10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended Dec. 31, 2002

OR

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

	Exact name of Registrant as specified in its charter, State or other jurisdiction
Commission	of incorporation or organization, Address of principal executive offices and	IRS Employer
File Number	Registrant’s Telephone Number, including area code	Identification No.
000-31709	NORTHERN STATES POWER COMPANY (a Minnesota Corporation) 414 Nicollet Mall, Minneapolis, Minn. 55401 Telephone (612) 330-5500		41-1967505
001-3140	NORTHERN STATES POWER COMPANY (a Wisconsin Corporation) 1414 W. Hamilton Ave., Eau Claire, Wis. 54701 Telephone (715) 839-2625		39-0508315
001-3280	PUBLIC SERVICE COMPANY OF COLORADO (a Colorado Corporation) 1225 17th Street, Denver, Colo. 80202 Telephone (303) 571-7511		84-0296600
001-3789	SOUTHWESTERN PUBLIC SERVICE COMPANY (a New Mexico Corporation) Tyler at Sixth, Amarillo, Texas 79101 Telephone (303) 571-7511		75-0575400

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

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

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

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

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

INDEX

TABLE OF CONTENTS

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

			Page
			No.
PART I
Item 1 — Business				3
	COMPANY OVERVIEW
	UTILITY REGULATION
		Ratemaking Principles		4
		Fuel, Purchased Gas and Resource Adjustment Clauses		5
		Other Regulatory Mechanisms and Requirements		7
		Pending Regulatory Matters		8
	ELECTRIC UTILITY OPERATIONS
		Competition and Industry Restructuring		13
		Capacity and Demand		18
		Energy Sources		18
		Fuel Supply and Costs		20
		Trading Operations		21
		Nuclear Power Operations and Waste Disposal		22
		Electric Operating Statistics		24
	GAS UTILITY OPERATIONS
		Competition and Industry Restructuring		27
		Capability and Demand		28
		Gas Supply and Costs		29
		Gas Operating Statistics		30
	ENVIRONMENTAL MATTERS			32
	EMPLOYEES			33
Item 2 — Properties				33
Item 3 — Legal Proceedings				36
Item 4 — Submission of Matters to a Vote of Security Holders				38
PART II
Item 5 — Market for Registrant’s Common Equity and Related Stockholder Matters				38
Item 6 — Selected Financial Data				38
Item 7 — Management’s Discussion and Analysis				38
Item 7A — Quantitative and Qualitative Disclosures About Market Risk				46
Item 8 — Financial Statements and Supplementary Data				48
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure				124
PART III
Item 10 — Directors and Executive Officers of the Registrant				124
Item 11 — Executive Compensation				124
Item 12 — Security Ownership of Certain Beneficial Owners and Management				124
Item 13 — Certain Relationships and Related Transactions				124
Item 14 — Controls and Procedures				124
PART IV
Item 15 — Exhibits, Financial Statement Schedules, and Reports on Form 8-K				125
SIGNATURES				135

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	Page
	No.
EXHIBIT (EXCERPT)
Ratio of Earnings to Fixed Charges
Statement Pursuant to Private Securities Litigation Reform Act
Exhibit Regarding the Use of Arthur Andersen Audit Firm

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

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Item l.     Business

COMPANY OVERVIEW

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

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

NSP-Minnesota

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

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

NSP-Wisconsin

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

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

PSCo

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

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

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SPS

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

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

UTILITY REGULATION

Ratemaking Principles

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

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

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

NSP-Minnesota

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

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

NSP-Wisconsin

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

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

PSCo

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

SPS

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

Fuel, Purchased Gas and Resource Adjustment Clauses

NSP-Minnesota

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

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

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

NSP-Wisconsin

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

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

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

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

PSCo

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

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

     SPS

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

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

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

Other Regulatory Mechanisms and Requirements

     NSP-Minnesota

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

     PSCo

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

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

•  a 10.50 percent return on equity for 2002;

•  no earnings sharing for 2003;

•  an annual electric earnings test with the sharing of earnings in excess of the return on equity to be determined in the pending 2002 rate case for 2004 through 2006;

•  an electric Quality Service Plan (QSP) that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2006;

•  a gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to gas leak repair time and customer service through 2007; and

•  an ICA that provides for the sharing of energy costs and savings relative to an annual baseline cost per delivered kilowatt-hour. According to the terms of the merger agreement in Colorado, the annual baseline cost was reset in 2002, based on a 2001 test year. The recovery of fuel and purchased energy expense beginning Jan. 1, 2003 will be decided in the 2002 general rate case.

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

     SPS

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

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

Pending Regulatory Matters

     NSP-Minnesota

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

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

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

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

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

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

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

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

•  reduce its Minnesota electric rates by $10 million annually through 2005;

•  not increase its electric rates through 2005, except under limited circumstances;

•  not seek recovery of certain merger costs from customers; and

•  meet various quality standards.

     NSP-Wisconsin

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

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

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

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

9

     PSCo

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

•  file a combined electric, gas and steam rate case in 2002 with new rates effective in January 2003;

•  extend its ICA mechanism through Dec. 31, 2002 with an increase in the ICA base rate from $12.78 per megawatt hour to a rate based on the 2001 actual costs;

•  continue the electric PBRP and the electric QSP through 2006 with an electric department earnings cap of 10.5 percent return on equity for 2002 and no earnings sharing for 2003;

•  develop a gas Quality Service Plan for calendar year 2002 through 2007 performance;

•  reduce electric rates annually by $11 million for the period August 2000 to July 2002; and

•  cap merger costs associated with electric operations at $30 million and amortize such costs through 2002.

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

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

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

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

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

10

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

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

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

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

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

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

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

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

SPS

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

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

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

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

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

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

•  guarantee annual merger savings credits of approximately $4.8 million and amortize merger costs through 2005;

•  retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and

•  comply with various service quality and reliability standards, covering service installations and upgrades, light replacements, customer service call centers and electric service reliability.

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

•  guarantee annual merger savings credits of approximately $780,000 and amortize merger costs through December 2004;

•  share net non-fuel operating and maintenance savings equally among retail customers and shareholders;

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•  retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and

•  not pass along any negative rate impacts of the merger.

ELECTRIC UTILITY OPERATIONS

Competition and Industry Restructuring

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

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

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

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

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

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

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

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

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

13

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

15

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

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

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

     NSP-Minnesota

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

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

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

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

     NSP-Wisconsin

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

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

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

     PSCo

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

     SPS

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

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

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

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

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

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

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

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

Capacity and Demand

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

	System Peak Demand
Operating Company	2000		2001		2002		2003 Forecast
	(in megawatts)
NSP System		7,936		8,344		8,259		8,090
PSCo.		5,406		5,644		5,872		5,947
SPS		3,870		4,080		4,018		4,052

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

Energy Sources

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

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

     Purchased Power

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

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

     NSP System Resource Plan

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

•  forecasts 1.7 percent annual growth in the NSP System’s energy and peak demand requirements;

•  outlines NSP System’s demand side management and conservation programs;

•  identifies various pending legislative and regulatory proceedings affecting over half of the generating capacity necessary to meet the demand for electricity;

•  proposes additional power purchase solicitations to meet growing demand for electricity; and

•  updates the status of spent nuclear fuel at the Prairie Island plant and at the Monticello plant and describes the alternatives to replace nuclear generation if the two plants must be replaced as the result of spent nuclear fuel storage limitations.

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

PSCo Resource Plan

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

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

Purchased Transmission Services

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

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

Fuel Supply and Costs

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

	Coal*					Nuclear
											Average
NSP System Generating Plants	Cost		Percent			Cost		Percent			Fuel Cost
2002	$	0.96		59	%	$	0.46		38	%	$	0.81
2001		0.96		62			0.47		35			0.86
2000		1.11		60			0.45		36			0.91

*  Includes refuse-derived fuel and wood

	Coal					Gas
											Average
PSCo Generating Plants	Cost		Percent			Cost		Percent			Fuel Cost
2002	$	0.91		79	%	$	2.25		21	%	$	1.19
2001		0.86		84			4.27		16			1.41
2000		0.91		87			3.97		13			1.30

	Coal					Gas
											Average
SPS Generating Plants	Cost		Percent			Cost		Percent			Fuel Cost
2002	$	1.33		74	%	$	3.27		26	%	$	1.84
2001		1.40		69			4.35		31			2.31
2000		1.45		70			4.23		30			2.28

NSP-Minnesota and NSP-Wisconsin

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

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

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

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

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

PSCo

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

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

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

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

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

SPS

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

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

Trading Operations

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

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

Nuclear Power Operations and Waste Disposal

      NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively.

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

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

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

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

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

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

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

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

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

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

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

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

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

Nuclear Management Co. (NMC)

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

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

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

Electric Operating Statistics (NSP-Minnesota)

			Year Ended December 31,
			2002		2001		2000
Electric Sales (Millions of Kwh):
	Residential			9,782		9,236		8,995
	Commercial and industrial			23,818		23,697		23,535
	Public authorities and other			274		282		280
		Total retail		33,874		33,215		32,810
	Sales for resale			4,945		6,100		6,764
		Total energy sold		38,819		39,315		39,574
Number of customers at end of period:
	Residential			1,165,237		1,151,235		1,137,649
	Commercial and industrial			139,779		137,267		134,216
	Public authorities and other			5,740		5,577		5,408
		Total retail		1,310,756		1,294,079		1,277,273
	Wholesale			58		81		80
		Total customers		1,310,814		1,294,160		1,277,353
Electric revenues (Thousands of dollars):
	Residential		$	736,485	$	735,683	$	705,502
	Commercial and industrial			1,204,371		1,288,679		1,245,267
	Public authorities and other			30,442		32,759		27,218
	Regulatory accrual adjustment			4,766		15,480		—
		Total retail		1,976,064		2,072,601		1,977,987
	Wholesale			109,147		163,147		179,770
	Sales to NSP-Wisconsin			219,006		236,118		217,122
	Other electric revenues			56,649		97,902		37,004
		Total electric revenues	$	2,360,866	$	2,569,768	$	2,411,883
Kwh sales per retail customer				25,843		25,667		25,688
Revenue per retail customer			$	1,507.58	$	1,601.60	$	1,548.60
Residential revenue per Kwh				7.53¢		7.97¢		7.84¢
Commercial and industrial revenue per Kwh				5.06¢		5.44¢		5.29¢
Wholesale revenue per Kwh				2.21¢		2.67¢		2.66¢

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Electric Operating Statistics (NSP-Wisconsin)

			Year Ended December 31,
			2002		2001		2000
Electric sales (Millions of Kwh):
	Residential			1,874		1,780		1,774
	Commercial and industrial			3,846		3,755		3,786
	Public authorities and other			40		39		40
		Total retail		5,760		5,574		5,600
	Sales for resale			564		527		473
		Total energy sold		6,324		6,101		6,073
Number of customers at end of period:
	Residential			196,701		193,842		191,287
	Commercial and industrial			34,224		33,627		33,075
	Public authorities and other			1,107		1,092		1,047
		Total retail		232,032		228,561		225,409
	Wholesale			10		10		10
		Total customers		232,042		228,571		225,419
Electric revenues (Thousands of dollars):
	Residential		$	142,104	$	135,351	$	131,201
	Commercial and industrial			207,979		202,699		195,298
	Public authorities and other			5,387		4,576		4,450
		Total retail		355,470		342,626		330,949
	Wholesale			20,404		18,706		16,936
	Sales to NSP-Minnesota			80,200		85,895		73,425
	Other electric revenues			2,663		3,668		3,167
		Total electric revenues	$	458,737	$	450,895	$	424,477
Kwh sales per retail customer				24,824		24,387		24,843
Revenue per retail customer			$	1,531.99	$	1,499.06	$	1,468.22
Residential revenue per Kwh				7.58¢		7.60¢		7.40¢
Commercial and industrial revenue per Kwh				5.41¢		5.40¢		5.16¢
Wholesale revenue per Kwh				3.62¢		3.55¢		3.58¢

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Electric Operating Statistics (PSCo)

			Year Ended December 31,
			2002		2001			2000
Electric sales (Millions of Kwh):
	Residential			8,129		7,673			7,647
	Commercial and industrial			17,408		17,223			17,033
	Public authorities and other			277		229			252
		Total retail		25,814		25,125			24,932
	Sales for resale			8,701		11,110			9,148
		Total energy sold		34,515		36,235			34,080
Number of customers at end of period:
	Residential			1,058,082		1,040,029			1,019,961
	Commercial and industrial			139,573		136,671			133,947
	Public authorities and other(1)			68,601		88,083			86,364
		Total retail		1,266,256		1,264,783			1,240,272
	Wholesale			171		159			96
		Total customers		1,266,427		1,264,942			1,240,368
Electric revenues (Thousands of dollars):
	Residential		$	585,035	$	571,308		$	558,153
	Commercial and industrial			866,955		854,397			844,511
	Public authorities and other			32,803		32,169			32,185
		Total retail		1,484,793		1,457,874			1,434,849
	Wholesale			355,713		896,805			577,226
	Other electric revenues			38,364		(12,495	)		2,479
		Total electric revenues	$	1,878,870	$	2,342,184		$	2,014,554
Kwh sales per retail customer				20,386		19,865			20,102
Revenue per retail customer			$	1,172.59	$	1,152.67		$	1,156.88
Residential revenue per Kwh				7.20¢		7.45¢			7.30¢
Commercial and industrial revenue per Kwh				4.98¢		4.96¢			4.96¢
Wholesale revenue per Kwh				4.09¢		8.07¢			6.31¢

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

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Electric Operating Statistics (SPS)

			Year Ended December 31,
			2002		2001		2000
Electric sales (Millions of Kwh):
	Residential			3,300		3,212		3,467
	Commercial and industrial			12,044		12,404		12,383
	Public authorities and other			549		549		608
		Total retail		15,893		16,165		16,458
	Sales for resale			9,045		8,367		9,898
		Total energy sold		24,938		24,532		26,356
Number of customers at end of period:
	Residential			304,971		306,622		311,660
	Commercial and industrial			75,676		74,761		74,343
	Public authorities and other			5,615		5,786		5,705
		Total retail		386,262		387,169		391,708
	Wholesale			70		55		34
		Total customers		386,332		387,224		391,742
Electric revenues (Thousands of dollars):
	Residential		$	192,030	$	236,931	$	198,123
	Commercial and industrial			462,556		595,788		458,719
	Public authorities and other			29,104		21,318		30,275
		Total retail		683,690		854,037		687,117
	Wholesale			287,768		439,817		393,502
	Other electric revenues(1)			53,720		91,604		(1,039	)
		Total electric revenues	$	1,025,178	$	1,385,458	$	1,079,580
Kwh sales per retail customer				41,146		41,752		42,013
Revenue per retail customer			$	1,770.02	$	2,205.85	$	1,754.16
Residential revenue per Kwh				5.82¢		7.38¢		5.72¢
Commercial and industrial revenue per Kwh				3.84¢		4.80¢		3.70¢
Wholesale revenue per Kwh				3.18¢		5.26¢		3.98¢

