available, annual earnings for 2003 would be reduced by an estimated $33 million, after tax, prospectively, which represents 8 cents per share using 2003 share levels.

Environmental Matters — Our environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and wastes, remediation of contaminated sites and monitoring of discharges to the environment. A trend of greater environmental awareness and increasingly stringent regulation has caused, and may continue to cause, slightly higher operating expenses and capital expenditures for environmental compliance.

In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to our operating expenses for environmental monitoring and disposal of hazardous materials and wastes were approximately:

  $149 million in 2002
 
  $146 million in 2001
 
  $144 million in 2000

We expect to expense an average of approximately $177 million per year from 2003 through 2007 for similar costs. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain.

Capital expenditures on environmental improvements at our regulated facilities, which include the cost of constructing spent nuclear fuel storage casks, were approximately:

  $108 million in 2002
 
  $136 million in 2001
 
  $57 million in 2000

Our regulated utilities expect to incur approximately $44 million in capital expenditures for compliance with environmental regulations in 2003 and approximately $948 million during the period from 2003 through 2007. Most of the costs are related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area. See Notes 18 and 19 to the Consolidated Financial Statements for further discussion of our environmental contingencies.

NRG expects to incur as much as $145 million in capital expenditures over the next five years to address conditions that existed when it acquired facilities, and to comply with new regulations.

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Impact of Other Nonregulated Investments — Xcel Energy’s investments in nonregulated operations have had a significant impact on its results of operations. Xcel Energy does not expect to continue investing in nonregulated domestic and international power production projects through NRG, but may continue investing in natural gas marketing and trading through e prime and construction projects through Utility Engineering. Xcel Energy’s nonregulated businesses may carry a higher level of risk than its traditional utility businesses due to a number of factors, including:

  competition, operating risks, dependence on certain suppliers and customers, and domestic and foreign environmental and energy regulations;
 
  partnership and government actions and foreign government, political, economic and currency risks; and
 
  development risks, including uncertainties prior to final legal closing.

Xcel Energy’s earnings from nonregulated subsidiaries, other than NRG, also include investments in international projects, primarily in Argentina, through Xcel Energy International, and broadband communications systems through Seren. Management currently intends to hold and operate these investments, but is evaluating their strategic fit in Xcel Energy’s business portfolio. As of Dec. 31, 2002, Xcel Energy’s investment in Seren was approximately $255 million. Seren had capitalized $290 million for plant in service and had incurred another $21 million for construction work in progress for these systems at Dec. 31, 2002. Xcel Energy International’s gross investment in Argentina, excluding unrealized currency translation losses of approximately $62 million, was $112 million at Dec. 31, 2002. Given the political and economic climate in Argentina, Xcel Energy continues to closely monitor the investment for asset impairment. Currently, management believes that no impairment exists in addition to what was recognized in 2002, as previously discussed.

Some of Xcel Energy’s nonregulated subsidiaries have project investments, as listed in Note 14 to the Consolidated Financial Statements, consisting of minority interests, which may limit the financial risk, but also limit the ability to control the development or operation of the projects. In addition, significant expenses may be incurred for projects pursued by Xcel Energy’s subsidiaries that do not materialize. The aggregate effect of these factors creates the potential for volatility in the nonregulated component of Xcel Energy’s earnings. Accordingly, the historical operating results of Xcel Energy’s nonregulated businesses may not necessarily be indicative of future operating results.

Inflation — Inflation at its current level is not expected to materially affect Xcel Energy’s prices or returns to shareholders. Since late 2001, the Argentine peso has been significantly devalued due to the inflationary Argentine economy. Xcel Energy will continue to experience related currency translation adjustments through Xcel Energy International.

Pending Accounting Changes

SFAS No. 143 — In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” This statement will require Xcel Energy 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 SFAS No. 71 — “Accounting for the Effects of Certain Types of Regulation” are met.

Xcel Energy 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, Xcel Energy 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.

Xcel Energy 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.

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Xcel Energy has completed a detailed assessment of the specific applicability and implications of SFAS No. 143 for obligations other than nuclear decommissioning. Other assets that may have potential asset retirement obligations include ash ponds, any generating plant with a Part 30 license and electric and natural gas transmission and distribution assets on property under easement agreements. Easements are generally perpetual and require retirement action only upon abandonment or cessation of use of the property for the specified purpose. The liability is not estimable because Xcel Energy intends to utilize these properties indefinitely. The asset retirement obligations for the ash ponds and generating plants cannot be reasonably estimated due to an indeterminate life for the assets associated with the ponds and uncertain retirement dates for the generating plants. Since the time period for retirement is unknown, no liability would be recorded. When a retirement date is certain, a liability will be recorded.

SFAS No. 143 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 GAAP 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 over time, Xcel Energy has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, Xcel Energy has an estimated regulatory liability accrued in accumulated depreciation for future removal costs of the following amounts at Dec. 31, 2002:

(Millions of Dollars)

         
NSP-Minnesota
  $ 304  
NSP-Wisconsin
    70  
PSCo
    329  
SPS
    97  
Cheyenne
    9  
 
   
 
Total Xcel Energy
  $ 809  
 
   
 

SFAS No. 145 — In April 2002, the FASB issued SFAS No. 145 — “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” which supercedes previous guidance for the reporting of gains and losses from extinguishment of debt and accounting for leases, among other things. Adoption of SFAS No. 145 may affect the recognition of impacts from NRG’s financial improvement and restructuring plan, if existing debt agreements are ultimately renegotiated while NRG is still a consolidated subsidiary of Xcel Energy. Other impacts of SFAS No. 145 are not expected to be material to Xcel Energy.

SFAS No. 146 — In June 2002, the FASB issued SFAS No. 146 — “Accounting for Exit or Disposal Activities,” addressing recognition, measurement and reporting of costs associated with exit and disposal activities, including restructuring activities. SFAS No. 146 may have an impact on the timing of recognition of costs related to the implementation of the NRG financial improvement and restructuring plan; however, such impact is not expected to be material.

SFAS No. 148 — In December 2002, the FASB issued SFAS No. 148 — “Accounting for Stock-Based Compensation — Transition and Disclosure,” amending FASB Statement No. 123 to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation, and requiring disclosure in both annual and interim Consolidated Financial Statements about the method used and the effect of the method used on results. Xcel Energy continues to account for its stock-based compensation plans under Accounting Principles Board (APB) Opinion No. 25 — “Accounting for Stock Issued to Employees” and does not plan at this time to adopt the voluntary provisions of SFAS No. 148.

Emerging Issues Tax Force (EITF) Nos. 02-03 and 98-10 — See Note 1 to the Consolidated Financial Statements regarding reporting changes made in 2002 for the presentation of trading results and pending changes related to accounting for the impacts of trading operations in 2003.

FASB Interpretation No. 45 (FIN No. 45) — In November 2002, the FASB issued FIN No. 45 — “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”. The initial recognition and measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after Dec. 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after Dec. 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

FASB Interpretation No. 46 (FIN No. 46) — In January 2003, the FASB issued FIN No. 46 requiring an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling financial interest. Historically, that requirement has been applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated financial statements do not include the consolidations of variable interest entities with which it has similar relationships but no majority voting interest. Under FIN No. 46, the voting interest approach is not effective in identifying controlling financial interest. As a result, Xcel Energy expects that it will have to consolidate its affordable housing investments made through Eloigne, which currently are accounted for under the equity method.

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As of Dec. 31, 2002, the assets of these entities were approximately $155 million and long-term liabilities were approximately $87 million. Currently, investments of $62 million are reflected as a component of investments in unconsolidated affiliates in the Dec. 31, 2002, Consolidated Balance Sheet. FIN No. 46 requires that for entities to be consolidated, the entities’ assets be initially recorded at their carrying amounts at the date the new requirement first applies. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value as of the first date the new requirements apply. Any difference between the net consolidated amounts added to the Xcel Energy’s balance sheet and the amount of any previously recognized interest in the newly consolidated entity should be recognized in earnings as the cumulative effect adjustment of an accounting change. Had Xcel Energy adopted FIN No. 46 requirements early in 2002, there would have been no material impact to net income. Xcel Energy plans to adopt FIN No. 46 when required in the third quarter of 2003.

DERIVATIVES, RISK MANAGEMENT AND MARKET RISK

Business and Operational Risk Xcel Energy and its subsidiaries are exposed to commodity price risk in their generation, retail distribution and energy trading operations. In certain jurisdictions, purchased energy expenses and natural gas costs are recovered on a dollar-for-dollar basis. However, in other jurisdictions, Xcel Energy and its subsidiaries have limited exposure to market price risk for the purchase and sale of electric energy and natural gas. In such jurisdictions, electric energy and natural gas expenses are recovered based on fixed price limits or under established sharing mechanisms.

Xcel Energy manages 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 instruments. Xcel Energy’s risk management policy allows the company 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 manage market price risk where the rate regulation jurisdiction does not already provide for dollar-for-dollar recovery. One exception to this policy exists in which we use various physical contracts and derivative instruments to reduce the cost of natural gas and electricity we provide to our retail customers even though the regulatory jurisdiction may provide dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments and physical contracts is done consistently with the local jurisdictional cost recovery mechanism.

Xcel Energy and its subsidiaries are exposed to market price risk for the sale of electric energy and the purchase of fuel resources, including coal, natural gas and fuel oil used to generate the electric energy within its nonregulated operations. Xcel Energy manages this market price risk by entering into firm power sales agreements for approximately 55 to 75 percent of its electric capacity and energy from each generation facility, using contracts with terms ranging from one to 25 years. In addition, we manage the market price risk covering the fuel resource requirements to provide the electric energy by entering into purchase commitments and derivative instruments for coal, natural gas and fuel oil as needed to meet fixed-priced electric energy requirements. Xcel Energy’s risk management policy allows the company to manage market price risks, and provides guidelines for the level of price risk exposure that is acceptable within the company’s operations.

