UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

		For the fiscal year ended December 31, 2004

OR

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

		For the transition period from to

COMMISSION FILE NUMBER 000-31387

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

Minnesota		41-1967505
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

414 Nicollet Mall

Minneapolis, Minnesota 55401

(Address of principal executive offices)

(Zip Code)

(612) 330-5500

(Registrant’s telephone number, including area code)

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

Securities registered pursuant to Section 12(g) of the Act: Common Stock

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 ý No o

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

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

As of Feb. 28, 2005, 1,000,000 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota Corporation.

DOCUMENTS INCORPORATED BY REFERENCE: Xcel Energy Inc.’s 2005 Proxy Statement

Northern States Power Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

*Xcel Energy Subsidiaries and Affiliates*
NSP-Minnesota		Northern States Power Co., a Minnesota corporation
NSP-Wisconsin		Northern States Power Co., a Wisconsin corporation
PSCo		Public Service Company of Colorado, a Colorado corporation
SPS		Southwestern Public Service Co., a New Mexico corporation
Utility Subsidiaries		NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy		Xcel Energy Inc., a Minnesota corporation

*Federal and State Regulatory Agencies*
ASLB		Atomic Safety and Licensing Board
DOE		United States Department of Energy
DOL		United States Department of Labor
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas, and the sale of electricity at wholesale, in interstate commerce, including the sale of electricity at market-based rates.
IRS		Internal Revenue Service
MEQB		Minnesota Environment Quality Board. Selects and designates sites for new power plants (capacity of 50MW or more), wind energy conversion plants (capacity of 5MW or more) and routes for electric transmission lines (capacity of 100KV or more) in Minnesota.
MPUC		Minnesota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in Minnesota. The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.
NDPSC		North Dakota Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in North Dakota.
NRC		Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
SDPUC		South Dakota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in South Dakota.
SEC		Securities and Exchange Commission

*Fuel, Purchased Gas and Resource Adjustment Clauses*
FCA		Fuel clause adjustment. A clause included in NSP-Minnesota’s retail electric rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of electric fuel and purchased energy. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent three-month period.
PGA		Purchased gas adjustment. A clause included in NSP-Minnesota’s retail gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased gas. The annual difference between the gas costs collected through PGA rates and the actual gas costs is collected or refunded over the subsequent 12-month period.

RCR		Renewable cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities and other costs incurred to facilitate the purchase of renewable energy (including wind energy) in retail electric rates in Minnesota. The RCR is revised annually.

*Other Terms and Abbreviations*
AFDC		Allowance for funds used during construction. Defined in regulatory accounts as a non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ		Administrative law judge. A judge presiding over regulatory proceedings.
ARO		Asset Retirement Obligation.
C20		Derivatives Implementation Group of FASB Implementation Issue No. C20. Clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended.
Decommissioning		The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.
Deferred energy costs		The amount of fuel costs applicable to service rendered in one accounting period that will not be reflected in billings to customers until a subsequent accounting period.
Derivative instrument		A financial instrument or other contract with all three of the following characteristics: • An underlying and a notional amount or payment provision or both, • Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and • Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement
Distribution		The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
ERISA		Employee Retirement Income Security Act
FASB		Financial Accounting Standards Board
FTRs		Financial Transmission Rights
GAAP		Generally accepted accounting principles
Generation		The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
JOA		Joint operating agreement among the Utility Subsidiaries
LDC		Local distribution company. A company or division that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or natural gas for ultimate consumption.
LIBOR		London Interbank Offered Rate
LNG		Liquefied natural gas. Natural gas that has been converted to a liquid by cooling it to – 260 degrees Fahrenheit.
Mark-to-market		The process whereby an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in current earnings in the Consolidated Statements of Operations or in Other Comprehensive Income within equity during the current period.

MERP		Metropolitan emissions reduction project.
MGP		Manufactured gas plant.
MISO		Midwest Independent Transmission System Operator, Inc.
Native load		The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
Natural gas		A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
Nonutility		All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
OMOI		FERC Office of Market Oversight and Investigations
PFS		Private Fuel Storage, LLC. A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.
PJM		PJM Interconnection, Inc.
PUHCA		Public Utility Holding Company Act of 1935. Enacted to regulate the corporate structure and financial operations of utility holding companies. Applies to companies that own or control 10% or more of a utility.
QF		Qualifying facility. As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price equal to that which it would otherwise pay if it were to build its own power plant or buy power from another source.
Rate base		The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
ROE		Return on equity
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utilities’ electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SFAS		Statement of Financial Accounting Standards
SMA		Supply margin assessment
SMD		Standard market design
SO2		Sulfur dioxide
TEMT		Transmission and Energy Markets Tariff
Unbilled revenues		Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
Underlying		A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
VaR		Value-at-risk
Wheeling or Transmission		An electric service wherein high voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
Working capital		Funds necessary to meet operating expenses

*Measurements*
Btu		British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
Bcf		Billion cubic feet
Dth		Dekatherm (one Dth is equal to one MMBtu)

COMPANY OVERVIEW

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. Prior to 2000, the regulated utility operations were conducted by the legal entity now operating under the name Xcel Energy, Inc. NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale 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 natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.4 million customers and gas utility service to approximately 454,000 customers.

The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the NSP System, including capital costs.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds real estate; and NSP Nuclear Corp., which holds NSP-Minnesota’s interest in the Nuclear Management Co. (NMC). NSP-Minnesota owned NSP Financing I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Sept. 15, 2003. NSP-Minnesota is a wholly owned subsidiary of Xcel Energy.

Xcel Energy was incorporated under the laws of Minnesota in 1909 and is a registered holding company under the PUHCA. Xcel Energy is subject to the regulatory oversight of the SEC under PUHCA. The rules and regulations under PUHCA impose a number of restrictions on the operations of registered holding company systems. These restrictions include, subject to certain exceptions, a requirement that the SEC approve securities issuances, payments of dividends out of capital or unearned surplus, sales and acquisitions of utility assets or of securities of utility companies and acquisitions of other businesses. PUHCA also generally limits the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules require that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions.

In 2004, Xcel Energy continuing operations included the activity of four wholly owned utility subsidiaries, including NSP-Minnesota, that serve electric and natural gas customers in 10 states. The other utility subsidiaries are NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin.

ELECTRIC UTILITY OPERATIONS

Overview

Utility Industry Growth — After a decade of cost cutting and efficiency gains in anticipation of industry restructuring and competition, areas of growth for the utility industry are limited. The most significant areas for earnings growth include increasing regulated rates, increased investment in rate base, diversification, acquisition or modification of rate structures to implement performance-based rates. NSP-Minnesota intends to focus on growing through investments in electric and natural gas rate base to meet growing customer demands and to maintain or increase reliability and quality of service to customers and rate case filings with state and federal regulators to increase rates congruent with increasing costs of operations associated with such investments.

Utility Restructuring and Retail Competition — The structure of the utility industry has been subject to change. Merger and acquisition activity in the past had been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future, although such activity slowed substantially after 2001. All investor-owned utilities were required to provide nondiscriminatory access to the use of their transmission systems in 1996. Beginning in the late 1990s, many states began studying or implementing some form of retail electric utility competition. As a result of the failure of the California power market structure and nonregulated investments of many utilities, as well as other factors, most utility retail market restructuring has ceased. No significant activity has occurred or is expected to occur in any of the retail jurisdictions in which NSP-Minnesota operates.

The retail electric business does face some competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas or steam/chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. While NSP-Minnesota faces these challenges, it believes its rates are competitive with currently available

alternatives.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, accounting practices and certain other activities of NSP-Minnesota. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters.

Market Based Rate Authority — The FERC regulates the wholesale sale of electricity. In addition to FERC’s traditional cost of service methodology for determining the rates allowed to be charged for wholesale electric sales, in the 1990’s FERC began to allow utilities to make sales at market-based rates. In order to obtain market-based rate authorization from the FERC, utilities such as NSP-Minnesota, have been required to submit analyses demonstrating that they did not have market power in the relevant markets. NSP-Minnesota has been authorized by FERC to make wholesale sales at market-based rates.

In November 2001, after the market disruptions in California and other regions, the FERC issued an order under Section 206 of the Federal Power Act initiating a generic investigation proceeding against all jurisdictional electric suppliers making sales in interstate commerce at market-based rates. In November 2003, the FERC issued a final order requiring amendments to the market-based wholesale tariffs of all FERC jurisdictional electric utilities to impose new market behavior rules and requiring submission of compliance tariff amendments in December 2003. NSP-Minnesota made a timely compliance filing. Violations of the new tariffs could result in the loss of certain wholesale sales revenues or the loss of authority to make sales at market-based rates.

In 2004, FERC initiated a new proceeding on future market-based rate authorizations and issued interim requirements for FERC jurisdictional electric utilities that have been granted authority to make wholesale sales at market-based rates. The FERC adopted a new interim methodology to assess generation market power and modified measures to mitigate market power where it is found. The FERC upheld and clarified the interim requirements on rehearing in an order issued on July 8, 2004. This methodology is to be applied to all initial market-based rate applications and triennial reviews. Under this methodology, the FERC has adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) to assess market power. Passage of the two screens creates a rebuttable presumption that an applicant does not have market power, while the failure creates a rebuttable presumption that the utility does have market power. An applicant or intervenor can rebut the presumption by performing a more extensive delivered-price test analysis. If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC. The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power.

As required by the FERC, Xcel Energy filed the required analysis applying the FERC’s two indicative screens on behalf of itself and the Utility Subsidiaries with the FERC on Feb. 7, 2005. This analysis demonstrated that NSP-Minnesota passed the pivotal supplier analysis in its own control area and all adjacent markets, but that it failed the market share analysis in its own control area, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointly operate a single control area and accordingly are analyzed as one company, in certain adjacent markets. It is accordingly expected that the FERC will set the market-rate authorizations for NSP-Minnesota for investigation and hearing under Section 206 of the Federal Power Act. At that time, NSP-Minnesota expects to submit a delivered-price test analysis to support the continuance of market-based rate authority in its control areas. NSP-Minnesota also expects that upon the commencement of the MISO Day 2 market (see Electric Transmission Rate Regulation, below for further discussion), NSP-Minnesota and NSP-Wisconsin will be analyzed as part of the larger MISO market, and that those companies will pass both of the FERC’s indicative screens in the larger MISO market. NSP-Minnesota does not expect the mitigation measures imposed, if any, to have a significant financial impact on its commodity marketing operations.

In order to enable it and interested parties to monitor each individual utility’s market-based rate authority, the FERC on Feb. 10, 2005 issued a final rule requiring that a utility with market-based rate authority file reports notifying the FERC of changes in status (e.g., additions of certain generating resources) that reflect a departure from the characteristics that the FERC relied upon in granting that utility market-based rate authority within thirty days of the occurrence of a triggering event.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services. Since 1996, the FERC has required NSP-Minnesota to provide open access transmission service at rates and tariffs on file with the FERC. In addition, FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility for the sale of electric transmission services to an RTO. NSP-Minnesota is a member of the MISO, which began RTO operations in early 2002. Each RTO separately files for regional transmission tariff rates for approval by FERC. All members within that RTO are then subjected to those rates.

Generation Interconnection Rules — In August 2003, the FERC issued final rules requiring the standardization of generation interconnection procedures and agreements for interconnection of new electric generators of 20 megawatts or more to the transmission systems of all FERC-jurisdictional electric utilities, including NSP-Minnesota. The FERC also established pricing rules for interconnections and related transmission system upgrades, which allow the transmission-owning utility to require the interconnecting customer to fund the interconnection costs and network upgrades required by the new generator, but require the transmission utility to provide transmission service credits, with interest, for the full amount of prepayment. The FERC required compliance filings for detailing proposed changes to NSP-Minnesota’s tariff and the MISO regional tariff, which will govern most generation interconnections to the NSP-Minnesota transmission system. In October 2004, the FERC accepted proposed tariff changes for NSP-Minnesota, subject to certain conditions. In November 2004, NSP-Minnesota submitted a compliance filing. In December 2004, the FERC issued further modifications to the interconnection rules on rehearing and required NSP-Minnesota to submit a further compliance filing by February 2005. The required compliance filing was submitted on Feb. 18, 2005.

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the jurisdiction of the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC has 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 for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices and is a transmission-only member of the MISO RTO.

The MEQB is empowered to select and designate sites for new power plants with a capacity of 50 MW or more and wind energy conversion plants with a capacity of five MW or more. It also designates routes for electric transmission lines with a capacity of 100 KV or more. No power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB. The NDPSC and SDPUC have regulatory authority over the need for certain generating and transmission facilities, and the siting and routing of certain new generation and transmission facilities in North Dakota and South Dakota, respectively.

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota jurisdictions include an FCA that provides for monthly adjustments to billings and revenues for changes in prudently incurred cost of fuel, fuel related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms individually approved by the regulators in each jurisdiction. The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers. In general, capacity costs are not recovered through the FCA. NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.

The MPUC has opened an investigation to consider the continuing usefulness of fuel clause adjustments for electric utilities in Minnesota. No action has been proposed. The MPUC has the authority to disallow recovery of 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 on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for electric conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

Performance-Based Regulation and Quality of Service Requirements — In December 2003, the MPUC voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. All three plants are located in the Minneapolis - St. Paul metropolitan area. These

improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion. The MPUC also approved NSP-Minnesota’s proposal to recover prudent costs of the projects through a rate adjustment provision applicable to retail electric rates beginning Jan. 1, 2006, including a rate of return on the construction work in progress. The MPUC approval has a sliding ROE scale based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and debt of 51.5 percent) to incentivize NSP-Minnesota to control construction costs.

Actual Costs as a Percent of Target Costs	ROE

Less than or equal to 75%	11.47	%
Over 75% and up through 85%	11.22	%
Over 85% and up through 95%	11.00	%
Over 95% and up through 105%	10.86	%
Over 105% and up through 115%	10.55	%
Over 115% and up through 125%	10.22	%
Over 125%	9.97	%

Pending and Recently Concluded Regulatory Proceedings - FERC

MISO Operations — In August 2000, NSP-Minnesota and NSP-Wisconsin joined the MISO. In December 2001, the FERC approved the MISO as the first RTO in the United States under FERC Order No. 2000. On Feb. 1, 2002, the MISO began interim operations, including regional transmission tariff administration services for the NSP-Minnesota and NSP-Wisconsin electric transmission systems. In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 KV and above) transmission systems to the MISO. The MISO membership grants MISO functional control over the operations of these facilities and the facilities of certain neighboring electric utilities.

On March 31, 2004, the MISO filed its proposed TEMT, which would establish regional wholesale energy markets using locational marginal cost pricing and FTRs. NSP-Minnesota and NSP-Wisconsin’s generation plants and transmission systems would operate subject to the TEMT. The MISO proposed a Dec. 1, 2004 effective date.

On May 26, 2004, the FERC issued an initial procedural order. The FERC found that certain pre-Order 888 “grandfathered” agreements (GFAs) for transmission service could negatively affect implementation of the TEMT, so FERC delayed the effective date of the energy market to March 1, 2005. NSP-Minnesota and NSP-Wisconsin submitted compliance filings regarding their approximately 50 GFAs on June 25, 2004. Approximately 10 GFAs were disputed, and hearings were held June 30, 2004 and July 1, 2004. The other GFAs are not disputed. The primary disputed issues related to responsibility for TEMT charges for loads served under the GFAs. On Sept. 16, 2004, the FERC issued an order ruling that certain GFAs would be “carved out” of the MISO market but that transmission owners would be subject to the TEMT charges for other GFAs. The FERC has not issued a final decision on rehearing. On Jan. 13, 2005, several transmission-owning members of the MISO, including NSP-Minnesota, filed revisions to the MISO tariff to recover TEMT charges from the customers subject to the “carved out” GFAs, effective March 1, 2005. NSP-Minnesota and NSP-Wisconsin expect to file for rate changes under certain GFAs to recover TEMT charges from these GFA customers later in 2005.