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

GAS UTILITY OPERATIONS

Competition and Industry Restructuring

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

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

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

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

Capability and Demand

     NSP-Minnesota and NSP-Wisconsin

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

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

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

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

     PSCo

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

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

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

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

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

Gas Supply and Costs

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

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

	NSP-Minnesota		NSP-Wisconsin		PSCo
2002	$	3.98	$	4.63	$	3.17
2001	$	5.83	$	5.11	$	4.99
2000	$	4.56	$	4.71	$	4.48

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

     NSP-Minnesota and NSP-Wisconsin

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

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

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

     PSCo

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

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

Gas Operating Statistics (NSP-Minnesota)

			Year Ended December 31,
			2002		2001		2000
Gas deliveries (Thousands of Dth):
	Residential			38,407		36,880		38,461
	Commercial and industrial			38,320		38,346		41,257
	Other			1,286		2,058		1,225
		Total retail		78,013		77,284		80,943
	Transportation and other			8,559		11,204		9,510
		Total deliveries		86,572		88,488		90,453
Number of customers at end of period:
	Residential			393,538		384,965		371,894
	Commercial and industrial			37,445		36,311		35,381
		Total retail		430,983		421,276		407,275
	Transportation and other			42		74		51
		Total customers		431,025		421,350		407,326
Gas revenues (Thousands of dollars):
	Residential		$	263,178	$	323,611	$	285,868
	Commercial and industrial			199,196		258,803		227,414
	Other			1		166		1,569
		Total retail		462,375		582,580		514,851
	Transportation and other			27,197		42,926		21,849
		Total gas revenues	$	489,572	$	625,506	$	536,700
Dth sales per retail customer				181.01		183.45		198.74
Revenue per retail customer			$	1,072.84	$	1,382.89	$	1,264.14
Residential revenue per Dth			$	6.85	$	8.77	$	7.43
Commercial and industrial revenue per Dth			$	5.20	$	6.75	$	5.51
Transportation and other revenue per Dth			$	3.18	$	3.83	$	2.30

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Gas Operating Statistics (NSP-Wisconsin)

			Year Ended December 31,
			2002		2001		2000
Gas deliveries (Thousands of Dth):
	Residential			6,720		5,554		6,281
	Commercial and industrial			11,800		11,479		11,544
	Other			722		1,415		868
		Total retail		19,242		18,448		18,693
	Transportation and other			1,413		1,399		1,353
		Total deliveries		20,655		19,847		20,046
Number of customers at end of period:
	Residential			81,252		79,027		75,449
	Commercial and industrial			11,140		11,002		10,626
		Total retail		92,392		90,029		86,075
	Transportation and other			5		5		—
		Total customers		92,397		90,034		86,075
Gas revenues (Thousands of dollars):
	Residential		$	49,426	$	51,049	$	49,156
	Commercial and industrial			52,223		69,084		58,249
	Other			—		2,102		1,946
		Total retail		101,649		122,235		109,351
	Transportation and other			494		818		672
		Total gas revenues	$	102,143	$	123,053	$	110,023
Dth sales per retail customer				208.27		204.91		217.17
Revenue per retail customer			$	1,100.19	$	1,357.73	$	1,270.42
Residential revenue per Dth			$	7.36	$	9.19	$	7.83
Commercial and industrial revenue per Dth			$	4.43	$	6.02	$	5.05
Transportation and other revenue per Dth			$	0.35	$	0.58	$	0.50

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Gas Operating Statistics (PSCo)

			Year Ended December 31,
			2002		2001		2000
Gas deliveries (Thousands of Dth):
	Residential			95,882		91,389		90,270
	Commercial and industrial			43,449		45,036		41,165
		Total retail		139,331		136,425		131,435
	Transportation and other			120,626		122,513		117,992
		Total deliveries		259,957		258,938		249,427
Number of customers at end of period:
	Residential			1,063,378		1,032,529		1,001,951
	Commercial and industrial			96,669		95,879		94,516
		Total retail		1,160,047		1,128,408		1,096,467
	Transportation and other			3,134		2,967		3,173
		Total customers		1,163,181		1,131,375		1,099,640
Gas revenues (Thousands of dollars):
	Residential		$	510,890	$	832,320	$	526,409
	Commercial and industrial			192,419		366,048		208,589
		Total retail		703,309		1,198,368		734,998
Transportation and other				46,046		53,173		52,112
		Total gas revenues	$	749,355	$	1,251,541	$	787,110
Dth sales per retail customer				120.11		120.90		119.87
Revenue per retail customer			$	606.28	$	1,060.20	$	670.33
Residential revenue per Dth			$	5.33	$	9.11	$	5.83
Commercial and industrial revenue per Dth			$	4.43	$	8.13	$	5.07
Transportation and other revenue per Dth			$	0.38	$	0.43	$	0.44

ENVIRONMENTAL MATTERS

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

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

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EMPLOYEES

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

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

Item 2.     Properties

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

      Electric utility generating stations:

NSP-Minnesota

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

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

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NSP-Wisconsin

						Summer 2002
						Net Dependable
Station, City and Unit				Fuel	Installed	Capability (Mw)
	Combustion Turbine:
		Flambeau Station — Park Falls, Wis.
			1 Unit	Natural Gas/Oil	1969		12
		Wheaton — Eau Claire, Wis.
			6 Units	Natural Gas/Oil	1973		345
		French Island — La Crosse, Wis.
			2 Units	Oil	1974		142
	Steam:
		Bay Front — Ashland, Wis.
			3 Units	Coal/Wood/Natural Gas	1945 - 1960		76
		French Island — La Crosse, Wis.
			2 Units	Wood/RDF*	1940 - 1948		27
	Hydro:
			19 Plants		Various		249
Total							851

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

PSCo

					Summer 2002 Net
					Dependable
Station, City and Unit			Fuel	Installed	Capability (Mw)
Steam:
	Arapahoe — Denver, Colo.
		2 Units	Coal	1950 - 1955		156
	Cameo — Grand Junction, Colo.
		2 Units	Coal	1957 - 1960		73
	Cherokee — Denver, Colo.
		4 Units	Coal	1957 - 1968		717
	Comanche — Pueblo, Colo.
		2 Units	Coal	1973 - 1975		660
	Craig — Craig, Colo.
		2 Units	Coal	1979 - 1980		83	(a)
	Hayden — Hayden, Colo.
		2 Units	Coal	1965 - 1976		237	(b)
	Pawnee — Brush, Colo.		Coal	1981		505
	Valmont — Boulder, Colo.		Coal	1964		186
	Zuni — Denver, Colo.
		3 Units	Natural Gas/Oil	1948 - 1954		107

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						Summer 2002 Net
						Dependable
Station, City and Unit				Fuel	Installed	Capability (Mw)
	Combustion Turbines:
		Fort St. Vrain — Platteville, Colo.
			4 Units	Natural Gas	1972 - 2001		690
		Various Locations
			6 Units	Natural Gas	Various		171
	Hydro:
		Various Locations
			12 Units		Various		32
		Cabin Creek — Georgetown, Colo.			1967		210
			Pumped Storage
	Wind:
		Ponnequin — Weld County, Colo.			1999 - 2001		—
	Diesel Generators:
		Cherokee — Denver, Colo.
			2 Units		1967		6
Total							3,833

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

SPS

					Summer 2002 Net
					Dependable
Station, City and Unit			Fuel	Installed	Capability (Mw)
Steam:
	Harrington — Amarillo, Texas
		3 Units	Coal	1976 - 1980		1,066
	Tolk — Muleshoe, Texas
		2 Units	Coal	1982 - 1985		1,080
	Jones — Lubbock, Texas
		2 Units	Natural Gas	1971 - 1974		486
	Plant X — Earth, Texas
		4 Units	Natural Gas	1952 - 1964		442
	Nichols — Amarillo, Texas
		3 Units	Natural Gas	1960 - 1968		457
	Cunningham — Hobbs, N.M.
		2 Units	Natural Gas	1957 - 1965		267
	Maddox — Hobbs, N.M.		Natural Gas	1983		118
	CZ-2-Pampa, Texas		Purchased Steam	1979		26
	Moore County — Amarillo, Texas		Natural Gas	1954		48

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						Summer 2002 Net
						Dependable
Station, City and Unit				Fuel	Installed	Capability (Mw)
	Gas Turbine:
			Carlsbad — Carlsbad, N.M.	Natural Gas	1977		13
			CZ-1-Pampa, Texas	Hot Nitrogen	1965		13
			Maddox — Hobbs, N.M.	Natural Gas	1983		65
			Riverview — Electric City, Texas	Natural Gas	1973		23
			Cunningham — Hobbs, N.M.	Natural Gas	1998		220
	Diesel:
		Tucumcari — N.M.
			6 Units		1941 - 1968		—
Total							4,324

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

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

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

Quantity	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
		360		205		209		492

      Gas utility mains at Dec. 31, 2002:

Miles	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
Transmission		115		—		2,263		—
Distribution		8,608		1,929		18,114		—

Item 3. Legal Proceedings

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

     NSP-Minnesota

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

36

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

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

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

     NSP-Wisconsin

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

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

37

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

     SPS

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

     Other Matters

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

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

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

PART II

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

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

Item 6.      Selected Financial Data

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

Item 7.      Management’s Discussion and Analysis

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

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Forward Looking Information

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

      Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

•  general economic conditions, including their impact on capital expenditures;

•  rating agency actions;

•  business conditions in the energy industry;

•  competitive factors;

•  unusual weather;

•  changes in federal or state legislation;

•  regulation; and

•  the other risk factors listed from time to time by the utility subsidiaries of Xcel Energy in reports filed with the SEC, including Exhibit 99.01 to this Report on Form 10-K for the year ended Dec. 31, 2002.

NSP-Minnesota’s Management’s Discussion and Analysis

Results of Operations

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

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

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

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

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

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

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

39

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

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

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

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

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

	2002			2001
	(Millions of
	dollars)
Gas utility revenue	$	490		$	626
Cost of gas sold and transported		(344	)		(477	)
Gas utility margin	$	146		$	149

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

40

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

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

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

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

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

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

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

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

NSP-Wisconsin’s Management’s Discussion and Analysis

Results of Operations

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

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

	Total Electric
	Utility
	2002			2001
	(Millions of
	dollars)
Electric utility revenue	$	459		$	451
Electric fuel and purchased power		(212	)		(233	)
Gross margin before operating expenses	$	247		$	218
Margin as a percentage of revenue		53.8	%		48.3	%

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

41

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

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

	2002			2001
	(Millions of
	dollars)
Gas utility revenue	$	102		$	123
Cost of gas sold and transported		(72	)		(96	)
Gas utility margin	$	30		$	27

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

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

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

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

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

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

PSCo’s Management’s Discussion and Analysis

Results Of Operations

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

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

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

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

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

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

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

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

	2002			2001
	(Millions of
	Dollars)
Gas utility revenue	$	749		$	1,252
Cost of gas sold and transported		(422	)		(931	)
Gas utility margin	$	327		$	321

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

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

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

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

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

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

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

SPS’ Management’s Discussion and Analysis

Results of Operations

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Item 7A.     Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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

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

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

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

	2002		2001
	(Millions of
	dollars)
NSP-Minnesota	$	2.9	$	4.9
PSCo.	$	4.3	$	1.4
SPS	$	0.3	$	3.9

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

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

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

      Our trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. Xcel Energy utilizes the variance/ covariance approach in calculating VaR. The VaR model employs a 95 percent confidence interval level based on historical price movement, lognormal price distribution assumption and various holding periods varying from two to five days.

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

			During 2002
	Year Ended
Operations	Dec. 31, 2002		Average		High		Low
	(Millions of Dollars)
Electric Commodity Trading		0.29		0.62		3.39		0.01

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

			During 2001
	Year Ended
Operations	Dec. 31, 2001		Average		High		Low
	(Millions of Dollars)
Electric Commodity Trading		0.52		1.71		7.37		0.16

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

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

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

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Item 8.     Financial Statements and Supplemental Data

INDEPENDENT AUDITORS’ REPORT

To Northern States Power Company-Minnesota:

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

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

      We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

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

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2003

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

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — NSP-Minnesota

To Northern States Power Company-Minnesota:

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

      We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

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

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

/s/ ARTHUR ANDERSEN, LLP

ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota

February 21, 2002

49

INDEPENDENT AUDITORS’ REPORT

To Northern States Power Company-Wisconsin:

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

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

      We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

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

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2003

50

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

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — NSP-Wisconsin

To Northern States Power Company-Wisconsin:

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

      We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

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

/s/ ARTHUR ANDERSEN, LLP

ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota

February 21, 2002

51

INDEPENDENT AUDITORS’ REPORT

To Public Service Company of Colorado:

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

      We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

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

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2003

52

INDEPENDENT AUDITORS’ REPORT

To Southwestern Public Service Company:

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

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

      We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

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

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2003

53

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

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — SPS

To Southwestern Public Service Company:

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

      We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

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

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

/s/ ARTHUR ANDERSEN, LLP

ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota

February 21, 2002

54

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF INCOME

			Year Ended December 31,
			2002		2001		2000
			(Thousands of dollars)
Operating revenues:
	Electric utility		$	2,360,866	$	2,569,768	$	2,411,883
	Gas utility			489,572		625,506		536,700
	Electric trading margin			1,806		385		—
	Other			30,875		52,836		51,900
		Total operating revenues		2,883,119		3,248,495		3,000,483
Operating expenses:
	Electric fuel and purchased power			789,379		981,506		869,421
	Cost of gas sold and transported			343,700		476,528		382,596
	Operating and maintenance expenses			825,451		824,416		798,666
	Depreciation and amortization			354,157		339,509		323,935
	Taxes (other than income taxes)			168,721		175,209		202,245
	Special charges (see Note 2)			3,727		13,543		72,095
		Total operating expenses		2,485,135		2,810,711		2,648,958
Operating income				397,984		437,784		351,525
Other income (expenses) — net				25,069		3,713		(5,725	)
Interest charges and financing costs:
	Interest charges — net of amounts capitalized; includes other financing costs of $5,241, $4,489 and $5,158, respectively			98,940		85,150		126,635
	Distributions on redeemable preferred securities of subsidiary trust			15,750		15,750		15,750
		Total interest charges and financing costs		114,690		100,900		142,385
Income before income taxes				308,363		340,597		203,415
Income taxes				108,141		132,732		92,191
Net income			$	200,222	$	207,865	$	111,224

