10-K

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 001-03140

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

Wisconsin	39-0508315
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
1414 W. Hamilton Avenue
Eau Claire, Wisconsin 54701
(Address of principal executive offices)
(Zip Code)
(715) 839-2625
(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:  None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  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, 933,000 shares of common stock, par value $100 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).

INDEX

General Electric Utility Pending Regulatory Matters

This Form 10-K is filed by Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin). NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the U.S. Securities and Exchange Commission (SEC).  This report should be read in its entirety.

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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
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
MPSC	Michigan Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Wisconsin’s operations in Michigan.
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.
PSCW	Public Service Commission of Wisconsin. The state agency that regulates the retail rates, services, securities issuances and other aspects of NSP-Wisconsin’s operations in Wisconsin.
WDNR	Wisconsin Department of Natural Resources
SEC	Securities and Exchange Commission
Fuel, Purchased Gas and Resource Adjustment Clauses
PGA	Purchased gas adjustment or gas cost recovery mechanism. A clause included in NSP-Wisconsin’s retail natural gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas and natural gas transportation. The difference between the natural gas costs collected through PGA rates and the actual natural gas costs is collected or refunded over subsequent billing periods.
GCR	Gas Cost Recovery Mechanism. See PGA.
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.

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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
FIN No. 46	FASB Interpretation No. 46(R) – Consolidation of Variable Interest Entities (revised December 2003)-an interpretation of ARB 51
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).
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.
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
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.

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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)
KV	Kilovolts
KW	Kilowatts
Kwh	Kilowatt hours
Mcf	Thousand cubic feet
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.

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COMPANY OVERVIEW

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility primarily engaged in the generation, purchase, transmission, distribution and sale of electricity to approximately 240,000 customers in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan.  NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory to approximately 97,000 customers.

The electric production and transmission system of NSP-Wisconsin is managed as an integrated system with that of NSP-Minnesota, 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-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.  NSP-Wisconsin 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-Wisconsin, that serve electric and natural gas customers in 10 states. The other utility subsidiaries are NSP-Minnesota, 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-Wisconsin 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.  In 2002, NSP-Wisconsin began providing its Michigan electric customers with the opportunity to select an alternative electric energy provider.  To date, no NSP-Wisconsin customers have selected an alternative electric energy provider.  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 is expected to occur in any of the retail jurisdictions in which NSP-Wisconsin 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

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lower cost region.  While NSP-Wisconsin 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-Wisconsin.  State and local agencies have jurisdiction over many of NSP-Wisconsin’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-Wisconsin have been required to submit analyses demonstrating that they did not have market power in the relevant markets.  NSP-Wisconsin 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-Wisconsin 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-Wisconsin 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-Wisconsin for investigation and hearing under Section 206 of the Federal Power Act.  At that time, NSP-Wisconsin expects to submit a delivered-price test analysis to support the continuance of market-based rate authority in their control areas.  NSP-Wisconsin 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.

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.

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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-Wisconsin 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-Wisconsin 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-Wisconsin. 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-Wisconsin’s tariff and the MISO regional tariff, which will govern most generation interconnections to the NSP-Wisconsin’s transmission system.  In October 2004, the FERC accepted proposed tariff changes for NSP-Wisconsin, subject to certain conditions.  In November 2004, NSP-Wisconsin submitted a compliance filing.  In December 2004, the FERC issued further modifications to the interconnection rules on rehearing and required NSP-Wisconsin 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-Wisconsin’s operations are subject to regulation by the PSCW and the MPSC, within their respective states.  In addition, each of the state commissions certifies the need for new generating plants and electric and retail gas transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built.  NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices.

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

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers.  Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates. If the comparison results in a difference outside a prescribed range, the PSCW may hold hearings limited to fuel costs and revise rates upward or downward. Any revised rates would remain in effect until the next rate change. The adjustment approved is calculated on an annual basis, but applied prospectively.  NSP-Wisconsin’s wholesale electric rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

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

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.

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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-Wisconsin, 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-Wisconsin does not believe the outcome of the appeals will have a material financial impact.  In addition, various parties, including NSP-Wisconsin, have documented their concerns to MISO regarding MISO’s readiness to initiate the new energy market on March 1, 2005.  On Jan. 27, 2005, the MISO management announced a delay in the market start date until April 1, 2005.

NSP-Wisconsin opposes certain aspects of the TEMT as proposed, and believes the MISO should implement the new market mechanisms only after it demonstrates that it will protect reliability.  NSP-Wisconsin cannot at this time estimate the total financial impact of the new market structure.  NSP-Wisconsin also cannot predict at this time whether the numerous remaining issues will be resolved in time to allow the MISO market to commence on April 1, 2005, as proposed.

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 increase actual costs allocated to NSP-Wisconsin by approximately $11 million per year.

Pending and Recently Concluded Regulatory Proceedings - PSCW

NSP-Wisconsin 2004 Fuel Cost Recovery- Potential Rate Reduction Proceeding- On Aug. 2, 2004 the PSCW issued an order to reopen NSP-Wisconsin’s 2004 rate case.  In its decision, the PSCW ordered NSP-Wisconsin’s 2004 rates be made subject to refund pending a full review and final determination of the reasonableness of electric fuel costs.  On Jan. 18, 2005, the PSCW issued an order closing the docket with no adjustment to NSP-Wisconsin’s 2004 electric rates, after their review showed NSP-Wisconsin was

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expected to be within the allowed 2 percent electric fuel cost bandwidth at the end of 2004.  At year end, actual fuel costs exceeded the amount included in base rates by $4.0 million, largely due to higher than forecast costs in November and December 2004.

NSP-Wisconsin 2005 Fuel Cost Recovery Filing—On Aug. 2, 2004, NSP-Wisconsin filed an application with the PSCW to reopen its 2004 rate case for the limited purpose of resetting 2005 electric fuel monitoring costs, and to authorize an increase in Wisconsin retail electric rates to recover forecast increases in fuel and wholesale market purchased energy costs.  In its August application, NSP-Wisconsin indicated an increase of $17.3 million was necessary to avoid under-recovering its 2005 fuel costs based on the most recent forecast.  On Dec. 29, 2004, the PSCW issued a final order in the case, authorizing an annual increase of $18.6 million effective Jan. 1, 2005 and resetting the 2005 electric fuel monitoring costs.  Because the PSCW used updated market prices for natural gas, oil and purchased power to forecast 2005 costs, the amount of the increase authorized was greater than initially requested by NSP-Wisconsin.

MISO Cost Recovery – In 2005, NSP-Wisconsin filed a petition along with other Wisconsin utilities seeking deferred accounting treatment for net costs of MISO Day 2 energy market implementation, similar to relief already granted to Wisconsin Public Service Company in their most recent rate case.  In addition, the utilities requested that the PSCW begin the process to change their fuel and energy cost recovery rules to accommodate MISO Day 2 charges.