On Aug. 6, 2004, after completion of the GFA hearings and submission of the ALJ report, the FERC issued its initial substantive order regarding the TEMT. The FERC approved the TEMT and reaffirmed the March 1, 2005 effective date, but ordered various changes to the filed tariff. On Sept. 7, 2004, numerous requests for rehearing were filed contesting various FERC decisions. On Nov. 8, 2004, the FERC issued its order on rehearing largely upholding the August 6^th order. On or before Jan. 6, 2005, several appeals of the two FERC orders were filed with the District of Columbia Court of Appeals. NSP-Minnesota does not believe the outcome of the appeals will have a material financial impact. In addition, various parties, including NSP-Minnesota, have documented their concerns to MISO regarding MISO’s readiness to initiate the new energy market on March 1, 2005. On Jan. 27, 2005, MISO announced a delay in the full market start date until April 1, 2005.

NSP-Minnesota opposes certain aspects of the TEMT-related implementation practices as presently designed, and believes the MISO should implement the new market mechanisms only after it demonstrates that it has fully developed all operating procedures necessary to protect reliability. NSP-Minnesota cannot at this time estimate the total financial impact of the new market structure. NSP-Minnesota also cannot predict at this time whether the numerous remaining issues will be resolved in time to allow the MISO market to commence on the new April 1, 2005 start date, as proposed.

Wisconsin Public Service Corp. vs. MISO — On Dec. 27, 2004, Wisconsin Public Service Corp. (WPS) filed a complaint with the FERC alleging that certain FTRs allocated to NSP-Minnesota in MISO’s FTR nomination and allocation process, associated with the implementation of the new MISO TEMT, improperly granted NSP-Minnesota FTRs to the detriment of WPS. WPS alleged the FTR allocation to NSP-Minnesota would increase costs to WPS and its customers. WPS requested accelerated processing of the complaint. On Jan. 15, 2005, MISO and NSP-Minnesota filed answers asking that the WPS complaint be dismissed. The complaint is now pending resolution by the FERC. In a related matter, WPS appealed to the U.S. District Court for the District of Columbia previous FERC orders upholding NSP-Minnesota’s right to the underlying transmission service at issue in the MISO FTR allocation. The appeal is scheduled to be heard by the court in April 2005.

MISO Long Term Pricing — On Nov. 18, 2004, FERC issued an order approving portions of a plan providing for continued use of “license plate” rates for the MISO/PJM region, but rejecting proposed transition payments. FERC instead ordered the MISO and PJM to file a Seams Elimination Charge Adjustment (SECA) transition mechanism. The replacement compliance filings were submitted Nov. 24, 2004, to be effective December 1, 2004. The FERC order eliminates any transition payments and the SECA filings instead provide for both revenues and payments that net to approximately $117,000 in revenues per month to NSP-Minnesota and NSP-Wisconsin in the first three months of 2005. MISO and PJM are required to update the SECA charges effective April 1, 2005. The magnitude of the new charges and payments is unknown at this time, but is expected to be similar to the charges and payments for the first three months of 2005.

Various parties sought rehearing of the Nov. 18, 2004 order and/or filed objections to the Nov. 24, 2004 SECA compliance filings. On Feb. 10, 2005, the FERC issued an order accepting the SECA filings effective Dec. 1, 2004, subject to refund, and set the proposals for hearings. Therefore, the final resolution of the SECA issue and its impact on NSP-Minnesota and NSP-Wisconsin, is not fully known at this time.

Interchange Agreement — On Jan. 26, 2005, NSP-Minnesota and NSP-Wisconsin filed the annual revisions to the interchange agreement, a FERC rate schedule that shares the costs of the integrated generation and transmission systems of the two utilities. In addition to updating the cost allocation factors to reflect changes to their respective customer loads, NSP-Minnesota and NSP-Wisconsin filed a revised loss study that will affect the allocation of the costs of electrical losses to be effective Jan. 1, 2005. The updated loss study utilizes the same methodology previously approved by the FERC. The updated cost allocation factors, which include the updated loss ratios calculated in the study, are expected to decrease the actual costs allocated to NSP-Minnesota by approximately $11 million per year.

Pending and Recently Concluded Regulatory Proceedings - MPUC

Minnesota Service Quality Investigation — In 2002, the MPUC directed the Office of the Attorney General and the Minnesota Department of Commerce (state agencies) to investigate the accuracy of NSP-Minnesota’s electric reliability records, which are summarized and reported to the MPUC on a monthly and annual basis, subject to penalty for not meeting threshold requirements, under the terms of the merger settlement agreements.

In 2003, NSP-Minnesota and the state agencies announced that they had reached a settlement agreement, which was approved with modifications by the MPUC in January 2004. The settlement required NSP-Minnesota to refund $1 million to customers in Minnesota, which was paid in 2004. In addition, it required NSP-Minnesota to incur at least $15 million of costs for actions to improve system reliability above amounts being recovered in 2004 rates by Jan. 1, 2005, for which $19 million was expended in 2004. The MPUC modified the settlement to include an additional under-performance payment for any future finding of inaccurate reliability data.

NRG Tax Complaint — In November 2003, an NSP-Minnesota customer filed a complaint with the MPUC alleging that ratepayers are entitled to a share of the tax benefits attributable to NRG. The customer subsequently supplemented this complaint with sufficient signatures from customers to warrant a formal complaint process by the MPUC. NSP-Minnesota responded to the complaint, arguing that the requested treatment is not allowed by law and is inconsistent with the MPUC’s directives to ensure full separation of NSP-Minnesota and NRG. In August 2004, the MPUC decided not to pursue this complaint. The MPUC affirmed the long-standing precedent to view each utility as a stand-alone business that does not experience positive or negative effects from its affiliates. The customer filed an appeal of this decision on Jan. 7, 2005, and NSP-Minnesota filed a responsive statement of the case on Jan. 18, 2005. The Attorney General’s office petitioned to file an advisory brief to the customer’s case.

Renewable Transmission Cost Recovery — In 2002, NSP-Minnesota filed for MPUC approval to establish an RCR adjustment

mechanism to recover the costs of transmission investments incurred to deliver renewable energy resources. The RCR adjustment mechanism provides for annual filings to set the RCR adjustment rates using updated transmission cost information. The MPUC approved the RCR adjustment mechanism and the two-phase filing mechanism in April 2003. In February 2004, the MPUC conditionally approved the initial Phase 1 facility eligibility determination filing. NSP-Minnesota then filed for approval to recover annual additional transmission costs from May 2004 to December 2004, which were approximately $6 million. The request was approved and the RCR was implemented Dec. 1, 2004. NSP-Minnesota collected approximately $0.2 million in 2004. NSP-Minnesota submitted a filing to determine the eligibility of additional transmission projects and to establish the RCR factors for 2005 in February 2005, seeking recovery of $12.9 million of additional revenues in 2005.

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 customers about their use of electricity and its costs. NSP-Minnesota has petitioned the MPUC for recovery of program costs. The 2002 program costs were approximately $2 million. The Department of Commerce has supported deferred accounting to provide for recovery of 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. A MPUC hearing was held in January 2004 and requested NSP-Minnesota to further substantiate the prudence and appropriateness of the costs incurred. The MPUC has voted to allow recovery of the program costs. An order of the MPUC is expected in early 2005.

MISO Cost Recovery Petition — On Dec. 18, 2004, NSP-Minnesota filed a petition to seek recovery of all net costs associated with the implementation of the MISO TEMT through its FCA mechanism. Under the current mechanism, NSP-Minnesota is allowed full recovery of its fuel and purchased energy costs. The proposal would allow recovery of locational marginal pricing market costs, including congestion and marginal loss costs, which would be netted by FTR revenues and revenues received that are related to marginal compensation loss costs, as well as MISO energy market operations costs. NSP-Minnesota has sought recovery effective with the beginning of the Day 2 energy market, scheduled for April 1, 2005 and the deferral of costs incurred prior to MPUC action. A decision is expected in the second quarter of 2005.

Capacity and Demand

Assuming normal weather during 2005, system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2005 is listed below.

	System Peak Demand (in MW)
	2002	2003	2004	2005 Forecast

NSP System	8,259	8,289	8,595	8,369

The peak demand for the NSP System typically occurs in the summer. The 2004 system peak demand for the NSP System occurred on July 21, 2004.

Energy Sources and Related Transmission Initiatives

The NSP System expects to use existing electric generating stations; purchases from other utilities, independent power producers and power marketers; demand-side management options and phased expansion of existing generation at select power plants to meet its net dependable system capacity requirements.

Purchased Power — NSP-Minnesota has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwh or Mwh, is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term 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.

NSP-Minnesota also makes short-term firm 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 — On Nov. 1, 2004, NSP-Minnesota filed the NSP System 2004 resource plan with MPUC. The resource plan projects a need for an additional 3,100 MW of electricity resources during the next 15 years, based on an anticipated growth in demand of 1.61 percent annually, or approximately 170 MW per year, during the period. The resource plan:

• identifies the need for adding up to 1,125 MW of new base-load electricity generation by 2015;

• recommends a new resource acquisition process that includes multiple options for consideration, including generation built by NSP-Minnesota;

• recommends increasing energy-saving goals for demand-side energy management programs by nearly 17 percent;

• recommends extending the operating licenses for the Prairie Island and Monticello nuclear plants by 20 years (on Jan. 18, 2005, NSP-Minnesota applied for a certificate of need in Minnesota for a dry spent-fuel storage facility at the Monticello plant, and plans to file an application with the federal government to extend the Monticello plant’s license and to make similar filings for the Prairie Island plant in 2008);

• assumes nearly 1,700 MW of wind power with most developed on NSP-Minnesota’s system;

• identifies the need for obtaining up to 550 MW of new power resources for peak usage times by 2015 depending on the amount and timing of any base-load resources acquired; and

• cites the importance of ensuring that sufficient transmission resources are available to move electricity from generation sources.

The MPUC initially established a comment period on NSP-Minnesota’s proposed resource acquisition strategy with comments due Dec. 28, 2004 and reply comments due Jan. 17, 2005. The Department of Commerce has requested an extension to June 1, 2005 to file comments on the overall resource plan. NSP-Minnesota did not object to this request.

NSP-Minnesota Transmission Certificates of Need — In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades to provide transmission outlet capacity for up to 825 MW of renewable energy generation (wind and biomass) being constructed in southwest and western Minnesota. In March 2003, the MPUC granted four certificates of need to NSP-Minnesota, thereby approving construction, subject to certain conditions. The initial projected cost of the transmission upgrades was approximately $160 million. The MEQB granted a routing permit for the first major transmission facilities in the development program in 2004. The remaining route permit proceedings are underway and expected to be completed in 2005. In 2003, the MPUC also approved a RCR adjustment that allows NSP-Minnesota to recover the revenue requirements associated with certain transmission investments associated with delivery of renewable energy resources through an automatic adjustment mechanism that started in 2004. See the Pending and Recently Concluded Regulatory Proceedings – MPUC, Renewable Transmission Cost Recovery section for further discussion.

Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO to deliver power and energy to NSP System native load customers, which are retail and wholesale load obligations with terms of more than one year. Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered. Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

Nuclear Power Operations and Waste Disposal - NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 12 to the Consolidated Financial Statements.

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

Low-Level Radioactive Waste Disposal — Federal law places responsibility on each state for disposal of its low-level radioactive substance. Low-level radioactive substance from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed of at the Barnwell facility located in South Carolina (all classes of low-level substance), and the Clive facility located in Utah (class A low-level substance only). Chem Nuclear is the owner and operator of the Barnwell facility, which has been given authorization by South Carolina to accept low-level radioactive substance from out of state. Envirocare, Inc. operates the Clive facility. NSP-Minnesota has an annual contract with Barnwell, while NSP-Minnesota uses the Envirocare facility through various low-level substance

processors. NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their licensed lives, if off-site low-level disposal facilities were not available to NSP-Minnesota.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act requires the 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. The DOE has accepted none of NSP-Minnesota’s spent nuclear fuel. See Item 3 — Legal Proceedings and Note 12 to the Consolidated Financial Statements for further discussion of this matter. The National Commission on Energy Policy, a privately funded coalition, has recommended that the federal government continue to pursue a nuclear waste storage facility in Nevada’s Yucca Mountain and urged them to build multiple above ground dry cask storage sites in the eastern and western United States in case the Yucca Mountain project is delayed or cancelled.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. The Prairie Island plant is licensed by the federal 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. On May 29, 2003, the Minnesota Legislature enacted legislation that allows NSP-Minnesota to continue to operate the facility and store spent fuel there until its licenses with NRC expire in 2013 and 2014. This will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. See Note 12 in the Consolidated Financial Statements for further discussion of the matter.

Visual Inspections — Required visual inspections have been performed on the Prairie Island Unit 2 upper and lower reactor vessel heads, and the Unit 1 upper head. Reactor vessel heads for both units were found to be in compliance with all NRC requirements. Xcel Energy has placed orders and plans to replace the reactor vessel upper heads of Prairie Island Unit 2 during the 2005 refueling outage and Unit 1 during the 2006 refueling outage.

Private Fuel Storage — 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, PFS filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. The NRC license review process includes formal evidentiary hearings before an ASLB and opportunities for public input. Evidentiary hearings were held in 2000 and 2002. In December 2004, the state of Utah claimed a representative of the DOE stated that it would not accept waste sealed in the type of containers planned by PFS. PFS responded by providing documents that the DOE will accept fuel stored in dry casks. The ASLB ruled in February 2005 that it would not reopen the hearing record to consider this issue, indicating it was instead worthy of NRC consideration. The ASLB also issued its decision on the last remaining issue regarding the facility, finding in favor of PFS. NRC commissioners will decide whether to officially issue a license for the site. The state of Utah has asked the U.S. Supreme Court to consider whether the state of Utah can block PFS from locating a spent fuel storage facility in the state, if the federal government has exclusive control over the storage and transportation of nuclear waste. The court neither accepted nor declined the appeal filed by the state of Utah, but has sought additional information. Due to uncertainty regarding NRC and other regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all.

Prairie Island Steam Generator Replacement — In the fall of 2004, NSP-Minnesota spent approximately $132 million to successfully replace the steam generators at Unit 1 of the Prairie Island nuclear generating plant. The steam generators at Unit 2 have not yet been replaced, but will be inspected during a scheduled 2005 outage.

NSP-Minnesota Nuclear Plant Re-licensing — On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants. Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014. NSP-Minnesota filed its application for Monticello with the MPUC in January 2005 seeking a certificate of need for dry spent fuel storage and plans to file an application in 2005 with the NRC for an operating license extension of up to 20 years. A decision regarding Monticello re-licensing is expected in 2007. Plant assessments and other work for the Prairie Island applications are planned in the next two or three years.

Nuclear Management Co. (NMC) — During 1999, NSP-Minnesota, Wisconsin Electric Power Co., WPS and Alliant Energy Corp. established NMC. The objective in creating NMC was to enhance operational excellence in nuclear plant operations by consolidating

resources, combining talent and gaining efficiencies. 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 MW. WPS is seeking regulatory approval to sell its Kewaunee Nuclear Power Plant to a subsidiary of Dominion Resources, Inc., and may not continue to participate in NMC. In addition, Alliant Energy has announced that it intends to seek bids to potentially sell the Duane Arnold nuclear plant and, therefore, may not continue to participate in the NMC.

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 NSP-Minnesota, 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 implementing best practices from all NMC-operated plants for improved safety, reliability and operational performance.

For further discussion of nuclear issues, see Notes 11 and 12 to the Consolidated Financial Statements.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years.