Xcel Energy is exposed to market price risk for the sale of electric energy and the purchase of fuel resources used to generate the electric energy from the company’s equity method investments that own electric operations. Xcel Energy manages this market price risk through involvement with the management committee or board of directors of each of these ventures. Xcel Energy’s risk management policy does not cover the activities conducted by the ventures. However, other policies are adopted by the ventures as necessary and mandated by the equity owners.

Interest Rate Risk — Xcel Energy and its subsidiaries are exposed to fluctuations in interest rates when entering 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 the volatility of cash flows for interest 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 company to reduce interest rate exposure from variable rate debt obligations.

At Dec. 31, 2002 and 2001, a 100 basis point change in the benchmark rate on Xcel Energy’s variable debt would impact net income by approximately $52.2 million and $29.9 million, respectively. See Note 16 to the Consolidated Financial Statements for a discussion of Xcel Energy and its subsidiaries’ interest rate swaps.

Currency Exchange Risk — Xcel Energy and its subsidiaries have certain investments in foreign countries, creating exposure to foreign currency exchange risk. The foreign currency exchange risk includes the risk relative to the recovery of our net investment in a project, as well as the risk relative to the earnings and cash flows generated from such operations. Xcel Energy manages exposure to changes in foreign currency by entering into derivative

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instruments as determined by management. Xcel Energy’s risk management policy provides for this risk management activity.

As discussed in Note 21 to the Consolidated Financial Statements, Xcel Energy has substantial investments in foreign projects, through NRG and other subsidiaries, creating exposure to currency translation risk. Cumulative translation adjustments, included in the Consolidated Statement of Stockholders’ Equity as Accumulated Other Comprehensive Income, experienced to date have been material and may continue to occur at levels significant to the company’s financial position. As of Dec. 31, 2002, NRG had two foreign currency exchange contracts with notional amounts of $3.0 million. If the contracts had been discontinued on Dec. 31, 2002, NRG would have owed the counterparties approximately $0.3 million.

Trading Risk — Xcel Energy and its subsidiaries conduct various trading operations and power marketing activities, including the purchase and sale of electric capacity and energy and natural gas. The trading operations are conducted both in the United States and Europe with primary focus on specific market regions where trading knowledge and experience have been obtained. Xcel Energy’s risk management policy allows management to conduct the trading activity within approved guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not involved in the trading operations.

The fair value of Xcel Energy’s trading contracts as of Dec. 31, 2002, is as follows:

         
(Millions of dollars)   Total Fair Value

 
Fair value of trading contracts outstanding at Jan. 1, 2002
  $ 90.1  
Contracts realized or settled during 2002
    (139.5 )
Fair value of trading contract additions and changes during the year
    87.8  
 
   
 
Fair value of contracts outstanding at Dec. 31, 2002*
  $ 38.4  
 
   
 

*     Amounts do not include the impact of ratepayer sharing in Colorado.

The future maturities of Xcel Energy’s trading contracts are as follows:

                                         
Source of Fair Value   Maturity Less than                   Maturity Greater        
(Millions of dollars)   1 Year   Maturity 1 to 3 years   Maturity 4 to 5 years   than 5 years   Total Fair Value

 
 
 
 
 
Prices actively quoted
  $ 12.7     $ (7.1 )   $     $ (1.9 )   $ 3.7  
Prices based on models and other valuation methods (including prices quoted from external sources)
    61.7       52.6       (23.0 )     (56.6 )     34.7  

Xcel Energy’s trading operations and power marketing activities 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 know 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:

(Millions of Dollars)

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

 
 
 
 
Electric Commodity Trading
    0.29       0.62       3.39       0.01  
Natural Gas Commodity Trading
    0.11       0.35       1.09       0.09  
Natural Gas Retail Marketing
    0.54       0.47       0.92       0.32  
NRG Power Marketing (a)
    118.60       76.20       124.40       42.00  


(a)   NRG VaR is an undiversified VaR.

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

(Millions of Dollars)

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

 
 
 
 
Electric Commodity Trading
    0.52       1.71       7.37       0.16  
Natural Gas Commodity Trading
    0.16       0.15       0.52       0.01  
Natural Gas Retail Marketing
    0.69       0.39       0.94       0.13  
NRG Power Marketing
    71.70       78.80       126.60       58.60  

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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 and its subsidiaries are exposed to credit risk in the company’s 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 continues to expand its natural gas and power marketing and trading activities, exposure to credit risk and counterparty default may increase. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

                         
(Millions of dollars)   2002   2001   2000

 
 
 
Net cash provided by operating activities
$ 1,715   $ 1,584     $ 1,408  

Cash provided by operating activities increased during 2002, compared with 2001, primarily due to NRG’s efforts to conserve cash by deferring the payment of interest payments and managing its cash flows more closely. NRG’s accrued interest costs rose by nearly $200 million in 2002 compared to year-end 2001 levels. In addition, regulated utility operating cash flows increased in 2002 due to lower 2002 receivables and unbilled revenues, reflecting collections of higher year-end 2001 amounts. Cash provided by operating activities increased during 2001, compared with 2000, primarily due to the higher net income, depreciation and improved working capital.

                         
(Millions of dollars)   2002   2001   2000

 
 
 
Net cash used in investing activities
$ (2,718 ) $ (5,168 )   $ (3,347 )

Cash used in investing activities decreased during 2002, compared with 2001, primarily due to lower levels of nonregulated capital expenditures as a result of NRG terminating its acquisition program due to its financial difficulties. Such nonregulated expenditures decreased $2.8 billion in 2002 due mainly to NRG asset acquisitions in 2001 that did not recur in 2002. Cash used in investing activities increased during 2001, compared with 2000, primarily due to increased levels of nonregulated capital expenditures and asset acquisitions, primarily at NRG. The increase was partially offset by Xcel Energy’s sale of most of its investment in Yorkshire Power.

                         
(Millions of dollars)   2002   2001   2000

 
 
 
Net cash provided by financing activities
$ 1,580   $ 3,713     $ 2,016  

Cash provided by financing activities decreased during 2002, compared with 2001, primarily due to lower NRG capital requirements and constraints on NRG’s ability to access the capital market due to its financial difficulties, as discussed previously. NRG’s cash provided from financing activities declined by $2.7 billion in 2002, compared with 2001. Cash provided by financing activities increased during 2001, compared with 2000, primarily due to increased short-term borrowings and net long-term debt issuances, mainly to fund NRG acquisitions.

See discussion of trends, commitments and uncertainties with the potential for future impact on cash flow and liquidity under Capital Sources.

Capital Requirements

Utility Capital Expenditures, Nonregulated Investments and Long-term Debt Obligations — The estimated cost of the capital expenditure programs of Xcel Energy and its subsidiaries, excluding NRG, and other capital requirements for the years 2003, 2004 and 2005 are shown in the table below.

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(Millions of dollars)   2003   2004   2005

 
 
 
Electric utility
  $ 700     $ 840     $ 950  
Natural Gas utility
    110       110       110  
Common utility
    90       50       40  
 
   
     
     
 
 
Total utility
    900       1,000       1,100  
Other nonregulated (excluding NRG)
    32       23       15  
 
   
     
     
 
 
Total capital expenditures
    932       1,023       1,115  
Sinking funds and debt maturities
    563       169       223  
 
   
     
     
 
Total capital requirements
  $ 1,495     $ 1,192     $ 1,338  
 
   
     
     
 

The capital expenditure forecast for 2004 includes new steam generators at the Prairie Island nuclear plant. These expenditures will not occur unless the Minnesota Legislature grants additional spent fuel storage at Prairie Island during 2003. The capital expenditure forecast also includes the early stages of the costs related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis and St. Paul metropolitan area. This project is expected to cost approximately $1.1 billion with major construction starting in 2005 and finishing in 2009.

The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of merger, acquisition and divestiture opportunities to support corporate strategies, address restructuring requirements and comply with future requirements to install emission-control equipment may impact actual capital requirements. For more information, see Notes 4 and 18 to the Consolidated Financial Statements.

Xcel Energy’s investment in exempt wholesale generators and foreign utility companies, which includes NRG and other Xcel Energy subsidiaries, is currently limited to 100 percent of consolidated retained earnings, as a result of the PUHCA restrictions. At Dec. 31, 2002, such investments exceeded consolidated retained earnings.

NRG Energy is required to provide financial guarantees of up to approximately $8 million, for closure and ongoing monitoring costs of some sites to which it sends coal ash and other waste, by April 30, 2003.

NRG Capital Expenditures — Management expects NRG’s capital expenditures,which include refurbishments and environmental compliance, to total approximately $475 million to $525 million in the years 2003 through 2007. NRG anticipates funding its ongoing capital requirements through committed debt facilities, operating cash flows and existing cash. NRG’s capital expenditure program is subject to continuing review and modification. The timing and actual amount of expenditures may differ significantly based upon plant operating history, unexpected plant outages, changes in the regulatory environment and the availability of cash. The pending financial restructuring or bankruptcy filings of NRG may affect the timing and magnitude of capital resources available to NRG and, accordingly, the level of capital expenditures NRG can fund.

Contractual Obligations and Other Commitments — Xcel Energy has a variety of contractual obligations and other commercial commitments that represent prospective requirements in addition to its capital expenditure programs. The following is a summarized table of contractual obligations. See additional discussion in the Consolidated Statements of Capitalization and Notes 5, 6, 7, 16 and 18 to the Consolidated Financial Statements.