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 — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and nonregulated energy suppliers. Capacity, typically measured 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.

On behalf of the NSP System, 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, portions of which are filed by NSP-Wisconsin with the PSCW.  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;

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•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 in early 2005 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 megawatts 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 DOC has requested an extension to June 1, 2005 to file comments on the overall resource plan.  NSP-Minnesota did not object to this request.

Purchased Transmission Services — NSP-Wisconsin and NSP-Minnesota 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.

Fuel Supply and Costs

For the NSP System, 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.

NSP System	Coal*				Nuclear				Average Fuel
Generating Plants	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 maintain between 30 and 50 days of coal inventory at each plant site. Estimated coal requirements at NSP-Wisconsin’s coal-fired generating plants are approximately 350,000 tons per year.  The NSP System has 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.

The NSP System uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers.  Natural gas supplies for power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.  Current fuel oil inventory is adequate to meet anticipated 2005 requirements and the NSP-System also has access to the spot market to buy more oil, if needed.

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NSP-Wisconsin Electric Operating Statistics

	Year Ended Dec. 31,
	2004			2003			2002
Electric sales (Millions of Kwh):
Residential	1,844			1,884			1,874
Commercial and industrial	4,031			3,937			3,846
Public authorities and other	39			40			40
Total retail	5,914			5,861			5,760
Sales for resale	565			567			564
Total energy sold	6,479			6,428			6,324
Number of customers at end of period:
Residential	203,433			199,293			196,701
Commercial and industrial	35,464			34,653			34,224
Public authorities and other	1,128			1,098			1,107
Total retail	240,025			235,044			232,032
Wholesale	10			10			10
Total customers	240,035			235,054			232,042
Electric revenues (Thousands of dollars):
Residential	$	139,360		$	141,261		$	142,104
Commercial and industrial	213,262			209,286			207,979
Public authorities and other	5,321			5,340			5,387
Total retail	357,943			355,887			355,470
Wholesale	22,568			22,030			20,404
Sales to NSP-Minnesota	96,016			92,814			80,200
Other electric revenues	2,673			3,096			2,663
Total electric revenues	$	479,200		$	473,827		$	458,737
Kwh sales per retail customer	24,639			24,936			24,824
Revenue per retail customer	$	1,491.27		$	1,514.13		$	1,531.99
Residential revenue per Kwh	7.56		¢	7.50		¢	7.58		¢
Commercial and industrial revenue per Kwh	5.29		¢	5.32		¢	5.41		¢
Wholesale revenue per Kwh	3.99		¢	3.89		¢	3.62		¢

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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-Wisconsin 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 90 Dth per year to 81 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

Summary of Regulatory Agencies and Areas of Jurisdiction —NSP-Wisconsin is subject to retail rate and other regulation by the PSCW and the MPSC.  In addition, each of the state commissions certifies the need for new retail gas transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built.

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

Natural Gas Cost Recovery Mechanisms —NSP-Wisconsin has a retail gas cost recovery mechanism for Wisconsin operations to recover changes in the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds the utility was not prudent in its procurement activities.

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

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-Wisconsin was 153,423 MMBtu for 2004, which occurred on Jan. 29, 2004.

NSP-Wisconsin 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 124,492 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 21 percent of winter natural gas requirements and 31 percent of peak day, firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity

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equivalent to 18,408 MMBtu of natural gas per day, or approximately 14 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-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2004-2005 supply plan was approved by the PSCW in October 2004.

Natural Gas Supply and Costs

NSP-Wisconsin 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-Wisconsin’s regulated retail natural gas distribution business:

2004	$	7.00
2003	$	6.23
2002	$	4.63

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

NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2005 through 2013.

NSP-Wisconsin 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-Wisconsin was committed to approximately $129 million in such obligations under these contracts.

NSP-Wisconsin purchased 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-Wisconsin to maintain competition from suppliers and minimize supply costs.

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NSP-Wisconsin Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2004		2003		2002
Natural gas deliveries (Thousands of Dth):
Residential	6,618		6,986		6,720
Commercial and industrial	8,366		8,805		10,044
Other	1,067		1,170		722
Total retail	16,051		16,961		17,486
Transportation and other	4,378		4,375		3,196
Total deliveries	20,429		21,336		20,682
Number of customers at end of period:
Residential	85,888		83,587		81,252
Commercial and industrial	11,549		11,283		11,140
Total retail	97,437		94,870		92,392
Transportation and other	26		22		5
Total customers	97,463		94,892		92,397
Natural gas revenues (Thousands of dollars):
Residential	$	65,657	$	63,091	$	49,426
Commercial and industrial	67,256		63,748		52,223
Total retail	132,913		126,839		101,649
Transportation and other	1,715		1,280		494
Total natural gas revenues	$	134,628	$	128,119	$	102,143
Dth sales per retail customer	164.73		178.78		189.26
Revenue per retail customer	$	1,364.09	$	1,336.98	$	1,100.19
Residential revenue per Dth	$	9.92	$	9.03	$	7.36
Commercial and industrial revenue per Dth	$	8.04	$	7.24	$	5.20
Transportation and other revenue per Dth	$	0.39	$	0.29	$	0.15

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ENVIRONMENTAL MATTERS

Certain of NSP-Wisconsin 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-Wisconsin 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-Wisconsin 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 its operations. For more information on environmental contingencies, see Note 9 to the Consolidated Financial Statements and the matter discussed below.

EMPLOYEES

The number of full-time NSP-Wisconsin employees on Dec. 31, 2004 was 536. Of these full-time employees, 414, or 77 percent, are covered under collective bargaining agreements. See Note 5 to the Consolidated Financial Statements for further discussion. Xcel Energy Services Inc., a subsidiary of Xcel Energy, employees provide services to NSP-Wisconsin.

Item 2 — Properties

Virtually all of the utility plant of NSP-Wisconsin 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)
Combustion Turbine:
Flambeau Station — Park Falls, Wis. 1 Unit	Natural Gas/Oil	1969	13
Wheaton — Eau Claire, Wis. 6 Units	Natural Gas/Oil	1973	353
French Island — La Crosse, Wis. 2 Units	Oil	1974	147
Steam:
Bay Front — Ashland, Wis. 3 Units	Coal/Wood/Natural Gas	1945 - 1960	73
French Island — La Crosse, Wis. 2 Units	Wood/RDF*	1940 - 1948	29
Hydro:
19 Plants		Various	254
Total			869

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

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2004:

Conductor Miles

345 KV	1,312
161 KV	1,494
115 KV	1,528
Less than 115 KV	31,336

NSP-Wisconsin had 207 electric utility transmission and distribution substations at Dec. 31, 2004.