	Coal*				Nuclear				Average Fuel

	Cost		Percent		Cost		Percent		Cost

2004	$	0.99	61	%	$	0.44	37	%	$	0.92
2003	$	0.99	61	%	$	0.43	36	%	$	0.90
2002	$	0.96	59	%	$	0.46	38	%	$	0.81

* Includes refuse-derived fuel and wood

Fuel Sources — The NSP System normally maintains between 30 and 50 days of coal inventory at each plant site. Estimated coal requirements at NSP-Minnesota’s major coal-fired generating plants are approximately 12.7 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 97 percent of 2005 coal requirements and up to 59 percent of the 2006 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 burned in 2005 will have an average sulfur content of less than 0.5 percent. The NSP System has contracts for a maximum of 22.9 million tons of low-sulfur coal for the next 3 years. The contracts are with 1 Montana coal supplier, 3 Wyoming suppliers and 1 Minnesota oil refinery, with expiration dates ranging between 2006 and 2007. The NSP System could purchase approximately 20 percent of coal requirements in the spot market in 2006 if spot prices are more favorable than contracted prices.

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 nuclear fuel supply contracts cover 46 percent of uranium requirements through 2006 with no coverage of requirements for 2007 and beyond.

• Current contracts for conversion services requirements cover 32 percent of the requirements through 2007 with no coverage of requirements for 2008 and beyond.

• Current enrichment services contracts cover 55 percent of the requirements through 2010 with no coverage of requirements for 2011 and beyond. These current contracts expire at varying times between 2005 and 2010.

• Fuel fabrication for Monticello is covered through 2010. Fuel fabrication is 100 percent committed for Prairie Island Unit 1 through 2006 and through 2005 for Prairie Island Unit 2. Both Prairie Island Units are not contracted for fuel fabrication beyond those dates. NSP-Minnesota and NMC are currently in negotiations with Westinghouse to pursue fuel fabrication for

NSP-Minnesota Electric Operating Statistics

	Year Ended Dec. 31,
	2004			2003			2002
Electric Sales (Millions of Kwh):
Residential	9,558			9,778			9,782
Commercial and industrial	24,323			24,087			23,818
Public authorities and other	284			281			274
Total retail	34,165			34,146			33,874
Sales for resale	4,635			4,750			4,945
Total energy sold	38,800			38,896			38,819

Number of customers at end of period:
Residential	1,201,560			1,180,558			1,165,237
Commercial and industrial	144,631			141,584			139,779
Public authorities and other	5,984			5,496			5,740
Total retail	1,352,175			1,327,638			1,310,756
Wholesale	69			59			58
Total customers	1,352,244			1,327,697			1,310,814

Electric revenues (Thousands of dollars):
Residential	$	757,748		$	753,661		$	736,485
Commercial and industrial	1,324,773			1,267,470			1,204,371
Public authorities and other	31,965			31,427			30,442
Regulatory accrual adjustment	—			—			4,766
Total retail	2,114,486			2,052,558			1,976,064
Wholesale	168,317			148,087			109,147
Sales to NSP-Wisconsin	220,165			227,946			219,006
Other electric revenues	82,388			57,151			58,455
Total electric revenues	$	2,585,356		$	2,485,742		$	2,362,672

Kwh sales per retail customer	25,267			25,719			25,843
Revenue per retail customer	$	1,563.77		$	1,546.02		$	1,507.58
Residential revenue per Kwh	7.93		¢	7.71		¢	7.53		¢
Commercial and industrial revenue per Kwh	5.45		¢	5.26		¢	5.06		¢
Wholesale revenue per Kwh	3.63		¢	3.12		¢	2.21		¢

NATURAL GAS UTILITY OPERATIONS

Summary of Recent Regulatory Developments

Changes in regulatory policies and market forces have shifted the industry from traditional bundled natural gas sales service to an unbundled transportation and market-based commodity service at the wholesale level and for larger commercial and industrial retail customers. These customers have greater ability to buy natural gas directly from suppliers and arrange their own pipeline and retail LDC transportation service.

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

As an LDC, NSP-Minnesota provides unbundled 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 make them economically indifferent to whether natural gas has been sold and transported or merely transported. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDCs distribution system.

The most significant recent developments in the natural gas operations of the Utility Subsidiaries are the substantial and continuing increases in wholesale natural gas market prices and the continued trend toward declining use per customer by residential customers as a result of improved building construction technologies and higher appliance efficiencies. From 1994 to 2004, average annual sales to the typical residential customer declined from 111 Dth per year to 99 Dth per year on a weather-normalized basis. Although recent wholesale price increases do not directly affect earnings because of gas cost recovery mechanisms, the high prices are expected to encourage further efficiency efforts by customers.

Ratemaking Principles

Purchased Gas and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail natural gas rate schedules for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs are collected or refunded over the subsequent 12-month period. The MPUC has the authority to disallow recovery of 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 0.5 percent of Minnesota natural gas revenue on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for natural gas conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

Pending and Recently Concluded Regulatory Proceedings

NSP-Minnesota Retail Gas Rate Case - On Sept. 17, 2004, NSP-Minnesota submitted a $10 million natural gas general rate increase request to the MPUC with a requested return on equity of 11.5 percent. An interim rate increase, subject to refund, of approximately $6.4 million was implemented effective Dec. 1, 2004. The ALJ held a pre-hearing conference and established a procedural schedule, with an MPUC decision expected in mid-2005. The Department of Commerce filed testimony in February 2005 recommending an increase of $1 million. NSP-Minnesota plans to file its rebuttal testimony on March 15, 2005.

North Dakota Retail Gas Rate Case — On Nov. 2, 2004, NSP-Minnesota submitted a natural gas general rate increase application to the NDPSC. The filing proposes an overall increase in annual revenues of $1.3 million, exclusive of natural gas supply costs, or 1.8 percent. On Dec. 1, 2004, the NDPSC issued an order approving a $0.7 million interim rate increase, or 1.1 percent, effective Jan. 1, 2005. The NDPSC staff is scheduled to file its testimony in March 2005, and the NDPSC will conduct evidentiary hearings in April 2005. The NDPSC is required to issue its order by June 2, 2005. On Feb. 17, 2005, however, NSP-Minnesota and the NDPSC staff filed a settlement agreement with the NDPSC. Under the terms of the settlement, the NDPSC can elect one of two alternativ es. The alternatives are a $745,000 rate increase and a $15.70 monthly residential service charge or an $887,000 rate increase with an $8.75

monthly residential service charge. The NDPSC is expected to consider the settlement agreement at a hearing in March 2005.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 647,547 MMBtu for 2004, which occurred on Jan. 29, 2004.

NSP-Minnesota purchases natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 506,391 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 16 percent of winter natural gas requirements and 19 percent of peak day, firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.13 Bcf equivalent and three 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 250,300 MMBtu of natural gas per day, or approximately 34 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.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes or to exchange one form of demand for another. NSP-Minnesota’s 2003-2004 entitlement levels were approved on Sept. 2, 2004, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation, supply, and storage levels in its monthly PGA. The 2004-2005 entitlement levels are pending MPUC action.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural 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 natural gas purchased for resale by NSP-Minnesota’s regulated retail natural gas distribution business:

2004	$	6.88
2003	$	5.47
2002	$	3.98

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

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2005 through 2017.

NSP-Minnesota has certain natural gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2004, NSP-Minnesota was committed to approximately $1.09 billion in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 35 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

NSP-Minnesota Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2004		2003		2002
Natural gas deliveries (Thousands of Dth):
Residential	39,168		40,608		38,407
Commercial and industrial	39,186		40,597		38,320
Other	1,334		1,674		1,286
Total retail	79,688		82,879		78,013
Transportation and other	7,727		6,477		8,559
Total deliveries	87,415		89,356		86,572

Number of customers at end of period:
Residential	414,782		402,893		393,538
Commercial and industrial	39,190		38,078		37,445
Total retail	453,972		440,971		430,983
Transportation and other	10		10		42
Total customers	453,982		440,981		431,025

Natural gas revenues (Thousands of dollars):
Residential	$	376,676	$	360,410	$	263,178
Commercial and industrial	307,730		291,467		199,196
Other	—		—		1
Total retail	684,406		651,877		462,375
Transportation and other	30,665		22,653		27,197
Total gas revenues	$	715,071	$	674,530	$	489,572

Dth sales per retail customer	175.54		187.95		181.01
Revenue per retail customer	$	1,507.60	$	1,478.28	$	1,072.84
Residential revenue per Dth	$	9.62	$	8.88	$	6.85
Commercial and industrial revenue per Dth	$	7.85	$	7.18	$	5.20
Transportation and other revenue per Dth	$	3.97	$	3.50	$	3.18

ENVIRONMENTAL MATTERS

Certain of NSP-Minnesota’s 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. NSP-Minnesota has 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.

NSP-Minnesota strives to comply with all environmental regulations applicable to its operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon NSP-Minnesota’s operations. For more information on environmental contingencies, see Note 11 to the Consolidated Financial Statements and the matters discussed below.

Notice of Violation — On Dec. 10, 2001, the Minnesota Pollution Control Agency (MPCA) 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. On April 22, 2004, the MPCA executed an agreement with NSP-Minnesota to resolve the alleged air quality violations at the A.S. King generating plant and address alleged air quality reporting violations at the Red Wing and Wilmarth generating plants. Conditions of the agreement were for NSP-Minnesota to pay an $80,000 civil penalty and to complete corrective actions at the A.S. King, Red Wing and Wilmarth generating plants. In 2004, NSP-Minnesota paid the civil penalty and completed all required corrective actions. On Dec. 15, 2004, the MPCA issued a letter acknowledging receipt of the civil penalty payment and completion of all requirements in the agreement.

EMPLOYEES

The number of full-time NSP-Minnesota employees on Dec. 31, 2004 was 2,843. Of these full-time employees, 2,197, or 77 percent, are covered under collective bargaining agreements. NSP-Minnesota full-time employees include 395 employees loaned to the NMC. In addition, the NMC has 778 full-time employees of its own. See Note 7 to the Consolidated Financial Statements for further discussion. Xcel Energy Services Inc., a subsidiary of Xcel Energy, employees provide services to NSP-MN.

Item 2 — Properties

Virtually all of the utility plant of NSP-Minnesota is subject to the lien of its first mortgage bond indenture.

Electric utility generating stations:

Station, City and Unit	Fuel	Installed	Summer 2004 Net Dependable Capability (MW)
*Steam:*
Sherburne — Becker, Minn.
Unit 1	Coal	1976	697
Unit 2	Coal	1977	682
Unit 3(a)	Coal	1987	504
Prairie Island — Welch,
Minn.
Unit 1	Nuclear	1973	523
Unit 2	Nuclear	1974	522
Monticello — Monticello,
Minn.	Nuclear	1971	572
King — Bayport, Minn.	Coal	1968	528
Black Dog — Burnsville,
Minn.
2 Units	Coal/Natural Gas	1955 - 1960	276
2 Units	Natural Gas	2002	298
High Bridge — St. Paul,
Minn.
2 Units	Coal	1956 - 1959	267
Riverside — Minneapolis,
Minn.
2 Units	Coal	1964 - 1987	375
*Combustion Turbine:*
Angus Anson — Sioux
Falls, S.D.
2 Units	Natural Gas	1994	226
Inver Hills — Inver Grove
Heights, Minn.
6 Units	Natural Gas	1972	350
Blue Lake — Shakopee,
Minn.
4 Units	Natural Gas	1974	174
Other	Various	Various	261
Total			6,255

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

other intervenors with respect to the majority of the licensing regulations of the NRC, the congressional resolution selecting Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the selection of Yucca Mountain. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal and incorporated in the NRC regulations governing Yucca Mountain licensing. Xcel Energy has not ascertained the impact of the decision on its nuclear operations and storage of spent nuclear fuel; however, the decision may result in additional delay and uncertainty around disposal of spent nuclear fuel.

St. Cloud Gas Explosion — Twenty-five lawsuits were filed as a result of a Dec. 11, 1998, gas explosion in St. Cloud, Minn. that killed four persons (including two employees of NSP-Minnesota), injured several others and damaged numerous buildings. Most of the lawsuits named as defendants NSP-Minnesota, Xcel Energy’s Seren subsidiary, Cable Constructors, Inc. (CCI) (the contractor hired by Seren that struck the marked gas line), and Sirti, an architectural/engineering firm hired by Seren for its St. Cloud cable installation project. The court granted the plaintiffs’ request to amend the complaint to seek punitive damages against Seren and CCI. The plaintiffs brought a similar motion against NSP-Minnesota, which was subsequently denied by the court. On Nov. 11, 2003, court-ordered mediation was conducted. As a result of this mediation NSP-Minnesota reached a confidential settlement with a group of plaintiffs representing the most significant claims asserted against NSP-Minnesota. In November and December of 2003, similar mediations were conducted that resulted in confidential settlements with various plaintiffs representing the most significant claims asserted against Seren. The remaining lawsuits were settled in 2004. The settlements were paid primarily by Seren’s insurance carriers. Remaining settlement payments by NSP-Minnesota are not material.

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 complied with the preliminary injunction and has relocated the pertinent utility lines. 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 appealed to the United States Court of Appeals for the Eighth Circuit. In February 2004, the court of appeals affirmed the district court decision. Further appellate review is not being sought. In August 2004, defendants filed a summary judgment motion in Federal District Court for attorney’s fees in the amount of $700,000, premised on an argument that pursuant to Minnesota Rule 8810.3300 NSP-Minnesota is liable for all claims occasioned by a failure to remove facilities from the right-of-way when ordered to do so. On Feb. 3, 2005, the federal district court denied the Defendant’s claim for attorneys’ fees and granted NSP-Minnesota’s motion for summary judgment, dismissing the Defendant’s counterclaims.

Other Matters

For more discussion of legal claims and environmental proceedings, see Note 11 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates, see Pending and Recently Concluded Regulatory Proceedings under Item 1, 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, Related Stockholder Matters and Issuer Purchases of Equity Securities

NSP-Minnesota is a wholly owned subsidiary and there is no market for its common equity securities.

NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $833 million in additional cash dividends on common stock at Dec. 31, 2004. In addition, NSP-Minnesota has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends NSP-Minnesota can pay to Xcel Energy. These restrictions include, but may not be limited to, the following:

• maintenance of an equity ratio of 43.27 percent to 52.91 percent;

• payment of dividends only from retained earnings; and

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations

NSP-Minnesota’s net income was approximately $230.3 million for 2004, compared with approximately $192.9 million for 2003.

Electric Utility, Short-Term Wholesale and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers, most fluctuations in energy costs do not materially affect electric utility margin.

NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from NSP-Minnesota’s generation assets and energy and capacity purchased to serve native load. Commodity trading is not associated with NSP-Minnesota’s generation assets or the energy and capacity purchased to serve native load.

Margins from commodity trading activity are partially redistributed to PSCo and SPS pursuant to the JOA approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenues. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net of trading costs (i.e., on a margin basis) in the Consolidated Statements of Income. Commodity trading costs include fuel, purchased power, transmission and other related costs. The following table details base electric utility, short-term wholesale and commodity trading activities:

	Base Electric Utility			Short-Term Wholesale			Commodity Trading			Consolidated Totals
	(Millions of dollars)
2004
Electric utility revenue (excluding commodity trading)	$	2,434		$	149		$	—		$	2,583
Electric fuel and purchased power	(917		)	(60		)	—			(977		)
Commodity trading revenue	—			—			123			123
Commodity trading costs	—			—			(120		)	(120		)
Gross margin before operating expenses	$	1,517		$	89		$	3		$	1,609
Margin as a percentage of revenue	62.3		%	59.7		%	2.4		%	59.5		%

2003
Electric utility revenue (excluding commodity trading)	$	2,350		$	128		$	—		$	2,478
Electric fuel and purchased power	(820		)	(68		)	—			(888		)
Commodity trading revenue	—			—			89			89
Commodity trading costs	—			—			(81		)	(81		)
Gross margin before operating expenses	$	1,530		$	60		$	8		$	1,598
Margin as a percentage of revenue	65.1		%	46.9		%	9.0		%	62.3		%

The following summarizes the components of the changes in base electric revenue and base electric margin for the year ended Dec. 31:

Base Electric Revenue

(Millions of dollars)	2004 vs 2003
Fuel Cost recovery	$	63.3
Sales growth (excluding weather impact)	30.9
Estimated impact of weather	(30.1		)
Interchange agreement billing with NSP-Wisconsin	(7.8		)
Firm wholesale	6.0
Transmission and other	21.7
Total base electric revenue increase	$	84.0

Base Electric Margin

(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	23.7
Estimated impact of weather	(23.0		)
Interchange agreement — prior period fixed charge adjustment	(19.2		)
Purchased capacity costs	(6.7		)
Firm wholesale	4.0
Renewable development fund recovery	(4.7		)
Transmission and other	12.9
Total base electric decrease	$	(13.0	)

Short-term wholesale increased in 2004, compared with 2003, due to favorable market conditions.