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

55

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Year Ended December 31,
				2002			2001			2000
				(Thousands of dollars)
Operating activities:
	Net income			$	200,222		$	207,865		$	111,224
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			366,362			358,718			340,868
		Nuclear fuel amortization			48,675			41,928			44,591
		Deferred income taxes			(26,280	)		10,414			1,341
		Amortization of investment tax credits			(7,490	)		(8,046	)		(9,017	)
		Allowance for equity funds used during construction			(5,491	)		(4,898	)		4,176
		Conservation incentive accrual adjustments			(9,152	)		(49,271	)		19,248
		Special charges — not requiring cash			1,567			12,888			14,932
		Gain on sale of nonutility property			(6,785	)		—			—
		Change in accounts receivable			1,649			72,775			16,016
		Change in inventories			(4,296	)		(5,363	)		(2,447	)
		Change in other current assets			25,340			62,903			(64,324	)
		Change in accounts payable			(12,745	)		(64,722	)		123,059
		Change in other current liabilities			54,404			(26,441	)		(42,460	)
		Change in other assets and liabilities			25,107			(45,996	)		(64,942	)
			Net cash provided by operating activities		651,087			562,754			492,265
Investing activities:
	Utility capital/ construction expenditures				(383,857	)		(483,936	)		(391,727	)
	Allowance for equity funds used during construction				5,491			4,898			(4,176	)
	Proceeds from sale of property				11,152			—			—
	Investments in external decommissioning fund				(57,830	)		(54,996	)		(48,967	)
	Restricted cash				(23,000	)		—			—
	Other investments — net				(4,939	)		(5,922	)		454
		Net cash used in investing activities			(452,983	)		(539,956	)		(444,416	)
Financing activities:
	Short-term borrowings — net				(381,115	)		21,995			(61,005	)
	Proceeds from issuance of long-term debt				624,892			—			76,127
	Repayment of long-term debt, including reacquisition premiums				(4,876	)		(155,081	)		(180,730	)
	Capital contributions from parent				51,714			282,768			358,632
	Dividends and cash distributions paid to parent				(195,550	)		(167,237	)		(240,291	)
		Net cash provided by (used in) financing activities			95,065			(17,555	)		(47,267	)
Net increase in cash and cash equivalents					293,169			5,243			582
Cash and cash equivalents at beginning of year					17,169			11,926			11,344
Cash and cash equivalents at end of year				$	310,338		$	17,169		$	11,926
Supplemental disclosure of cash flow information:
	Cash paid for interest (net of amounts capitalized)			$	75,315		$	84,789		$	128,530
	Cash paid for income taxes (net of refunds received)			$	83,636		$	84,957		$	105,720

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

56

NSP-MINNESOTA

CONSOLIDATED BALANCE SHEETS

			December 31,			December 31,
			2002			2001
			(Thousands of dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	310,338		$	17,169
	Restricted cash			23,000			—
	Accounts receivable — net of allowance for bad debts: $5,812 and $5,452, respectively			231,996			227,007
	Accounts receivable from affiliates			24,773			31,528
	Accrued unbilled revenues			109,435			125,770
	Materials and supplies inventories			106,037			103,934
	Fuel inventory			34,875			31,945
	Gas inventory			24,385			25,122
	Derivative instruments valuation — at market			3,831			204
	Prepayments and other			34,234			48,285
		Total current assets		902,904			610,964
Property, plant and equipment, at cost:
	Electric utility plant			6,855,807			6,582,337
	Gas utility plant			716,844			695,338
	Construction work in progress			313,931			316,468
	Other			384,214			368,513
		Total property, plant and equipment		8,270,796			7,962,656
	Less accumulated depreciation			(4,624,988	)		(4,310,214	)
	Nuclear fuel — net of accumulated amortization: $1,058,531 and $1,009,855, respectively			74,139			96,315
		Net property, plant and equipment		3,719,947			3,748,757
Other assets:
	Nuclear decommissioning fund investments			617,048			596,113
	Other investments			22,730			22,542
	Regulatory assets			212,539			226,088
	Prepaid pension asset			263,713			188,287
	Other			72,144			64,278
		Total other assets		1,188,174			1,097,308
		Total assets	$	5,811,025		$	5,457,029
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	226,462		$	153,134
	Short-term debt			69			381,184
	Accounts payable			198,889			235,930
	Accounts payable to affiliates			66,866			42,550
	Taxes accrued			210,041			168,491
	Dividends payable to parent			52,280			44,332
	Derivative instruments valuation — at market			3,958			—
	Other			83,464			76,004
		Total current liabilities		842,029			1,101,625
Deferred credits and other liabilities:
	Deferred income taxes			700,966			697,605
	Deferred investment tax credits			74,577			82,598
	Regulatory liabilities			486,035			468,051
	Benefit obligations and other			136,452			133,771
		Total deferred credits and other liabilities		1,398,030			1,382,025
Long-term debt				1,569,938			1,039,220
Mandatorily redeemable preferred securities of subsidiary trust (see Note 6)				200,000			200,000
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares				10			10
Premium on common stock				813,869			762,155
Retained earnings				987,158			990,435
Leveraged ESOP				—			(18,564	)
Accumulated other comprehensive (loss) income				(9	)		123
	Total common stockholder’s equity			1,801,028			1,734,159
Commitments and contingencies (see Note 13)
Total liabilities and equity			$	5,811,025		$	5,457,029

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

57

NSP-MINNESOTA

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

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

(a)  Did not affect cash flows.

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

58

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

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

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

59

NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF INCOME

				Year Ended December 31,
				2002		2001		2000
				(Thousands of dollars)
Operating revenues:
	Electric utility			$	458,737	$	450,895	$	424,477
	Gas utility				102,143		123,053		110,023
	Other				761		692		670
		Total operating revenues			561,641		574,640		535,170
Operating expenses:
	Electric fuel and purchased power				212,180		233,165		210,088
	Cost of gas sold and transported				72,260		95,617		81,843
	Operating and maintenance expenses				102,496		106,999		105,235
	Depreciation and amortization				44,466		41,645		40,502
	Taxes (other than income taxes)				16,066		15,944		15,350
	Special charges (see Note 2)				675		2,488		12,848
			Total operating expenses		448,143		495,858		465,866
Operating income					113,498		78,782		69,304
Other income (expense) — net					917		837		937
Interest charges — net of amounts capitalized; includes other financing costs of $896, $896 and $840, respectively					23,117		22,069		19,255
Income before income taxes					91,298		57,550		50,986
Income taxes					36,925		21,158		20,690
Net income				$	54,373	$	36,392	$	30,296

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

60

NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Year Ended December 31,
				2002			2001			2000
				(Thousands of dollars)
Operating activities:
	Net income			$	54,373		$	36,392		$	30,296
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			45,641			42,724			41,473
		Deferred income taxes			21,682			3,049			1,868
		Amortization of investment tax credits			(808	)		(819	)		(827	)
		Allowance for equity funds used during construction			(641	)		(1,449	)		(200	)
		Undistributed equity in earnings of unconsolidated affiliates			(232	)		(553	)		(411	)
		Special charges — not requiring cash			171			2,427			2,459
		Changes in accounts receivable			(14,473	)		13,696			(16,127	)
		Change in inventories			(1,213	)		(485	)		(31	)
		Change in other current assets			2,213			7,377			(10,235	)
		Change in accounts payable			15,889			(47,930	)		24,265
		Change in other current liabilities			(2,923	)		1,645			2,162
		Change in other assets and liabilities			(10,716	)		(8,363	)		(3,599	)
			Net cash provided by operating activities		108,963			47,711			71,093
Investing activities:
	Utility capital/ construction expenditures				(38,414	)		(62,010	)		(88,624	)
	Allowance for equity funds used during construction				641			1,449			200
	Other investments — net				240			611			(161	)
			Net cash used in investing activities		(37,533	)		(59,950	)		(88,585	)
Financing activities:
	Short-term borrowings — net				(27,420	)		18,400			(64,900	)
	Proceeds from issuance of long-term debt				—			—			79,399
	Repayment of long-term debt				(34	)		(34	)		—
	Contribution of capital by parent				3,210			26,353			—
	Issuance of common stock to parent				—			—			29,977
	Dividends paid to parent				(47,118	)		(32,481	)		(27,004	)
			Net cash provided by (used in) financing activities		(71,362	)		12,238			17,472
	Net increase (decrease) in cash and cash equivalents				68			(1	)		(20	)
	Cash and cash equivalents at beginning of year				30			31			51
	Cash and cash equivalents at end of year			$	98		$	30		$	31
Supplemental disclosure of cash flow information:
	Cash paid for interest (net of amounts capitalized)			$	21,399		$	20,227		$	17,175
	Cash paid for income taxes (net of refunds received)			$	13,456		$	16,821		$	22,665

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

61

NSP-WISCONSIN

CONSOLIDATED BALANCE SHEETS

			December 31,			December 31,
			2002			2001
			(Thousands of dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	98		$	30
	Accounts receivable — net of allowance for bad debts: $1,373 and $969, respectively			47,890			31,870
	Accounts receivable from affiliates			1,460			3,006
	Accrued unbilled revenues			20,074			20,596
	Material and supplies inventories — at average cost			5,994			5,885
	Fuel inventory — at average cost			6,006			5,854
	Gas inventory — at average cost			4,263			3,311
	Prepaid taxes			13,735			13,157
	Prepayments and other			1,681			3,949
		Total current assets		101,201			87,658
Property, plant and equipment, at cost:
	Electric utility plant			1,161,901			1,132,114
	Gas utility plant			131,969			127,635
	Other			113,936			115,435
		Total property, plant and equipment		1,407,806			1,375,184
	Less accumulated depreciation			(592,187	)		(553,467	)
		Net property, plant and equipment		815,619			821,717
Other assets:
	Other investments			9,817			9,824
	Regulatory assets			48,112			37,123
	Prepaid pension asset			38,557			28,563
	Other			7,577			7,373
		Total other assets		104,063			82,883
		Total assets	$	1,020,883		$	992,258
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	40,034		$	34
	Notes payable to affiliate			6,880			34,300
	Accounts payable			23,535			14,482
	Accounts payable to affiliates			6,836			—
	Dividends payable to parent			12,260			10,988
	Other			20,225			22,515
		Total current liabilities		109,770			82,319
Deferred credits and other liabilities:
	Deferred income taxes			146,471			119,895
	Deferred investment tax credits			14,820			15,628
	Regulatory liabilities			11,950			16,891
	Benefit obligations and other			46,026			34,925
		Total deferred credits and other liabilities		219,267			187,339
Long-term debt				273,108			313,054
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares				93,300			93,300
Premium on common stock				62,981			59,771
Retained earnings				262,457			256,475
		Total common stockholder’s equity		418,738			409,546
Commitments and contingencies (see Note 13)
		Total liabilities and equity	$	1,020,883		$	992,258

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

62

NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

	Common Stock				Premium on					Total
					Common		Retained			Stockholder’s
	Shares		Amount		Stock		Earnings			Equity
	(Thousands of dollars, except share information)
Balance at Dec. 31, 1999		862,000	$	86,200	$	10,541	$	260,259		$	357,000
Net income								30,296			30,296
Common dividends declared to parent								(27,004	)		(27,004	)
Issuance of common stock to parent		71,000		7,100		22,877					29,977
Balance at Dec. 31, 2000		933,000		93,300		33,418		263,551			390,269
Net income								36,392			36,392
Common dividends declared to parent								(43,468	)		(43,468	)
Contribution of capital by parent						26,353					26,353
Balance at Dec. 31, 2001		933,000		93,300		59,771		256,475			409,546
Net income								54,373			54,373
Common dividends declared to parent								(48,391	)		(48,391	)
Contribution of capital by parent						3,210					3,210
Balance at Dec. 31, 2002		933,000	$	93,300	$	62,981	$	262,457		$	418,738

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

63

NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

(a)  Resource recovery financing

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

64

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF INCOME

			Year Ended December 31,
			2002			2001			2000
			(Thousands of dollars)
Operating revenues:
	Electric utility		$	1,878,870		$	2,342,184		$	2,014,554
	Electric trading margin			(677	)		23,655			25,100
	Gas utility			749,355			1,251,541			787,110
	Steam and other			24,365			32,465			26,751
		Total operating revenues		2,651,913			3,649,845			2,853,515
Operating expenses:
	Electric fuel and purchased power			890,135			1,352,839			1,132,418
	Cost of gas sold and transported			422,442			931,246			486,800
	Cost of sales — steam			4,746			9,554			6,177
	Operating and maintenance expenses			469,090			474,466			413,665
	Depreciation and amortization			247,598			239,309			210,704
	Taxes (other than income taxes)			77,042			70,680			77,885
	Special charges (see Note 2)			622			38,033			78,779
		Total operating expenses		2,111,675			3,116,127			2,406,428
Operating income				540,238			533,718			447,087
Other income				76,942			78,324			73,904
Other expense				(81,583	)		(73,746	)		(60,802	)
Interest charges and financing costs:
	Interest charges — net of amounts capitalized, includes other financing costs of $3,780, $3,691, and $4,741, respectively			127,487			116,028			146,091
	Distributions on redeemable preferred securities of subsidiary trust			14,744			15,200			15,200
		Total interest charges and financing costs		142,231			131,228			161,291
Income before income taxes and extraordinary item				393,366			407,068			298,898
Income taxes				128,686			132,501			102,770
Income before extraordinary item				264,680			274,567			196,128
Extraordinary item, net of income taxes of $940 (see Note 4)				—			(1,534	)		—
Net income			$	264,680		$	273,033		$	196,128