                                         
            Payments Due by Period
Contractual          
Obligations                                        
(Thousands of dollars)   Total   Less than 1 year   1-3 years   4-5 years   After 5 years

 
 
 
 
 
Long-term debt
  $ 14,311,689     $ 7,756,903     $ 547,796     $ 1,137,934     $ 4,869,056  
Capital lease
obligations
    688,421       34,422       67,771       66,386       519,842  
Operating leases(a)
    386,215       66,155       125,031       108,534       86,495  
Unconditional
purchase obligations
    11,240,364       1,317,293       2,214,974       1,817,770       5,890,327  
Other long-term
obligations
    699,248       42,597       64,517       34,594       557,540  
Short-term debt
    1,541,963       1,541,963                    
     
     
     
     
     
 
Total contractual
cash obligations
  $ 28,867,900     $ 10,759,333     $ 3,020,089     $ 3,165,218     $ 11,923,260  
     
     
     
     
     
 

(a)  Under some leases, we would have to sell or purchase the property that we lease if we chose to terminate before the scheduled lease expiration date. Most of our railcar, vehicle and equipment, and aircraft leases have these terms. We would then own the equipment and could continue to use it in the normal course of business or sell the equipment. At Dec. 31, 2002, the amount that we would have to pay if we chose to terminate these leases was approximately $160 million.

Common Stock Dividends — Future dividend levels will be dependent upon the statutory limitations discussed below, as well as Xcel Energy’s results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy board of directors.

Under the PUHCA, unless there is an order from the SEC, a holding company or any subsidiary may only declare and pay dividends out of retained earnings. Due to 2002 losses incurred by NRG, retained earnings of Xcel Energy were a deficit of $101 million at Dec. 31, 2002. Xcel Energy did not declare a dividend on its common stock during the first quarter of 2003. Xcel Energy has requested authorization from the SEC to pay

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dividends out of paid-in capital up to $260 million until Sept. 30, 2003. Xcel Energy did not declare a dividend on its common stock during the first quarter of 2003. It is not known when or if the SEC will act on this request. As explained below, Xcel Energy has reached a preliminary settlement agreement with the various NRG creditors. Also, Xcel Energy could be required to cease including NRG as a consolidated subsidiary for financial reporting purposes, if NRG were to seek protection under the bankruptcy laws and Xcel Energy ceased to have control over NRG. In the event the tentative settlement is effectuated and Xcel Energy is required to cease including NRG as a consolidated subsidiary in its financial statements, the financial impact of these events are expected to positively impact retained earnings and may be sufficient to eliminate the negative retained earnings balance, absent additional charges at NRG. Xcel Energy cannot predict the precise financial impact of these items at this time. For this reason, Xcel Energy will continue seeking authorization from the SEC so it is able to pay dividends notwithstanding negative retained earnings. Xcel Energy intends to make every effort to pay the full common stock dividend of 75 cents per share during 2003.

The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only, i.e., not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (1) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, our capitalization ratio at Dec. 31, 2002, was 85 percent. Therefore, the restrictions do not place any effective limit on our ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of our common stock.

Capital Sources

Xcel Energy expects to meet future financing requirements by periodically issuing long-term debt, short-term debt, common stock and preferred securities to maintain desired capitalization ratios. As a result of its registration as a holding company under the PUHCA, Xcel Energy is required to maintain a common equity ratio of 30 percent or higher in its consolidated capital structure.

On Nov. 7, 2002, the SEC issued an order authorizing Xcel Energy to engage in certain financing transactions through March 31, 2003, so long as its common equity ratio, as reported in its most recent Form 10-K, or Form 10-Q and as adjusted for pending subsequent items that affect capitalization, was at least 24 percent of its total capitalization. Financings of Xcel Energy authorized by the SEC included the issuance of debt, including convertible debt, to refinance or replace Xcel Energy’s $400-million credit facility that expired on Nov. 8, 2002, issuance of $450 million of common stock, less any amounts issued as part of the refinancing of the $400-million credit facility, and the renewal of guarantees for various trading obligations of NRG’s power marketing subsidiary. The SEC reserved authorizing additional securities issuances by Xcel Energy through June 30, 2003, while its common equity ratio is below 30 percent.

For this purpose, common equity, including minority interest, at Dec. 31, 2002, was 23 percent of total capitalization. As a result, Xcel Energy may experience constraints on available capital sources that may be affected by factors including earnings levels, project acquisitions and the financing actions of our subsidiaries. In the event NRG were to seek protection under bankruptcy laws and Xcel Energy ceased to have control over NRG, NRG would no longer be a consolidated subsidiary of Xcel Energy for financial reporting purposes and Xcel Energy’s common equity ratio under the SEC’s method of calculation would exceed 30 percent.

In December 2002, Xcel Energy filed a request for additional financing authorization with the SEC. Xcel Energy requested an increase from $2.0 billion to $2.5 billion in the aggregate amount of securities that it may issue during the period through Sept. 30, 2003. In addition, the request proposed that common equity will be at least 30 percent of total consolidated capitalization, provided that in any event that the 30-percent common equity requirement is not met, Xcel Energy may issue common stock. The notice period expired with no comments. SEC action on the request is pending. As a result, Xcel Energy at the present time cannot finance, either on a short-term or long-term basis, without SEC approval unless its common equity is at least 30 percent of total capitalization.

With approval of the request currently pending before the SEC, further described below, management believes it will have adequate authority under SEC orders and regulations to conduct business as proposed during 2003 and will seek additional authorization when necessary.

Short-Term Funding Sources — Historically, Xcel Energy has used a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on financing needs for utility construction expenditures and nonregulated project investments. Another significant short-term funding need is the dividend payment requirement, as discussed previously in Common Stock Dividends.

Operating cash flow as a source of short-term funding is reasonably likely to be affected by such operating factors as weather, regulatory requirements, including rate recovery of costs, environmental regulation compliance and industry deregulation, changes in the trends for energy prices and supply, and operational uncertainties that are difficult to predict. See further discussion of such factors under Statement of Operations Analysis and Factors Affecting Results of Operations.

Short-term borrowing as a source of funding is affected by regulatory actions and access to reasonably priced capital markets. This varies based on financial performance and existing debt levels. These factors are evaluated by credit rating agencies that review Xcel Energy and its subsidiary operations on an ongoing basis. NRG’s credit situation has affected Xcel Energy’s credit ratings and access to short-term funding. As a result of a decline in its credit ratings, Xcel Energy has been unable to utilize the commercial paper market to satisfy any short-term funding needs. For additional information on Xcel Energy’s short-term borrowing arrangements, see Note 5 to the Consolidated Financial Statements.

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Access to reasonably priced capital markets is also dependent in part on credit agency reviews. In the past year, our credit ratings and those of our subsidiaries have been adversely affected by NRG’s credit contingencies, despite what management believes is a reasonable separation of NRG’s operations and credit risk from our utility operations and corporate financing activities. These ratings reflect the views of Moody’s and Standard & Poor’s. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating company. As of Feb. 10, 2003, the following represents the credit ratings assigned to various Xcel Energy companies:

             
Company   Credit Type   Moody’s*   Standard & Poor’s

 
 
 
Xcel Energy   Senior Unsecured Debt   Baa3   BBB-
Xcel Energy   Commercial Paper   NP   A3
NSP-Minnesota   Senior Unsecured Debt   Baa1   BBB-
NSP-Minnesota   Senior Secured Debt   A3   BBB+
NSP-Minnesota   Commercial Paper   P2   A3
NSP-Wisconsin   Senior Unsecured Debt   Baa1   BBB
NSP-Wisconsin   Senior Secured Debt   A3   BBB+
PSCo   Senior Unsecured Debt   Baa2   BBB-
PSCo   Senior Secured Debt   Baa1   BBB+
PSCo   Commercial Paper   P2   A3
SPS   Senior Unsecured Debt   Baa1   BBB
SPS   Commercial Paper   P2   A3
NRG   Corporate Credit Rating   Caa3**   D**


*    Negative credit watch/negative outlook
**   Below investment grade

NRG’s access to short-term capital is currently non-existent outside of bankruptcy. The downgrade of NRG’s credit ratings below investment grade in July 2002 has resulted in cash collateral requirements, as discussed previously and in Notes 4 and 7 to the Consolidated Financial Statements. In addition, lower credit ratings will increase the relative cost of NRG’s capital financing compared to historical levels, assuming NRG could obtain such financing.

In June 2002, Xcel Energy’s access to commercial paper markets was reduced due to lowered credit ratings, shown previously. Xcel Energy typically uses sources of financing, both short- and long-term, other than commercial paper to fulfill its cash needs and manage its capital structure.

NRG Capital Sources — NRG has generally financed the acquisition and development of its projects under financing arrangements to be repaid solely from each of its project’s cash flows, which are typically secured by the plant’s physical assets and equity interests in the project company. As discussed above, NRG’s credit situation has significantly affected its credit ratings and has virtually eliminated its access to short-term funding. See credit ratings in previous table. NRG anticipates funding its ongoing capital requirements through committed debt facilities, operating cash flows, and existing cash.

NRG’s operating cash flows have been affected by lower operating margins as a result of low power prices since mid-2001. Seasonal variations in demand and market volatility in prices are not unusual in the independent power sector, and NRG does normally experience higher margins in peak summer periods and lower margins in non-peak periods. NRG has also incurred significant amounts of debt to finance its acquisitions in the past several years, and the servicing of interest and principal repayments from such financing is largely dependent on domestic project cash flows. Management has concluded that the forecasted free cash flow available to NRG after servicing project-level obligations will be insufficient to service recourse debt obligations at NRG.

Substantially all of NRG’s operations are conducted by project subsidiaries and project affiliates. NRG’s cash flow

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and ability to service corporate-level indebtedness when due is dependent upon receipt of cash dividends and distributions or other transfers from NRG’s projects and other subsidiaries. NRG has generally financed the acquisition and development of its projects under financing arrangements to be repaid solely from each of its project’s cash flows, which are typically secured by the plant’s physical assets and equity interests in the project company. In August 2002, NRG suspended substantially all of its acquisition and development activities indefinitely, pending a comprehensive restructuring of NRG. The debt agreements of NRG’s subsidiaries and project affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to NRG. As of Dec. 31, 2002, Loy Yang, Energy Center Kladno, LSP Energy (Batesville), NRG South Central, and NRG Northeast Generating do not currently meet the minimum debt service coverage ratios required for these projects to make payments to NRG. In addition, NRG’s subsidiaries, including LSP Kendall, NRG McClain, NRG Mid-Atlantic, NRG South Central and NRG Northeast Generating are in default on their various debt instruments, resulting in dividend payment restrictions.