Natural gas utility mains at Dec. 31, 2004:

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Miles

Transmission	—
Distribution	2,051

Item 3 — Legal Proceedings

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

Stray Voltage

On Nov. 13, 2001, Ralph and Karline Schmidt filed a complaint in Clark County, Wisconsin against NSP-Wisconsin. Plaintiffs allege that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, property damage and seek compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1.0 million and pre-verdict interest of $1.2 million.  In addition, plaintiffs allege an unspecified amount of damages related to nuisance.  NSP-Wisconsin has sought summary judgment on several bases; including statute of limitations; filed rate doctrine; public policy; and failure to state claims for strict products liability, nuisance, treble damages and pre-verdict interest.  The motion is set for hearing on March 4, 2005.  A final pretrial hearing has been scheduled for April 1, 2005, at which time a trial date is expected to be determined.

On Nov. 13, 2001, August C. Heeg Jr. and Joanne Heeg filed a complaint in Clark County, Wisconsin against NSP-Wisconsin. Plaintiffs allege that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, property damage and seek compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1.9 million and pre-verdict interest of $6.1 million.  In addition, plaintiffs allege an unspecified amount of damages related to nuisance.  On Feb. 7, 2005, the trial court granted NSP-Wisconsin’s motion for summary judgment based upon the statute of limitations.

On March 1, 2002, NSP-Wisconsin was served with a lawsuit commenced by James and Grace Gumz and Michael and Susan Gumz in Marathon County Circuit Court, Wisconsin, alleging that electricity supplied by NSP-Wisconsin harmed their dairy herd and caused them personal injury.  In 2004, the trial court granted partial summary judgment to NSP-Wisconsin, dismissing plaintiff’s claims for strict products liability, trespass, pre-verdict interest, personal injury and treble damage claims.  As a result of these rulings and some modifications by the plaintiffs in their damage calculations, the plaintiffs’ alleged compensatory damages have been reduced to approximately $901,000 and an unspecified amount for nuisance.  Trial began in February 2005, in Wausau, Wisconsin.

Personal Injury

On Jan. 16, 2003, NSP-Wisconsin was served with a lawsuit commenced by George and Diane Grosjean in the Circuit Court for Ashland County, Wis.  Mr. Grosjean alleged that in connection with his employment for the City of Ashland he was exposed to contaminants present at or near NSP-Wisconsin’s former MGP site located in Ashland, Wis.  The lawsuit was resolved on a confidential basis in the third quarter of 2004 without any material impact to NSP-Wisconsin.

Manufactured Gas Plant Insurance Coverage Litigation

In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire, and LaCrosse, Wis. In lieu of participating in discussions, on Oct. 28, 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court. On Nov. 12, 2003, NSP-Wisconsin commenced suit in Wisconsin state circuit court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Wisconsin court denied the insurers’ motion to stay the Wisconsin case pending resolution of the Minnesota action.  On Jan. 6, 2005, the Minnesota court issued an injunction prohibiting NSP-Wisconsin from prosecuting the Wisconsin action.  No trial date has been set in either proceeding. The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers, therefore, these lawsuits should not have an impact on shareholders, and no accruals have been made.

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Other Matters

For more discussion of legal claims and environmental proceedings, see Note 9 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-Wisconsin is a wholly owned subsidiary of Xcel Energy and there is no market for its common equity securities.

NSP-Wisconsin has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends NSP-Wisconsin can pay to Xcel Energy. These restrictions include, but may not be limited to:

•maintenance of an equity ratio of 52 percent to 57 percent; and

•payment of dividends only from retained earnings.

The dividends declared during 2004 and 2003 were as follows:

Quarter Ended (thousands of dollars)
March 31, 2004		June 30, 2004		Sept. 30, 2004		Dec. 31, 2004
$	12,291	$	12,352	$	12,205	$	11,961
March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003
$	12,455	$	12,683	$	12,712	$	12,563

Item 6 — Selected Financial Data

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

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Forward Looking Information

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions. Actual results may vary materially. Factors

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that could cause actual results to differ materially include, but are not limited to:

•general economic conditions, including the availability of credit and its impact on capital expenditures and the ability to obtain financing on favorable terms;

•rating agency actions;

•business conditions in the energy industry;

•competitive factors including the extent and timing of the entry of additional competition;

•unusual weather;

•changes in federal or state legislation;

•geopolitical events, including war and acts of terrorism;

•regulation; and

•the other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including Exhibit 99.01 to this Annual Report on Form 10-K for the year ended Dec. 31, 2004.

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

Results of Operations

NSP-Wisconsin’s net income was approximately $54.4 million for 2004, compared with approximately $57.5 million for 2003.

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

	Total Electric Utility
	2004			2003
	(Millions of dollars)
Electric utility revenue	$	479		$	474
Electric fuel and purchased power	(217		)	(225		)
Gross margin before operating expenses	$	262		$	249
Margin as a percentage of revenue	54.7		%	52.5		%

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
Sales growth (excluding weather impact)	$	7.8
Estimated impact of weather	(4.8		)
Fuel cost recovery	(1.0		)
Interchange Agreement billing with NSP-Minnesota	3.2
Wholesale and other	0.2
Total base electric revenue increase	$	5.4

Base Electric Margin

(Millions of dollars)	2004 vs 2003
Interchange Agreement — prior period fixed charge adjustment	$	19.2
Fuel cost recovery	(10.3		)
Sales growth (excluding weather impact)	5.7
Estimated impact of weather	(3.5		)
Wholesale and other	2.0
Total base electric margin increase	$	13.1

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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	$	134.6		$	128.1
Cost of natural gas sold and transported	(104.1		)	(96.5		)
Natural gas utility margin	$	30.5		$	31.6

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	$	7.6
Estimated impact of weather on firm sales volume	(0.7		)
Sales growth (excluding weather impact)	(0.5		)
Transportation and other	0.1
Total natural gas revenue increase	$	6.5

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
Estimated impact of weather on firm sales volume	$	(0.7	)
Sales growth (excluding weather impact)	(0.5		)
Transportation and other	0.1
Total natural gas margin decrease	$	(1.1	)

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
Higher information technology costs	$	2.0
Higher reliability costs	2.0
Higher legal settlement costs	1.5
Higher employee benefit costs	1.3
Higher environmental and gas clean-up costs	1.0
Higher public benefit payments	0.6
Storm repair assistance costs, which are reimbursed	0.5
Higher interchange expense with NSP-Minnesota (see Note 12)	0.4
Higher governmental affairs costs	0.4
Higher costs related to Sarbanes-Oxley and audit fees	0.2
Higher power plant related costs	0.2
Lower compensation costs	(3.0		)
Other	2.0
Total other utility operating and maintenance expense increase	$	9.1

Depreciation and amortization expense increased by approximately $0.2 million, or 0.4 percent, for 2004 compared with 2003.

Taxes (other than income taxes) increased by approximately $0.3 million, or 2.0 percent, for 2004 compared with 2003, primarily due to higher gross receipts tax for calendar year 2004.