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

	2004			2003
	(Millions of dollars)
Natural gas utility revenue	$	715		$	675
Cost of natural gas sold and transported	(557		)	(517		)
Natural gas utility margin	$	158		$	158

The following summarizes the components of the changes in natural gas revenue and margin for the year ended Dec. 31:

Natural Gas Revenue

(Millions of dollars)	2004 vs 2003
Purchased gas adjustment clause recovery	$	42.4
Estimated impact of weather on firm sales volume	(7.0		)
Sales growth (excluding weather impact)	(3.0		)
Off system sales	9.0
Transportation and other	(0.9		)
Total natural gas revenue increase	$	40.5

Natural gas revenue increased primarily due to higher natural gas costs in 2004, which are passed through to customers. Retail gas weather-normalized sales declined in 2004, largely due to the rising cost of natural gas and its impact on customer usage.

Natural Gas Margin

(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	0.1
Estimated impact of weather on firm sales volume	(2.2		)
Off system sales	0.7
Regulatory adjustments	0.9
Transportation and other	1.0
Total natural gas margin increase	$	0.5

Non-Fuel Operating Expense and Other Costs — The following summarizes the components of the changes in other utility operating and maintenance expense for the year ended Dec. 31:

(Millions of dollars)	2004 vs 2003
Lower compensation costs	$	(16.7	)
Lower plant outage costs	(12.9		)
Lower private fuel storage costs	(5.6		)
Higher employee benefit costs	7.6
Costs offset in revenue	6.4
Higher interchange expense with NSP-Wisconsin (see Note 15)	2.9
Higher bad debt costs	2.0
Unfavorable obsolete inventory write-off and inventory adjustments	1.8
Higher information technology costs	1.6
Higher costs related to Sarbanes-Oxley and audit fees	1.6
Higher power plant related costs related to projects moved from 2005 into 2004	1.3
Other	1.6
Total other utility operating and maintenance expense decrease	$	(8.4	)

Depreciation and amortization expense decreased by approximately $16.6 million, or 4.7 percent, for 2004 compared with 2003. The reduction is largely due to a regulatory decision. In 2004, as a result of an MPUC order, NSP-Minnesota modified its decommissioning expense recognition, which served to reduce decommissioning accruals by approximately $18 million when compared with 2003.

Other income increased by approximately $12.0 million due primarily to higher allowance for funds used during construction in 2004 and lower non-operating amortizations due to the 2003 write-off of an intangible asset.

Interest charges and financing costs decreased by approximately $7.1 million, or 5.2 percent, for 2004, compared with 2003. The decrease is due to the issuance of debt during 2003 to refinance higher coupon debt, including the redemption of the preferred securities of NSP-Minnesota’s subsidiary trust. Financing costs were further reduced by higher allowance for funds used during construction in 2004.

Income Taxes — Income tax expense increased by approximately $18.1 million in 2004, compared with 2003. The increase was primarily due to higher income levels. The effective tax rate was 29.1 percent for the period ended Dec. 31, 2004, compared with 28.4 percent for the same period in 2003. Significant tax benefits were recorded during both periods due to the resolution of tax audit issues, largely related to prior periods, as discussed below.

The significant audit activity that occurred late in 2003 continued in 2004. During 2004, NSP-Minnesota concluded IRS income tax audit and appeal activities spanning several examination cycles dating back to 1993. In addition, the IRS nearly completed the examination cycle ended 2001 and began its review of NSP-Minnesota’s 2002 and 2003 tax years.

Income tax benefits of $12.5 million were recorded in 2004, including $4.1 million related to the successful resolution of various IRS audit issues and other adjustments to current and deferred taxes related to prior years, $7.0 million for the 2003 return to accrual true-up and $1.4 million from revisions to benefits related to foreign power sales. Excluding the tax benefits, the effective rate for the year 2004 would have been 32.9 percent.

The income tax expense recorded in 2003 included $13 million in tax benefits to reflect the successful resolution of various open tax audit issues related to prior years. The resolved issues included the tax deductibility of certain merger costs associated with the merger to form Xcel Energy and the deductibility, for state tax purposes, of certain tax benefit transfer lease benefits. Excluding these tax benefits, the effective rate for the year 2003 would have been 33.5 percent.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, NSP-Minnesota is exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity related instruments, including derivatives, are subject to market risk. These risks, as applicable to NSP-Minnesota, are discussed in further detail below.

Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in its generation and retail distribution operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric power, natural gas, coal and fuel oil. Commodity price risk is also managed through the use of financial derivative instruments. NSP-Minnesota’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various commodity-marketing activities, including the purchase and sale of capacity, energy and energy related instruments. These marketing activities are primarily focused on specific regions where market knowledge and experience have been obtained and are generally less than one year in length. NSP-Minnesota’s risk management policy allows management to conduct the marketing activities within approved guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

Certain contracts within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities,” as amended, while others are subject to the fair value requirements of this pronouncement.

See Note 9 to the Consolidated Financial Statements for a discussion of the various trading and hedging contracts of NSP-Minnesota.

NSP-Minnesota’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as 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. NSP-Minnesota utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas. Previously, NSP-Minnesota calculated VaR using a holding period of five days for electricity and two days for natural gas. However, the methodology was changed to ensure consistency in risk measurement across both commodities. NSP-Minnesota’s revised holding periods remain consistent with current industry practice. VaR using the current methodology for 2004 and previous methodology for 2003 are as follows:

As of Dec. 31, 2004, the calculated VaRs using the current methodology were:

	Year ended		During 2004
Current Methodology	Dec. 31, 2004		Average		High		Low
(Millions of dollars)
Commodity trading (a)	$	0.29	$	0.97	$	2.09	$	0.27

(a) Comprises transactions for NSP-Minnesota, PSCo and SPS.

As of Dec. 31, 2003, the calculated VaRs using the previous methodology were:

	Year ended		During 2003
Previous Methodology	Dec. 31, 2003		Average		High		Low
(Millions of dollars)
Electric commodity trading (a)	$	0.92	$	0.70	$	1.51	$	0.29

(a) Comprises transactions for both NSP-Minnesota and PSCo.

Interest Rate Risk — NSP-Minnesota is subject to the risk of fluctuating interest rates in the normal course of business. NSP-Minnesota’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options, subject to regulatory approval when required.

NSP-Minnesota may engage in hedges of cash flow exposure. The fair value of interest rate swaps designated as cash flow hedges is initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument and generally offsets the change in the interest accrued on the underlying variable rate debt. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

At Dec. 31, 2004 and 2003, a 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense by approximately $0.3 million and $0.2 million, respectively.

NSP-Minnesota also maintains trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning, which are subject to interest rate risk and equity price risk. As of Dec. 31, 2004 and 2003, these funds were invested primarily in domestic and international equity securities and fixed-rate fixed-income securities. Per NRC mandates, these funds may be used only for activities related to nuclear decommissioning. The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore fluctuations in equity prices or interest rates do not have an impact on earnings.

Credit Risk — In addition to the risks discussed previously, NSP-Minnesota is exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. NSP-Minnesota maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

NSP-Minnesota conducts standard credit reviews for all counterparties. NSP-Minnesota 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.

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended Dec. 31,
	2004			2003			2002
	(Thousands of dollars)
Operating revenues:
Electric utility	$	2,585,356		$	2,485,742		$	2,362,672
Natural gas utility	715,071			674,530			489,572
Other	19,135			17,180			30,875
Total operating revenues	3,319,562			3,177,452			2,883,119

Operating expenses:
Electric fuel and purchased power	976,639			888,274			789,379
Cost of natural gas sold and transported	556,662			516,631			343,700
Operating and maintenance expenses	845,209			853,656			829,178
Depreciation and amortization	336,744			353,341			354,157
Taxes (other than income taxes)	172,675			170,318			168,721
Total operating expenses	2,887,929			2,782,220			2,485,135

Operating income	431,633			395,232			397,984

Other income (expense):
Interest and other income, net of nonoperating expenses (see Note 8)	1,089			(2,800		)	19,578
Allowance for funds used during construction – equity	20,747			12,674			5,491
Total other income	21,836			9,874			25,069

Interest charges and financing costs
Interest charges — including financing costs of $8,258, $8,989 and $5,241, respectively	142,147			135,764			107,470

Allowance for funds used during construction – debt	(13,565		)	(9,311		)	(8,530		)
Distributions on redeemable preferred securities of subsidiary trust	—			9,187			15,750
Total interest charges and financing costs	128,582			135,640			114,690

Income before income taxes	324,887			269,466			308,363
Income taxes	94,613			76,524			108,141
Net income	$	230,274		$	192,942		$	200,222

See Notes to Consolidated Financial Statements

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended Dec. 31,
	2004			2003			2002
	(Thousands of dollars)
Operating activities:
Net income	$	230,274		$	192,942		$	200,222
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	351,887			352,630			366,362
Nuclear fuel amortization	43,296			43,401			48,675
Deferred income taxes	20,545			1,561			(26,280		)
Amortization of investment tax credits	(7,150		)	(7,365		)	(7,490		)
Allowance for equity funds used during construction	(20,747		)	(12,674		)	(5,491		)
Gain on sale of nonutility property	—			—			(6,785		)
Change in accounts receivable	(18,185		)	(46,150		)	(7,933		)
Change in accounts receivable from affiliates	40,466			(30,923		)	(17,893		)
Change in inventories	(12,622		)	(6,206		)	(4,296		)
Change in other current assets	(73,706		)	(45,026		)	21,712
Change in accounts payable	27,032			17,757			(12,745		)
Change in other current liabilities	(24,204		)	(75,155		)	59,929
Change in other assets	(9,396		)	(8,205		)	(60,052		)
Change in other liabilities	92,246			(7,404		)	75,677
Net cash provided by operating activities	639,736			369,183			623,612

Investing activities:
Utility capital/construction expenditures	(641,476		)	(352,389		)	(383,857		)
Allowance for equity funds used during construction	20,747			12,674			5,491
Investments in and advances to affiliates	(7,790		)	(16,830		)	27,475
Proceeds from sale of property	—			—			11,152
Investments in external decommissioning fund	(80,582		)	(80,581		)	(57,830		)
Restricted cash	—			23,000			(23,000		)
Other investments	(1,293		)	(4,138		)	(4,939		)
Net cash used in investing activities	(710,394		)	(418,264		)	(425,508		)

Financing activities:
Short-term borrowings — net	32,000			57,931			(381,115		)
Proceeds from issuance of long-term debt	10			372,943			624,892
Repayment of long-term debt and trust preferred securities, including reacquisition premiums	(4,508		)	(426,568		)	(4,876		)
Capital contributions from parent	180,408			29,100			51,714
Dividends and cash distributions paid to parent	(213,033		)	(212,648		)	(195,550		)
Net cash provided by (used in) financing activities	(5,123		)	(179,242		)	95,065

Net (decrease) increase in cash and cash equivalents	(75,781		)	(228,323		)	293,169
Cash and cash equivalents at beginning of year	82,015			310,338			17,169
Cash and cash equivalents at end of year	$	6,234		$	82,015		$	310,338

Supplemental disclosure of cash flow information
Cash paid for interest (net of amounts capitalized)	$	123,705		$	120,993		$	75,315
Cash paid for income taxes (net of refunds received)	$	32,796		$	181,701		$	83,636

See Notes to Consolidated Financial Statements

NSP-MINNESOTA

CONSOLIDATED BALANCE SHEETS

	Dec. 31, 2004			Dec. 31, 2003
	(Thousands of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	6,234		$	82,015
Notes receivable from affiliates	31,500			23,710
Accounts receivable — net of allowance for bad debts: $7,845 and $7,581, respectively	296,331			278,146
Accounts receivable from affiliates	8,350			48,816
Accrued unbilled revenues	172,512			125,872
Materials and supplies inventories — at average cost	96,953			100,297
Fuel inventory — at average cost	31,483			27,727
Natural gas inventory — at average cost	55,689			43,479
Income tax receivable	—			11,249
Derivative instruments valuation — at market	62,272			26,666
Prepayments and other	32,719			30,011
Total current assets	794,043			797,988

Property, plant and equipment, at cost:
Electric utility plant	7,586,873			7,268,609
Natural gas utility plant	778,256			746,835
Construction work in progress	438,474			328,880
Other	406,229			400,448
Total property, plant and equipment	9,209,832			8,744,772
Less accumulated depreciation	(4,175,557		)	(3,991,875		)
Nuclear fuel — net of accumulated amortization: $1,145,228 and $1,101,932, respectively	74,308			80,289
Net property, plant and equipment	5,108,583			4,833,186

Other assets:
Nuclear decommissioning fund investments	918,442			779,382
Other investments	24,039			25,055
Regulatory assets	476,485			492,491
Prepaid pension asset	361,446			317,956
Derivative instruments valuation — at market	234,509			177,581
Other	47,968			59,463
Total other assets	2,062,889			1,851,928
Total assets	$	7,965,515		$	7,483,102
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	82,185		$	4,502
Short-term debt	90,000			58,000
Accounts payable	287,531			250,628
Accounts payable to affiliates	23,013			32,884
Taxes accrued	147,144			116,862
Accrued interest	42,998			44,485
Dividends payable to parent	53,033			53,852
Derivative instruments valuation — at market	58,366			67,664
Other	51,560			44,863
Total current liabilities	835,830			673,740

Deferred credits and other liabilities:
Deferred income taxes	785,046			738,677
Deferred investment tax credits	59,119			66,681
Regulatory liabilities	944,364			889,152
Asset retirement obligations (see Note 12)	1,091,089			1,024,529
Derivative instruments valuation — at market	246,872			212,263
Benefit obligations and other	136,131			128,247
Total deferred credits and other liabilities	3,262,621			3,059,549

Long-term debt	1,859,737			1,940,958
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10			10
Premium on common stock	1,023,377			842,969
Retained earnings	983,940			965,880
Accumulated other comprehensive loss	—			(4		)
Total common stockholder’s equity	2,007,327			1,808,855
Commitments and contingencies (see Note 11)
Total liabilities and equity	$	7,965,515		$	7,483,102

See Notes to Consolidated Financial Statements

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND OTHER COMPREHENSIVE INCOME (LOSS)

				Premium on Common Stock		Retained Earnings			Leveraged ESOP			Accumulated Other Comprehensive Income (Loss)			Total Stockholder’s Equity
	Common Stock
	Shares	Amount
	(Thousands of dollars, except share information)

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
Net derivative instrument fair value changes during the period, net of tax of $(83)												(121		)	(121		)
Unrealized loss-marketable securities, net of tax of $6												(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									18,564						18,564
Balance at Dec. 31, 2002	1,000,000	$	10	$	813,869	$	987,158		$	—		$	(9	)	$	1,801,028

Net income						192,942									192,942
Unrealized gain-marketable securities, net of tax of $(4)												5			5
Comprehensive income for 2003															192,947
Common dividends declared to parent						(214,220		)							(214,220		)
Contribution of capital by parent				29,100											29,100
Balance at Dec. 31, 2003	1,000,000	$	10	$	842,969	$	965,880		$	—		$	(4	)	$	1,808,855

Net income						230,274									230,274
Unrealized gain-marketable securities, net of tax of $(2)												4			4
Comprehensive income for 2004															230,278
Common dividends declared to parent						(212,214		)							(212,214		)
Contribution of capital by parent				180,408											180,408
Balance at Dec. 31, 2004	1,000,000	$	10	$	1,023,377	$	983,940		$	—		$	—		$	2,007,327

See Notes to Consolidated Financial Statements

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CAPITALIZATION

	Dec. 31,
	2004			2003
	(Thousands of dollars)
Long-Term Debt
First Mortgage Bonds, Series due:
Dec. 1, 2005 — 2006, 4% — 4.1%	$	4,750	(a)	$	6,990	(a)
Dec. 1, 2005, 6.125%	70,000			70,000
Aug. 1, 2006, 2.875%	200,000			200,000
Aug. 1, 2010, 4.75%	175,000			175,000
Aug. 28, 2012, 8%	450,000			450,000
March 1, 2019, 8.5%	27,900		(b)	27,900		(b)
Sept. 1, 2019, 8.5%	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%	69,000		(b)	69,000		(b)
Dec. 1, 2005 — 2008, 4.4% — 5%	9,790		(a)	11,990		(a)
Senior Notes due Aug. 1, 2009, 6.875%	250,000			250,000
Retail Notes due July 1, 2042, 8%	185,000			185,000
Other	8,241			8,301
Unamortized discount	(7,759		)	(8,721		)
Total	1,941,922			1,945,460
Less current maturities	82,185			4,502
Total NSP-Minnesota long-term debt	$	1,859,737		$	1,940,958

Common Stockholder’s Equity
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares in 2004 and 2003	$	10		$	10
Capital in excess of par value on common stock	1,023,377			842,969
Retained earnings	983,940			965,880
Accumulated other comprehensive loss	—			(4		)
Total common stockholder’s equity	$	2,007,327		$	1,808,855

(a) Resource recovery financing

(b) Pollution control financing

See Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — NSP-Minnesota is engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. NSP-Minnesota is subject to the regulatory provisions of the PUHCA. NSP-Minnesota is also subject to regulation by the FERC and state utility commissions. All of NSP-Minnesota’s 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 has subsidiaries, which have been consolidated and for which all significant intercompany transactions and balances are eliminated.