For additional information on NRG’s defaults on short-term and long-term borrowing arrangements, see Note 7 to the Consolidated Financial Statements.

Registration Statements — Xcel Energy’s Articles of Incorporation authorize the issuance of 1 billion shares of common stock. As of Dec. 31, 2002, Xcel Energy had approximately 399 million shares of common stock outstanding. In addition, Xcel Energy’s Articles of Incorporation authorize the issuance of 7 million shares of $100 par value preferred stock. On Dec. 31, 2002, Xcel Energy had approximately 1 million shares of preferred stock outstanding. Registered securities available for issuance are as follows:

In February 2002, Xcel Energy filed a $1-billion shelf registration with the SEC. Xcel Energy may issue debt securities, common stock and rights to purchase common stock under this shelf registration. Xcel Energy has approximately $482.5 million remaining under this registration, which it can only issue when its common equity exceeds 30 percent of its total capitalization absent SEC approval under PUHCA.

In April 2001, NSP-Minnesota filed a $600-million, long-term debt shelf registration with the SEC. NSP-Minnesota has approximately $415 million remaining under this registration.

PSCo has an effective shelf registration statement with the SEC under which $300 million of senior debt securities are available for issuance.

In June 2001, NRG filed a shelf registration with the SEC to sell up to $2 billion in debt securities, common and preferred stock, warrants and other securities. NRG has approximately $1.5 billion remaining under this shelf registration. However, NRG’s access to capital markets is severely constrained and the registration no longer represents access to financing sources.

In March 2003, PSCo issued $250 million of 4.875 percent, First Collateral Trust Bonds due in 2013. The bonds were issued in a private placement to qualified institutional buyers and were not registered under the Securities Act of 1933. Pursuant to a registration rights agreement, PSCo has an obligation to file a registration statement for an exchange offer for these bonds.

Other Liquidity and Capital Resource Considerations

NRG Financial Issues and Potential BankruptcyHistorically, NRG has obtained cash from operations, issuance of debt and equity securities, borrowings under credit facilities, capital contributions from Xcel Energy, reimbursement by Xcel Energy of tax benefits pursuant to a tax-sharing agreement and proceeds from non-recourse project financings. NRG has used these funds to finance operations, service debt obligations, fund the acquisition, development and construction of generation facilities, finance capital expenditures and meet other cash and liquidity needs.

As discussed previously, substantially all of NRG’s operations are conducted by project subsidiaries and project affiliates. NRG’s cash flow and ability to service corporate-level indebtedness when due is dependent upon receipt of cash dividends and distributions or other transfers from NRG’s projects and other subsidiaries. The debt agreements of NRG’s subsidiaries and project affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to NRG. As of Dec. 31, 2002, Loy Yang, Killingholme, Energy Center Kladno, LSP Energy (Batesville), NRG South Central and NRG Northeast Generating do not currently meet the minimum debt service coverage ratios required for these projects to make payments to NRG.

Killingholme, NRG South Central and NRG Northeast Generating are in default on their credit agreements. NRG believes the situations at Energy Center Kladno, Loy Yang and Batesville do not create an event of default and will not allow the lenders to accelerate the project financings.

In all of these cases, NRG’s corporate-level financial obligations to project lenders is limited to no more than six-months’ debt service.

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As previously discussed, NRG’s operating cash flows have been affected by lower operating margins as a result of low power prices since mid-2001. Seasonal variations in demand and market volatility in prices are not unusual in the independent power sector, and NRG does normally experience higher margins in peak summer periods and lower margins in non-peak periods. NRG has also incurred significant amounts of debt to finance its acquisitions in the past several years, and the servicing of interest and principal repayments from such financing is largely dependent on domestic project cash flows. NRG’s management has concluded that the forecasted free cash flow available to NRG after servicing project-level obligations will be insufficient to service recourse debt obligations.

Since mid-2002, as discussed previously, NRG has experienced severe financial difficulties, resulting primarily from declining credit ratings and lower prices for power. These financial difficulties have caused NRG to, among other things, miss several scheduled payments of interest and principal on its bonds and incur an approximately $3-billion asset impairment charge. The asset impairment charge relates to write-offs for anticipated losses on sales of several projects as well as anticipated losses for projects for which NRG has stopped funding. In addition, as a result of having its credit ratings downgraded, NRG is in default of obligations to post cash collateral of approximately $1 billion. Furthermore, on Nov. 6, 2002, lenders to NRG accelerated approximately $1.1 billion of NRG’s debt under the construction revolver financing facility, rendering the debt immediately due and payable. In addition, on Feb. 27, 2003, lenders to NRG accelerated approximately $1.0 billion of NRG Energy’s debt under the corporate revolver financing facility, rendering the debt immediately due and payable. NRG continues to work with its lenders and bondholders on a comprehensive restructuring plan. NRG does not contemplate making any principal or interest payments on its corporate-level debt pending the restructuring of its obligations. Consequently, NRG is, and expects to continue to be, in default under various debt instruments. By reason of these various defaults, the lenders are able to seek to enforce their remedies, if they so choose, and that would likely lead to a bankruptcy filing by NRG in 2003.

Whether NRG does or does not reach a consensual restructuring plan with its creditors, there is a substantial likelihood that NRG will be the subject of a bankruptcy proceeding in 2003. If an agreement is reached with NRG’s creditors on a restructuring plan, it is expected that NRG would as soon as practicable commence a Chapter 11 bankruptcy case and immediately seek approval of a prenegotiated plan of reorganization. Absent an agreement with NRG’s creditors and the continued forbearance by such creditors, NRG will be subject to substantial doubt as to its ability to continue as a going concern and will likely be the subject of a voluntary or involuntary bankruptcy proceeding, which, due to the lack of a prenegotiated plan of reorganization, would be expected to take an extended period of time to be resolved and may involve claims against Xcel Energy under the equitable doctrine of substantive consolidation, as discussed following.

In addition to the collateral requirements, NRG must continue to meet its ongoing operational and construction funding requirements. Since NRG’s credit rating downgrade, its cost of borrowing has increased and it has not been able to access the capital markets. NRG believes that its current funding requirements under its already reduced construction program may be unsustainable given its inability to raise money in the capital markets and the uncertainties involved in obtaining additional equity funding from Xcel Energy. NRG and Xcel Energy have retained financial advisors to help work through these liquidity issues.

As discussed above, NRG is not making any payments of principal or interest on its corporate-level debt, and neither NRG nor any subsidiary is making payment of principal or interest on publicly held bonds. This failure to pay, coupled with past and anticipated proceeds from the sales of projects, has provided NRG with adequate liquidity to meet its day-to-day operating costs. However, there can be no assurance that holders of NRG indebtedness, on which interest and principal are not being paid, will not seek to accelerate the payment of their indebtedness, which would likely lead to NRG seeking relief under the bankruptcy laws.

At the present time and based on conversations with various lenders, Xcel Energy management believes that the appropriate course is to seek a consensual restructuring of NRG with its creditors. Following an agreement on the restructuring with NRG’s creditors, as described in Note 4 to the Consolidated Financial Statements, it is expected that NRG would commence a Chapter 11 bankruptcy proceeding and immediately seek approval of a prenegotiated plan of reorganization. If a consensual restructuring cannot be reached, the likelihood of NRG becoming subject to a protracted voluntary or involuntary bankruptcy proceeding is increased. If a consensual restructuring of NRG cannot be obtained and NRG remains outside of a bankruptcy proceeding, NRG is expected to continue selling assets to reduce its debt and improve its liquidity. Through Jan. 31, 2003, NRG completed a number of transactions, which resulted in net cash proceeds to NRG after debt pay-downs and after financial advisor fees of approximately $350 million.

Xcel Energy Impacts — During 2002, Xcel Energy provided NRG with $500 million of cash infusions. In May 2002, Xcel Energy and NRG entered into a support and capital subscription agreement (Support Agreement) pursuant to which Xcel Energy agreed, under certain circumstances, to provide an additional $300 million to NRG.

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Xcel Energy has not, to date, provided funds to NRG under this agreement. See discussion of preliminary Settlement with NRG’s creditors at Note 4 to the Financial Statements.

Many companies in the regulated utility industry, with which the independent power industry is closely linked, are also restructuring or reviewing their strategies. Several of these companies are discontinuing going forward with unregulated investments, seeking to divest of their unregulated subsidiaries or attempting to have their regulated subsidiaries acquire their unregulated subsidiaries. This may lead to an increased competition between the regulated utilities and the unregulated power producers within certain markets. In such instances, NRG may compete with regulated utilities in the influence of market designs and rulemaking.

On March 26, 2003, Xcel Energy’s board of directors approved a tentative settlement with holders of most of NRG’s long-term notes and the steering committee representing NRG’s bank lenders regarding alleged claims of such creditors against Xcel Energy, including claims related to the Support Agreement. The settlement is subject to a variety of conditions as set forth below, including definitive documentation. As described in Note 4 to the Consolidated Financial Statements, the settlement would require Xcel Energy to pay up to $752 million over 13 months. Xcel Energy would expect to fund those payments with cash from tax savings. The principal terms of the settlement as of the date of this report were as follows:

Xcel Energy would pay up to $752 million to NRG to settle all claims of NRG, and the claims of NRG against Xcel Energy, including all claims under the Support Agreement.

$350 million would be paid at or shortly following the consummation of a restructuring of NRG’s debt through a bankruptcy proceeding. It is expected that this payment would be made prior to year-end 2003. $50 million would be paid on Jan. 1, 2004, and all or any part of such payment could be made, at Xcel Energy’s election, in Xcel Energy common stock. Up to $352 million would be paid on April 30, 2004, except to the extent that Xcel Energy had not received at such time tax refunds equal to $352 million associated with the loss on its investment in NRG. To the extent Xcel Energy had not received such refunds, the April 30 payment would be due on May 30, 2004.