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Other income for 2004 increased by approximately $0.4 million, compared with 2003, largely due to higher allowance for funds used during construction related to the difference in rates between the FERC and the PSCW.

Interest charges and financing costs for 2004 decreased by approximately $1.8 million, or 8.0 percent, compared with 2003, primarily due to the long-term debt refinancing in October 2003 at a lower coupon rate.

Income tax expense increased by approximately $8.2 million in 2004 compared with 2003.  The effective tax rate was 39.3 percent for the period ended Dec. 31, 2004, compared with 32.0 percent for the same period in 2003.  The increase was primarily due to additional tax benefits recorded in 2003.  The income tax expense recorded in 2003 included approximately $5 million in tax benefits to reflect the resolution of various audit issues related to prior years.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, NSP-Wisconsin 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-Wisconsin, are discussed in further detail below.

Commodity Price Risk — NSP-Wisconsin 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-Wisconsin’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulation.

See Note 7 to the Consolidated Financial Statements for a discussion of the hedging contracts of NSP-Wisconsin.

Interest Rate Risk — NSP-Wisconsin is subject to the risk of fluctuating interest rates in the normal course of business.  NSP-Wisconsin’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.

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

Credit Risk — In addition to the risks discussed previously, NSP-Wisconsin 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-Wisconsin maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

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

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Item 8 — Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Northern States Power Company—Wisconsin

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northern States Power Company—Wisconsin (a Wisconsin corporation) and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, stockholder’s equity and other comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2004. Our audit also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company—Wisconsin and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 3, 2005

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NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended Dec. 31,
	2004			2003			2002
	(Thousands of dollars)
Operating revenues:
Electric utility	$	479,200		$	473,827		$	458,737
Natural gas utility	134,628			128,119			102,143
Other	667			225			761
Total operating revenues	614,495			602,171			561,641
Operating expenses:
Electric fuel and purchased power	217,468			225,208			212,180
Cost of natural gas sold and transported	104,056			96,529			72,260
Operating and maintenance expenses	120,880			111,756			103,171
Depreciation and amortization	47,020			46,815			44,466
Taxes (other than income taxes)	16,792			16,456			16,066
Total operating expenses	506,216			496,764			448,143
Operating income	108,279			105,407			113,498
Other income:
Interest and other income, net of nonoperating expenses (see Note 6)	100			322			276
Allowance for funds used during construction - equity	2,005			1,375			641
Total other income	2,105			1,697			917
Interest charges and financing costs:
Interest charges — including financing costs of $1,225, $968 and $896, respectively	21,871			23,249			23,467
Allowance for funds used during construction - debt	(1,087		)	(651		)	(350		)
Total interest charges and financing costs	20,784			22,598			23,117
Income before income taxes	89,600			84,506			91,298
Income taxes	35,215			27,036			36,925
Net income	$	54,385		$	57,470		$	54,373

See Notes to Consolidated Financial Statements

23

NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended Dec. 31,
	2004			2003			2002
	(Thousands of dollars)
Operating activities:
Net income	$	54,385		$	57,470		$	54,373
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	48,363			48,072			45,641
Deferred income taxes	6,395			7,122			21,682
Amortization of investment tax credits	(789		)	(791		)	(808		)
Allowance for equity funds used during construction	(2,005		)	(1,375		)	(641		)
Undistributed equity in (earnings)/losses of unconsolidated affiliates	10			(21		)	(232		)
Changes in accounts receivable	(8,492		)	5,358			(14,473		)
Change in inventories	(436		)	(3,551		)	(1,213		)
Change in other current assets	(3,070		)	(3,258		)	2,213
Change in accounts payable	5,984			125			15,889
Change in other current liabilities	4,059			(5,165		)	(2,923		)
Change in other assets	(6,813		)	(5,309		)	(22,331		)
Change in other liabilities	(3,266		)	(2,912		)	11,786
Net cash provided by operating activities	94,325			95,765			108,963
Investing activities:
Utility capital/construction expenditures	(57,705		)	(57,071		)	(38,414		)
Allowance for equity funds used during construction	2,005			1,375			641
Other investments	89			(149		)	240
Net cash used in investing activities	(55,611		)	(55,845		)	(37,533		)
Financing activities:
Borrowings from (payments to) affiliates	8,490			16,830			(27,420		)
Proceeds from issuance of long-term debt	(167		)	146,080			—
Repayment of long-term debt	(34		)	(153,158		)	(34		)
Capital contribution from parent	1,820			476			3,210
Dividends paid to parent	(49,412		)	(50,109		)	(47,118		)
Net cash used in financing activities	(39,303		)	(39,881		)	(71,362		)
Net increase (decrease) in cash and cash equivalents	(589		)	39			68
Net increase in cash and cash equivalents — adoption of FIN No. 46	683			—			—
Cash and cash equivalents at beginning of year	137			98			30
Cash and cash equivalents at end of year	$	231		$	137		$	98
Supplemental disclosure of cash flow information
Cash paid for interest (net of amounts capitalized)	$	19,560		$	22,186		$	21,399
Cash paid for income taxes (net of refunds received)	$	25,598		$	23,320		$	13,456

See Notes to Consolidated Financial Statements

24

NSP-WISCONSIN

CONSOLIDATED BALANCE SHEETS

	Dec. 31, 2004			Dec. 31, 2003
	(Thousands of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	231		$	137
Accounts receivable — net of allowance for bad debts: $1,258 and $1,212, respectively	51,380			42,603
Accounts receivable from affiliates	1,154			1,389
Accrued unbilled revenues	27,665			21,522
Material and supplies inventories — at average cost	4,709			5,274
Fuel inventory — at average cost	6,295			4,962
Natural gas inventory — at average cost	9,246			9,578
Current deferred income taxes	2,678			3,430
Prepaid taxes	13,471			17,082
Derivative instruments valuation — at market	1,405			307
Prepayments and other	3,029			3,570
Total current assets	121,263			109,854
Property, plant and equipment, at cost:
Electric utility plant	1,232,525			1,189,122
Natural gas utility plant	146,749			138,767
Common and other plant	96,346			85,639
Construction work in progress	20,153			31,428
Total property, plant and equipment	1,495,773			1,444,956
Less accumulated depreciation	(575,099		)	(543,768		)
Net property, plant and equipment	920,674			901,188
Other assets:
Other investments	7,800			9,989
Regulatory assets	50,760			50,049
Prepaid pension asset	52,272			46,384
Other	7,660			7,407
Total other assets	118,492			113,829
Total assets	$	1,160,429		$	1,124,871
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	34		$	34
Notes payable to affiliate	32,200			23,710
Accounts payable	26,993			23,586
Accounts payable to affiliates	9,568			6,910
Accrued interest	4,265			4,266
Accrued payroll and benefits	5,318			5,431
Dividends payable to parent	11,961			12,563
Derivative instruments valuation — at market	1,060			—
Other	9,640			6,245
Total current liabilities	101,039			82,745
Deferred credits and other liabilities:
Deferred income taxes	166,765			158,972
Deferred investment tax credits	13,237			14,027
Regulatory liabilities	91,403			87,180
Customer advances for construction	16,912			18,015
Benefit obligations and other	22,952			25,371
Total deferred credits and other liabilities	311,269			303,565
Minority interest in subsidiaries	100			—
Long-term debt	315,398			313,410
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares	93,300			93,300
Premium on common stock	65,277			63,457
Retained earnings	275,092			269,516
Accumulated other comprehensive loss	(1,046		)	(1,122		)
Total common stockholder’s equity	432,623			425,151
Commitments and contingencies (see Note 9)
Total liabilities and equity	$	1,160,429		$	1,124,871