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

NSP-Minnesota has 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. In addition, NSP-Minnesota presents its revenue, net of any excise or other fiduciary-type taxes or fees. A summary of significant rate adjustment mechanisms follows:

• NSP-Minnesota’s rates include a cost-of-fuel and energy and a cost-of-gas recovery mechanism allowing dollar-for-dollar recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively.

• NSP-Minnesota operates under various service standards, which could require customer refunds if certain criteria are not met. NSP-Minnesota’s rates include monthly adjustments for the recovery of conservation and energy management program costs, which are reviewed annually.

• NSP-Minnesota sells firm power and energy in wholesale markets, which is regulated by the FERC. These sales include monthly wholesale fuel cost recovery mechanisms.

Commodity Trading Operations — All applicable gains and losses related to trading activities, whether or not settled physically, are shown on a net basis in the Consolidated Statements of Income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from NSP-Minnesota are apportioned to PSCo and SPS. Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Commodity trading results are recorded at fair market value in accordance with SFAS 133, as amended. For more information, see Note 9 to the Consolidated Financial Statements.

Derivative Financial Instruments — NSP-Minnesota utilizes physical and financial commodity based contracts to reduce exposure to commodity price risk. These contracts consist mainly of commodity forwards, futures and options. For further discussion of NSP-Minnesota’s risk management and derivative activities, see Note 9 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 is charged to accumulated depreciation and amortization. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses. Property, plant and equipment also include costs associated with the engineering design of future generating stations and other property held for future use.

NSP-Minnesota determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense for NSP-Minnesota, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2004, 2003 and 2002 was 3.8 percent, 3.5 percent and 3.7 percent, respectively.

Allowance for Funds Used During Construction (AFDC) — AFDC represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income and deductions (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota.

Decommissioning — NSP-Minnesota accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota will recover those costs through rates. The fair value of external nuclear decommissioning fund investments are estimated based on quoted market prices for those or similar investments. Unrealized gains or losses on the fund’s assets are deferred as regulatory assets or liabilities. For more information on nuclear decommissioning, see Note 12 to the Consolidated Financial Statements.

Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants consume 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 the DOE’s fuel enrichment facility.

Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota is liable for the costs and the liability can be reasonably estimated. Costs may be deferred as a regulatory asset based on an expectation that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as pollution-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If several designated responsible parties exist, costs are estimated and recorded only for the utility subsidiary share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which has the latitude to compensate for final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs — Litigation settlements are recorded when it is probable NSP-Minnesota is liable for the costs and the liability can be reasonably estimated. Legal accruals are recorded net of insurance recovery. Legal costs related to settlements are not accrued, but expensed as incurred.

Income Taxes — Xcel Energy and its utility subsidiaries, including NSP-Minnesota, 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 tax liability of each company in the consolidated federal or combined state returns. NSP-Minnesota defers income taxes for all temporary differences between the book and tax bases of assets and liabilities. The tax rates used are those that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences was accounted for as current income tax expense. Investment tax credits are deferred and their benefits spread over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13 to the Consolidated Financial Statements. For more information on income taxes, see Note 8

to the Consolidated Financial Statements.

Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Minnesota uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information is obtained or actual amounts are determinable. Those revisions can affect operating results. Each year the depreciable lives of certain plant assets are reviewed and revised, if appropriate.

Cash and Cash Equivalents — NSP-Minnesota considers 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 is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.

Inventory — All inventory for NSP-Minnesota is recorded at average cost.

Regulatory Accounting — NSP-Minnesota accounts for certain income and expense items in accordance with SFAS No. 71–“Accounting for the Effects of Certain Types of Regulation.” Under SFAS No. 71:

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

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

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.

If restructuring or other changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations in the period the write-off is recorded. See more discussion of regulatory assets and liabilities at Note 13 to the Consolidated Financial Statements.

Deferred Financing Costs — Other assets include deferred financing costs, which were amortized over the remaining maturity periods of the related debt. NSP-Minnesota’s deferred financing costs, net of amortization at Dec. 31, 2004, 2003 and 2002 are $15.8 million, $17.4 million and $21.1 million, respectively.

Reclassifications — Certain items in the 2002 and 2003 statements of income and the 2003 balance sheet have been reclassified to conform to 2004 presentation. These reclassifications had no effect on net income.

2. Short-Term Borrowings

Credit Facilities — At Dec. 31, 2004, NSP-Minnesota had the following credit facility in effect, in millions of dollars. A syndicate of lending banks supports the credit facility in exchange for a negotiated commitment fee.

Maturity	Term	Credit Line		Credit Line Available
May 2005	364 days	$	300	$	171

NSP-Minnesota’s credit facility is expected to be renewed as a five-year revolving credit facility prior to May 2005 for which borrowings will be classified as a long-term liability on the consolidated balance sheet.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit, and, depending on credit ratings, provide support for commercial paper borrowings. The borrowing rate under the line of credit is based on either the bank’s prime rate or the applicable London Interbank Offered Rate (LIBOR) plus a borrowing margin.

At Dec. 31, 2004 and 2003, NSP-Minnesota had $90 million and $58 million, respectively, in notes payable to banks, which were drawn on the line of credit. The weighted average interest rate at Dec. 31, 2004 was 5.25 percent. Also, $39.4 million of letters of credit were outstanding at Dec. 31, 2004, as discussed in Note 10 to the Consolidated Financial Statements, of which approximately $38.6 million were outstanding under the credit facility, which further reduced amounts available under the line.

Money Pool - In 2003, Xcel Energy established a money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. NSP-Minnesota received approval to participate in the money pool arrangement in 2004. The money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The money pool arrangement does not allow loans from the utility subsidiaries to the holding company. NSP-Minnesota has approval to borrow up to $250 million under the arrangement. NSP-Minnesota had no borrowings or loans outstanding under the arrangement at Dec. 31, 2004.

3. Long-Term Debt

Except for minor exclusions, all property of NSP-Minnesota is subject to the lien of its first mortgage indenture, which is a contract between NSP-Minnesota and its bondholders.

NSP-Minnesota’s first mortgage bond indenture provides for the ability to have sinking fund requirements. Such sinking fund obligations may be satisfied with property additions or cash. At Dec. 31, 2004, NSP-Minnesota has no sinking fund requirements for current bonds outstanding.

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 $833 million in additional cash dividends on common stock at Dec. 31, 2004.

To facilitate its potential debt issuances, NSP-Minnesota may file a long-term debt shelf registration statement with the SEC for up to $1 billion in 2005.

Maturities of long-term debt are listed in the following table, in millions of dollars:

2005	$	82
2006	205
2007	3
2008	3
2009	250

4. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

NSP Financing I, a wholly owned, special-purpose subsidiary trust of NSP-Minnesota, had $200 million of 7.875-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2037. The preferred securities were redeemable at the option of NSP-Minnesota at $25 per share, beginning in 2002. On July 31, 2003, NSP-Minnesota redeemed the $200 million of trust preferred securities. A certificate of cancellation was filed to dissolve NSP Financing I on Sept. 15, 2003.

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

5. Joint Plant Ownership

Following are the investments by NSP-Minnesota in jointly owned plants and the related ownership percentages as of Dec. 31, 2004:

	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership%
	(Thousands of dollars)

NSP-Minnesota:
Sherco Unit 3	$	492,581	$	268,734	$	2,244	59.0
Sherco Common Facilities Units 1, 2 & 3	102,556		50,428		—		65.6
Transmission facilities, including substations	4,832		1,765		—		59.0
Total NSP-Minnesota	$	599,969	$	320,927	$	2,244

NSP-Minnesota is part owner of Sherco 3, an 860-megawatt, coal-fueled electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility components of operating expenses. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs.

6. Income Taxes

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 at Dec. 31 are:

	2004		2003		2002

Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.2	%	3.6	%	5.6	%
Life insurance policies	(0.3	)%	(0.4	)%	(0.3	)%
Tax credits recognized	(2.9	)%	(3.0	)%	(3.8	)%
Regulatory differences — utility plant items	(2.2	)%	(1.2	)%	(0.3	)%
Resolution of income tax audits	(3.8	)%	(5.1	)%	—
Other — net	(0.9	)%	(0.5	)%	(1.1	)%
Effective income tax rate	29.1	%	28.4	%	35.1	%

Income taxes comprise the following expense (benefit) items:

	2004			2003			2002
	(Thousands of dollars)
Current federal tax expense	$	53,693		$	74,954		$	114,221
Current state tax expense	29,826			8,013			31,740
Current federal tax credits	(2,301		)	(639		)	(636		)
Deferred federal tax expense (benefit)	25,739			5,212			(20,972		)
Deferred state tax expense (benefit)	(5,194		)	(3,651		)	(5,308		)
Deferred investment tax credits	(7,150		)	(7,365		)	(10,904		)
Total income tax expense	$	94,613		$	76,524		$	108,141

The components of deferred income tax at Dec. 31 were:

	2004				2003
	(Thousands of dollars)
Deferred tax expense excluding items below	$		53,280		$	44,242
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(32,732			)	(42,677			)
Tax expense allocated to other comprehensive income and other	(3			)	(4			)
Deferred tax expense	$	20,545			$		1,561

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

	2004		2003
	(Thousands of dollars)

Deferred tax liabilities:
Differences between book and tax bases of property	$	730,792	$		677,359
Regulatory assets	165,157		152,101
Other	14,723		10,213
Total deferred tax liabilities	$	910,672	$		839,673

Deferred tax assets:
Regulatory liabilities	$	20,903	$		22,482
Employee benefits	47,417		33,177
Deferred investment tax credits	24,069		27,050
Tax credit carryforward	2,965		—
Other	21,727		16,652
Total deferred tax assets	$	117,081	$			99,361
Net deferred tax liability	$	793,591	$	740,312

7. Benefit Plans and Other Postretirement Benefits

Xcel Energy offers various benefit plans to its benefit employees, including those of NSP-Minnesota. Approximately 51 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2004, NSP-Minnesota had 2,197 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2007.

Pension Benefits

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

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Pension Plan Assets — Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. In 2004, Xcel Energy completed a review of its pension plan asset allocation and adopted revised asset allocation targets. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments, no cash investments and 20 percent in nontraditional investments, such as real estate, timber ventures, private equity and a diversified commodities index.

The actual composition of pension plan assets at Dec. 31 was:

	2004		2003

Equity securities	69	%	75	%
Debt securities	19		14
Real estate	4		3
Cash	1		—
Nontraditional investments	7		8
	100	%	100	%

During 2003, Xcel Energy entered into a number of hedging arrangements within the pension trust designed to provide protection from a loss of asset value in the event of a broad decline in equity prices. These arrangements were closed out in December 2004.

Xcel Energy bases its investment return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 12.8 percent, which is in excess of the current assumption level. The pension cost determinations assume the continued current mix of investment types over the long-term. The Xcel Energy portfolio is heavily weighted toward equity securities, includes nontraditional investments that can provide a

higher-than-average return. As is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year. Investment returns in 2002 were below the assumed level of 9.5 percent, but in 2003 investment returns exceeded the assumed level of 9.25 percent and in 2004 investment returns exceeded the assumed level of 9.0 percent. Xcel Energy continually reviews its pension assumptions. For 2005, Xcel Energy has changed the investment return assumption to 8.75 percent to reflect its current expectations of investment returns.

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table:

(Thousands of dollars)	2004				2003

Accumulated Benefit Obligation at Dec. 31	$	2,575,317			$			2,512,138

Change in Projected Benefit Obligation
Obligation at Jan. 1	$	2,632,491			$			2,505,576
Service cost	58,150				67,449
Interest cost	165,361				170,731
Plan amendments	—				85,937
Actuarial loss	133,552				82,197
Settlements	(27,627			)	(9,546					)
Curtailment gain	—				(26,407					)
Benefit payments	(229,664			)	(243,446					)
Obligation at Dec. 31	$	2,732,263			$			2,632,491

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	3,024,661			$				2,639,963
Actual return on plan assets	284,600				605,978
Employer contributions	10,046				31,712
Settlements	(27,627			)	(9,546					)
Benefit payments	(229,664			)	(243,446					)
Fair value of plan assets at Dec. 31	$	3,062,016			$				3,024,661

Funded Status of Plans at Dec. 31
Net asset	$	329,753			$		392,170
Unrecognized transition asset	—				(7					)
Unrecognized prior service cost	244,437				273,725
Unrecognized loss	176,957				9,710
Xcel Energy net pension amounts recognized on balance sheet	$	751,147			$	675,598

NSP-Minnesota prepaid pension asset recorded	$		361,446		$	317,956

Measurement Date	Dec. 31, 2004				Dec. 31, 2003

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	6.00			%	6.25					%
Expected average long-term increase in compensation level	3.50			%	3.50					%

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2002 through 2004 for Xcel Energy’s pension plans and is not expected to require cash funding in 2005.

Benefit Costs — The components of net periodic pension cost (credit) are:

(Thousands of dollars)	2004				2003					2002

Service cost	$		58,150		$			67,449		$	65,649
Interest cost	165,361				170,731					172,377
Expected return on plan assets	(302,958			)	(322,011				)	(339,932			)
Curtailment (gain) loss	—				(17,363				)	—
Settlement (gain) loss	(926			)	(1,135				)	—
Amortization of transition asset	(7			)	(1,996				)	(7,314			)
Amortization of prior service cost	30,009				28,230					22,663
Amortization of net gain	(15,207			)	(44,825				)	(69,264			)
Net periodic pension cost (credit) under SFAS No. 87	$		(65,578	)	$	(120,920			)	$	(155,821		)

NSP-Minnesota
Net periodic pension credit	$		(43,490	)	$		(54,243		)	$		(71,928	)
Credits not recognized due to effects of regulation	38,967				51,311					71,928
Net benefit cost (credit) recognized for financial reporting	$	(4,523		)	$			(2,932	)	—

Significant Assumptions Used to Measure Costs
Discount rate	6.25			%	6.75				%	7.25			%
Expected average long-term increase in compensation level	3.50			%	4.00				%	4.50			%
Expected average long-term rate of return on assets	9.00			%	9.25				%	9.50			%

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2005 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.