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

65

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Year Ended December 31,
				2002			2001			2000
				(Thousands of dollars)
Operating activities:
	Net income			$	264,680		$	273,033		$	196,128
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			255,712			242,999			216,212
		Deferred income taxes			108,721			(13,309	)		(8,582	)
		Amortization of investment tax credits			(4,665	)		(4,152	)		(5,481	)
		Allowance for equity funds used during construction			24			(393	)		(54	)
		Special charges — not requiring cash			267			37,699			2,333
		Extraordinary item — net of tax (see Note 4)			—			1,534			—
		Change in accounts receivable			24,763			19,044			(29,653	)
		Change in accrued utility revenues			65,198			99,851			(148,688	)
		Change in recoverable purchased gas and electric energy costs			(74,077	)		132,032			(106,098	)
		Change in inventories			(18,091	)		(35,216	)		36,480
		Change in prepayments and other current assets			8,881			(6,166	)		26,788
		Change in accounts payable			(61,134	)		(260,236	)		278,703
		Change in other current liabilities			(56,964	)		9,441			(1,072	)
		Change in other assets and liabilities			(69	)		11,063			3,688
			Net cash provided by operating activities		513,246			507,224			460,704
Investing activities:
	Capital/ construction expenditures				(443,176	)		(469,768	)		(373,566	)
	Proceeds from disposition of property, plant and equipment				17,322			11,074			10,514
	Allowance for equity funds used during construction				(24	)		393			54
	Payment received for notes receivable from affiliate				—			—			192,620
	Other investments — net				(2,207	)		1,046			1,521
			Net cash used in investing activities		(428,085	)		(457,255	)		(168,857	)
Financing activities:
	Short-term borrowings — net				(488,161	)		436,177			(200,992	)
	Proceeds from issuance of long-term debt-net				593,599			—			101,020
	Repayment of long-term debt, including reacquisition premiums				(18,674	)		(273,159	)		(207,124	)
	Capital contribution from parent				62,200			15,249			160,000
	Dividends paid to parent				(230,867	)		(221,266	)		(180,786	)
			Net cash used in financing activities		(81,903	)		(42,999	)		(327,882	)
Net increase (decrease) in cash and cash equivalents					3,258			6,970			(36,035	)
	Cash and cash equivalents at beginning of year				22,666			15,696			51,731
	Cash and cash equivalents at end of year			$	25,924		$	22,666		$	15,696
Supplemental disclosure of cash flow information:
	Cash paid for interest (net of amounts capitalized)			$	112,179		$	117,316		$	162,823
	Cash paid for income taxes (net of refunds received)			$	15,255		$	130,917		$	104,349

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

66

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED BALANCE SHEETS

			December 31,			December 31,
			2002			2001
			(Thousands of dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	25,924		$	22,666
	Accounts receivable — net of allowance for bad debts: $13,685 and $14,510, respectively			165,743			209,913
	Accounts receivable from affiliates			19,407			—
	Accrued unbilled revenues			203,969			269,167
	Recoverable purchased gas and electric energy costs			23,131			16,763
	Materials and supplies inventories			49,579			40,893
	Fuel inventory			25,366			22,135
	Gas inventories — replacement cost in excess of LIFO: $20,502 and $11,331, respectively			85,679			79,505
	Derivative instruments valuation — at market			2,735			3,855
	Prepayments and other			13,257			56,001
		Total current assets		614,790			720,898
Property, plant and equipment, at cost:
	Electric utility plant			5,345,464			5,253,693
	Gas utility plant			1,494,017			1,416,730
	Construction work in progress			456,800			273,539
	Other			624,764			586,261
		Total property, plant and equipment		7,921,045			7,530,223
	Less accumulated depreciation			(2,896,978	)		(2,746,687	)
		Net property, plant and equipment		5,024,067			4,783,536
Other assets:
	Other investments			12,319			10,112
	Regulatory assets			238,600			192,841
	Prepaid pension asset			—			60,797
	Other			35,150			72,694
		Total other assets		286,069			336,444
		Total assets	$	5,924,926		$	5,840,878
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	282,097		$	17,174
	Short-term debt			88,074			562,812
	Note payable to affiliate			15,142			28,565
	Accounts payable			318,005			359,406
	Accounts payable to affiliates			40,449			60,151
	Taxes accrued			47,363			60,780
	Dividends payable to parent			60,550			53,387
	Derivative instruments valuation — at market			2,593			50,385
	Accrued interest			44,391			32,717
	Other			75,872			108,528
		Total current liabilities		974,536			1,333,905
Deferred credits and other liabilities:
	Deferred income taxes			553,006			564,268
	Deferred investment tax credits			74,987			79,652
	Regulatory liabilities			45,707			49,048
	Other deferred credits			5,052			12,435
	Customers’ advances for construction			142,992			85,582
	Minimum pension liability			104,773			—
	Benefit obligations and other			69,283			66,835
		Total deferred credits and other liabilities		995,800			857,820
Long-term debt				1,782,128			1,465,055
Mandatorily redeemable preferred securities of subsidiary trust (see Note 6)				194,000			194,000
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares				—			—
Premium on common stock				1,652,284			1,590,084
Retained earnings				430,997			404,347
Accumulated comprehensive income (loss)				(104,819	)		(4,333	)
		Total common stockholder’s equity		1,978,462			1,990,098
Commitments and contingencies (see Note 13)
		Total liabilities and equity	$	5,924,926		$	5,840,878

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

67

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND OTHER COMPREHENSIVE INCOME

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

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

68

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

(b) Pollution control financing.

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

69

SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF INCOME

			Year Ended December 31,
			2002		2001		2000
			(Thousands of dollars)
Operating revenues			$	1,025,178	$	1,385,458	$	1,079,580
Operating expenses:
	Electric fuel and purchased power			554,874		863,624		582,013
	Operating and maintenance expenses			156,880		154,410		149,036
	Depreciation and amortization			89,087		83,972		78,526
	Taxes (other than income taxes)			54,105		48,383		47,407
	Special charges (see Note 2)			5,114		4,512		24,345
		Total operating expenses		860,060		1,154,901		881,327
Operating income				165,118		230,557		198,253
Other income (expense) — net				6,025		11,814		11,468
Interest charges and financing costs:
	Interest charges — net of amounts capitalized; includes other financing costs of $6,138, $1,614 and $1,720 respectively			46,048		45,067		54,643
	Distributions on redeemable preferred securities of subsidiary trust			7,850		7,850		7,850
		Total interest charges and financing costs		53,898		52,917		62,493
Income before income taxes and extraordinary items				117,245		189,454		147,228
Income taxes				43,363		71,175		58,776
Income before extraordinary items				73,882		118,279		88,452
Extraordinary items, net of income taxes of $0, $5,747 and $(8,549), respectively (see Note 10)				—		11,821		(18,960	)
Net income			$	73,882	$	130,100	$	69,492

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

70

SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Year Ended December 31,
				2002			2001			2000
				(Thousands of dollars)
Operating activities:
	Net income			$	73,882		$	130,100		$	69,492
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			97,595			88,183			82,617
		Deferred income taxes			29,885			3,609			45,871
		Amortization of investment tax credits			(250	)		(250	)		(250	)
		Allowance for equity funds used during construction			—			—			11
		Special charges — not requiring cash			5,321			4,377			—
		Deferred energy costs			(56,322	)		104,249			(102,300	)
		Extraordinary items (see Note 10)			—			(11,821	)		18,960
		Change in accounts receivable			(10,559	)		17,191			5,049
		Change in inventories			(4,575	)		583			5,766
		Change in other current assets			27,036			(8,641	)		(44,625	)
		Change in accounts payable			9,045			(68,056	)		55,118
		Change in other current liabilities			(19,311	)		50,270			(3,056	)
		Change in other assets and liabilities			(14,214	)		(47,012	)		(45,485	)
			Net cash provided by operating activities		137,533			262,782			87,168
Investing activities:
	Capital/ construction expenditures				(57,116	)		(117,431	)		(103,915	)
	Allowance for equity funds used during construction				—			—			(11	)
	Proceeds from (cost of) disposition of property, plant and equipment				5,393			(3,592	)		(3,433	)
	Other investments — net				(3,037	)		119,986			(6,349	)
			Net cash used in investing activities		(54,760	)		(1,037	)		(113,708	)
Financing activities:
	Short-term borrowings — net				—			(674,579	)		496,834
	Proceeds from issuance of long-term debt — net				—			500,168			—
	Repayment of long-term debt, including reacquisition premiums				—			—			(383,145	)
	Capital contribution by parent				5,793			52,437			—
	Dividends paid to parent				(93,365	)		(85,098	)		(77,855	)
			Net cash provided by (used in) financing activities		(87,572	)		(207,072	)		35,834
	Net increase (decrease) in cash and cash equivalents				(4,799	)		54,673			9,294
	Cash and cash equivalents at beginning of year				65,499			10,826			1,532
	Cash and cash equivalents at end of year			$	60,700		$	65,499		$	10,826
Supplemental disclosure of cash flow information:
	Cash paid for interest (net of amounts capitalized)			$	37,870		$	45,001		$	70,857
	Cash paid for income taxes (net of refunds received)			$	37,112		$	83,715		$	17,490

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

71

SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED BALANCE SHEETS

			December 31,			December 31,
			2002			2001
			(Thousands of dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	60,700		$	65,499
	Accounts receivable — net of allowance for bad debts: $1,559 and $1,785, respectively			49,460			61,688
	Accounts receivable from affiliates			22,787			—
	Accrued unbilled revenues			52,999			75,924
	Recoverable electric energy costs			16,439			—
	Materials and supplies inventories — at average cost			17,231			12,588
	Fuel and gas inventories — at average cost			1,322			1,390
	Current portion of accumulated deferred income taxes			—			10,068
	Prepayments and other			6,059			10,170
		Total current assets		226,997			237,327
Property, plant and equipment, at cost:
	Electric utility plant			3,076,970			3,056,459
	Other and construction work in progress			64,908			55,436
		Total property, plant and equipment		3,141,878			3,111,895
	Less accumulated depreciation			(1,338,340	)		(1,275,501	)
		Net property, plant and equipment		1,803,538			1,836,394
Other assets:
	Other investments			14,382			11,345
	Regulatory assets			105,404			96,613
	Prepaid pension asset			105,044			82,503
	Deferred charges and other			9,979			36,598
		Total other assets		234,809			227,059
		Total assets	$	2,265,344		$	2,300,780
LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable		$	73,536		$	72,204
	Accounts payable to affiliates			9,604			1,891
	Taxes accrued			24,107			35,274
	Accrued interest			7,630			9,696
	Dividends payable to parent			24,427			20,969
	Current portion of accumulated deferred income taxes			13,034			—
	Recovered electric energy costs			—			39,883
	Derivative instruments valuation — at market			1,176			1,131
	Other			22,473			28,222
		Total current liabilities		175,987			209,270
Deferred credits and other liabilities:
	Deferred income taxes			399,800			392,907
	Deferred investment tax credits			4,217			4,467
	Regulatory liabilities			2,363			1,117
	Derivative instruments valuation-at market			6,008			5,809
	Benefit obligations and other			22,597			15,815
		Total deferred credits and other liabilities		434,985			420,115
Long-term debt				725,662			725,375
Mandatorily redeemable preferred securities of subsidiary trust (see Note 6)				100,000			100,000
Common stock — authorized 200 shares of $1.00 par value; outstanding 100 shares				—			—
Premium on common stock				411,329			405,536
Retained earnings				421,976			444,917
Accumulated comprehensive income (loss)				(4,595	)		(4,433	)
		Total common stockholder’s equity		828,710			846,020
Commitments and contingencies (see Notes 10 and 13)
		Total liabilities and equity	$	2,265,344		$	2,300,780

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

72

SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY AND

OTHER COMPREHENSIVE INCOME

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

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

73

SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

      Business and System of Accounts — This report reflects Xcel Energy’s four largest domestic utility subsidiaries, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, which are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries are subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility commissions. All of the utility companies’ accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material aspects.

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

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

      Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based of the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated.

      Xcel Energy’s utility subsidiaries have various rate adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred.

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

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

75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

	2002		2001		2000
	(Millions of dollars)
NSP-Minnesota	$	28	$	12	$	—
PSCo.	$	1,499	$	1,255	$	788

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

      Property, Plant, Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired, plus net removal cost is charged to accumulated depreciation and amortization. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses.

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

	2002			2001			2000
NSP-Minnesota		3.7	%		4.2	%		3.7	%
NSP-Wisconsin		3.3	%		3.1	%		3.3	%
PSCo.		2.5	%		3.0	%		2.8	%
SPS		2.8	%		2.8	%		2.7	%

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

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

76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income and deductions (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in Xcel Energy’s utility subsidiaries rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota. Interest capitalized as AFDC for Xcel Energy’s utility subsidiaries is listed in the following table:

	2002		2001		2000
	(Millions of dollars)
NSP-Minnesota	$	8.5	$	11.9	$	3.8
NSP-Wisconsin	$	0.4	$	1.1	$	2.3
PSCo.	$	8.0	$	12.1	$	9.4
SPS	$	1.0	$	4.4	$	4.5

      Decommissioning — NSP-Minnesota accounts for the future cost of decommissioning — or permanently retiring — its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. Our decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. For more information on nuclear decommissioning, see Note 14 to the Consolidated Financial Statements.

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

      Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of nuclear fuel used in the current period, as well as future disposal costs of spent nuclear fuel. In addition, nuclear fuel expense includes fees assessed by the U.S. Department of Energy (DOE) and NSP-Minnesota’s portion of the cost of decommissioning or shutting down the DOE’s fuel enrichment facility.

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

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

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

77

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

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

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

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

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

•  we defer certain costs, which would otherwise be charged to expense, as regulatory assets based on our expected ability to recover them in future rates; and

•  we defer certain credits, which would otherwise be reflected as income, as regulatory liabilities based on our expectation they will be returned to customers in future rates.

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

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

78

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

	2002		2001		2000
	(Millions of dollars)
NSP-Minnesota	$	21.1	$	12.4	$	13.4
NSP-Wisconsin	$	1.7	$	1.9	$	2.1
PSCo.	$	18.9	$	14.2	$	16.6
SPS	$	8.4	$	9.2	$	6.8

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

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

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

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

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

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

79

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

		Dec. 31,							Dec. 31,							Dec. 31,
		2000		Expensed		Payments			2001		Expensed		Payments			2002
		Liability*		2001		2001			Liability*		2002		2002			Liability*
		(Millions of dollars)
Special charge activities for utility subsidiaries:
	NSP-Minnesota	$	19	$	14	$	(28	)	$	5	$	4	$	(7	)	$	2
	NSP-Wisconsin		3		2		(3	)		2		1		(3	)		—
	PSCo.		2		15		(15	)		2		1		(3	)		—
	SPS		1		5		(5	)		1		—		(1	)		—

*  Reported on the balance sheets in other current liabilities.

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

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

		2002			2001
		(Thousands of dollars,
		except interest rates)
NSP — Minnesota
	Notes payable to banks	$	69		$	184
	Commercial paper		—			381,000
	Total short-term debt	$	69		$	381,184
	Weighted average interest rate at year end		4.40	%		2.16	%
PSCo
	Notes payable to banks	$	88,074		$	—
	Commercial paper		—			562,812
	Total short-term debt	$	88,074		$	562,812
	Weighted average interest rate at year end		2.42	%		2.76	%
SPS
	Notes payable to banks	$	—		$	—
	Commercial paper		—			—
	Total short-term debt	$	—		$	—
	Weighted average interest rate at year end		n/a			n/a

80

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

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

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

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

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

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

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

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

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

	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
	(Millions of dollars)
2003	$	226	$	41	$	284	$	—
2004		4		1		149		—
2005		75		1		138		—
2006		5		1		129		500
2007		3		1		104		—

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

81

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.     Preferred Stock (PSCo and SPS)

      SPS and PSCo have authorized the issue of preferred shares.