See Notes to Consolidated Financial Statements

25

NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND OTHER COMPREHENSIVE INCOME (LOSS)

	Common Stock			Premium on Common		Retained			Accumulated Other Comprehensive			Total Stockholder’s
	Shares	Amount		Stock		Earnings			Income (Loss)			Equity
	(Thousands of dollars, except share information)
Balance at Dec. 31, 2001	933,000	$	93,300	$	59,771	$	256,476		$	(1	)	$	409,546
Net income						54,373						54,373
Unrealized loss — marketable securities, net of tax of $0									(1		)	(1		)
Comprehensive income for 2002												54,372
Common dividends declared to parent						(48,390		)				(48,390		)
Contribution of capital by parent				3,210								3,210
Balance at Dec. 31, 2002	933,000	$	93,300	$	62,981	$	262,459		$	(2	)	$	418,738
Net income						57,470						57,470
Net derivative instrument fair value changes during the period, net of tax of $751									(1,122		)	(1,122		)
Unrealized gain — marketable securities, net of tax of $0									2			2
Comprehensive income for 2003												56,350
Common dividends declared to parent						(50,413		)				(50,413		)
Contribution of capital by parent				476								476
Balance at Dec. 31, 2003	933,000	$	93,300	$	63,457	$	269,516		$	(1,122	)	$	425,151
Net income						54,385						54,385
Net derivative instrument fair value changes during the period, net of tax of $51									76			76
Comprehensive income for 2004												54,461
Common dividends declared to parent						(48,809		)				(48,809		)
Contribution of capital by parent				1,820								1,820
Balance at Dec. 31, 2004	933,000	$	93,300	$	65,277	$	275,092		$	(1,046	)	$	432,623

See Notes to Consolidated Financial Statements

26

NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF CAPITALIZATION

	Dec. 31,
	2004			2003
	(Thousands of dollars)
Long-Term Debt
First Mortgage Bonds Series due:
Oct. 1, 2018, 5.25%	$	150,000		$	150,000
Dec. 1, 2026, 7.375%	65,000			65,000
City of La Crosse Resource Recovery Bond — Series due Nov. 1, 2021, 6%	18,600(a		)	18,600(a		)
Fort McCoy System Acquisition — due Oct. 31, 2030, 7%	862			895
Senior Notes due Oct. 1, 2008, 7.64%	80,000			80,000
Other	1,955			—
Unamortized discount	(985		)	(1,051		)
Total	315,432			313,444
Less current maturities	34			34
Total NSP-Wisconsin long-term debt	$	315,398		$	313,410
Common Stockholder’s Equity
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares in 2004 and 2003	$	93,300		$	93,300
Capital in excess of par value on common stock	65,277			63,457
Retained earnings	275,092			269,516
Other comprehensive loss	(1,046		)	(1,122		)
Total common stockholder’s equity	$	432,623		$	425,151

(a) Resource recovery financing

See Notes to Consolidated Financial Statements

27

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts— NSP-Wisconsin is principally engaged in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. NSP-Wisconsin is subject to the regulatory provisions of the PUHCA and regulation by the FERC and state utility commissions. All of NSP-Wisconsin’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-Wisconsin consolidates one subsidiary for which all significant intercompany transactions and balances are eliminated.  NSP-Wisconsin has subsidiaries for which the equity method of accounting is used, and it records its portion of earnings from such investments after subtracting income taxes.

In 2004, NSP-Wisconsin began consolidating the financial statements of a subsidiary in which it has a controlling financial interest, pursuant to the requirements of FIN No. 46.  Historically, consolidation has been required only for subsidiaries in which an enterprise has a majority voting interest.  As a result, NSP-Wisconsin is required to consolidate a portion of its affordable housing investments, which for periods prior to 2004 are accounted for under the equity method.  As of Jan. 1, 2004, the assets of the affordable housing investments consolidated as a result of FIN No. 46, as revised, were approximately $5 million and long-term liabilities were approximately $2 million, primarily long-term debt.  The long-term debt is collateralized by the affordable housing projects and is nonrecourse to NSP-Wisconsin.

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

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

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

Derivative Financial Instruments — NSP-Wisconsin utilizes a variety of derivatives, including interest rate swaps and locks and physical and financial commodity based contracts, to reduce exposure to corresponding risks. These contracts consist mainly of options, index or fixed price swaps and basis swaps. For further discussion of NSP-Wisconsin’s risk management and derivative activities, see Note 7 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-Wisconsin determines the depreciation of their plant by using the straight-line method, which spreads the original cost equally

28

over the plant’s useful life. Depreciation expense for NSP-Wisconsin, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2004, 2003 and 2002 is 3.3 percent, 3.3 percent and 3.3 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-Wisconsin’s rate base for establishing utility service rates.

Environmental Costs— Environmental costs are recorded when it is probable NSP-Wisconsin 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.

                                                                                                                                                       0;                                              

Legal Costs – Litigation settlements are recorded when it is probable NSP-Wisconsin 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-Wisconsin, 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-Wisconsin 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 10 to the Consolidated Financial Statements. For more information on income taxes, see Note 4 to the Consolidated Financial Statements.

Use of Estimates— In recording transactions and balances resulting from business operations, NSP-Wisconsin use 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-Wisconsin 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.

Inventory— All inventories are recorded at average cost.

Regulatory Accounting— NSP-Wisconsin 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

29

•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-Wisconsin 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-Wisconsin’s results of operations in the period the write-off is recorded.  See more discussion of regulatory assets and liabilities at Note 10 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-Wisconsin’s deferred financing costs, net of amortization at Dec. 31, 2004, 2003 and 2002 are $2.0 million, $2.1 million, and $1.7 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.

2.Short-Term Borrowings

Notes Payable— NSP-Wisconsin has an intercompany borrowing arrangement with NSP-Minnesota, with interest charged at NSP-Minnesota’s short-term borrowing rate. At Dec. 31, 2004 and 2003, NSP-Wisconsin had $32.2 million and $23.7 million, respectively, in short-term borrowings related to this intercompany arrangement. The weighted average interest rate for NSP-Wisconsin was 5.20 percent at Dec. 31, 2004.