Xcel Energy and its operating utilities also maintain noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of their operating cash flows.

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for NSP-Minnesota were approximately $3.8 million in 2004, $3.2 million in 2003, and $3.1 million in 2002.

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 terminated and its assets were combined into the Xcel Energy retirement savings 401(k) plan. Starting with the 2003 plan year, the ESOP component of the 401(k) plan is no longer leveraged.

Xcel Energy’s leveraged ESOP held 10.7 million shares of Xcel Energy common stock at May 6, 2002. Xcel Energy excluded an average of 0.7 million uncommitted leveraged ESOP shares from 2002 earnings-per-share-calculations. On Nov. 19, 2002, Xcel Energy paid off all of the ESOP loans. All uncommitted ESOP shares were released and were used by Xcel Energy for the 2002 employer matching contribution to its 401(k) plan.

Postretirement Health Care Benefits

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees. The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. 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 Pensions,”

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. NSP-Minnesota transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.

Plan Assets — Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs. In 2004, the investment strategy for the union asset fund was changed to increase the exposure to equity funds. Also, a portion of the assets contributed on behalf of non-bargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The actual composition of postretirement benefit plan assets at Dec. 31 was:

	2004		2003

Fixed income/debt securities	21	%	2	%
Equity mutual fund securities	54		14
Cash equivalents	25		84
	100%		100	%

Xcel Energy bases its investment return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Given the fairly short time period in which funding has been required, Xcel Energy does not consider the actual historical returns achieved by its postretirement health care fund asset portfolio to be significant in establishing long-term return assumptions. Instead, Xcel Energy considers the long-term return levels projected and recommended by investment experts, weighted for the target mix of asset categories in our portfolio, and does not consider investment return volatility to be a material factor in postretirement health care costs.

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

(Thousands of dollars)	2004			2003

Change in Benefit Obligation
Obligation at Jan. 1	$	775,230		$		767,975
Service cost	6,100			5,893
Interest cost	52,604			52,426
Acquisitions/(divestitures)	—			(31,584			)
Plan amendments	(1,600		)	(33,304			)
Plan participants’ contributions	9,532			16,577
Actuarial loss	148,341			122,864
Curtailments	—			(249			)
Benefit payments	(61,082		)	(60,754			)
Impact of Medicare Prescription Drug, Improvement and Modernization Act of 2003	—			(64,614			)
Obligation at Dec. 31	$	929,125		$		775,230

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	285,861		$		250,983
Actual return on plan assets	21,950			11,045
Plan participants’ contributions	9,532			16,577
Employer contributions	62,406			68,010
Benefit payments	(61,082		)	(60,754			)
Fair value of plan assets at Dec. 31	$	318,667		$	285,861

Funded Status at Dec. 31
Net obligation	$	610,458		$	489,369
Unrecognized transition asset (obligation)	(117,600		)	(133,778			)
Unrecognized prior service cost	17,914			20,093
Unrecognized gain (loss)	(383,026		)	(255,174			)
Accrued benefit liability recorded	$	127,746		$	120,510

NSP-Minnesota accrued benefit liability recorded	$	54,801		$	53,942

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	6.00		%	6.25			%

Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend assumption from 5.5 percent to 5.0 percent. The period until the ultimate rate is reached was also increased from two years to six years. This trend assumption was used to value the actuarial benefit obligations at year-end 2004, and will be used in 2005 retiree medical cost determinations. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

A 1-percent change in the assumed health care cost trend rate would have the following effects on NSP-Minnesota:

(Millions of dollars)

1-percent increase in APBO components at Dec. 31, 2004	$	23.8
1-percent decrease in APBO components at Dec. 31, 2004	(19.7		)
1-percent increase in service and interest components of the net periodic cost	1.6
1-percent decrease in service and interest components of the net periodic cost	(1.3		)

Curtailment and settlement gains resulted from activities of some of Xcel Energy’s nonregulated subsidiaries.

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $73 million during 2005.

Benefit Costs — The components of net periodic postretirement benefit cost are:

(Thousands of dollars)	2004			2003			2002

Service cost	$	6,100		$	5,893		$	5,967
Interest cost	52,604			52,426			48,304
Expected return on plan assets	(23,066		)	(22,185		)	(21,011		)
Curtailment (gain) loss	—			(2,128		)	—
Settlement (gain) loss	—			(916		)	—
Amortization of transition obligation	14,578			15,426			16,771
Amortization of prior service cost (credit)	(2,179		)	(1,533		)	(1,130		)
Amortization of net loss (gain)	21,651			15,409			5,380
Net periodic postretirement benefit cost (credit) under SFAS No. 106	$	69,688		$	62,392		$	54,281

NSP-Minnesota
Net periodic postretirement benefit cost recognized – SFAS No. 106	$	15,936		$	16,897		$	12,667

Significant assumptions used to measure costs (income)
Discount rate	6.25		%	6.75		%	7.25		%
Expected average long-term rate of return on assets (before tax)	5.5 - 8.5		%	8.0 - 9.0		%	9.0		%

Impact of 2003 Medicare Legislation — On Dec. 8, 2003, President Bush signed into law the Medicare Prescription Drug,

Improvement and Modernization Act of 2003 (the Act). The Act expanded Medicare to include, for the first time, coverage for prescription drugs. This new coverage is generally effective Jan. 1, 2006. Many of Xcel Energy’s retiree medical programs provide prescription drug coverage for retirees over age 65 with coverage at least equivalent to the benefit to be provided under Medicare. While retirees remain in Xcel Energy’s postretirement health care plan without participating in the new Medicare prescription drug coverage, Medicare will share the cost of Xcel Energy’s plan. This legislation has therefore reduced Xcel Energy’s share of the obligation for future retiree medical benefits.

As of Dec. 31, 2003, Xcel Energy had reduced the postretirement health care benefit obligation by $64.6 million due to the expected sharing of the cost of the program by Medicare under the new legislation. Also, beginning in 2004, the annual net periodic postretirement benefit cost was reduced by approximately $10 million as a result of the expected sharing of the cost of the program by Medicare, with similar savings expected in subsequent years. These estimated reductions do not reflect any changes that may result in future levels of participation in the plan or the associated per capita claims cost due to the availability of prescription drug coverage for Medicare-eligible retirees. Also, in reflecting this legislation, Medicare cost sharing for a plan has been assumed only if Xcel Energy’s projected contribution to the plan is expected to be at least equal to the Medicare Part D basic benefit.

Projected Benefit Payments

The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans.

(Thousands of dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2005	$	199,117	$	59,642	$	—	$	59,642
2006	211,830		61,652		4,297		57,355
2007	217,582		63,640		4,591		59,049
2008	225,050		65,393		4,821		60,572
2009	231,704		67,036		5,008		62,028
2010-2014	1,202,161		352,308		27,192		325,116

8. Detail of Interest and Other Income, Net of Nonoperating Expenses

Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 comprises the following:

(Thousands of dollars)	2004				2003			2002

Interest income	$		8,681		$	7,745		$	19,215
Other nonoperating income	557				193			2,163
Gain (Loss) on disposal of assets	(1,888			)	(1,125		)	4,764
Interest expense on corporate-owned life insurance and other employee-related insurance policies	(6,261			)	(6,622		)	(6,181		)
Other nonoperating expense	—				(2,991		)	(383		)
Total interest and other income, net of nonoperating expenses	$	1,089			$	(2,800	)	$	19,578

9. Derivative Instruments

In the normal course of business, NSP-Minnesota is exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. NSP-Minnesota utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance our operations. The use of these derivative instruments is discussed in further detail below.

Utility Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in their generation and retail distribution operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric power, natural gas, coal and fuel oil. Commodity risk also is managed through the use of financial derivative instruments. NSP-Minnesota utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of our retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs. In these instances, the use

of derivative instruments is done consistently with the local jurisdictional cost recovery mechanism. NSP-Minnesota’s risk management policy allows it to manage market price risk to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various marketing and commodity trading activities, including the purchase and sale of electric capacity and energy and other energy related instruments. These activities are primarily focused on specific regions where market knowledge and experience have been obtained and are generally less than one year in length. NSP-Minnesota’s risk management policy allows management to conduct the marketing activity within approved guideline and limitations as approved by our risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Types of and Accounting for Derivative Instruments

NSP-Minnesota uses a number of different derivative instruments in connection with its utility commodity price, short-term wholesale and commodity trading activities, including forward contracts, futures, and options. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, as amended, are recorded at fair value. The classification of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship. The fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings. This includes certain instruments used to mitigate market risk for NSP-Minnesota and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income, to the extent effective.

SFAS No. 133, as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. NSP-Minnesota formally documents hedging 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. NSP-Minnesota also formally assesses, both at inception and on an ongoing basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

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 natural gas purchased for resale are recorded as a component of natural gas costs. NSP-Minnesota is allowed to recover in natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility.

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions that NSP-Minnesota is currently engaged in are discussed below.

Cash Flow Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a cash flow hedge is recognized in Other Comprehensive Income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.

Commodity Cash Flow Hedges — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes. At Dec. 31, 2004, NSP-Minnesota had various commodity-related contracts classified as cash flow hedges extending through 2005. Amounts deferred from current earnings are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy and energy-related products, the use of natural gas to generate electric energy or natural gas purchased for resale.

As of Dec. 31, 2004, NSP-Minnesota had no amounts accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

NSP-Minnesota had no ineffectiveness related to commodity cash flow hedges during the years ended Dec. 31, 2004 and 2003, respectively.

Financial Impacts of Qualifying Cash Flow Hedges — The impact of qualifying cash flow hedges on NSP-Minnesota’s Other Comprehensive Income, included in the Consolidated Statements of Stockholder’s Equity, are detailed in the following table:

(Millions of Dollars)
Accumulated other comprehensive income related to hedges at Dec. 31, 2001	$	0.1
After-tax net unrealized gains related to derivatives accounted for as hedges	—
After-tax net realized gains on derivative transactions reclassified into earnings	(0.1		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2002	$	—

After-tax net unrealized losses related to derivative accounted for as hedges	(0.2		)
After-tax net realized losses on derivative transactions reclassified into earnings	0.2
Accumulated other comprehensive income related to hedges at Dec. 31, 2003	$	—

After-tax net unrealized losses related to derivatives accounted for as hedges	(0.7		)
After-tax net realized losses on derivative transactions reclassified into earnings	0.7
Accumulated other comprehensive income related to hedges at Dec. 31, 2004	$	—

Fair Value Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of a derivative instrument's change in fair value is recognized in current earnings.

At Dec. 31, 2004, NSP-Minnesota had no fair value hedges.

Normal Purchases or Normal Sales Contracts

NSP-Minnesota enters into 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 amended, as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.

Contracts that meet the requirements of normal are documented and exempted from the accounting and reporting requirements of SFAS No. 133. In June 2003, C20 clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended. NSP-Minnesota’s implementation of C20 in 2003 had no impact on earnings. However, certain contracts did require a one-time fair value adjustment as of Oct. 1, 2003. The result of this adjustment was the creation of a derivative liability with an offsetting regulatory asset to reflect expected recovery of the amounts from customers. The derivative liability and related regulatory asset will be amortized over the respective lives of the contracts. See Note 13 to the Consolidated Financial Statements.

NSP-Minnesota evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the commodity trading operations qualify for a normal designation.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under GAAP.

The fair value of qualifying hedges is presented as a component of Other Comprehensive Income in the Consolidated Statements of Stockholder’s Equity. At Dec. 31, 2004 and 2003, the fair value of these contracts was $(7.2) million and $(0.7) million, respectively.

The fair value of the trading contracts as of Dec. 31, 2004 and 2003 was $0.9 million and $3.5 million, respectively.

For a further discussion of other financial instruments at NSP-Minnesota, see Note 10 to the Consolidated Financial Statements.

10. Financial Instruments

The estimated Dec. 31 fair values of NSP-Minnesota’s financial instruments are as follows:

	2004				2003
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term investments	$	922,571	$	922,571	$	781,951	$	781,952
Long-term debt, including current portion	1,941,922		2,193,546		1,945,460		2,191,052

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates. The fair values of NSP-Minnesota’s long-term investments, mainly debt securities in an external nuclear decommissioning fund, are estimated based on quoted market prices for those or similar investments. The fair value of NSP-Minnesota’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2004 and 2003. These fair value estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current estimates of fair values may differ significantly.

NSP-Minnesota provides guarantees that guarantee payment or performance under specified agreements or transactions. As a result, NSP-Minnesota’s exposure under the guarantees is based upon the net liability under the specified agreements or transactions. The guarantees issued by NSP-Minnesota limit the exposure of NSP-Minnesota to a maximum amount stated in the guarantees. The guarantees require no liability to be recorded and contain no recourse provisions. On Dec. 31, 2004, NSP-Minnesota had the following guarantees and exposures related to those guarantees:

(Millions of dollars)
Nature of Guarantee

Guarantor

Guarantee
Amount

Current
Exposure

Term or Expiration Date

Triggering
Event
Requiring
Performance

Assets Held as
Collateral

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 loan 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 expected to have a material impact on the results of operations

NSP-Minnesota

0.4

Latest expiration in 2007

(a)

(b)

(a) Nonpayment by the government entity on the underlying debt

(b) Security interest in underlying loan agreements, contracts and arrangements between NSP-Minnesota and the government entities

Letters of Credit

NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2004, there was $39.4 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

11. Commitments and Contingent Liabilities

Legislative Resource Commitments — In 1994 and 2003, 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. Commitments related to the 17 dry cask storage containers approved in 1994 have been fulfilled. The use of 29 dry cask storage containers has been approved. As of Dec. 31, 2004, NSP-Minnesota had loaded 17 of the containers.

On May 29, 2003, the Minnesota Legislature enacted legislation that will enable NSP-Minnesota to store at least 12 more casks of spent-fuel outside the Prairie Island nuclear generating plant, in addition to those approved in 1994. This will allow NSP-Minnesota to continue to operate the plant and store spent-fuel in the facility until its licenses with the Nuclear Regulatory Commission (NRC) expire in 2013 and 2014. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. The legislation requires NSP-Minnesota to add at least 300 megawatts of additional wind power by 2010 with an option to own 100 megawatts of this power.

The legislation also requires payments during the remaining operating life of the Prairie Island plant. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously established Renewable Energy Development Fund from $8.5 million in 2002 to $16 million per year beginning in 2003. The legislation also designated $10 million in one-time grants to the University of Minnesota for additional renewable energy research, which is to be funded from commitments already made to the Renewable Energy Development Fund. All of the cost increases to NSP-Minnesota from these required payments and funding commitments are expected to be recoverable in Minnesota retail customer rates, mainly through existing cost recovery mechanisms. Funding commitments to the Renewable Energy Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that NSP-Minnesota failed to make a good faith effort to store or dispose of the spent fuel out of state, in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year.

Capital Commitments — NSP-Minnesota expects to incur approximately $43 million in capital expenditures and $988 million for environmental improvements related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area pursuant to the metropolitan emissions reduction project (MERP). The MERP project will begin major construction in 2005 and finish in 2009. NSP-Minnesota expects cash recovery of the costs of the emission-reduction project through customer rates beginning in 2006.

Leases — NSP-Minnesota leases a variety of equipment and facilities used in the normal course of business. The leases are accounted for as operating leases. Rental expense under operating lease obligations was approximately $27.3 million, $27.1 million and $31.0 million for 2004, 2003 and 2002, respectively.

Expected operating lease expenses are:

2005		2006		2007		2008		2009
(Millions of dollars)
$	27.7	$	27.5	$	27.5	$	27.1	$	26.7

Nuclear Insurance — NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $10.8 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $10.5 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $100.6 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $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 $2.1 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $6.9 million for business interruption insurance and $26.1 million for property damage insurance if losses exceed accumulated reserve funds.