$390 million of the Xcel Energy payments are contingent on receiving releases from NRG creditors. To the extent Xcel Energy does not receive a release from an NRG creditor. Xcel Energy’s obligation to make $390 million of the payments would be reduced based on the amount of the creditor’s claim against NRG. As noted below, however, the entire settlement is contingent upon Xcel Energy receiving releases from at least 85 percent of the claims in various NRG creditor groups. As a result, it is not expected that Xcel Energy’s payment obligations would be reduced by more than approximately $60 million. Any reduction would come from the Xcel Energy payment due on April 30, 2004.

Upon the consummation of NRG’s debt restructuring through a bankruptcy proceeding, Xcel Energy’s exposure on any guarantees or other credit support obligations incurred by Xcel Energy for the benefit of NRG or any subsidiary would be terminated and any cash collateral posted by Xcel Energy would be returned to it. The current amount of such cash collateral is approximately $11.5 million.

As part of the settlement with Xcel Energy, any intercompany claims of Xcel Energy against NRG or any subsidiary arising from the provision of intercompany goods or services or the honoring of any guarantee will be paid in full in cash in the ordinary course except that the agreed amount of such intercompany claims arising or accrued as of Jan. 31, 2003 will be reduced from approximately $55 million as asserted by Xcel Energy to $13 million. The $13 million agreed amount is to be paid upon the consummation of NRG’s debt restructuring with $3 million in cash and an unsecured promissory note of NRG on market terms in the principal amount of $10 million.

NRG and its direct and indirect subsidiaries would not be reconsolidated with Xcel Energy or any of its other affiliates for tax purposes at any time after their June 2002 re-affiliation or treated as a party to or otherwise entitled to the benefits of any tax sharing agreement with Xcel Energy. Likewise, NRG would not be entitled to any tax benefits associated with the tax loss Xcel Energy expects to incur in connection with the write down of its investment in NRG.

Xcel Energy’s obligations under the tentative settlement, including its obligations to make the payments set forth above, are contingent upon, among other things, the following:

     (1)      Definitive documentation, in form and substance satisfactory to the parties;
  (2)   Between 50 percent and 100 percent of the claims represented by various NRG facilities or creditor groups (the “NRG Credit Facilities”) having executed an agreement, in form and substance satisfactory to Xcel Energy, to support the settlement;
  (3)   Various stages of the implementation of the settlement occurring by dates currently being negotiated, with the consummation of the settlement to occur by Sept. 30, 2003;
  (4)   The receipt of releases in favor of Xcel Energy by at least 85 percent of the claims represented by the NRG Credit Facilities;
  (5)   The receipt by Xcel Energy of all necessary regulatory approvals; and
  (6)   No downgrade prior to consummation of the settlement of any Xcel Energy credit rating from the level of such rating as of March 25, 2003.

Based on the foreseeable effects of a settlement agreement with the major NRG noteholders and bank lenders and the tax effect of an expected write-off of Xcel Energy’s investment in NRG, Xcel Energy would recognize the expected tax benefits of the write-off as of Dec. 31, 2002. The tax benefit has been estimated at approximately $706 million. This benefit is based on the tax basis of Xcel Energy’s investment in NRG.

Xcel Energy expects to claim a worthless stock deduction in 2003 on its investment. This would result in Xcel Energy having a net operating loss for the year. Under current law, this 2003 net operating loss could be carried back two years for federal purposes. Xcel Energy expects to file for a tax refund of approximately $355 million in first quarter 2004. This is refund based on a two-year carryback. However, under the Bush administration’s new dividend tax proposal, the carryback could be one year, which would reduce the refund to $125 million.

As to the remaining $351 million of expected tax benefits, Xcel Energy expects to eliminate or reduce estimated quarterly income tax payments, beginning in 2003. The amount of cash freed up by the reduction in estimated tax payments would depend on Xcel Energy’s taxable income.

While it is an exception rather than the rule, especially where one of the companies involved is not in bankruptcy, the equitable doctrine of substantive consolidation permits a bankruptcy court to disregard the separateness of related entities; to consolidate and pool the entities’ assets and liabilities; and treat them as though held and incurred by one entity where the interrelationship between the entities warrants such consolidation. In the event the settlement described above is not effectuated, Xcel Energy believes that any effort to substantively consolidate Xcel Energy with NRG would be without merit. However, it is possible that NRG or its creditors would attempt to advance such claims, or other claims under piercing the corporate veil, alter ego or related theories, should an NRG bankruptcy proceeding commence, particularly in the absence of a prenegotiated plan of reorganization, and Xcel Energy cannot be certain how a bankruptcy court would resolve these issues. One of the creditors of the NRG project Pike, as discussed in Note 18 to the Consolidated Financial Statements, has already filed involuntary bankruptcy proceedings against that project and has included claims against both NRG and Xcel Energy. Also, as discussed in Note 18 to the Consolidated Financial Statements, a group of former executives of NRG have commenced an involuntary bankruptcy proceeding against NRG related to the payments of certain benefits and deferred compensation amounts claimed to be due them. If a bankruptcy court were to allow substantive consolidation of Xcel Energy and NRG, it would have a material adverse effect on Xcel Energy.

The accompanying Consolidated Financial Statements do not reflect any conditions or matters that would arise if NRG were in bankruptcy.

If NRG were to file for bankruptcy, and the necessary actions were taken by Xcel Energy to fully relinquish its effective control over NRG, Xcel Energy anticipates that NRG would no longer be included in Xcel Energy’s consolidated financial statements, prospectively from the date such actions were taken. Such de-consolidation of NRG would encompass a change in Xcel Energy’s accounting for NRG to the equity method, under which Xcel Energy would continue to record its interest in NRG’s income or losses until Xcel Energy’s investment in NRG (under the equity method) reached the level of obligations that Xcel Energy had either guaranteed on behalf of NRG or was otherwise committed to in the form of financial assistance to NRG. Prior to completion of a bankruptcy proceeding, a prenegotiated plan of reorganization or other settlement reached with NRG’s creditors would be the determining factors in assessing whether a commitment to provide financial assistance to NRG existed at the time of de-consolidation.

At Dec. 31, 2002, Xcel Energy’s pro forma investment in NRG, calculated under the equity method if applied at that date, was a negative $625 million. If the amount of guarantees or other financial assistance committed to NRG by Xcel Energy exceeded that level after de-consolidation of NRG, then NRG’s losses would continue to be included in Xcel Energy’s results until the amount of negative investment in NRG reaches the amount of guarantees and financial assistance committed to by Xcel Energy. As of Dec. 31, 2002, the estimated guarantee exposure that Xcel Energy had provided on behalf of NRG of $96 million, as discussed in Note 16, and potential financial assistance was committed in the form of a support and capital subscription agreement pursuant to which Xcel Energy agreed, under certain circumstances, to provide an additional $300 million contribution to NRG if the financial restructuring plan discussed earlier is approved by NRG’s creditors. Additional commitments for financial assistance to NRG could be created in 2003 as Xcel Energy, NRG and NRG’s creditors continue to negotiate terms of a possible prenegotiated plan of reorganization to resolve NRG’s financial difficulties.

In addition to the effects of NRG’s losses, Xcel Energy’s operating results and retained earnings in 2003 could also be affected by the tax effects of any guarantees or financial commitments to NRG, if such income tax benefits were considered likely of realization in the foreseeable future. The income tax benefits recorded in 2002 related to Xcel Energy’s investment in NRG, as discussed in Note 11 to the Consolidated Financial Statements, includes only the tax benefits related to cash and stock investments already made in NRG at Dec. 31, 2002. Additional tax benefits could be recorded in 2003 at the time that such benefits are considered likely of realization, when the payment of guarantees and other financial assistance to NRG become probable.

As noted above, a bankruptcy filing by NRG would have several effects on Xcel Energy’s financial condition and results of operations. If a bankruptcy filing and other necessary governance actions eliminate Xcel Energy’s control over NRG, then management anticipates that NRG would no longer be included in Xcel Energy’s consolidated financial statements, prospectively from the date such actions were taken. Such de-consolidation of NRG would encompass a change in Xcel Energy’s accounting for NRG to the equity method, thus all of NRG’s assets and liabilities would be presented in a single line on Xcel Energy’s balance sheet at that point. This would reduce Xcel Energy’s debt leverage ratios and increase its equity ratio as a percent of total capitalization to above 30 percent, thereby reinstating its financing authority under PUHCA. In addition, the revenues and expenses of NRG would be reported on a net basis as equity income or losses. Losses would be subject to certain limitations. Also, the operating, investing and financing cash flows of NRG would not be included in Xcel Energy’s except to the extent cash flowed between Xcel Energy and NRG. Finally, there may be tax effects for guarantees or financial commitments made by Xcel Energy to NRG related to the bankruptcy or other resolution of NRG’s financial difficulties. See Note 4 to the Consolidated Financial Statements for further discussion of these possible effects of an NRG bankruptcy filing on Xcel Energy.

Xcel Energy believes that the ultimate resolution of NRG’s financial difficulties and going-concern uncertainty will not affect Xcel Energy’s ability to continue as a going concern. Xcel Energy is not dependent on cash flows from NRG, nor is Xcel Energy contingently liable to creditors of NRG in an amount material to Xcel Energy’s liquidity. Xcel Energy believes that its cash flows from regulated utility operations and anticipated financing capabilities will be sufficient to fund its non-NRG-related operating, investing and financing requirements. Beyond these sources of liquidity, Xcel Energy believes it will have adequate access to additional debt and equity financing that is not conditioned upon the outcome of NRG’s financial restructuring plan.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

See Management’s Discussion and Analysis under Item 7, incorporated by reference.

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Item 8. Financial Statements and Supplementary Data

See Item 15(a)-1 in Part IV for index of financial statements included herein.

See Note 22 of Notes to Consolidated Financial Statements for summarized quarterly financial data.