Money Pool — In 2003, Xcel Energy established a money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals.  The money pool would allow 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 would not allow loans from the utility subsidiaries to the holding company.  On Jan. 18, 2005, NSP-Wisconsin submitted a letter to the PSCW withdrawing its request for approval to participate in the money pool arrangement after it became apparent the conditions likely to be imposed by the PSCW would have limited flexibility and reduced the economic benefits of NSP-Wisconsin’s participation.

3.Long-Term Debt

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

NSP-Wisconsin’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-Wisconsin had no sinking fund requirements for current bonds outstanding.

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

2005	$	—
2006	1
2007	—
2008	80
2009	—

4.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	5.1	%	5.0	%	5.7	%
Life insurance policies	—		(0.1	)%	(0.1	)%
Tax credits recognized	(1.1	)%	(0.9	)%	(0.9	)%
Regulatory differences — utility plant items	(0.6	)%	(1.0	)%	0.6	%
Resolution of income tax audits	1.2	%	(6.1	)%	—
Other — net	(0.3	)%	0.1	%	0.1	%
Effective income tax rate	39.3	%	32.0	%	40.4	%

30

Income taxes comprise the following expense (benefit) items:

	2004			2003			2002
	(Thousands of dollars):
Current federal tax expense	$	21,413		$	17,140		$	13,143
Current state tax expense	8,339			3,565			2,907
Current tax credits	(143		)	—			—
Deferred federal tax expense	7,128			5,276			16,569
Deferred state tax expense (benefit)	(733		)	1,846			5,113
Deferred investment tax credits	(789		)	(791		)	(807		)
Total income tax expense	$	35,215		$	27,036		$	36,925

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

	2004			2003
	(Thousands of dollars)
Deferred tax expense excluding items below	$	8,546		$	6,219
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(2,098		)	152
Tax expense allocated to other comprehensive income and other	(53		)	751
Deferred tax expense	$	6,395		$	7,122

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	$	143,609	$	132,086
Employee benefits	16,995		14,190
Regulatory assets	18,203		22,910
Other	5,783		5,737
Total deferred tax liabilities	$	184,590	$	174,923
Deferred tax assets:
Deferred investment tax credits	$	5,309	$	5,624
Regulatory liabilities	4,903		4,561
Tax credit carryforward	1,203		—
Other	9,087		9,196
Total deferred tax assets	$	20,502	$	19,381
Net deferred tax liability	$	164,088	$	155,542

5. Benefit Plans and Other Postretirement Benefits

Xcel Energy offers various benefit plans to its benefit employees, including those of NSP-Wisconsin.  Approximately 51 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2004, NSP-Wisconsin had 414 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-Wisconsin.  Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.

31

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-Wisconsin prepaid pension asset recorded	$	52,272		$	46,384
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		%

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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-Wisconsin
Net periodic pension credit	$	(5,888	)	$	(7,827	)	$	(9,994	)
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.

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Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for NSP-Wisconsin were approximately $0.8 million in 2004, $0.7 million in 2003 and $0.7 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 NSP who retired after 1998 are eligible to participate in the Xcel Energy health care program with no employer subsidy.

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

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106.

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 and 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:

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(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-Wisconsin accrued benefit liability recorded	$	4,603		$	4,605
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-Wisconsin:

(Millions of dollars)
1-percent increase in APBO components at Dec. 31, 2004	$	4.3
1-percent decrease in APBO components at Dec. 31, 2004	(3.5		)
1-percent increase in service and interest components of the net periodic cost	0.3
1-percent decrease in service and interest components of the net periodic cost	(0.2		)

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

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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-Wisconsin
Net periodic postretirement benefit cost recognized – SFAS No. 106	$		2,394		$		2,522		$		1,531
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

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6. 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	$	573		$	583		$	1,087
Other nonoperating income	140			159			4
Gain (Loss) on disposal of assets	7			(10		)	(415		)
Interest expense on corporate-owned life insurance and other employee-related insurance policies	(613		)	(410		)	(400		)
Other nonoperating expense	(7		)	—			—
Total interest and other income, net of nonoperating expenses	$	100		$	322		$	276

7. Derivative Instruments

In the normal course of business, NSP-Wisconsin 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-Wisconsin 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-Wisconsin 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-Wisconsin 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-Wisconsin’s risk management policy allows it to manage market price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulation.

Interest Rate Risk — NSP-Wisconsin is subject to the risk of fluctuating interest rates in the normal course of business.  NSP-Wisconsin’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.

Types of and Accounting for Derivative Instruments

NSP-Wisconsin uses a number of different derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options.  All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, as amended, are recorded at fair value. The classification of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship.  The fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings.  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-Wisconsin 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-Wisconsin 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, hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs and hedging transactions for interest rate swaps and lock agreements are recorded as a component of interest expense.  NSP-Wisconsin is allowed to recover in natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility.

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

Interest Rate Cash Flow Hedges — NSP-Wisconsin enters intointerest rate lock agreements, including treasury-rate locks and forward starting swaps, that effectively fix the yield or price on a specified treasury security for a specific period.  These derivative instruments are designated as cash flow hedges for accounting purposes.

As of Dec. 31, 2004, NSP-Wisconsin had net losses of $0.1 million accumulated in Other Comprehensive Income that it expects to recognize in earnings during the next 12 month.

NSP-Wisconsin had no ineffectiveness related to interest rate 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-Wisconsin’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	$	—
After-tax net unrealized gains related to derivatives accounted for as hedges	—
After-tax net realized gains on derivative transactions reclassified into earnings	—
Accumulated other comprehensive income related hedges at Dec. 31, 2002	$	—
After-tax net unrealized losses related to derivative accounted for as hedges	(1.1		)
After-tax net realized gains on derivative transactions reclassified into earnings	—
Accumulated other comprehensive loss related to hedges at Dec. 31, 2003	$	(1.1	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—
After-tax net realized losses on derivative transactions reclassified into earnings	0.1
Accumulated other comprehensive loss related to hedges at Dec. 31, 2004	$	(1.0	)

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 a derivative instrument to offset, in the same period, the gains and losses of the hedged item.  The

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ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings. At Dec. 31, 2004, NSP-Wisconsin had no fair value hedges.

Normal Purchases or Normal Sales Contracts

NSP-Wisconsin 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.

NSP-Wisconsin 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.

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 $(1.1) million and $0.2 million, respectively.

For a further discussion of other financial instruments at NSP-Wisconsin, see Note 8 to the Consolidated Financial Statements.