Fuel Contracts — NSP-Minnesota has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2005 and 2017. In addition, NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss 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 estimated minimum purchase for NSP-Minnesota under these contracts as of Dec. 31, 2004, is as follows:

Coal		Nuclear Fuel		Natural Gas Supply		Gas Storage & Transportation
(Millions of dollars)

$	258	$	133	$	673	$	417

Purchased Power Agreements — NSP-Minnesota has 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 has various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indexes. However, the effect of these price adjustments are mitigated through cost-of-energy adjustment mechanisms.

At Dec. 31, 2004, the estimated future payments for capacity that NSP-Minnesota is obligated to purchase, subject to availability, is as follows (Thousands of dollars):

2005	$		106,648
2006	148,574
2007	154,289
2008	157,098
2009	160,396
2010 and thereafter	1,826,820
Total	$	2,553,825

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

Environmental Contingencies

NSP-Minnesota is 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 — NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota and some other parties have caused environmental contamination. At Dec. 31, 2004 there were three categories of sites:

• the site of a former federal uranium enrichment facility,

• the site of former a manufactured gas plant (MGP) operated by NSP-Minnesota’s subsidiaries or predecessors and

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

NSP-Minnesota records a liability when enough information is available 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, assumptions are made where facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

Estimates are revised as facts become known, but at Dec. 31, 2004, NSP-Minnesota estimated its liability for the cost of remediating sites was $16.2 million, of which $7.5 million was considered to be a current liability.

Some of the cost of remediation may be recovered from:

• insurance coverage;

• other parties that have contributed to the contamination; and

• customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. NSP-Minnesota has recorded estimates of its future costs for these sites.

Federal Uranium Enrichment Facility

Approximately $4.6 million of the long-term liability and $4.6 million of the current liability for NSP-Minnesota relates to a DOE assessment for decommissioning a federal uranium enrichment facility. This environmental liability does 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 12 to Consolidated Financial Statements for further discussion of nuclear obligations.

Manufactured Gas Plant Site

Levee Station Manufactured Gas Plant Site — A portion of NSP-Minnesota’s High Bridge plant coal yard is located on the site of the former Levee Station MGP site. The Levee Station was a coke-oven gas purification, storage and distribution facility. The Levee Station supplied manufactured gas to the city of St. Paul from 1918 to the early 1950s. In the 1950s, the facility was demolished, and the High Bridge coal yard was extended onto the property. In the 1990s, the site was investigated and partially remediated at a cost of approximately $2.9 million. In 2006, NSP-Minnesota plans to commence construction of the High Bridge Combined Cycle Generating Plant, as part of MERP, on the site of the Levee Station. The construction of the new plant will require the removal of buried structures and soil and groundwater remediation. Remediation activities will begin in 2005. The cost of the additional remediation is estimated to be $5.8 million, which will be accounted for as a capital expenditure of the MERP project.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. 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.

Federal Clean Water Act — The federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require NSP-Minnesota to perform additional environmental studies at 7 power plants in Minnesota to determine the impact the facilities may be having on aquatic organisms vulnerable to injury. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these plants. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. Preliminary cost estimates range from less than $1 million at some plants to more than $10 million at others depending on site-specific circumstances. Based on the limited information available, total capital costs to NSP-Minnesota are estimated at approximately $55 million. Actual costs may be significantly higher or lower depending on issues such as the resolution of outstanding third-party legal challenges to the rule.

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

Legal Contingencies

In the normal course of business, NSP-Minnesota is party to routine claims and litigation arising from prior and current operations. NSP-Minnesota is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition.

SchlumbergerSema, Inc. vs. Xcel Energy Inc. — Under a 1996 data services agreement, 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 committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling approximately $24 million for alleged breach of an expansion contract and a meter-purchasing contract. In the arbitration, NSP-Minnesota asserted counterclaims against SLB, including those related to 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, for total claims of approximately $41 million. NSP-Minnesota also sought a declaratory judgment from the arbitrators that would terminate SLB’s rights under the data services agreement. In August 2004, the U.S. Bankruptcy Court for the District of Delaware ruled that claims related to use of certain equipment are barred unless NSP-Minnesota can establish a basis for the claims in SLB’s conduct subsequent to the time of the assumption of this contract by SLB. If NSP-Minnesota cannot establish that basis, the decision would reduce NSP-Minnesota’s damage claim by approximately $5.5 million.

Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota state district court asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1 million that NSP-Minnesota has charged over the past five years for relocation costs should be repaid. The case is in early stages, there has been no discovery and NSP-Minnesota intends to vigorously defend against these claims.

Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO₂) emissions. Although NSP-Minnesota is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on NSP-Minnesota. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO₂ is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO₂ emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO₂ emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit contending, among other reasons, that the lawsuit should be dismissed because it is an attempt to usurp the policy-setting role of the U.S Congress and the president. The ultimate financial impact of these lawsuits, if any, is not determinable at this time.

The issue of global climate change is receiving increased attention. Debate continues in the scientific community concerning the extent to which the earth’s climate is warming, the causes of climate variations that have been observed, and the ultimate impacts that might result from a changing climate. There also is considerable debate regarding public policy for the approach that the United States should follow to address the issue. The United Nations-sponsored Kyoto Protocol, which establishes greenhouse gas reduction targets for developed nations, entered into force on Feb. 16, 2005. President Bush has declared that the United States will not ratify the protocol and is opposed to legislative mandates, preferring a program based on voluntary efforts and research on new technologies. NSP-Minnesota is closely monitoring the issue from both scientific and policy perspectives. While it is not possible to know the eventual outcome, NSP-Minnesota believes the issue merits close attention and is taking actions it believes are prudent to be best positioned for a variety of possible future outcomes. Xcel Energy, including NSP-Minnesota, is participating in a voluntary carbon

management program and has established goals to reduce its volume of carbon dioxide emissions by 12 million tons by 2009 and to reduce carbon intensity by 7 percent by 2012. NSP-Minnesota’s evaluation process for future generating resources incorporates the risk of future carbon limits through the use of externality costs. NSP-Minnesota also is involved in other projects to improve available methods for managing carbon.

12. Nuclear and Other Asset Retirement Obligations

NSP-Minnesota records future plant decommissioning obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation has no income statement impact due to the deferral of adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.

Asset retirement obligations have been recorded for the decommissioning of two NSP-Minnesota nuclear generating plants, the Monticello plant and the Prairie Island plant. A liability also has been recorded for decommissioning of an NSP-Minnesota steam production plant, the Pathfinder 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. Pathfinder operated as a steam production peaking facility from 1969 until its retirement.

A reconciliation of the beginning and ending aggregate carrying amount of NSP-Minnesota’s asset retirement obligations are shown in the table below for the 12 months ended Dec. 31, 2004:

(Thousands of dollars)	Beginning Balance Jan. 1, 2004			Liabilities Incurred			Liabilities Settled			Accretion			Revisions To Prior Estimates			Ending Balance Dec. 31, 2004

Steam plant retirement	$		2,860	$	—		$	—		$		142	$	—		$		3,002
Nuclear plant decommissioning	1,021,669			—			—			66,418			—			1,088,087
Total liability	$	1,024,529		$		—	$		—	$	66,560		$		—	$	1,091,089

The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $986 million as of Dec. 31, 2004, including external nuclear decommissioning investment funds and internally funded amounts.

Removal Costs —NSP-Minnesota also accrues an obligation for plant removal costs for other generation, transmission and distribution facilities. Generally, the accrual of future non-legal removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, the NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs as of Dec. 31, 2004 and 2003 are $323 million and $324 million, respectively.

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 2004, $13 million in 2003 and $13 million in 2002. In total, NSP-Minnesota had paid approximately $335 million to the DOE through Dec. 31, 2004. However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.

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

NSP-Minnesota has its own temporary, on-site storage facilities for spent-fuel at its Monticello and Prairie Island nuclear plants, which consists of storage pools and a dry cask facility. With the dry cask storage facility licensed by the NRC approved in 1994 and again in 2003, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at

least the end of its license terms in 2013 and 2014. The Monticello nuclear plant has storage capacity in the pool to continue operations until 2010. Storage availability to permit operation beyond these dates is not known at this time. All of the alternatives for spent-fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent-nuclear fuel as part of a consortium of electric utilities.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from 1993 to 2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2004 was $4.6 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $12.6 million at Dec. 31, 2004, is deferred as a regulatory asset.

Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is planned for the years 2010 through 2048, assuming the prompt dismantlement method. NSP-Minnesota is currently accruing the costs for decommissioning over the MPUC approved cost-recovery period and including the accruals in Accumulated Depreciation. Upon implementation of SFAS No. 143, the decommissioning costs in Accumulated Depreciation and ongoing recoveries are reclassified to a regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with SFAS No. 143.

Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. In 2003, the Minnesota Legislature changed a law that had limited expansion of on-site storage. On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants. NSP-Minnesota filed its application for Monticello with the MPUC in January 2005, seeking a certificate of need for dry spent-fuel storage and plans to file an application in early 2005 with the NRC for an operating license extension of up to 20 years. A decision regarding Monticello relicensing is expected in 2007. Plant assessments and other work for the Prairie Island applications are planned in the next two or three years. The Prairie Island license renewal process has not yet begun.

Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Funding presumes that current costs will escalate in the future at a rate of 4.19 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding. Unrealized gains on nuclear decommissioning investments are deferred as Regulatory Liabilities based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in December 2003, using 2002 cost data. An original filing was submitted to the MPUC in October 2002 and updated in August 2003; final approval was received in December 2003. The most recent cost estimate represents an annual increase in external fund accruals, along with the extension of Prairie Island cost recovery to the end of license life in 2014. The MPUC also approved the Department of Commerce recommendation to accelerate the internal fund transfer to the external funds effective July 1, 2003, ending on Dec. 31, 2005. This approval increased the fund cash contribution by approximately $29 million in 2003. Consistent with previous treatment, the transfers from the internal fund are effectively moving previously collected funds to the external fund, thereby reducing the external fund book expense. Based on the last MPUC approval requiring the acceleration of the internal fund transfer, there is a step change in the level of the overall decommissioning expense at the expiration of the transfer beginning Jan. 1, 2006. Expecting to operate Prairie Island through the end of each unit’s licensed life, the approved capital recovery will allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2014. NSP-Minnesota believes future decommissioning cost accruals will continue to be recovered in customer rates.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2004, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

At Dec. 31, 2004, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $768 million. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters. These amounts are not those recorded in the financial statements for the asset retirement obligation in accordance with SFAS No. 143:

	2004
	(Thousands of dollars)
Estimated decommissioning cost obligation from most recently approved study (2002 dollars)	$	1,716,618
Effect of escalating costs to 2004 dollars (at 4.19 percent per year)	146,866
Estimated decommissioning cost obligation in current dollars	1,863,484
Effect of escalating costs to payment date (at 4.19 percent per year)	1,929,881
Estimated future decommissioning costs (undiscounted)	3,793,365
Effect of discounting obligation (using risk-free interest rate)	(2,139,561		)
Discounted decommissioning cost obligation	1,653,804
Assets held in external decommissioning trust	918,442
Discounted decommissioning obligation in excess of assets currently held in external trust	$	735,362

Decommissioning expenses recognized include the following components:

	2004				2003				2002
	(Thousands of dollars)
Annual decommissioning cost accrual reported as depreciation expense:
Externally funded	$	80,582			$		80,582		$	51,433
Internally funded (including interest costs)	(53,307			)	(35,906			)	(18,797			)
Interest cost on externally funded decommissioning obligation	(19,026			)	(14,952			)	(32			)
Earnings from external trust funds	19,026				14,952				32
Net decommissioning accruals recorded	$		27,275		$	44,676			$		32,636

Decommissioning and interest accruals are included with Regulatory Liabilities on the Consolidated 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 2002, 2003 and 2004 reflect the impacts of the 1999 and 2002 decommissioning studies, which have 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.

13. Regulatory Assets and Liabilities

NSP-Minnesota’s financial statements are prepared in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of the business that is not rate regulated cannot use SFAS No. 71 accounting. The components of unamortized regulatory assets and liabilities on the balance sheets of NSP-Minnesota are as follows:

(Thousands of dollars)		See note	Remaining amortization period	2004			2003

Regulatory Assets:
Net nuclear asset retirement obligations		12	End of licensed life	$	221,864		$			186,989
AFDC recorded in plant (a)			Plant lives	92,080			85,552
Purchase power contract valuation adjustments (d)		9	Term of contract	17,700			78,446
Losses on reacquired debt		1	Term of related debt	32,844			36,623
Renewable resource costs			To be determined	38,985			25,972
Conservation programs (a)			Generally one year	23,209			25,380
Nuclear decommissioning costs (c)			Up to three years	12,610			16,750
Unrecovered gas costs (b)		1	One to two years	14,553			16,008
Other			Various	9,667			12,304
Minnesota renewable cost recovery			Generally one year	5,292			—
State commission accounting adjustments (a)	%		Plant lives	4,476			4,604
Environmental costs		11,12	Various	3,205			3,863
Total regulatory assets				$	476,485		$		492,491

Regulatory Liabilities:
Pension costs-regulatory differences		7		377,893			338,926
Plant removal costs		12		323,440			324,637
Unrealized gains on decommissioning investments		12		129,028			105,518
Deferred income tax adjustments				60,521			65,749
Investment tax credit deferrals				40,602			45,698
Interest on income tax refunds				9,315			6,630
Fuel costs, refunds and other				3,565			1,994
Total regulatory liabilities				$		944,364	$	889,152

	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
	(Thousands of dollars)
2004
Operating revenues from external customers	$	2,585,356	$	715,071	$	19,135		$	—		$	3,319,562
Intersegment revenues	821		4,658					(5,479		)
Total revenues	2,586,177		719,729		19,135			(5,479		)	3,319,562
Depreciation and amortization	307,048		28,787		909			—			336,744
Financing costs, mainly interest expense	113,405		14,349		875			(47		)	128,582
Income tax expense (benefit)	90,428		7,332		(3,147		)	—			94,613
Segment net income	$	206,726	$	23,131	$	417		$	—		$	230,274

2003
Operating revenues from external customers	$	2,485,742	$	674,530	$	17,180		$	—		$	3,177,452
Intersegment revenues	720		7,245		—			(7,965		)	—
Total revenues	2,486,462		681,775		17,180			(7,965		)	3,177,452
Depreciation and amortization	318,801		31,420		3,120			—			353,341
Financing costs, mainly interest expense	117,332		18,004		10,180			(9,876		)	135,640
Income tax expense	67,104		8,965		455			—			76,524
Segment net income (loss)	$	177,333	$	17,852	$	(2,243	)	$	—		$	192,942

2002
Operating revenues from external customers	$	2,362,672	$	489,572	$	30,875		$	—		$	2,883,119
Intersegment revenues	602		4,099		—			(4,701		)	—
Total revenues	2,363,274		493,671		30,875			(4,701		)	2,883,119
Depreciation and amortization	325,738		27,682		737			—			354,157
Financing costs, mainly interest expense	101,336		13,253		16,909			(16,808		)	114,690
Income tax expense	99,873		4,775		3,493			—			108,141
Segment net income	$	177,703	$	15,752	$	6,767		$	—		$	200,222

15. Related Party Transactions

In 2003, Xcel Energy established a money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. NSP-Minnesota received approval to participate in the money pool arrangement in 2004. The money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The money pool arrangement does not allow loans from the utility subsidiaries to the holding company. NSP-Minnesota has approval to borrow up to $250 million under the arrangement. NSP-Minnesota had no borrowings or loans outstanding under the arrangement at Dec. 31, 2004.

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with Service Agreements approved by the SEC and executed by each subsidiary. Costs are charged directly to the subsidiary which uses the service whenever possible, and are allocated using an SEC approved method if they cannot be directly assigned.

Viking Gas Transmission Co. (Viking), a subsidiary of Xcel Energy until it was sold on Jan. 17, 2003, transported gas purchased by NSP-Minnesota from various suppliers. NSP-Minnesota paid Viking $4.6 million in 2002 for gas transportation services.