	Preferred Shares				Preferred Shares
	Authorized		Par Value		Outstanding
SPS		10,000,000	$	1.00		none
PSCo.		10,000,000	$	0.01		none

6. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts (NSP-Minnesota, PSCo and SPS)

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

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

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

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

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

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

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

82

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

     NSP-Minnesota

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

		2002			2001			2000
Federal statutory rate			35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit		5.6	%		5.9	%		7.2	%
	Life insurance policies		(0.3	)%		(0.3	)%		(0.3	)%
	Tax credits recognized		(3.8	)%		(2.4	)%		(4.5	)%
	Regulatory differences — utility plant items		(0.3	)%		2.3	%		3.8	%
	Non-deductibility of merger costs		—			—			4.5	%
	Other — net		(1.1	)%		(1.5	)%		(0.4	)%
Effective income tax rate			35.1	%		39.0	%		45.3	%

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

		2002			2001			2000
Current federal tax expense		$	114,222		$	113,670		$	80,085
Current state tax expense			31,740			16,791			19,980
Current federal tax credits			(636	)		(628	)		(799	)
Deferred federal tax credits			(20,973	)		(3,740	)		(1,206	)
Deferred state tax expense (credits)			(5,308	)		14,154			2,546
Deferred investment tax credits			(10,904	)		(7,515	)		(8,415	)
	Total income tax expense	$	108,141		$	132,732		$	92,191

83

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

			2002		2001
			(Thousands of dollars)
Deferred tax liabilities:
	Differences between book and tax bases of property		$	706,256	$	724,096
	Regulatory assets			73,890		69,851
	Tax benefit transfer leases			10,964		14,724
	Other			11,029		22,536
		Total deferred tax liabilities	$	802,139	$	831,207
Deferred tax assets:
	Regulatory liabilities		$	25,113	$	39,892
	Employee benefits and other accrued liabilities			42,633		45,229
	Deferred investment tax credits			30,088		33,168
	Other			8,235		8,072
		Total deferred tax assets	$	106,069	$	126,361
		Net deferred tax liability	$	696,070	$	704,846

     NSP-Wisconsin

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

		2002			2001			2000
Federal statutory rate			35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit		5.7	%		4.4	%		5.2	%
	Life insurance policies		(0.1	)%		—			—
	Tax credits recognized		(0.9	)%		(1.4	)%		(1.6	)%
	Equity income from unconsolidated affiliates		(0.1	)%		(0.4	)%		(0.4	)%
	Regulatory differences — utility plant items		0.6	%		(1.1	)%		(1.0	)%
	Non-deductibility of merger costs		—			—			3.2	%
	Other — net		0.2	%		0.3	%		0.2	%
Effective income tax rate			40.4	%		36.8	%		40.6	%

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

		2002			2001			2000
Current federal tax expense		$	13,143		$	15,691		$	14,924
Current state tax expense			2,907			3,237			3,500
Deferred federal tax expense			16,569			2,462			2,487
Deferred state tax expense			5,113			587			606
Deferred investment tax credits			(807	)		(819	)		(827	)
	Total income tax expense	$	36,925		$	21,158		$	20,690

84

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

			2002		2001
			(Thousands of dollars)
Deferred tax liabilities:
	Differences between book and tax bases of property		$	132,044	$	113,039
	Regulatory assets			21,744		17,583
	Other			20,048		14,777
		Total deferred tax liabilities	$	173,836	$	145,399
Deferred tax assets:
	Regulatory liabilities		$	5,040	$	6,877
	Deferred investment tax credits			6,019		6,284
	Employee benefits and other accrued liabilities			12,773		8,786
	Other			680		1,183
		Total deferred tax assets	$	24,512	$	23,130
		Net deferred tax liability	$	149,324	$	122,269

     PSCo

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

		2002			2001			2000
Federal statutory rate			35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit		2.7	%		3.3	%		1.9	%
	Life insurance policies		(6.2	)%		(5.1	)%		(6.8	)%
	Tax credits recognized		(3.0	)%		(1.4	)%		(3.1	)%
	Regulatory differences — utility plant items		2.6	%		2.4	%		2.7	%
	Non-deductibility of merger costs		—			—			3.3	%
	Extraordinary item		—			(0.1	)%		—
	Other — net		1.6	%		(1.6	)%		1.4	%
Effective income tax rate including extraordinary items			32.7	%		32.5	%		34.4	%
	Extraordinary items		—			0.1	%		—
Effective income tax rate excluding extraordinary items			32.7	%		32.6	%		34.4	%

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

		2002			2001			2000
Current federal tax expense		$	20,833		$	116,173		$	91,281
Current state tax expense			2,338			20,687			7,037
Current tax credits			(7,087	)		(1,523	)		(3,699	)
Deferred federal tax expense			103,108			1,371			11,835
Deferred state tax expense			14,159			(55	)		1,797
Deferred investment tax credits			(4,665	)		(4,152	)		(5,481	)
	Income tax expense excluding extraordinary items	$	128,686		$	132,501		$	102,770
Tax expense (benefit) on extraordinary item			—			(940	)		—
	Total income tax expense	$	128,686		$	131,561		$	102,770

85

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

			2002		2001
			(Thousands of dollars)
Deferred tax liabilities:
	Differences between book and tax bases of property		$	567,817	$	504,694
	Employee benefits and other accrued liabilities			56,840		52,132
	Regulatory assets			36,469		39,069
	Other			35,745		33,556
		Total deferred tax liabilities	$	696,871	$	629,451
Deferred tax assets:
	Deferred investment tax credits		$	28,501	$	30,403
	Regulatory liabilities			17,375		18,646
	Other comprehensive income			64,329		621
	Other			11,362		49,375
		Total deferred tax assets	$	121,567	$	99,045
		Net deferred tax liability	$	575,304	$	530,406

     SPS

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

		2002			2001			2000
Federal statutory rate			35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit		(0.3	)%		1.5	%		0.9	%
	Life insurance policies		—			—			(0.1	)%
	Tax credits recognized		(0.2	)%		(0.2	)%		(0.2	)%
	Regulatory differences — utility plant items		1.9	%		1.8	%		2.9	%
	Non-deductibility of merger costs		—			—			2.1	%
	Extraordinary item		—			(0.4	)%		5.8	%
	Other — net		0.6	%		(0.5	)%		(0.7	)%
Effective income tax rate including extraordinary items			37.0	%		37.2	%		45.7	%
	Extraordinary items		—			0.4	%		(5.8	)%
Effective income tax rate excluding extraordinary items			37.0	%		37.6	%		39.9	%

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

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

86

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

			2002		2001
			(Thousands of dollars)
Deferred tax liabilities:
	Differences between book and tax bases of property		$	357,874	$	330,601
	Regulatory assets			27,617		28,586
	Employee benefits and other accrued liabilities			32,719		24,645
	Other			13,034		18,669
		Total deferred tax liabilities	$	431,244	$	402,501
Deferred tax assets:
	Deferred investment tax credits		$	1,519	$	1,609
	Regulatory liabilities			844		895
	Other			16,048		17,158
		Total deferred tax assets	$	18,411	$	19,662
		Net deferred tax liability	$	412,833	$	382,839

9. Benefit Plans and Other Postretirement Benefits (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

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

      Pension Benefits — Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all utility employees. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.

      Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws. Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities.

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

	2002			2001
	(Thousands of dollars)
Change in Benefit Obligation
Obligation at January 1	$	2,409,186		$	2,254,138
Service cost		65,649			57,521
Interest cost		172,377			172,159
Acquisitions		7,848			—
Plan amendments		3,903			2,284
Actuarial loss		65,763			108,754
Settlements		(994	)		—
Special termination benefits		4,445			—
Benefit payments		(222,601	)		(185,670	)
Obligation at December 31	$	2,505,576		$	2,409,186

87

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	2002			2001
	(Thousands of dollars)
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1	$	3,267,586		$	3,689,157
Actual return on plan assets		(404,940	)		(235,901	)
Employer contributions — acquisitions		912			—
Settlements		(994	)		—
Benefit payments		(222,601	)		(185,670	)
Fair value of plan assets at December 31	$	2,639,963		$	3,267,586
Funded Status of Plans at December 31
Net asset	$	134,387		$	858,400
Unrecognized transition asset		(2,003	)		(9,317	)
Unrecognized prior service cost		224,651			242,313
Unrecognized (gain) loss		165,927			(712,571	)
Xcel Energy net pension amounts recognized on balance sheet	$	522,962		$	378,825
NSP-Minnesota prepaid pension asset recorded	$	263,713		$	188,287
NSP-Wisconsin prepaid pension asset recorded		38,557			28,563
PSCo prepaid pension asset recorded		—			60,797
PSCo intangible asset recorded — prior service costs		6,874			—
PSCo accrued benefit liability recorded		(3,182	)		—
PSCo minimum pension liability		(104,773	)		—
PSCo accumulated other comprehensive income recorded — pretax		169,958			—
SPS prepaid pension asset recorded		105,044			82,503
Significant Assumptions
Discount rate for year end valuation		6.75	%		7.25	%
Expected average long term increase in compensation level		4.00	%		4.50	%
Expected average long term rate of return on assets		9.50	%		9.50	%

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

88

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Xcel Energy	2002			2001			2000
	(Thousands of dollars)
Service cost	$	65,649		$	57,521		$	59,066
Interest cost		172,377			172,159			172,063
Expected return on plan assets		(339,932	)		(325,635	)		(292,580	)
Curtailment		—			1,121			—
Amortization of transition asset		(7,314	)		(7,314	)		(7,314	)
Amortization of prior service cost		22,663			20,835			19,197
Amortization of net gain		(69,264	)		(72,413	)		(60,676	)
Net periodic pension credit under SFAS No. 87	$	(155,821	)	$	(153,726	)	$	(110,244	)
NSP-Minnesota
Net periodic pension credit under SFAS No. 87	$	(71,928	)	$	(76,509	)	$	(56,182	)
Credits not recognized due to effects of regulation		71,928			76,509			56,182
Net benefit cost (credit) recognized for financial reporting	$	—		$	—		$	—
NSP-Wisconsin
Net SFAS No. 87 benefit credit recognized for reporting	$	(9,994	)	$	(10,002	)	$	(6,369	)
PSCo
Net SFAS No. 87 benefit credit recognized for reporting	$	(14,747	)	$	(17,311	)	$	(16,825	)
SPS
Net SFAS No. 87 benefit credit recognized for reporting	$	(22,235	)	$	(21,131	)	$	(21,352	)

      Xcel Energy also maintains noncontributory defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s operating cash flows.

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Postretirement Health Care Benefits — Xcel Energy has contributory health and welfare benefit plans that provide health care and death benefits to most Xcel Energy retirees. The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. However, employees of the former NCE who retired in 2002 continue to receive employer subsidized health care benefits. Employees of the former NSP who retired after 1998 are eligible to participate in the Xcel Energy health care program with no employer subsidy.

      In conjunction with the 1993 adoption of SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pension,” Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

      Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional SFAS No. 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.

      Certain state agencies, which regulate Xcel Energy’s utility subsidiaries, have also issued guidelines related to the funding of SFAS No. 106 costs. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Minnesota and Wisconsin retail regulators required external funding of accrued SFAS No. 106 costs to the extent such funding is tax advantaged. Plan assets held in external funding trusts principally consist of investments in equity mutual funds, fixed-income securities and cash equivalents.

      A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:

	2002			2001
	(Thousands of dollars)
Change in Benefit Obligation
Obligation at January 1	$	662,853		$	558,994
Service cost		5,967			5,258
Interest cost		48,304			45,177
Acquisitions		773			—
Plan amendments		—			—
Plan participants’ contributions		5,755			3,517
Actuarial loss		57,175			98,655
Special termination benefits		(173	)		—
Benefit payments		(44,263	)		(48,748	)
Obligation at December 31	$	736,391		$	662,853
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1	$	242,803		$	223,266
Actual return on plan assets		(13,632	)		(3,701	)
Plan participants’ contributions		5,755			3,517
Employer contributions		60,320			68,469
Benefit payments		(44,263	)		(48,748	)
Fair value of plan assets at December 31	$	250,983		$	242,803

90

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	2002			2001
	(Thousands of dollars)
Funded Status of Plan at December 31
Net obligation	$	485,408		$	420,050
Unrecognized transition asset (obligation)		(169,328	)		(186,099	)
Unrecognized prior service cost		10,675			12,559
Unrecognized gain (loss)		(200,634	)		(132,354	)
Total accrued benefit liability recorded	$	126,121		$	114,156
NSP-Minnesota accrued benefit liability recorded	$	58,660		$	59,462
NSP-Wisconsin accrued benefit liability recorded	$	4,899		$	5,052
PSCo accrued benefit liability recorded	$	44,876		$	36,350
SPS accrued benefit liability recorded	$	9,772		$	6,656
Significant Assumptions
Discount rate for year end valuation		6.75	%		7.25	%
Expected average long term rate of return on assets		8.0 - 9.0	%		9.0	%

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

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

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

	2002			2001			2000
	(Thousands of dollars)
Xcel Energy
Service cost	$	5,967		$	6,160		$	5,679
Interest cost		48,304			46,579			43,477
Expected return on plan assets		(21,011	)		(18,920	)		(17,902	)
Amortization of transition obligation		16,771			16,771			16,773
Amortization of prior service credit		(1,130	)		(1,235	)		(1,211	)
Amortization of net loss		5,380			1,457			915
Net periodic postretirement benefit cost under SFAS No. 106		54,281			50,812			47,731
Additional cost recognized due to effects of regulation		4,043			3,738			6,641
Net cost recognized for financial reporting	$	58,324		$	54,550		$	54,372

91

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	2002		2001			2000
	(Thousands of dollars)
NSP-Minnesota
Net periodic postretirement benefit cost recognized — SFAS No. 106	$	12,667	$	11,124		$	10,718
NSP-Wisconsin
Net periodic postretirement benefit cost recognized — SFAS No. 106	$	1,531	$	1,155		$	852
PSCo
Net periodic postretirement benefit cost recognized — SFAS No. 106	$	30,619	$	29,910		$	28,323
Additional cost recognized due to effects of regulation		3,890		3,890			3,890
Net cost recognized for financial reporting	$	34,509	$	33,800		$	32,213
SPS
Net periodic postretirement benefit cost recognized — SFAS No. 106	$	5,542	$	3,254		$	3,696
Additional cost (credit) recognized due to effects of regulation		153		(152	)		2,751
Net cost recognized for financial reporting	$	5,695	$	3,102		$	6,447

10.     Extraordinary Items (SPS)

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

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

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

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

92

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

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

Fair Values

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

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

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

	2002				2001
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(Thousands of dollars)
PSCo
Mandatorily redeemable preferred securities of subsidiary trust	$	194,000	$	178,868	$	194,000	$	189,732
Long-term investments		6,598		6,598		4,727		4,727
Long-term debt, including current portion		2,064,225		2,147,775		1,482,229		1,523,735

93

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	2002				2001
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(Thousands of dollars)
SPS
Mandatorily redeemable preferred securities of subsidiary trust	$	100,000	$	96,400	$	100,000	$	100,200
Long-term investments		9,622		8,098		6,017		6,744
Long-term debt, including current portion		725,662		748,666		725,375		708,586

      The carrying amount of cash, cash equivalents, short-term investments and other financial instruments approximates fair value because of the short maturity of those instruments. The fair values of Xcel Energy’s utility subsidiaries’ long-term investments, mainly debt securities in an external nuclear decommissioning fund held by NSP-Minnesota, are estimated based on quoted market prices for those or similar investments. The fair value of Xcel Energy’s utility subsidiaries’ long-term debt and the mandatorily redeemable preferred securities are estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

      The fair value estimates presented are based on information available to management as of Dec. 31, 2002 and 2001. These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date and current estimates of fair values may differ significantly from the amounts presented herein.