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INDEPENDENT AUDITORS’ REPORT

To Xcel Energy Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. (a Minnesota corporation) and subsidiaries (the Company) as of December 31, 2002 and 2001, and the related consolidated statements of operations, common stockholders’ equity and other comprehensive income and cash flows for the three years ended December 31, 2002. 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 and financial statement schedule based on our audits. We did not audit the consolidated balance sheet of NRG Energy, Inc. (a wholly owned subsidiary of Xcel Energy Inc.) for the years ended December 31, 2002 and 2001, or the consolidated statements of operations, stockholder’s (deficit)/equity and cash flows for the three years ended December 31, 2002 included in the consolidated financial statements of the Company, which statements reflect total assets and revenues of 40% and 24% for 2002, respectively, and total assets and revenues of 45% and 21% for 2001, respectively, and revenues of 20% for 2000, of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us (which as to 2002 expresses an unqualified opinion and includes an explanatory paragraph describing conditions that raise substantial doubt about NRG Energy, Inc.’s ability to continue as a going concern and emphasis of a matter paragraphs related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets on January 1, 2002 and the adoption of SFAS 133, Accounting for Derivative Instruments and Hedging Activities on January 1, 2001), and our opinion, insofar as it relates to the amounts included for NRG Energy, Inc. for the periods described above, is based solely on the report of the other auditors.

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 and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Xcel Energy Inc. and subsidiaries as of December 31, 2002 and 2001 and the results of their operations and their cash flows for each of the three years 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 17 to the consolidated financial statements, effective January 1, 2001 Xcel Energy Inc. and subsidiaries adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2002, Xcel Energy Inc. and subsidiaries adopted SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

Note 4 to the consolidated financial statements discusses the implications to the Company related to credit and liquidity constraints, various defaults under credit arrangements and a likely Chapter 11 bankruptcy protection filing at NRG Energy, Inc.

/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 28, 2003



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REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder
   of NRG Energy, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows and stockholder’s (deficit)/equity present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries at 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. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company is experiencing credit and liquidity constraints and has various credit arrangements that are in default. As a direct consequence, during 2002 the Company entered into discussions with its creditors to develop a comprehensive restructuring plan. In connection with its restructuring efforts, it is likely the Company and certain of its subsidiaries will file for Chapter 11 bankruptcy protection. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 19 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” for the year ended December 31, 2002. As discussed in Note 26 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” on January 1, 2001. As discussed in Notes 3 and 5 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002.

/S/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Minneapolis, Minnesota
March 28, 2003



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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

(Thousands of Dollars, Except Per Share Data)

                             
        Year ended Dec. 31,
       
        2002   2001   2000
       
 
 
Operating revenues:
                       
 
Electric utility
  $ 5,435,377     $ 6,394,737     $ 5,674,485  
 
Natural gas utility
    1,397,800       2,052,651       1,468,880  
 
Electric and natural gas trading margin
    8,485       89,249       41,357  
 
Nonregulated and other
    2,611,149       2,579,715       1,856,030  
 
Equity earnings from investments in affiliates
    71,561       217,070       182,714  
 
 
   
     
     
 
   
Total operating revenues
    9,524,372       11,333,422       9,223,466  
Operating expenses:
                       
 
Electric fuel and purchased power — utility
    2,199,099       3,171,660       2,580,723  
 
Cost of natural gas sold and transported — utility
    851,987       1,517,557       948,145  
 
Cost of sales — nonregulated and other
    1,361,466       1,318,586       876,698  
 
Other operating and maintenance expenses — utility
    1,501,602       1,506,039       1,446,122  
 
Other operating and maintenance expenses — nonregulated
    787,968       676,408       533,379  
 
Depreciation and amortization
    1,037,429       906,303       766,746  
 
Taxes (other than income taxes)
    318,641       316,492       351,412  
 
Writedowns and disposal losses from investments (see Notes 2 and 3)
    207,290              
 
Special charges (see Note 2)
    2,691,223       62,230       241,042  
 
 
   
     
     
 
   
Total operating expenses
    10,956,705       9,475,275       7,744,267  
 
 
   
     
     
 
Operating income (loss)
    (1,432,333 )     1,858,147       1,479,199  
Interest income
    45,863       43,548       27,480  
Other non-operating income
    28,167       17,961       5,094  
Other non-operating expense
    (30,043 )     (15,623 )     (15,994 )
Interest charges and financing costs:
                       
 
Interest charges — net of amounts capitalized (includes other financing costs
of $59,724, $21,058 and $20,772, respectively)
    879,736       727,976       614,173  
 
Distributions on redeemable preferred securities of subsidiary trusts
    38,344       38,800       38,800  
 
 
   
     
     
 
   
Total interest charges and financing costs
    918,080       766,776       652,973  
 
 
   
     
     
 
Income (loss) from continuing operations before income taxes and minority interest
    (2,306,426 )     1,137,257       842,806  
Income taxes
    (627,985 )     331,371       299,030  
Minority interest
    (17,071 )     68,199       29,994  
 
 
   
     
     
 
Income (loss) from continuing operations
    (1,661,370 )     737,687       513,782  
Income (loss) from discontinued operations — net of tax (see Note 3)
    (556,621 )     46,992       32,006  
 
 
   
     
     
 
Income (loss) before extraordinary items
    (2,217,991 )     784,679       545,788  
Extraordinary items — net of income taxes of $0, $4,807 and ($8,549), respectively
          10,287       (18,960 )
 
 
   
     
     
 
Net income (loss)
    (2,217,991 )     794,966       526,828  
Dividend requirements on preferred stock
    4,241       4,241       4,241  
 
 
   
     
     
 
Earnings available for common shareholders
  $ (2,222,232 )   $ 790,725     $ 522,587  
 
 
   
     
     
 
Weighted average common shares outstanding (in thousands):
                       
 
Basic
    382,051       342,952       337,832  
 
Diluted
    382,051       343,742       338,111  
Earnings (loss) per share — basic:
                       
 
Income (loss) from continuing operations
  $ (4.36 )   $ 2.14     $ 1.51  
 
Discontinued operations (see Note 3)
    (1.46 )     0.14       0.09  
 
Extraordinary items (see Note 15)
          0.03       (0.06 )
 
 
   
     
     
 
   
Earnings (loss) per share
  $ (5.82 )   $ 2.31     $ 1.54  
 
 
   
     
     
 
Earnings (loss) per share — diluted:
                       
 
Income (loss) from continuing operations
  $ (4.36 )   $ 2.13     $ 1.51  
 
Discontinued operations (see Note 3)
    (1.46 )     0.14       0.09  
 
Extraordinary items (see Note 15)
          0.03       (0.06 )
 
 
   
     
     
 
   
Earnings (loss) per share
  $ (5.82 )   $ 2.30     $ 1.54  
 
 
   
     
     
 

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)

                                 
            Year ended Dec. 31,
            2002   2001   2000
           
 
 
Operating activities:
                       
 
Net (loss) income
  $ (2,217,991 )   $ 794,966     $ 526,828  
 
Adjustments to reconcile net income to cash provided by operating activities:
                       
     
Depreciation and amortization
    1,028,494       945,555       828,780  
     
Nuclear fuel amortization
    48,675       41,928       44,591  
     
Deferred income taxes
    (781,531 )     11,190       62,716  
     
Amortization of investment tax credits
    (13,272 )     (12,867 )     (15,295 )
     
Allowance for equity funds used during construction
    (7,810 )     (6,829 )     3,848  
     
Undistributed equity in earnings of unconsolidated affiliates
    (16,478 )     (124,277 )     (87,019 )
     
Gain on sale of property
    (6,785 )            
     
Write-downs and losses from investments
    207,290              
     
Gain on sale of discontinued operations
    (2,814 )            
     
Non-cash special charges — asset write-downs
    3,160,374             41,991  
     
Conservation incentive accrual adjustments
    (9,152 )     (49,271 )     19,248  
     
Unrealized gain on derivative financial instruments
    (8,407 )     (9,804 )      
     
Extraordinary items — net of tax (see Note 15)
          (10,287 )     18,960  
     
Change in accounts receivable
    126,073       218,353       (443,347 )
     
Change in inventories
    8,620       (178,530 )     21,933  
     
Change in other current assets
    67,596       340,478       (484,288 )
     
Change in accounts payable
    80,338       (325,946 )     713,069  
     
Change in other current liabilities
    156,471       142,617       183,679  
     
Change in other noncurrent assets
    (203,997 )     (329,442 )     (130,764 )
     
Change in other noncurrent liabilities
    99,417     136,178       102,795  
 
 
   
     
     
 
       
Net cash provided by operating activities
    1,715,111       1,584,012       1,407,725  
Investing activities:
                       
 
Nonregulated capital expenditures and asset acquisitions
    (1,502,601 )     (4,259,791 )     (2,196,168 )
 
Utility capital/construction expenditures
    (906,341 )     (1,105,989 )     (984,935 )
 
Proceeds from sale of discontinued operations
    160,791              
 
Allowance for equity funds used during construction
    7,810       6,829       (3,848 )
 
Investments in external decommissioning fund
    (57,830 )     (54,996 )     (48,967 )
 
Equity investments, loans, deposits and sales of nonregulated projects
    (118,844 )     154,845       (93,366 )
 
Restricted cash
    (220,800 )            
 
Collection of loans made to nonregulated projects
    22,498       6,374       17,039  
 
Other investments — net
    (102,457 )     84,769       (36,749 )
 
 
   
     
     
 
     
Net cash used in investing activities
    (2,717,774 )     (5,167,959 )     (3,346,994 )
Financing activities:
                       
 
Short-term borrowings — net
    (663,365 )     708,335       42,386  
 
Proceeds from issuance of long-term debt
    2,521,375       3,777,075       3,565,227  
 
Repayment of long-term debt, including reacquisition premiums
    (362,760 )     (860,623 )     (1,667,335 )
 
Proceeds from issuance of common stock
    581,212       133,091       116,678  
 
Proceeds from NRG stock offering
          474,348       453,705  
 
Dividends paid
    (496,375 )     (518,894 )     (494,992 )
 
 
   
     
     
 
     