8. Financial Instruments

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

	2004				2003
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	315,432	$	328,892	$	313,444	$	339,165

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 value of NSP - Wisconsin'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-Wisconsin provides a guarantee that guarantees payment or performance under a specified agreement.  As a result, NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the specified agreement.  The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee.  The guarantee requires no liability to be recorded, contains no recourse provisions and requires no collateral.  On Dec. 31, 2004, NSP-Wisconsin had the following guarantee and exposure related to that guarantee:

(Millions of dollars) Nature of Guarantee	Guarantor	Guarantee Amount		Current Exposure		Term or Expiration Date	Triggering Event Requiring Performance		Assets Held as Collateral
NSP-Wisconsin guarantees customer loans to encourage business growth and expansion	NSP-Wisconsin	$	0.4	$	0.4	Latest expiration in 2006		(a)	N/A

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(a)Non-timely payment of the obligations or at the time the Debtor becomes the subject of bankruptcy or other insolvency proceedings

Letters of Credit

NSP-Wisconsin may use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2004, there were no letters of credit outstanding.

9. Commitments and Contingent Liabilities

Leases— NSP-Wisconsin 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 $3.5 million, $3.8 million and $4.8 million for 2004, 2003 and 2002, respectively.

Expected operating lease expenses are:

2005		2006		2007		2008		2009
(Millions of dollars)
$	3.7	$	3.7	$	3.7	$	3.7	$	3.7

Fuel Contracts— NSP-Wisconsin has contracts providing for the purchase and delivery of a significant portion of its current natural gas requirements. These contracts expire in various years between 2005 and 2012. In addition, NSP-Wisconsin is required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss for NSP-Wisconsin 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-Wisconsin under these contracts as of Dec. 31, 2004, is as follows:

Natural Gas Supply		Gas Storage & Transportation
(Millions of dollars)
$	90	$	39

Plant Removal Costs - NSP-Wisconsin records a regulatory liability for plant removal costs for generation, transmission and distribution facilities.  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.  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, NSP-Wisconsin has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.  Removal costs as of Dec. 31, 2004 and 2003 are $81 million and $75 million, respectively.

Joint Operating System - The electric production and transmission system of NSP-Wisconsin is managed as an integrated system with that of NSP-Minnesota, 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 system, including capital costs.  Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is legally limited to $10.8 billion.  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.

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NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs with coverage limits of $2.1 billion for each of NSP-Minnesota’s two nuclear plant sites.  The insurance 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, subject to retroactive premium adjustments if losses exceed accumulated reserve funds.  Capital has been accumulated in the insurance reserve funds 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.

Environmental Contingencies

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

•sites of former manufactured gas plants (MGP’s) operated by NSP-Wisconsin or its 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-Wisconsin records a liability when there is enough information to develop an estimate of the cost of remediating a site and revise the estimate as information is received. The estimated remediation cost may vary materially.

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

Estimates are revised as facts become known, but at Dec. 31, 2004, NSP-Wisconsin estimated its liability for the cost of remediating sites was $17.9 million, of which $3.0 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-Wisconsin has recorded estimates of its future costs for these sites.

Manufactured Gas Plant Sites

Ashland MGP Site — NSP-Wisconsin was named a PRP for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin, which was previously an MGP facility, and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior’s Chequemegon Bay adjoining the park.

As an interim action, Xcel Energy proposed, and the Wisconsin Department of Natural Resources (WDNR) approved, a coal tar removal and groundwater treatment system for one area of concern at the site for which NSP-Wisconsin has accepted responsibility. The groundwater treatment system began operating in the fall of 2000. In 2002, NSP-Wisconsin installed additional monitoring wells in the deep aquifer under the former MGP site to better characterize the extent and degree of contaminants in that aquifer while the coal tar removal system is operational.  In 2002, a second interim response action was also implemented.  As approved by the WDNR,

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this interim response action involved the removal and capping of a seep area in a city park.  Surface soils in the area of the seep were contaminated with tar residues.  The interim action also included the diversion and ongoing treatment of groundwater that contributed to the formation of the seep.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL).  The NPL is intended primarily to guide the EPA in determining which sites require further investigation.  On Nov. 14, 2003, the EPA and NSP-Wisconsin signed an administrative order on consent requiring NSP-Wisconsin to complete the remedial investigation and feasibility study for the site.  On Dec. 7, 2004, the EPA approved NSP-Wisconsin’s proposed work plan with minor contingencies to complete the remedial investigation and feasibility study.  On Feb. 1, 2005, NSP-Wisconsin submitted its revised work plan to the EPA addressing all of the contingencies raised with the previous proposal.  The final approval results in specific delineation of the investigative fieldwork and scientific assessments that must be performed.  The estimated cost of carrying out the work plan is $1.3 million in 2005.  Resolution of Ashland remediation issues is not currently expected until 2007 or 2008.  NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.

The WDNR and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The EPA and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility for the ultimate cost of remediating the Ashland site is not determinable.  On July 2, 2004, the WDNR sent NSP-Wisconsin an invoice for recovery of past costs incurred at the Ashland site between 1994 and March 2003 in the amount of $1.4 million.  On Oct. 19, 2004, the WDNR, represented by the Wisconsin Department of Justice, filed a lawsuit in Wisconsin state court for reimbursement of the past costs.  This lawsuit has been stayed until further action by either party.  NSP-Wisconsin is reviewing the invoice to determine whether all costs charged are appropriate. All appropriate insurance carriers have been notified of the WDNR’s invoice and the lawsuit and will be invited to participate in any future efforts to address the WDNR’s actions.  All costs paid are expected to be recoverable in rates.

NSP-Wisconsin has recorded a liability of $17.3 million for its estimate of its share of the cost of remediating the Ashland site, using information available to date and reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the remediation costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed as part of the Wisconsin biennial retail rate case process for prudence. Once approved by the PSCW, deferred MGP remediation costs, less carrying costs, are historically amortized over four or six years. In addition, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers.

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-Wisconsin to perform additional environmental studies at 2 power plants in Wisconsin 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. Based on the limited information available, total capital costs to NSP-Wisconsin are estimated at approximately $1 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.

Industrial Boiler Maximum Achievable Control Technology Standards - On Sept. 13, 2004, the EPA published final maximum achievable control technology (MACT) standards for hazardous air pollutants from industrial boilers.  Two boilers at the Bay Front plant must comply with this rule by September 2007 because they are categorized as non-fossil fuel-fired utility boilers and electric

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utility steam generating units less than 25 megawatts.  The rule regulates hydrogen chloride, particulate matter, mercury and opacity.  NSP-Wisconsin is reviewing the rule to determine its options for compliance at Bay Front.  If new environmental control equipment is required, the cost of capital improvements needed to comply with the new standard is estimated to be approximately $10 million.