Guarantees

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

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

94

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

95

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Fair Value of Derivative Instruments

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

*  Does not include the impact of ratepayer sharing in Colorado

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

	Maturity less			Maturity		Total Fair
Source of Fair Value	than 1 year			1 to 3 years		Value
	(Millions of dollars)
Prices actively quoted	$	(0.1	)	$	0.0	$	(0.1	)
Prices based on models and other valuation methods (including prices quoted from external sources)		0.0			0.0		0.0

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

	2002					2001
	NSP-Minnesota		PSCo			NSP-Minnesota			PSCo
	(Millions of dollars)
Notional value	$	34.0	$	(28.3	)	$	71.8		$	12.0
Fair value (liability) asset		10.6		22.7			(15.1	)		(8.9	)

Letters of Credit

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

	NSP-Minnesota		PSCo		SPS
	(Millions of dollars)
Letters of credit outstanding	$	16.8	$	0.0	$	9.5

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

Use of Derivatives to Manage Risk

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

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

97

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

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

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

Derivatives as Hedges

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

      A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change in the fair value of the underlying asset, liability, or firm commitment being hedged. That is, fair value hedge accounting allows the gain or loss on the hedged item to offset the gain or loss on the derivative instrument in the same period. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in Other Comprehensive Income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized currently in earnings.

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

98

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financial Impacts of Derivatives

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

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

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

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

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

      SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. SPS reclassified into earnings during 2002 net after-tax gains from Other Comprehensive Income of approximately $0.5 million.

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

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

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

      Normal Purchases or Normal Sales — Xcel Energy’s utility subsidiaries enter into fixed price contracts for the purchase and sale of various commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented as normal and exempted from the accounting and reporting requirements of SFAS No. 133.

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

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

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

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

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

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

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

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

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

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

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

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

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

      Rental expense under operating leases was:

	2002		2001		2000
	(Millions of dollars)
NSP-Minnesota	$	31.0	$	30.7	$	34.3
NSP-Wisconsin		4.8		4.7		3.4
PSCo.		22.6		2.6		9.6
SPS		4.6		0.1		2.2

      Future commitments under operating leases are:

	2003		2004		2005		2006		2007
	(Millions of dollars)
NSP-Minnesota	$	21.5	$	20.1	$	19.2	$	19.1	$	19.1
NSP-Wisconsin		3.7		3.7		3.7		3.7		3.7
PSCo.		7.6		7.5		7.4		6.9		6.2
SPS		2.1		2.2		2.2		2.1		2.1

      Future commitments under PSCo’s two capital leases are:

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

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

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Minnesota has secured $200 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $9.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $88 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $10 million per reactor during any one year.

      NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $1.5 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $7.5 million for business interruption insurance and $21.6 million for property damage insurance if losses exceed accumulated reserve funds.

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

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

							Gas Storage &
	Coal		Nuclear Fuel		Natural Gas		Transportation
	(Millions of dollars)
NSP-Minnesota and NSP-Wisconsin (combined)	$	219	$	122	$	284	$	268
PSCo	$	670	$	—	$	1,264	$	906
SPS	$	1,442	$	—	$	5	$	—

      Purchased Power Agreements — The utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2050. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Most of the capacity and energy costs are recovered through base rates and other cost recovery mechanisms.

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

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

      At Dec. 31, 2002, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows (Thousands of dollars):

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

*  Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Environmental Contingencies

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

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

•  third party sites, such as landfills, to which we are alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes,

•  the site of a former federal uranium enrichment facility, and

•  sites of former manufactured gas plants (MGP’s) operated by our subsidiaries or predecessors.

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

      To estimate the cost to remediate these sites, we may have to make assumptions where facts are not fully known. For instance, we might make assumptions about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

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

			Current Portion
	Total Liability		of Liability
	(Millions of dollars)
NSP-Minnesota	$	19.0	$	5.1
NSP-Wisconsin		23.1		2.0
PSCo		2.8		0.4
SPS		—		—

      Some of the cost of remediation may be recovered from:

•  insurance coverage;

•  other parties that have contributed to the contamination; and

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•  customers.

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

      Federal Uranium Enrichment Facility — Approximately $13 million of the long-term liability and $4 million of the current liability for NSP-Minnesota, and approximately $2 million of the long-term liability for PSCo, relate to a DOE assessment for decommissioning a federal uranium enrichment facility. These environmental liabilities do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota’s nuclear generating plants. See Note 14 to Consolidated Financial Statements for further discussion of nuclear obligations.

      Asbestos Removal — Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Since we intend to operate most of these facilities indefinitely, we cannot estimate the amount or timing of payments for its final removal. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

NSP-Minnesota

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

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

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

NSP-Wisconsin

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

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

      The Wisconsin Department of Natural Resources (WDNR) and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The Environmental Protection Agency (EPA) and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for all operable units at the site and determine the level of responsibility of each PRP, we are not able to accurately determine our share of the ultimate cost of remediating the Ashland site.

      In the interim, NSP-Wisconsin has recorded a liability for an estimate of its share of the cost of remediating the portion of the Ashland site that it owns, estimated using information available to date and using reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the remediation costs accrued for the Ashland site because we expect that the Public Service Commission of Wisconsin (PSCW) will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities.

      We proposed, and the EPA and WDNR have approved, an interim action (a coal tar removal/ groundwater treatment system) for one operable unit at the site for which NSP-Wisconsin has accepted responsibility. The groundwater treatment system began operating in the fall of 2000. In 2002 NSP-Wisconsin installed additional monitoring wells in the deep aquifer to better characterize the extent and degree of contaminants in that aquifer while the coal tar removal system is operational. In 2002 a second interim response action was also implemented. As approved by the WDNR, this interim response action involved the removal and capping of a seep area in a city park. Surface soils in the area of the seep were contaminated with tar residues. The interim action also included the diversion and ongoing treatment of groundwater that contributed to the formation of the seep.

      On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the EPA in determining which sites require further investigation. Resolution of Ashland remediation issues is not expected until 2004 or 2005.

      NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.

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

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

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

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

     PSCo

      Leyden Gas Storage Facility — In February 2001, the CPUC granted PSCo’s application to abandon the Leyden natural gas storage facility (Leyden) after 40 years of operation. In July 2001, the CPUC decided that the recovery of all Leyden costs would be addressed in a future rate proceeding when all costs were known. Since late 2001, PSCo has operated the facility to withdraw the recoverable gas in inventory. Beginning in 2003, PSCo will start to flood the facility with water, as part of an overall plan to convert Leyden into a municipal water storage facility owned and operated by the city of Arvada, Colo. As of Dec. 31, 2002, PSCo has deferred approximately $4.5 million of costs associated with engineering buffer studies, damage claims paid to landowners and other closure costs. PSCo expects to incur an additional $6 million to $8 million of costs through 2005 to complete the decommissioning and closure of the facility. PSCo believes that these costs will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

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

      On July 1, 2002, Xcel Energy received a Notice of Violation (NOV) from the EPA alleging violations of the NSR requirements of the Clean Air Act at the Comanche and Pawnee Stations in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. Xcel Energy believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. Xcel Energy also believes that the projects would be expressly authorized under the EPA’s NSR policy announced by the EPA administrator on June 22, 2002 and proposed in the Federal Register on Dec. 31, 2002. Xcel Energy disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the Clean Air Act, the EPA met with Xcel Energy in a conference in September 2002 to discuss the NOV.

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

Legal Contingencies

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

     NSP-Minnesota

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

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

     NSP-Wisconsin

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

     SPS

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

Other Contingencies

     NSP-Minnesota

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

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

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

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

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

     PSCo

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

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

     SPS

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

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

108

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

14. Nuclear Obligations (NSP-Minnesota)

      Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $13 million in 2002, $11 million in 2001 and $12 million in 2000. In total, NSP-Minnesota had paid approximately $312 million to the DOE through Dec. 31, 2002. However, we cannot determine whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.

      The Nuclear Waste Policy Act required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. In 1996, the DOE notified commercial spent-fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.

      NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants. With the dry cask storage facilities approved in 1994, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least 2007. The Monticello nuclear plant has storage capacity to continue operations until 2010. Storage availability to permit operation beyond these dates is not assured at this time. We are investigating all of the alternatives for spent fuel storage until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities. If on-site temporary storage at Prairie Island reaches approved capacity, we could seek interim storage at this or another contracted private facility, if available.

      Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from 1993 to 2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2002 was $4 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, we deferred the unamortized assessment of $21 million at Dec. 31, 2002, as a regulatory asset.

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

      Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Funding presumes that current costs will escalate in the future at a rate of 4.35 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding. Unrealized gains on nuclear decommissioning investments are deferred as Regulatory Liabilities based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

109

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

      The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2002, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. We plan to reinvest matured securities until decommissioning begins.

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

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

      Decommissioning expenses recognized include the following components:

		2002			2001			2000
		(Thousands of dollars)
Annual decommissioning cost accrual reported as depreciation expense:
	Externally funded	$	51,433		$	51,433		$	51,433
	Internally funded (including interest costs)		(18,797	)		(17,396	)		(16,111	)
Interest cost on externally funded decommissioning obligation			(32	)		4,535			5,151
Earnings from external trust funds			32			(4,535	)		(5,151	)
Net decommissioning accruals recorded		$	32,636		$	34,037		$	35,322

110

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

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

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

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

      Our regulated businesses prepare their financial statements in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators allow us to collect from, or require us to pay back to, customers in future electric and natural gas rates.

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

111

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

NSP-Minnesota

					December 31,
				Remaining
		Note Ref.		Amortization Period	2002		2001
		(Thousands of dollars)
AFDC recorded in plant(a)				Plant lives	$	82,697	$	88,005
Conservation programs(a)				Up to five years		25,259		35,573
Losses on reacquired debt			1	Term of related debt		33,817		36,631
Environmental costs			13,14	To be determined		4,140		5,366
Unrecovered gas costs(b)			1	One to two years		12,296		10,324
Nuclear decommissioning costs(c)				Up to five years		20,769		24,696
Renewable resource costs				To be determined		26,000		17,500
State commission accounting adjustments(a)				Plant lives		4,732		4,860
Other				Various		2,829		3,133
	Total regulatory assets				$	212,539	$	226,088
Investment tax credit deferrals					$	50,836	$	56,018
Unrealized gains on decommissioning investments			14			112,145		149,041
Pension costs-regulatory differences			9			287,615		215,687
Deferred income tax adjustments						27,687		46,157
Fuel costs, refunds and other						1,786		1,148
Interest on income tax refunds						5,966		—
	Total regulatory liabilities				$	486,035	$	468,051

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

112

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NSP-Wisconsin

					December 31,
				Remaining
		Note Ref.		Amortization Period	2002		2001
		(Thousands of dollars)
AFDC recorded in plant(d)				Plant lives	$	7,290	$	7,391
Conservation programs(d)				Through 2003		1,296		1,597
Losses on reacquired debt			1	Term of Related Debt		9,328		9,968
Environmental costs			13	To be determined		26,833		14,803
State commission accounting adjustments(d)				Plant lives		2,858		2,718
Other				Various		507		646
	Total regulatory assets				$	48,112	$	37,123
Investment tax credit deferrals					$	10,134	$	10,510
Interest on income tax refunds						603		—
Deferred income tax adjustments						474		5,572
Fuel costs, refunds and other						739		809
	Total regulatory liabilities				$	11,950	$	16,891

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

PSCo

					December 31,
				Remaining
		Note Ref.		Amortization Period	2002		2001
		(Thousands of dollars)
AFDC recorded in plant(e)				Plant lives	$	36,469	$	39,069
Conservation programs(e)				Up to five years		13,520		15,643
Losses on reacquired debt			1	Term of Related Debt		13,853		15,047
Unrecovered energy costs(f)				27 months		67,709		—
Deferred income tax adjustments			1	Mainly plant lives		23,058		34,556
Nuclear decommissioning costs				Three years		32,798		43,788
Employees’ postretirement benefits other than pension			9	Ten years		38,899		42,790
Other				Various		12,294		1,948
	Total regulatory assets				$	238,600	$	192,841
Investment tax credit deferrals					$	45,707	$	49,048
	Total regulatory liabilities				$	45,707	$	49,048

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

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

113

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     SPS

					December 31,
				Remaining
		Note Ref.		Amortization Period	2002		2001
		(Thousands of dollars)
AFDC recorded in plant(g)				Plant lives	$	27,617	$	$15,027
Conservation programs(g)				Up to five years		13,784		13,012
Losses on reacquired debt			1	Term of related debt		28,426		33,260
Deferred income tax adjustments			1	Mainly plant lives		24,010		35,162
New Mexico restructuring costs.				To be determined		5,147		—
Texas restructuring costs				Five years		6,420		—
Other						—		152
	Total regulatory assets				$	105,404	$	96,613
Investment tax credit deferrals					$	2,363	$	1,117
	Total regulatory liabilities				$	2,363	$	1,117

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

      The adoption of SFAS No. 143 in 2003 will also affect Xcel Energy’s accrued plant removal costs for other generation, transmission and distribution facilities for its utility subsidiaries. Although SFAS No. 143 does not recognize the future accrual of removal costs as a Generally Accepted Accounting Principles liability, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, we have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the estimated amounts of future removal costs, which are considered regulatory liabilities under SFAS No. 143 that are accrued in accumulated depreciation, are as follows at Dec. 31, 2002:

(Millions of Dollars)
NSP-Minnesota	$	304
NSP-Wisconsin		70
PSCo		329
SPS		97

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

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

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

•  Xcel Energy’s Gas Utility transmits, transports, stores and distributes natural gas and propane primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

114

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category. Those primarily include steam revenue (PSCo), appliance repair services (NSP-Minnesota and PSCo), nonutility real estate activities (NSP-Minnesota), parking ramp operations (NSP-Minnesota) and revenues associated with processing solid waste into refuse-derived fuel (NSP-Minnesota).