NSP-Minnesota purchased gas from e prime, another subsidiary of Xcel Energy, paying $2.7 million in 2002. In addition NSP-Minnesota sold transportation services to e prime for $0.1 million in 2002 for gas delivered into the Minnesota operating area. e prime ceased conducting business in 2004.

Utility Engineering Corp., an Xcel Energy subsidiary, provided construction services to NSP-Minnesota, for which it was paid $9.3 million in 2004, $5.3 million in 2003 and $5.1 million in 2002.

NSP-Minnesota and four other utility companies formed the NMC, and each of the five member companies retains a 20 percent ownership interest in the NMC. The NMC is an operating company that manages the operations, maintenance and physical security of eight nuclear generating units on six sites, including three units/two sites owned by NSP-Minnesota. NSP-Minnesota continues to own the plants, controls all energy produced by the plants, and retains responsibility for nuclear property and liability insurance and decommissioning costs. In accordance with the Nuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays its proportionate share of the operating expenses and capital improvement costs incurred by NMC. NSP-Minnesota paid NMC $314.7 million in 2004, $227.0 million in 2003 and $182.5 million in 2002.

The electric production and transmission costs of the entire NSP system are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement (called the “Interchange Agreement”) between the two companies provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.

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

(Thousands of dollars)	2004		2003		2002
Operating revenues:
Electric utility	$	220,165	$	227,946	$	220,674
Natural gas utility	303		287		363
Operating expenses:
Purchased power	96,016		92,814		80,200
Other operations – paid to Xcel Energy Services Inc.	274,074		266,560		272,825

Accounts receivable and payable with affiliates at Dec. 31, was:

	2004				2003
(Thousands of dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable

NSP-Wisconsin	$	2,826	$	—	$	—	$		329
PSCo	72		12,197		20		714
SPS	—		1,576		—		4,297
Other subsidiaries of Xcel Energy Inc.	5,452		9,240		48,796		27,544
	$	8,350	$	23,013	$	48,816	$	32,884

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. As of Dec. 31, 2004, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in the amount of $31.5 million. Interest income on NSP-Minnesota’s statement of income was $0.3 million, $0.1 million and $0.2 million for 2004, 2003 and 2002.

16. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31, 2004		June 30, 2004		Sept. 30, 2004 (a)		Dec. 31, 2004 (b)
	(Thousands of dollars)

Revenue	$	929,662	$	696,941	$	800,759	$	892,200
Operating income	132,633		77,703		127,182		94,115
Net income	68,357		34,263		68,435		59,219

	Quarter Ended
	March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003
	(Thousands of dollars)

Revenue	$	927,755	$	667,261	$	814,387	$	768,049
Operating income	102,915		45,469		155,225		91,623
Net income	44,451		19,641		80,410		48,440

(a) In the third quarter of 2004, an adjustment of $9.8 million was recorded, which lowered 2003 costs of NSP-Minnesota shared with NSP-Wisconsin, pursuant to the Interchange Agreement. In addition, an adjustment, which reduced expenses charged to NSP-Wisconsin by NSP-Minnesota of $6.2 million was recorded for 2004 year-to-date billings.

(b) Fourth quarter 2004 results were increased by $10.5 million of income tax benefits, including $4.1 million related to the successful resolution of various IRS audit issues and other adjustments to current and deferred taxes related to prior years, $5 million for the 2003 return- to- accrual true-up and $1.4 million from revisions to benefits related to foreign power sales.

Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

During 2003 and 2004, and through the date of this report, there were no disagreements with the independent public accountants for NSP-Minnesota on accounting principles or practices, financial disclosures or audit scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

NSP-Minnesota maintains 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. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the NSP-Minnesota’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

No change in NSP-Minnesota’s internal control over financial reporting has occurred during NSP-Minnesota’s most recent fiscal quarter that has materially affected, or is reasonably likely to affect, NSP-Minnesota’s internal controls over financial reporting.

Item 9B — Other Information

None

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1. Consolidated Financial Statements:

Reports of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2004, 2003 and 2002.

Consolidated Statements of Income — For the three years ended Dec. 31, 2004, 2003 and 2002.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2004, 2003 and 2002.

Consolidated Balance Sheets — As of Dec. 31, 2004 and 2003.

2. Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2004, 2003 and 2002.

3. Exhibits

*Indicates incorporation by reference

+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

2.01*		Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Co. (a Minnesota corporation) and New Century Energies, Inc. (Exhibit 2.1 to New Century Energies, Inc. Form 8-K (file no. 001-12907) dated March 24, 1999).
3.01*		Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*		By-Laws of Northern States Power Co. (a Minnesota corporation) (Exhibit 3.02 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.01*		Trust Indenture, dated Feb. 1, 1937, from Northern States Power Co. (a Minnesota corporation) 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 Northern States Power Co. (a Minnesota corporation) to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K (file no. 001-03034) for the year 1988). Supplemental Indentures between NSP-Minnesota and said Trustee, supplemental to Exhibit 4.02, 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).
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. 001-03034).
4.38*		Sept. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985, File No. 001-03034).
4.39*		July 1, 1989 (Exhibit 4.01 to Form 8-K dated July 7, 1989, File No. 001-03034).
4.40*		June 1, 1990 (Exhibit 4.01 to Form 8-K dated June 1, 1990, File No. 001-03034
4.41*		Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated Oct. 13, 1992, File No. 001-03034).
4.42*		April 1, 1993 (Exhibit 4.01 to Form 8-K dated March 30, 1993, File No. 001-03034).
4.43*		Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated Dec. 7, 1993, File No. 001-03034).
4.44*		Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated Feb. 10, 1994, File No. 001-03034).
4.45*		Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated Oct. 5, 1994, File No. 001-03034).
4.46*		June 1, 1995 (Exhibit 4.01 to Form 8-K dated June 28, 1995, File No. 001-03034).
4.47*		April 1, 1997 (Exhibit 4.47 to Form 10-K for the year 1997, File No. 001-03034).
4.48*		March 1, 1998 (Exhibit 4.01 to Form 8-K dated March 11, 1998, File No. 001-03034).
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 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.52*		Trust Indenture, dated July 1, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated July 21, 1999).
4.53*		Supplemental Trust Indenture dated July 15, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to Form 8-K (file no. 001-03034) dated July 21, 1999).
4.54*		Supplemental Trust Indenture dated Aug. 18, 2000, among Xcel Energy, Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to Form 10 (file no. 000-31709) dated Oct. 5, 2000).
4.55*		Supplemental Trust Indenture dated June 1, 2002, between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., as successor trustee. (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.56*		Supplemental Trust Indenture dated July 1, 2002, between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., as successor trustee. (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.57*		Supplemental Trust Indenture dated July 1, 2002, between Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated July 8, 2002).
4.58*		Supplemental Trust Indenture dated Aug. 1, 2002, between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., as Trustee. (Exhibit 4.01 to Form 8-K (file no 000-31709) dated Aug. 22, 2002).
4.59*		Supplemental Trust Indenture dated Aug. 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.60*		Supplemental Trust Indenture dated May 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.73 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
4.61*		Credit Agreement between Northern States Power Company (a Minnesota corporation), Wells Fargo Bank, National Association, Bank One NA and other financial institutions, dated May 14, 2004 (Exhibit 4.02 to Xcel Energy Form 10-Q (file no. 001-03034) filed Aug. 4, 2004).
10.01*+		Xcel Energy Omnibus Incentive Plan (Exhibit A to Xcel Energy Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+		Xcel Energy Executive Annual Incentive Award Plan (Exhibit B to Xcel Energy Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).

10.03*+		Employment Agreement dated March 24, 1999, among Northern States Power Co. (a Minnesota corporation), New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).
10.04*+		Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.05*+		Stock Equivalent Plan for Non-Employee Directors of Xcel Energy As Amended and Restated Effective Oct. 1, 1997. (Exhibit 10.15 to NSP-Minnesota Form 10-K (file no. 001-03034) for the year 1997).
10.06*+		Senior Executive Severance Policy, effective March 24, 1999, between New Century Energies, Inc. and Senior Executives (Exhibit 10(a)(2) to New Century Energies, Inc. Form 10-Q, (File no. 001-12927) dated March 31, 1999).
10.07*+		New Century Energies Omnibus Incentive Plan (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.08*+		Directors’ Voluntary Deferral Plan (Exhibit 10(d) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.09*+		Supplemental Executive Retirement Plan (Exhibit 10(e) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.10*+		Salary Deferral and Supplemental Savings Plan for Executive Officers (Exhibit 10(f) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.11*+		Salary Deferral and Supplemental Savings Plan for Key Managers (Exhibit 10(g) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.12*+		Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (Exhibit 10(e)(2) to PSCo Form 10-K (File no. 001-3280) dated Dec. 31, 1991).
10.13*+		Form of Key Executive Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(e)(4) to PSCo Form 10-K (File no. 001-3280) dated Dec. 31, 1995).
10.14*+		Supplemental Retirement Income Plan as amended July 23, 1991 (Exhibit 10(d) to SPS Form 10-K, (File no. 001-03789) dated Aug. 31, 1996).
10.15*+		Xcel Energy Senior Executive Severance and Change-in Control Policy dated Oct. 22, 2003 (Exhibit 10.10 to SPS Form S-4, (file no. 333-112032) dated Jan. 21, 2004).
10.16*+		Stock Equivalent Plan for Non-employee Directors of Xcel Energy as amended and restated Jan. 1, 2004 (Exhibit B to Xcel Energy Form DEF-14A (file no. 001-03034) dated Apr. 9, 2004).
10.17*+		Xcel Energy Nonqualified Deferred Compensation Plan (2002 restatement) (Exhibit 10.23 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.18*+		Xcel Energy Inc. Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.19*+		Xcel Energy 401(k) Savings Plan, amended and restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4 (file no. 333-112032) dated Jan. 21, 2004).
10.20*+		New Century Energies, Inc. Employee Investment Plan for Bargaining Unit Employees and Former Non-bargaining Unit Employees, as amended and restated effective Jan. 1, 2002 but with certain retroactive amendments (Exhibit 10.20 to SPS Form S-4 (file no 333-112032) dated Jan. 21, 2004).
10.21*		Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Xcel Energy Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.22*		Securities Litigation Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.01 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.23*		ERISA Actions Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.02 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.24*		Shareholder Derivative Action Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.03 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.25*+		Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.26*+		Compensation and reimbursement practices for Xcel Energy non-employee directors (Exhibit 10.26 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.27*+		Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2005 (Exhibit 10.27 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.28*+		Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.28 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.29*+		Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.29 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.30*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.30 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.31*+		Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.31 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.32*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.32 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.33*		Facilities Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (KV) line. (Exhibit 5.06I to File No. 2-54310).
10.34*		Transactions Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06J to File No. 2-54310).
10.35*		Coordinating Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06K to File No. 2-54310).

SCHEDULE II

NSP-MINNESOTA
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Years Ended Dec. 31, 2004, 2003 and 2002

			Additions
	Balance at beginning of period		Charged to costs & expenses		Charged to other accounts		Deductions from reserves(1)		Balance at end of period
	(Thousands of dollars)
Reserve deducted from related assets:
Provision for uncollectible accounts:
2004	$	7,581	$	15,688	$	4,077	$	19,501	$	7,845
2003	$	5,812	$	11,762	$	4,066	$	14,059	$	7,581
2002	$	5,452	$	8,028	$	4,197	$	11,865	$	5,812

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

Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the Act by Registrants which have not registered securities in pursuant to Section 12 of the Act.

NSP-Minnesota has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

KV		Kilovolts
KW		Kilowatts
Kwh		Kilowatt hours
MMBtu		One million BTUs
MW		Megawatts (one MW equals one thousand KW)
Mwh		Megawatt hour. One Mwh equals one thousand Kwh.
Watt		A measure of power production or usage equal to the kinetic energy of an object with a mass of 2 kilograms moving with a velocity of one meter per second for one second.

Conductor Miles
500 kilovolt (KV)		2,919
345 KV		5,653
230 KV		1,442
161 KV		298
115 KV		6,278
Less than 115 KV		79,534

(Thousands of dollars) Quarter Ended
March 31, 2004		June 30, 2004		Sept. 30, 2004		Dec. 31, 2004
$	52,294	$	53,598	$	53,289	$	53,033

PART I
Item 1 — Business
DEFINITIONS
COMPANY OVERVIEW
ELECTRIC UTILITY OPERATIONS
Summary of Recent Regulatory Developments
General Electric Utility Pending Regulatory Matters
Ratemaking Principles
Capacity and Demand
Energy Sources
Fuel Supply and Costs
Trading Operations
Nuclear Power Operations and Waste Disposal
Electric Operating Statistics
NATURAL GAS UTILITY OPERATIONS
Summary of Recent Regulatory Developments
Ratemaking Principles
Capability and Demand
Natural Gas Supply and Costs
Natural Gas Operating Statistics
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 of Financial Condition and Results of Operations
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Item 8 — Financial Statements and Supplementary Data
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A — Controls and Procedures
Item 9B — Other Information

PART III
Item 10 — Directors and Executive Officers of the Registrant
Item 11 — Executive Compensation
Item 12 — Security Ownership of Certain Beneficial Owners and Management
Item 13 — Certain Relationships and Related Transactions
Item 14 — Principal Accounting Fees and Services

PART IV
Item 15 — Exhibits, Financial Statement Schedules

SIGNATURES

/S/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 3, 2005

10.36*		Ownership and Operating Agreement, dated March 11, 1982, between Northern States Power Co. (a Minnesota corporation), 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 (file no. 001-03034) for the quarter ended Sept. 30, 1994).
10.37*		Power Agreement, dated June 14, 1984, between Northern States Power Co. (a Minnesota corporation) 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 (file no. 001-03034) for the quarter ended Sept. 30, 1994).
10.38*		Power Agreement, dated August 1988, between Northern States Power Co. (a Minnesota corporation) and Minnkota Power Co. (Exhibit 10.08 to Form 10-K (file no. 001-03034) for the year 1988).
10.39*		Assignment and Assumption Agreement, dated Aug. 18, 2000 between Northern States Power Co. (a Minnesota corporation) and Xcel Energy Inc. (Exhibit 10.08 to Form 10 (file no. 000-31709) dated Oct. 5, 2000)
10.40*		Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly known as Norenco Corp.) and Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.33 to NRG’s Registration on Form S-1, file no. 333-35096).
10.41*		Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.42*		Operations and maintenance agreement dated Nov. 1, 1996 between NRG Energy and Northern States Power Co. (a Minnesota corporation). (Exhibit 10.34 to NRG’s Registration on Form S-1, File No. 333-35096).
10.43*		Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.36 to NRG’s Registration on Form S-1, File No. 333-35096).
10.44*		500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated March 25, 2003).
12.01		Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01		Consent of Independent Registered Public Accounting Firm.
31.01		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

	NORTHERN STATES POWER COMPANY

	/s/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III Vice President and Chief Financial Officer (Principal Financial Officer)

March 3, 2005

/s/ WAYNE H. BRUNETTI		/s/ RICHARD C. KELLY
Wayne H. Brunetti Chief Executive Officer and Chairman (Principal Executive Officer)		Richard C. Kelly President, Chief Operating Officer and Director (Principal Operating Officer)

/s/ GARY R. JOHNSON		/s/ TERESA S. MADDEN
Gary R. Johnson Vice President, General Counsel and Director		Teresa S. Madden Vice President and Controller (Principal Accounting Officer)

/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III Vice President and Chief Financial Officer (Principal Financial Officer)

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

COMPANY OVERVIEW

ELECTRIC UTILITY OPERATIONS

Summary of Recent Federal Regulatory Developments

Nuclear Power Operations and Waste Disposal - NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 12 to the Consolidated Financial Statements.

NSP-Minnesota Electric Operating Statistics

Summary of Recent Regulatory Developments

EMPLOYEES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Projected Benefit Payments

Types of and Accounting for Derivative Instruments

Cash Flow Hedges

Letters of Credit

Manufactured Gas Plant Site

SCHEDULE II