Net cash provided by financing activities
    1,580,087       3,713,332       2,015,669  
Effect of exchange rate changes on cash
    6,448       (4,566 )     360  
Net increase in cash and cash equivalents — discontinued operations
    56,096       (21,570 )     (57,638 )
 
 
   
     
     
 
Net increase in cash and cash equivalents — continuing operations
    639,968       103,249       19,122  
Cash and cash equivalents at beginning of year
    261,305       158,056       138,934  
 
 
   
     
     
 
Cash and cash equivalents at end of year
  $ 901,273     $ 261,305     $ 158,056  
 
 
   
     
     
 
Supplemental disclosure of cash flow information:
                       
 
Cash paid for interest (net of amounts capitalized)
  $ 640,628     $ 708,560     $ 610,584  
 
Cash paid for income taxes (net of refunds received)
  $ 24,935     $ 327,018     $ 216,087  

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)

                     
        Dec. 31,
        2002   2001
       
 
ASSETS
               
Current assets:
               
 
Cash and cash equivalents
  $ 901,273     $ 261,305  
 
Restricted cash
    305,581       142,676  
 
Accounts receivable — net of allowance for bad debts: $92,745 and $37,487, respectively
    961,060       1,048,073  
 
Accrued unbilled revenues
    390,984       495,994  
 
Materials and supplies inventories — at average cost
    321,863       308,593  
 
Fuel inventory — at average cost
    207,200       250,043  
 
Natural gas inventories — replacement cost in excess of LIFO: $20,502 and $11,331, respectively
    147,306       126,563  
 
Recoverable purchased natural gas and electric energy costs
    63,975       52,583  
 
Derivative instruments valuation — at market
    62,206       20,794  
 
Prepayments and other
    267,185       307,169  
 
Current assets held for sale
    108,535       316,621  
 
 
   
     
 
   
Total current assets
    3,737,168       3,330,414  
 
 
   
     
 
Property, plant and equipment, at cost:
               
 
Electric utility plant
    16,516,790       16,099,655  
 
Nonregulated property and other
    8,411,088       6,924,894  
 
Natural gas utility plant
    2,603,545       2,493,028  
 
Construction work in progress: utility amounts of $856,008 and $669,895, respectively
    1,513,807       3,663,371  
 
 
   
     
 
   
Total property, plant and equipment
    29,045,230       29,180,948  
 
Less accumulated depreciation
    (10,303,575 )     (9,495,835 )
 
Nuclear fuel — net of accumulated amortization: $1,058,531 and $1,009,855, respectively
    74,139       96,315  
 
 
   
     
 
   
Net property, plant and equipment
    18,815,794       19,781,428  
 
 
   
     
 
Other assets:
               
 
Investments in unconsolidated affiliates
    1,001,380       1,196,702  
 
Notes receivable, including amounts from affiliates of $206,308 and $202,411, respectively
    987,714       779,186  
 
Nuclear decommissioning fund and other investments
    732,166       695,070  
 
Regulatory assets
    576,403       502,442  
 
Derivative instruments valuation — at market
    93,225       96,095  
 
Prepaid pension asset
    466,229       378,825  
 
Goodwill, net
    35,538       36,916  
 
Intangible assets, net
    68,210       66,700  
 
Other
    364,243       360,158  
 
Noncurrent assets held for sale
    379,772       1,530,178  
 
 
   
     
 
   
Total other assets
    4,704,880       5,642,272  
 
 
   
     
 
   
Total assets
  $ 27,257,842     $ 28,754,114  
 
 
   
     
 
LIABILITIES AND EQUITY
               
Current liabilities:
               
 
Current portion of long-term debt
  $ 7,756,261     $ 392,938  
 
Short-term debt
    1,541,963       2,224,812  
 
Accounts payable
    1,399,195       1,263,690  
 
Taxes accrued
    267,214       246,098  
 
Dividends payable
    75,814       130,845  
 
Derivative instruments valuation — at market
    38,767       83,122  
 
Other
    749,521       698,142  
 
Current liabilities held for sale
    520,101       429,433  
 
 
   
     
 
   
Total current liabilities
    12,348,836       5,469,080  
 
 
   
     
 
Deferred credits and other liabilities:
               
 
Deferred income taxes
    1,283,667       2,134,977  
 
Deferred investment tax credits
    169,696       184,148  
 
Regulatory liabilities
    518,427       483,942  
 
Derivative instruments valuation — at market
    102,779       42,444  
 
Benefit obligations and other
    722,264       692,090  
 
Minimum pension liability
    106,897        
 
Noncurrent liabilities held for sale
    155,962       783,297  
 
 
   
     
 
   
Total deferred credits and other liabilities
    3,059,692       4,320,898  
 
 
   
     
 
Minority interest in subsidiaries
    34,762       614,750  
Commitments and contingencies (see Note 18)
                 
Capitalization (see Statements of Capitalization):
               
 
Long-term debt
    6,550,248       11,555,589  
 
Mandatorily redeemable preferred securities of subsidiary trusts (see Note 9)
    494,000       494,000  
 
Preferred stockholders’ equity
    105,320       105,320  
 
Common stockholders’ equity
    4,664,984       6,194,477  
 
 
   
     
 
Total liabilities and equity
  $ 27,257,842     $ 28,754,114  
 
 
   
     
 

See Notes to Consolidated Financial Statements

74



Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME
(Thousands of Dollars)

                                                           
                          Accumulated        
      Common Stock Issued                   Other        
     
  Retained           Comprehensive   Total
                      Capital in Excess   Earnings   Shares Held   Income   Stockholders'
      Shares   Par Value   Of Par Value   (Deficit)   By ESOP   (Loss)   Equity
     
 
 
 
 
 
 
Balance at Dec. 31, 1999
    335,277     $ 838,193     $ 2,288,254     $ 2,253,800     $ (11,606 )   $ (78,421 )   $ 5,290,220  
 
   
     
     
     
     
     
     
 
Net income
                            526,828                       526,828  
Currency translation adjustments
                                            (78,508 )     (78,508 )
 
                                                   
 
Comprehensive income for 2000
                                                    448,320  
Dividends declared:
                                                       
 
Cumulative preferred stock of Xcel Energy
                            (4,241 )                     (4,241 )
 
Common stock
                            (492,183 )                     (492,183 )
Issuances of common stock — net proceeds
    5,557       13,892       102,785                               116,677  
Tax benefit from stock options exercised
                    53                               53  
Other
                            16                       16  
Gain recognized from NRG stock offering
                    215,933                               215,933  
Loan to ESOP to purchase shares
                                    (20,000 )             (20,000 )
Repayment of ESOP loan (a)
                                    6,989               6,989  
 
   
     
     
     
     
     
     
 
Balance at Dec. 31, 2000
    340,834       852,085       2,607,025       2,284,220       (24,617 )     (156,929 )     5,561,784  
 
   
     
     
     
     
     
     
 
Net income
                            794,966                       794,966  
Currency translation adjustments
                                            (56,693 )     (56,693 )
Cumulative effect of accounting change — net
Unrealized transition loss upon adoption of
SFAS No. 133 (see Note 17)
                                            (28,780 )     (28,780 )
After-tax net unrealized losses related to
derivatives accounted for as hedges (see Note 17)
                                            43,574       43,574  
After-tax net realized losses on derivative
transactions reclassified into earnings (see Note 17)
                                            19,449       19,449  
Unrealized loss — marketable securities
                                            (75 )     (75 )
 
                                                   
 
Comprehensive income for 2001
                                                    772,441  
Dividends declared:
                                                       
 
Cumulative preferred stock of Xcel Energy
                            (4,241 )                     (4,241 )
 
Common stock
                            (516,515 )                     (516,515 )
Issuances of common stock — net proceeds
    4,967       12,418       120,673                               133,091  
Other
                            (27 )                     (27 )
Gain recognized from NRG stock offering
                    241,891                               241,891  
Repayment of ESOP loan (a)
                                    6,053               6,053  
 
   
     
     
     
     
     
     
 
Balance at Dec. 31, 2001
    345,801       864,503       2,969,589       2,558,403       (18,564 )     (179,454 )     6,194,477  
 
   
     
     
     
     
     
     
 
Net loss
                            (2,217,991 )                     (2,217,991 )
Currency translation adjustments
                                            30,008       30,008  
Minimum pension liability
                                            (107,782 )     (107,782 )
After-tax net unrealized losses related to
derivatives accounted for as hedges (see Note 17)
                                            (68,266 )     (68,266 )
After-tax net realized losses on derivative
transactions reclassified into earnings (see Note 17)
                                            28,791       28,791  
Unrealized loss — marketable securities
                                            (457 )     (457 )
 
                                                   
 
Comprehensive income (loss) for 2002
                                                    (2,335,697 )
Dividends declared:
                                                       
 
Cumulative preferred stock of Xcel Energy
                            (4,241 )                     (4,241 )
 
Common stock
                            (437,113 )                     (437,113 )
Issuances of common stock — net proceeds
    27,148       67,870       513,342                               581,212  
Acquisition of NRG minority common shares
    25,765       64,412       555,220                       28,150       647,782  
Repayment of ESOP loan (a)
                                    18,564               18,564  
 
   
     
     
     
     
     
     
 
Balance at Dec. 31, 2002
    398,714     $ 996,785     $ 4,038,151     $ (100,942 )   $     $ (269,010 )   $ 4,664,984  
 
   
     
     
     
     
     
     
 

See Notes to Consolidated Financial Statements

75



Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)

                   
      Dec. 31,
Long-Term Debt   2002   2001

 
 
NSP-Minnesota Debt
               
First Mortgage Bonds, Series due:
               
 
Dec. 1, 2003-2006, 3.75 - 4.1%
  $ 9,145 (a)   $ 11,225 (a)
      100,000       100,000  
      80,000       80,000  
 
Dec. 1, 2005, 6.125%
    70,000       70,000  
      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, 8.50% 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)
      250,000       250,000  
      150,000       150,000  
      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
    427       390  
Unamortized discount-net
    (8,931 )     (5,015 )
 
 
   
     
 