      To report net income for electric and natural gas utility segments, Xcel Energy must assign or allocate all costs and certain other income. In general, costs are:

•  directly assigned wherever applicable;

•  allocated based on cost causation allocators wherever applicable; or

•  allocated based on a general allocator for all other costs not assigned by the above two methods.

      The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. Xcel Energy evaluates performance by each legal entity based on profit or loss.

Business Segments

NSP-Minnesota

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

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

115

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

     NSP-Wisconsin

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

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

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

116

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     PSCo

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

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

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

     SPS

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

117

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

     NSP-Minnesota and NSP-Wisconsin

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

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

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

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

		2002		2001		2000
		(Thousands of dollars)
NSP-Minnesota
Operating revenues:
Electric
	Production related	$	205,203	$	218,385	$	200,522
	Transmission		15,471		17,733		16,600
	Gas		363		468		220
Operating expenses:
	Purchased and interchange power		43,511		50,083		45,294
	Gas purchased for resale		—		—		608
	Other operations*		309,514		325,151		571,144

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

118

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		2002		2001		2000
		(Thousands of dollars)
NSP-Wisconsin
Operating revenues:
	Electric	$	80,200	$	85,895	$	73,425
Operating expenses:
	Purchased and interchange power		205,174		218,534		199,730
	Gas purchased for resale		95		244		220
	Other operations*		50,449		46,371		42,330

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

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

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

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

     PSCo and SPS

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

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

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

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

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

119

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	2002		2001		2000
	(Thousands of dollars)
PSCo
Electric utility revenues	$	57,464	$	40,457	$	—
Gas utility revenues		311		513		8,750
Cost of gas sold		—		1,644		3,483
Operating expenses*		208,402		232,902		500,954
Interest income		—		—		10,377
Interest expense		1,648		2,311		3,952
Construction services — capitalized in plant		70,784		69,316		67,893

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

	2002		2001		2000
	(Thousands of dollars)
SPS
Electric fuel and purchased power expense	$	15,158	$	24,342	$	45,900
Operating expenses*		68,045		72,259		210,174
Interest income		—		—		8,640
Interest expense		147		253		850
Construction services — capitalized in plant		13,524		8,141		7,397

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

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

     NSP-Minnesota

	Quarter Ended
	March 31, 2002(a)		June 30, 2002		Sept. 30, 2002		Dec. 31, 2002
	(Thousands of dollars)
Revenue(c)	$	735,251	$	656,973	$	752,136	$	738,759
Operating income		67,370		86,279		169,418		74,917
Net income		33,033		42,424		82,992		41,773

	Quarter Ended
	March 31, 2001		June 30, 2001(b)		Sept. 30, 2001		Dec. 31, 2001(b)
	(Thousands of dollars)
Revenue(c)	$	982,073	$	759,215	$	826,706	$	680,501
Operating income		99,830		112,113		155,691		70,150
Net income		42,172		56,401		76,090		33,202

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

120

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

     NSP-Wisconsin

	Quarter Ended
	March 31, 2002		June 30, 2002		Sept. 30, 2002		Dec. 31, 2002
	(Thousands of dollars)
Revenue	$	157,402	$	129,059	$	130,232	$	144,948
Operating income		34,682		24,917		27,562		26,337
Net income		17,951		12,418		12,496		11,508

	Quarter Ended
	March 31, 2001		June 30, 2001		Sept. 30, 2001		Dec. 31, 2001(a)
	(Thousands of dollars)
Revenue	$	183,567	$	122,005	$	132,111	$	136,957
Operating income		26,565		9,928		19,431		22,858
Net income		13,092		3,414		8,627		11,259

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

     PSCo

	Quarter Ended
	March 31, 2002		June 30, 2002		Sept. 30, 2002		Dec. 31, 2002
	(Thousands of dollars)
Revenue(b)		$758,680	$	573,939	$	594,126	$	725,168
Operating income		132,858		134,033		134,716		138,631
Income before extraordinary items		66,691		62,361		66,967		68,661
Extraordinary items		—		—		—		—
Net income		66,691		62,361		66,967		68,661

	Quarter Ended
	March 31, 2001		June 30, 2001(a)		Sept. 30, 2001		Dec. 31, 2001(a)
	(Thousands of dollars)
Revenue(b)	$	1,171,056	$	910,487	$	791,876	$	776,426
Operating income		194,293		129,508		100,070		109,847
Income before extraordinary items		107,390		66,302		47,947		52,928
Extraordinary items		—		—		—		(1,534	)
Net income		107,390		66,302		47,947		51,394

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

121

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     SPS

	Quarter Ended
	March 31, 2002(a)		June 30, 2002		Sept. 30, 2002		Dec. 31, 2002
	(Thousands of dollars)
Revenue	$	211,692	$	266,917	$	291,857	$	254,712
Operating income		35,117		34,642		62,388		32,971
Income before extraordinary items		14,748		13,429		31,741		13,964
Extraordinary items		—		—		—		—
Net income		14,748		13,429		31,741		13,964

	Quarter Ended
	March 31, 2001		June 30, 2001		Sept. 30, 2001		Dec. 31, 2001(b)
	(Thousands of dollars)
Revenue	$	329,273	$	371,681	$	387,219	$	297,285
Operating income		53,713		42,384		85,679		48,781
Income before extraordinary items		26,049		20,302		47,709		24,219
Extraordinary items		—		—		—		11,821
Net income		26,049		20,302		47,709		36,040

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

122

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

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

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

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

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

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

PART III

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

Item 10. Directors and Executive Officers of the Registrant (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 11. Executive Compensation (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 12. Security Ownership of Certain Beneficial Owners and Management (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 13. Certain Relationships and Related Transactions (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 14. Controls and Procedures

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

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

123

PART IV

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

NSP-Minnesota

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

   2.       Exhibits

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

124

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

125

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

126

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

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

None

NSP-Wisconsin

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

   2.       Exhibits

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

127

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

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

        None

PSCo

		Page
(a)1.	Financial Statements and Schedules
	Reports of Independent Auditors for the years ended Dec. 31, 2002, 2001 and 2000.		52
	Statements of Income for the three years ended Dec. 31, 2002.		65
	Statements of Cash Flows for the three years ended Dec. 31, 2002.		66
	Balance Sheets, Dec. 31, 2002 and 2001.		67
	Notes to Financial Statements.		75
	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2002, 2001 and 2000

2.	Exhibits
*	Indicates incorporation by reference
2.01*	Merger Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, dated Aug. 22, 1995, File No. 1-3280 — Exhibit 2).
3.01*	Amended and Restated Articles of Incorporation dated July 10, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*	By-laws dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
4.01*	Indenture, dated as of Dec. 1, 1939, providing for the issuance of First Mortgage Bonds (Form 10 for 1946- Exhibit (B-1)).
4.02*	Indentures supplemental to Indenture dated as of Dec. 1, 1939:

	Previous Filing:						Previous Filing:
	Form; Date or		Exhibit				Form; Date or		Exhibit
Dated as of	File No.		No.		Dated as of		File No.		No.
Mar. 14, 1941		10, 1946		B-2		Sept. 1, 1970		8-K, Sept. 1970		2
May 14, 1941		10, 1946		B-3		Feb. 1, 1971		8-K, Feb. 1971		2
Apr. 28, 1942		10, 1946		B-4		Aug. 1, 1972		8-K, Aug. 1972		2
Apr. 14, 1943		10, 1946		B-5		June 1, 1973		8-K, June 1973		1

128

	Previous Filing:						Previous Filing:
	Form; Date or		Exhibit				Form; Date or		Exhibit
Dated as of	File No.		No.		Dated as of		File No.		No.
Apr. 27, 1944		10, 1946		B-6		Mar. 1, 1974		8-K, Apr. 1974		2
Apr. 18, 1945		10, 1946		B-7		Dec. 1, 1974		8-K, Dec. 1974		1
Apr. 23, 1946		10-K, 1946		B-8		Oct. 1, 1975		S-7, (2-60082)		2(b)(3)
Apr. 9, 1947		10-K, 1946		B-9		Apr. 28, 1976		S-7, (2-60082)		2(b)(4)
June 1, 1947		S-1, (2-7075)		7(b)		Apr. 28, 1977		S-7, (2-60082)		2(b)(5)
Apr. 1, 1948		S-1, (2-7671)		7(b)(1)		Nov. 1, 1977		S-7, (2-62415)		2(b)(3)
May 20, 1948		S-1, (2-7671)		7(b)(2)		Apr. 28, 1978		S-7, (2-62415)		2(b)(4)
Oct. 1, 1948		10-K, 1948		4		Oct. 1, 1978		10-K, 1978		D(1)
Apr. 20, 1949		10-K, 1949		1		Oct. 1, 1979		S-7, (2-66484)		2(b)(3)
Apr. 24, 1950		8-K, Apr. 1950		1		Mar. 1, 1980		10-K, 1980		4(c)
Apr. 18, 1951		8-K, Apr. 1951		1		Apr. 28, 1981		S-16, (2-74923)		4(c)
Oct. 1, 1951		8-K, Nov. 1951		1		Nov. 1, 1981		S-16, (2-74923)		4(d)
Apr. 21, 1952		8-K, Apr. 1952		1		Dec. 1, 1981		10-K, 1981		4(c)
Dec. 1, 1952		S-9, (2-11120)		2(b)(9)		Apr. 29, 1982		10-K, 1982		4(c)
Apr. 15, 1953		8-K, Apr. 1953		2		May 1, 1983		10-K, 1983		4(c)
Apr. 19, 1954		8-K, Apr. 1954		1		Apr. 30, 1984		S-3, (2-95814)		4(c)
Oct. 1, 1954		8-K, Oct. 1954		1		Mar. 1, 1985		10-K, 1985		4(c)
Apr. 18, 1955		8-K, Apr. 1955		1		Nov. 1, 1986		10-K, 1986		4(c)
Apr. 24, 1956		10-K, 1956		1		May 1, 1987		10-K, 1987		4(c)
May 1, 1957		S-9, (2-13260)		2(b)(15)		July 1, 1990		S-3, (33-37431)		4(c)
Apr. 10, 1958		8-K, Apr. 1958		1		Dec. 1, 1990		10-K, 1990		4(c)
May 1, 1959		8-K, May 1959		2		Mar. 1, 1992		10-K, 1992		4(d)
Apr. 18, 1960		8-K, Apr. 1960		1		Apr. 1, 1993		10-Q, June 30, 1993		4(a)
Apr. 19, 1961		8-K, Apr. 1961		1		June 1, 1993		10-Q, June 30, 1993		4(b)
Oct. 1, 1961		8-K, Oct. 1961		2		Nov. 1, 1993		S-3, (33-51167)		4(a)(3)
Mar. 1, 1962		8-K, Mar. 1962		3(a)		Jan. 1, 1994		10-K, 1993		4(a)(3)
June 1, 1964		8-K, June 1964		1		Sept. 2, 1994		8-K, Sept. 1994		4(a)
May 1, 1966		8-K, May 1966		2		May 1, 1996		10Q, June 30, 1996		4(a)
July 1, 1967		8-K, July 1967		2		Nov. 1, 1996		10-K, 1996		4(a)(3)
July 1, 1968		8-K, July 1968		2		Feb. 1, 1997		10-Q, Mar. 31, 1997		4(a)
Apr. 25, 1969		8-K, Apr. 1969		1		April 1, 1998		10-Q, Mar. 31, 1998		4(a)
Apr. 21, 1970		8-K, Apr. 1970		1		Aug. 15, 2002		10-Q, Sept. 30, 2002		4.01
						Sept. 15, 2002		10-Q, Sept. 30, 2002		4.02
						Sept. 18, 2002		8-K, Sept. 18, 2002		4.02

129

4.03*	Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
4.04*	Indentures supplemental to Indenture dated as of Oct. 1, 1993:

	Previous Filing:
	Form; Date or		Exhibit
Dated as of	File No.		No.
Nov. 1, 1993		S-3, (33-51167)		4(b)(2)
Jan. 1, 1994		10-K, 1993		4(b)(3)
Sept. 2, 1994		8-K, Sept. 1994		4(b)
May 1, 1996		10-Q, June 30, 1996		4(b)
Nov. 1, 1996		10-K, 1996		4(b)(3)
Feb. 1, 1997		10-Q, Mar. 31, 1997		4(b)
April 1, 1998		10-Q, Mar. 31, 1998		4(b)
Aug. 15, 2002		10-Q, Sept. 30, 2002		4.03
Sept. 1, 2002		8-K, Sept. 18, 2002		4.01
Sept. 15, 2002		10-Q, Sept. 30, 2002		4.04

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

130

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

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

           None

SPS

		Page
(a)1.	Financial Statements and Schedules
	Reports of Independent Auditors for the years ended Dec. 31, 2002, 2001 and 2000.		53
	Statements of Income for the three years ended Dec. 31, 2002.		70
	Statements of Cash Flows for the three years ended Dec. 31, 2002.		71
	Balance Sheets, Dec. 31, 2002 and 2001.		72
	Notes to Financial Statements.		75
	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2002, 2001 and 2000

2.	Exhibits
*	indicates incorporation by reference
2.01*	Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, Exhibit 2, dated Aug. 22, 1995).
3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(a)(2)).
3.02*	By-laws dated Sept. 29, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(2)).
4.01*	Indenture, dated as of Aug. 1, 1946, providing for the issuance of First Mortgage Bonds (Registration No. 2-6910, Exhibit 7-A).
4.02*	Indentures supplemental to Indenture dated as of Aug. 1, 1946:

	Previous Filing:
	Form; Date or	Exhibit
Dated as of	File No.	No.
Feb. 1, 1967	2-25983	2-S
Oct. 1, 1970	2-38566	2-T
Feb. 9, 1977	2-58209	2-Y
March 1, 1979	2-64022	b(28)
April 1, 1983 (two)	10-Q, May 1983	4(a)
Feb. 1, 1985	10-K, Aug. 1985	4(c)
July 15, 1992 (two)	10-K, Aug. 1992	4(a)
Dec. 1, 1992 (two)	10-Q, Feb. 1993	4
Feb. 15, 1995	10-Q, May 1995	4
March 1, 1996	333-05199	4(c)

4.03*	Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Form 8-K, Feb. 25, 1999, Exhibit B).
4.04*	Supplemental Indenture dated March 1, 1999, between SPS and The Chase Manhattan Bank (Form 8-K, Feb. 25, 1999, Exhibit C).
4.05*	Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 — Exhibit 4(b)).