 
Total
    1,788,781       1,181,054  
Less redeemable bonds classified as current (see Note 6)
    13,700       141,600  
Less current maturities
    212,762       11,134  
 
 
   
     
 
Total NSP-Minnesota long-term debt
  $ 1,562,319     $ 1,028,320  
 
 
   
     
 
PSCo Debt new line First Mortgage Bonds, Series due:
               
    $ 250,000     $ 250,000  
      100,000       100,000  
 
Nov. 1, 2005, 6.375%
    134,500       134,500  
      125,000       125,000  
      18,000 (b)     18,000 (b)
      50,000 (b)     50,000 (b)
 
Oct. 1, 2012, 7.875%
    600,000        
      61,500 (b)     61,500 (b)
      48,750 (b)     48,750 (b)
      146,340       147,840  
      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  
 
 
   
     
 


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

See Notes to Consolidated Financial Statements

76



Table of Contents

                       
          Dec. 31,
Long-Term Debt - continued (Thousands of dollars)   2002   2001

 
 
SPS 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 due:
               
      44,500       44,500  
      25,000       25,000  
 
Sept. 1, 2016, 5.75% series
    57,300       57,300  
Unamortized discount
    (1,138 )     (1,425 )
     
     
 
 
Total SPS long-term debt
  $ 725,662     $ 725,375  
     
     
 
NSP-Wisconsin Debt
               
First Mortgage Bonds Series due:
               
    $ 40,000     $ 40,000  
      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  
     
     
 
NRG Debt
               
Remarketable or Redeemable Securities due March 15, 2005, 7.97%
  $ 257,552     $ 232,960  
NRG Energy, Inc. Senior Notes, Series due
Feb. 1, 2006, 7.625%
    125,000       125,000  
      250,000       250,000  
      300,000       300,000  
      240,000       240,000  
      350,000       350,000  
      340,000       340,000  
      350,000       350,000  
      500,000       500,000  
      285,728       284,440  
 
NRG Finance Co. I LLC, due May 9, 2006, various rates
    1,081,000       697,500  
NRG debt secured solely by project assets:
               
 
NRG Northeast Generating Senior Bonds, Series due:
               
          126,500       180,000  
          130,000       130,000  
          300,000       300,000  
 
South Central Generating Senior Bonds, Series due:
               
          450,750       463,500  
          300,000       300,000  
 
MidAtlantic — various, due Oct 1, 2005, 4.625%
    409,201       420,892  
 
Flinders Power Finance Pty, due September 2012, various rates 6.14-6.49% at Dec.
31, 2002, and 8.56% at Dec. 31, 2001
    99,175       74,886  
 
Brazos Valley, due June 30, 2008, 6.75%
    194,362       159,750  
 
Camas Power Boiler, due June 30, 2007, and Aug. 1, 2007, 3.65% and 3.38%
    17,861       20,909  
 
Sterling Luxembourg # 3 Loan, due June 30, 2019, variable rate 7.86% at Dec. 31, 2001
    360,122       329,842  
 
Crockett Corp. LLP debt, due Dec. 31, 2014, 8.13%
    -       234,497  
 
Csepel Aramtermelo, due Oct. 2, 2017, 3.79% and 4.846%
    -       169,712  
 
Hsin Yu Energy Development, due November 2006- April 2012, 4-6.475%
    85,607       89,964  
 
LSP Batesville, due Jan. 15, 2014, 7.164% and July 15, 2025, 8.16%
    314,300       321,875  
 
LSP Kendall Energy, due Sept. 1, 2005, 2.65%
    495,754       499,500  
 
McClain, due Dec. 31, 2005, 6.75%
    157,288       159,885  
 
NEO, due 2005-2008, 9.35%
    7,658       23,956  
 
NRG Energy Center, Inc. Senior Secured Notes, Series due June 15, 2013, 7.31%
    133,099       62,408  
 
NRG Peaking Finance LLC, due 2019, 6.67%
    319,362        
 
NRG Pike Energy LLC, due 2010, 4.92%
    155,477        
 
PERC, due 2017-2018, 5.2%
    28,695       33,220  
 
Audrain Capital Lease Obligation, due Dec. 31, 2023, 10%
    239,930       239,930  
 
Saale Energie GmbH Schkopau Capital Lease, due May 2021, various rates
    333,926       311,867  
 
Various debt, due 2003-2007, 0.0 - 20.8%
    92,573       147,493  
Other
    676        
     
     
 
 
Total
    8,831,596       8,343,986  
Less current maturities — continuing operations
    7,193,237       210,885  
Less discontinued operations
    445,729       851,196  
     
     
 
 
Total NRG long-term debt
  $ 1,192,630     $ 7,281,905  
     
     
 

See Notes to Consolidated Financial Statements

77



Table of Contents

                     
        Dec. 31,
Long-Term Debt - continued (Thousands of dollars)   2002   2001

 
 
Other Subsidiaries’ Long-Term Debt
               
First Mortgage Bonds — Cheyenne:
               
 
Series due April 1, 2003 - Jan. 1, 2024, 7.5 - 7.875%
  $ 12,000     $ 12,000  
 
Industrial Development Revenue Bonds, due Sept. 1, 2021 - March 1, 2027, variable rate, 1.7% and 1.8% at Dec. 31, 2002 and 2001
    17,000       17,000  
Viking Gas Transmission Co. Senior Notes-Series due:
               
 
Oct. 31, 2008 - Sept. 30, 2014, 6.65% - 8.04%
    40,421       45,181  
Various Eloigne Co. Affordable Housing Project Notes, due 2003 - 2027, 0.3% - 9.91%
    41,353       47,856  
Other
    97,895       35,608  
 
 
   
     
 
 
Total
    208,669       157,645  
Less current maturities
    14,431       12,110  
 
 
   
     
 
 
Total other subsidiaries long-term debt
  $ 194,238     $ 145,535  
 
 
   
     
 
Xcel Energy Inc. Debt
               
Unsecured senior notes, due Dec. 1, 2010, 7%
  $ 600,000     $ 600,000  
Convertible notes, due Nov. 21, 2007, 7.5%
    230,000        
Unamortized discount
    (9,837 )     (3,655 )
 
 
   
     
 
 
Total Xcel Energy Inc. debt
  $ 820,163     $ 596,345  
 
 
   
     
 
Total long-term debt
  $ 6,550,248     $ 11,555,589  
 
 
   
     
 
Mandatorily Redeemable Preferred Securities of Subsidiary Trusts
holding as their sole asset the junior subordinated deferrable debentures of:
               
   
NSP-Minnesota, due 2037, 7.875%
  $ 200,000     $ 200,000  
   
PSCo, due 2038, 7.6%
    194,000       194,000  
   
SPS, due 2036, 7.85%
    100,000       100,000  
 
 
   
     
 
 
Total mandatorily redeemable preferred securities of subsidiary trusts
  $ 494,000     $ 494,000  
 
 
   
     
 
Cumulative Preferred Stock - authorized 7,000,000 shares of $100 par value;
outstanding shares: 2002, 1,049,800; 2001, 1,049,800
               
   
$3.60 series, 275,000 shares
  $ 27,500     $ 27,500  
   
$4.08 series, 150,000 shares
    15,000       15,000  
   
$4.10 series, 175,000 shares
    17,500       17,500  
   
$4.11 series, 200,000 shares
    20,000       20,000  
   
$4.16 series, 99,800 shares
    9,980       9,980  
   
$4.56 series, 150,000 shares
    15,000       15,000  
 
 
   
     
 
   
Total
    104,980       104,980  
 
Capital in excess of par value on preferred stock
    340       340  
 
 
   
     
 
   
Total preferred stockholders’ equity
  $ 105,320     $ 105,320  
 
 
   
     
 
Common Stockholders’ Equity
               
 
Common stock — authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2002, 398,714,039; 2001, 345,801,028
  $ 996,785     $ 864,503  
 
Capital in excess of par value on common stock
    4,038,151       2,969,589  
 
Retained earnings (deficit)
    (100,942 )     2,558,403  
 
Leveraged common stock held by ESOP — shares at cost: 2002, 0; 2001, 783,162
          (18,564 )
 
Accumulated other comprehensive income (loss)
    (269,010 )     (179,454 )
 
 
   
     
 
   
Total common stockholders’ equity
  $ 4,664,984     $ 6,194,477  
 
 
   
     
 


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

See Notes to Consolidated Financial Statements

78



Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     Summary of Significant Accounting Policies

Merger and Basis of Presentation — On Aug. 18, 2000, Northern States Power Co. (NSP) and New Century Energies, 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. References herein to Xcel Energy relates to Xcel Energy, Inc. and its consolidated subsidiaries.

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. All earnings-per-share amounts previously reported for NSP and NCE have been restated for presentation on an Xcel Energy share basis.

Business and System of Accounts — Xcel Energy’s domestic utility subsidiaries are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries 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 — Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. These six utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo, SPS, BMG and Cheyenne. Their service territories include portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. During the period covered by this report, Xcel Energy’s regulated businesses also included Viking, which was sold in January 2003, and WGI.

Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc., an independent power producer. Xcel Energy owned 100 percent of NRG until the second quarter of 2000, when NRG completed its initial public offering, and 82 percent until a secondary offering was completed in March 2001. At Dec. 31, 2001, Xcel Energy indirectly owned approximately 74 percent of NRG. During the second quarter of 2002, Xcel Energy acquired the 26 percent of NRG shares that it did not own through a tender offer and merger. See Note 4 to the Consolidated Financial Statements for further discussion of the acquisition of minority NRG common shares.

In addition to NRG, Xcel Energy’s nonregulated subsidiaries include Utility Engineering Corp. (engineering, construction and design), Seren Innovations, Inc. (broadband telecommunications services), e prime inc. (natural gas marketing and trading), Planergy International, Inc. (enterprise energy management solutions), Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits) and Xcel Energy International Inc. (an international independent power producer).

Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Energy Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc. and Xcel Energy O & M Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

Xcel Energy uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects. Under this method, we reco