131

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

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

None

132

SCHEDULE II

UTILITY SUBSIDIARIES OF XCEL ENERGY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Years Ended Dec. 31, 2002, 2001 and 2000

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

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

133

NSP-MINNESOTA

SIGNATURES

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

NSP-MINNESOTA

/s/ RICHARD C. KELLY

Richard C. Kelly

Vice President and Chief Financial Officer

(Principal Financial Officer)

February 25, 2003

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

/s/ WAYNE H. BRUNETTI	/s/ GARY R. JOHNSON
Wayne H. Brunetti Chairman, President and Chief Executive Officer (Principal Executive Officer)	Gary R. Johnson Director
/s/ DAVID E. RIPKA	/s/ RICHARD C. KELLY
David E. Ripka Vice President and Controller (Principal Accounting Officer)	Richard C. Kelly Director

134

NSP-MINNESOTA

CERTIFICATIONS

I, Wayne H. Brunetti, certify that:

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

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

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

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

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

      b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

      c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

      a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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

/s/ WAYNE H. BRUNETTI

Wayne H. Brunetti

Chairman, President and Chief Executive Officer

Date: Feb. 25, 2003

135

I, Richard C. Kelly, certify that:

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

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

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

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

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

      b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

      c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

      a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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

/s/ RICHARD C. KELLY

Richard C. Kelly

Vice President and Chief Financial Officer

Date: Feb. 25, 2003

136

NSP-WISCONSIN

SIGNATURES

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

NSP-WISCONSIN

/s/ RICHARD C. KELLY

Richard C. Kelly

Vice President and Chief Financial Officer

(Principal Financial Officer)

February 25, 2003

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

/s/ MICHAEL L. SWENSON	/s/ WAYNE H. BRUNETTI
Michael L. Swenson President and Chief Executive Officer (Principal Executive Officer)	Wayne H. Brunetti Chairman
/s/ DAVID E. RIPKA	/s/ GARY R. JOHNSON
David E. Ripka Vice President and Controller (Principal Accounting Officer)	Gary R. Johnson Director
/s/ RICHARD C. KELLY Richard C. Kelly Director

137

NSP-WISCONSIN

CERTIFICATIONS

I, Michael L. Swenson, certify that:

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

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

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

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

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

      b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

      c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

      a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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

/s/ MICHAEL L. SWENSON

Michael L. Swenson

President and Chief Executive Officer

Date: Feb. 25, 2003

138

I, Richard C. Kelly, certify that:

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

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

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

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

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

      b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

      c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

      a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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

/s/ RICHARD C. KELLY

Richard C. Kelly

Vice President and Chief Financial Officer

Date: Feb. 25, 2003

139

PSCo

SIGNATURES

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

PUBLIC SERVICE COMPANY OF COLORADO

/s/ RICHARD C. KELLY

Richard C. Kelly

Vice President and Chief Financial Officer

(Principal Finance Officer)

February 25, 2003

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

/s/ WAYNE H. BRUNETTI	/s/ GARY R. JOHNSON
Wayne H. Brunetti Chairman, President and Chief Executive Officer (Principal Executive Officer)	Gary R. Johnson Director
/s/ DAVID E. RIPKA	/s/ RICHARD C. KELLY
David E. Ripka Vice President and Controller (Principal Accounting Officer)	Richard C. Kelly Director

140

PSCo

CERTIFICATIONS

I, Wayne H. Brunetti, certify that:

      1. I have reviewed this annual report on Form 10-K of Public Service Company of Colorado;

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

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

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

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

      b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

      c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

      a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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

/s/ WAYNE H. BRUNETTI

Wayne H. Brunetti

Chairman, President and Chief Executive Officer

Date: Feb. 25, 2003

141

I, Richard C. Kelly, certify that:

      1. I have reviewed this annual report on Form 10-K of Public Service Company of Colorado;

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

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

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

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

      b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

      c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

      a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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

/s/ RICHARD C. KELLY

Richard C. Kelly

Vice President and Chief Financial Officer

Date: Feb. 25, 2003

142

SPS

SIGNATURES

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

SOUTHWESTERN PUBLIC SERVICE CO.

/s/ RICHARD C. KELLY

Vice President and Chief Financial Officer

(Principal Financial Officer)

February 25, 2003

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

/s/ GARY L. GIBSON	/s/ WAYNE H. BRUNETTI
Gary L. Gibson President and Chief Executive Officer (Principal Executive Officer)	Wayne H. Brunetti Chairman
/s/ DAVID E. RIPKA	/s/ GARY R. JOHNSON
David E. Ripka Vice President and Controller (Principal Accounting Officer)	Gary R. Johnson Director
/s/ RICHARD C. KELLY Richard C. Kelly Director

143

SPS

CERTIFICATIONS

I, Gary L. Gibson, certify that:

      1. I have reviewed this annual report on Form 10-K of Southwestern Public Service;

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

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

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

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

      b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

      c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

      a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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

/s/ GARY L. GIBSON

Gary L. Gibson

President and Chief Executive Officer

Date: Feb. 25, 2003

144

I, Richard C. Kelly, certify that:

      1. I have reviewed this annual report on Form 10-K of Southwestern Public Service;

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

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

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

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

      b) evaluated in this annual report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

      c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

      a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

      b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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

/s/ RICHARD C. KELLY

Richard C. Kelly

Vice President and Chief Financial Officer

Date: Feb. 25, 2003

145 EX-12.01 3 c75034exv12w01.htm EX-12.01 COMPUTATION OF RATIO OF EARNINGS

Exhibit 12.01

EXHIBIT 12(a)

NORTHERN STATES POWER COMPANY — MINNESOTA
AND SUBSIDIARIES

COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS
TO CONSOLIDATED FIXED CHARGES

(not covered by Report of Independent Auditor)

			Year Ended December 31,
			2002		2001		2000		1999		1998
					(in thousands, except ratios)
Earnings:
	Net income		$	200,222	$	207,865	$	111,224	$	158,980	$	210,206
	Provisions for Federal and state taxes on income			108,141		132,732		92,191		97,431		124,713
	Fixed charges as below			123,220		112,780		146,192		125,431		113,160
	Less: Undistributed equity in earnings of unconsolidated affiliates			—		—		—		—		—
		Total	$	431,583	$	453,377	$	349,607	$	381,842	$	448,079
Fixed Charges:
	Interest charges, excluding AFC — debt		$	107,470	$	97,030	$	130,442	$	109,681	$	97,410
	Distributions on redeemable preferred securities of subsidiary trust			15,750		15,750		15,750		15,750		15,750
		Total	$	123,220	$	112,780	$	146,192	$	125,431	$	113,160
Ratio of earnings to fixed charges				3.5		4.0		2.4		3.0		4.0

EXHIBIT 12(b)

NORTHERN STATES POWER COMPANY — WISCONSIN

COMPUTATION OF RATIO OF EARNINGS
TO FIXED CHARGES

(not covered by Report of Independent Auditor)

			Year Ended December 31,
			2002		2001		2000		1999		1998
					(in thousands, except ratios)
Earnings:
	Net income		$	54,373	$	36,392	$	30,296	$	36,366	$	32,195
	Provisions for Federal and state taxes on income			36,925		21,158		20,690		25,302		20,468
	Fixed charges as below			23,467		23,139		21,557		19,627		19,189
	Less: Undistributed equity in earnings of unconsolidated affiliates			232		553		411		409		3
		Total	$	114,533	$	80,136	$	72,132	$	80,886	$	71,849
Fixed Charges:
	Interest charges, excluding AFC — debt		$	23,467	$	23,139	$	21,557	$	19,627	$	19,189
	Distributions on redeemable preferred securities of subsidiary trust			—		—		—		—		—
		Total	$	23,467	$	23,139	$	21,557	$	19,627	$	19,189
Ratio of earnings to fixed charges				4.9		3.5		3.3		4.1		3.7

EXHIBIT 12(c)

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES

COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS
TO CONSOLIDATED FIXED CHARGES

(not covered by Report of Independent Auditor)

			Year Ended December 31,
			2002		2001		2000		1999		1998
					(in thousands, except ratios)
Earnings:
	Net income		$	264,680	$	273,033	$	196,128	$	204,265	$	200,103
	Provisions for Federal and state taxes on income			128,686		132,501		102,770		96,574		101,494
	Fixed charges as below			237,765		226,651		244,952		234,544		210,539
	Less: Undistributed equity in earnings of unconsolidated affiliates			—		—		—		—		—
		Total	$	631,131	$	632,185	$	543,850	$	535,383	$	512,136
Fixed Charges:
	Interest charges, excluding AFC — debt		$	223,021	$	211,451	$	229,752	$	219,344	$	200,828
	Distributions on redeemable preferred securities of subsidiary trust			14,744		15,200		15,200		15,200		9,711
		Total	$	237,765	$	226,651	$	244,952	$	234,544	$	210,539
Ratio of earnings to fixed charges				2.7		2.8		2.2		2.3		2.4

EXHIBIT 12(d)

SOUTHWESTERN PUBLIC SERVICE COMPANY
AND SUBSIDIARIES

COMPUTATION OF RATIO OF EARNINGS
TO FIXED CHARGES

(not covered by Report of Independent Auditor)

			Year Ended December 31,
			2002		2001		2000		1999		1998
					(in thousands, except ratios)
Earnings:
	Net income		$	73,882	$	130,100	$	69,492	$	102,709	$	114,987
	Provisions for Federal and state taxes on income			43,363		71,175		58,776		59,399		65,696
	Fixed charges as below			54,913		57,276		67,713		64,888		64,052
	Less: Undistributed equity in earnings of unconsolidated affiliates			—		—		—		—		—
		Total	$	172,158	$	258,551	$	195,981	$	226,996	$	244,735
Fixed Charges:
	Interest charges, excluding AFC — debt		$	47,063	$	49,426	$	59,863	$	57,038	$	56,202
	Distributions on redeemable preferred securities of subsidiary trust			7,850		7,850		7,850		7,850		7,850
		Total	$	54,913	$	57,276	$	67,713	$	64,888	$	64,052
Ratio of earnings to fixed charges				3.1		4.5		2.9		3.5		3.8

EX-23.01 4 c75034exv23w01.htm EX-23.01 CONSENT OF INDEPENDENT ACCOUNTANTS

EXHIBIT 23.01

INDEPENDENT AUDITORS’ CONSENT

We consent to the incorporation by reference in Registration Statements No. 333-59098 and 333-101531 of Northern States Power Company — Minnesota on Form S-3 and S-4 of our report dated February 24, 2003, appearing in this Annual Report on Form 10-K of Northern States Power Company — Minnesota for the year ended December 31, 2002.

DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 24, 2003

EXHIBIT 23.01

INDEPENDENT AUDITORS’ CONSENT

We consent to the incorporation by reference in Registration Statements No. 333-81791 and 333-101913 of Public Service Company of Colorado on Forms S-3 and S-4 of our report dated February 24, 2003, appearing in this Annual Report on Form 10-K of Public Service Company of Colorado for the year ended December 31, 2002.

DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 24, 2003

EX-99.01 5 c75034exv99w01.htm EX-99.01 STATEMENT PURSUANT TO SECURITIES ACT

Exhibit 99.01

Utility Subsidiaries of Xcel Energy Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of the Utility Subsidiaries of Xcel Energy. These statements are based on management’s beliefs as well as assumptions and information currently available to management. When used in the Utility Subsidiaries of Xcel Energy’s documents or oral presentations, the words “anticipate,” “estimate,” “expect,” “projected,” objective,” “outlook,” “forecast,” “possible,” “potential” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Utility Subsidiaries of Xcel Energy’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including their impact on capital expenditures and the ability of the Utility Subsidiaries of Xcel Energy to obtain financing on favorable terms, inflation rates and monetary fluctuations;

• Business conditions in the energy business;

• Demand for electricity in the nonregulated marketplace;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where the Utility Subsidiaries of Xcel Energy have a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, Xcel Energy or any of its subsidiaries; or security ratings;

• Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; or electric transmission or gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry;

• State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates; structures and affect the speed and degree to which competition enters the electric and gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;

• Social attitudes regarding the utility and power industries;

• Risks associated with the California power market;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Significant slowdown in growth or decline in the U.S. economy, delay in growth or recovery of the U.S. economy or increased cost for insurance premiums, security and other items as a consequence of the Sept. 11, 2001 terrorist attacks;

• Factors associated with nonregulated investments, including conditions of final legal closing, foreign government actions, foreign economic and currency risks, political instability in foreign countries, partnership actions, competition, operating risks, dependence on certain suppliers and customers, domestic and foreign environmental and energy regulations; and

• Other business or investment considerations that may be disclosed from time to time in the Utility Subsidiaries of Xcel Energy’s SEC filings or in other publicly disseminated written documents.

The Utility Subsidiaries of Xcel Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exhaustive.

EX-99.03 6 c75034exv99w03.htm EX-99.03 CERTIFICATION PURSUANT TO 18 USC SEC 1350

Exhibit 99.03 — Officer Certification

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of NSP-Minnesota on Form 10-K for 2002, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the NSP-Minnesota certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of NSP-Minnesota as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 25, 2003

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

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

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

1

Exhibit 99.03 — Officer Certification

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of NSP-Wisconsin on Form 10-K for the year 2002, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the NSP-Wisconsin certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of NSP-Wisconsin as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 25, 2003

/s/ Michael L. Swenson
Wayne H. Brunetti
President and Chief Executive Officer

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

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

2

Exhibit 99.03 — Officer Certification

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of PSCo on Form 10-K for the year 2002, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the PSCo certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of PSCo as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 25, 2003

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

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

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

3

Exhibit 99.03 — Officer Certification

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of SPS on Form 10-K for the year 2002, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the SPS certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of SPS as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 25, 2003

/s/ GARY L. GIBSON
Gary L. Gibson
President and Chairman

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

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

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