Plant Emissions — In October 2000, the EPA reversed a prior decision and found that the French Island plant, an NSP-Wisconsin facility that burns a fuel derived from solid waste, was subject to the federal large combustor regulations. On March 29, 2001, the EPA issued a finding of violation to NSP-Wisconsin. On April 2, 2001, a conservation group also sent NSP-Wisconsin a notice of intent to sue under the citizen suit provisions of the Clean Air Act. On Oct. 20, 2003, the U.S. District Court entered a consent decree settling the EPA’s claims against us related to the French Island plant. Pursuant to the terms of that consent decree, NSP-Wisconsin paid a penalty of $500,000. Under the consent decree, the court retains jurisdiction over the plant for several years to monitor compliance with the emission limits and other requirements contained in the decree. Installation of the emission control equipment has been completed and source tests confirm that the plant is now in compliance with the state and federal dioxin standards. NSP-Wisconsin has reached an agreement with La Crosse County through which La Crosse County, the source of the plant’s refuse derived fuel, will pay for the emissions equipment through increased waste disposal fees.

The French Island plant is required to conduct annual emissions performance tests to meet federal requirements for large municipal waste combustors. In April 2004, the annual test on one boiler was completed. In June 2004, NSP-Wisconsin received the test results, which indicated that all parameters tested, with the exception of hydrochloric acid (HCl), were below allowable levels. NSP-Wisconsin retested the unit later in June 2004 and found results that suggested that chemical interference of ammonium chloride may have caused an inaccurate result during the April test. Based on the results of the retesting, NSP-Wisconsin believes there is strong evidence to indicate the plant never exceeded the HCl limit. Under the terms of a consent decree between NSP-Wisconsin and the EPA, a failure to meet specified emission limits, including HCl, allows the EPA to pursue penalties. NSP-Wisconsin is unsure of future EPA action or penalty assessment, but pursuant to the consent order, any penalty is unlikely to exceed $300,000.

Legal Contingencies

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

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-Wisconsin 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-Wisconsin.  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-Wisconsin is closely monitoring the issue from both scientific and policy perspectives.  While it is not possible to know the eventual outcome, NSP-Wisconsin 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-Wisconsin, 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-Wisconsin also is involved in other projects to improve available methods for managing carbon.

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10. Regulatory Assets and Liabilities

NSP-Wisconsin’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-Wisconsin are:

(Thousands of dollars)	See note	Remaining amortization period	2004		2003
Regulatory Assets:
Environmental costs	1	To be determined	$	24,970	$	25,332
Losses on reacquired debt		Term of related debt	12,637		13,604
AFDC recorded in plant (a)		Plant lives	8,226		7,224
State commission accounting adjustments (a)		Plant lives	3,238		2,771
Other		Various	1,636		860
Conservation programs		To be determined	53		258
Total regulatory assets			$	50,760	$	50,049
Regulatory Liabilities:
Plant removal costs	9		$	80,954	$	75,415
Investment tax credit deferrals			8,866		9,389
Deferred income tax adjustments			732		1,305
Interest on income tax refunds			352		603
Fuel costs, refunds and other			499		468
Total regulatory liabilities			$	91,403	$	87,180

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

11. Segment and Related Information

NSP-Wisconsin has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility.

•NSP-Wisconsin’s Regulated Electric Utility generates, transmits and distributes electricity in Wisconsin and Michigan. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities primarily in Wisconsin.

•NSP-Wisconsin’s Regulated Natural Gas Utility transports, stores and distributes natural gas in portions of Wisconsin and Michigan.

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category.  Those primarily include investments in rental housing projects that qualify for low-income housing tax credits.

To report net income for Regulated Electric and Regulated Natural Gas Utility segments, NSP-Wisconsin must assign or allocate all costs and certain other income. In general, costs are:

•    directly assigned wherever applicable;

•    allocated based on cost causation allocators wherever applicable; or

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

The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements.

In 2003, the process to allocate common costs of the Regulated Electric and Regulated Natural Gas Utility segments was revised. Segment results for 2002 have been restated to reflect the revised cost allocation process.

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	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
	(Thousands of dollars)
2004
Operating revenues from external customers	$	479,200	$	134,628	$	667		$	—		$	614,495
Intersegment revenues	131		4,007		—			(4,138		)	—
Total revenues	479,331		138,635		667			(4,138		)	614,495
Depreciation and amortization	40,823		6,033		164			—			47,020
Financing costs, mainly interest expense	17,885		2,268		631			—			20,784
Income tax expense (benefit)	33,439		1,910		(134		)	—			35,215
Segment net income (loss)	$	51,808	$	3,162	$	(585	)	$	—		$	54,385
2003
Operating revenues from external customers	$	473,827	$	128,119	$	225		$	—		$	602,171
Intersegment revenues	151		3,573		—			(3,724		)	—
Total revenues	473,978		131,692		225			(3,724		)	602,171
Depreciation and amortization	40,620		6,195		—			—			46,815
Financing costs, mainly interest expense	18,826		3,772		—			—			22,598
Income tax expense	25,841		1,195		—			—			27,036
Segment net income (loss)	$	53,737	$	4,549	$	(816	)	$	—		$	57,470
2002
Operating revenues from external customers	$	458,737	$	102,143	$	761		$	—		$	561,641
Intersegment revenues	166		808		—			(974		)	—
Total revenues	458,903		102,951		761			(974		)	561,641
Depreciation and amortization	39,030		5,390		46			—			44,466
Financing costs, mainly interest expense	20,780		2,337		—			—			23,117
Income tax expense	33,799		3,126		—			—			36,925
Segment net income (loss)	$	49,341	$	5,545	$	(513	)	$	—		$	54,373

12. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including NSP-Wisconsin. 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.

Utility Engineering Corp., an Xcel Energy subsidiary, provided construction services to NSP-Wisconsin, for which it was paid $0.5 million in 2004, $0.6 million in 2003 and $1.9 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. In 2004, an adjustment was made for $9.8 million, which lowered 2003 costs of NSP - Minnesota shared with NSP - Wisconsin, pursuant to the Interchange Agreement.

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	$	96,016	$	92,814	$	80,200
Operating expenses:
Purchased power	220,165		227,946		220,674
Natural gas purchased for resale	303		474		458
Other operations – paid to Xcel Energy Services Inc.	51,370		43,570		36,695

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

	2004				2003
	Accounts		Accounts		Accounts		Accounts
(Thousands of dollars)	Receivable		Payable		Receivable		Payable
NSP-Minnesota	$	—	$	2,826	$	329	$	—
PSCo	—		54		883		—
SPS	7		—		—		36
Other subsidiaries of Xcel Energy Inc.	1,147		6,688		177		6,874
	$	1,154	$	9,568	$	1,389	$	6,910

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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-Wisconsin had notes payable outstanding to NSP-Minnesota in the amount of $31.5 million.  Interest expense on NSP-Wisconsin’s statement of income was $0.3 million, $0.1 million, and $0.2 million for 2004, 2003, and 2002.

Clearwater Investments Inc., a NSP-Wisconsin subsidiary, also had notes payable outstanding as of Dec. 31, 2004 to Xcel Energy, in the amount of $0.7 million.

13. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31, 2004		June 30, 2004		Sept. 30, 2004(a)		Dec. 31, 2004
	(Thousands of dollars)
Revenue	$	181,488	$	126,758	$	135,495	$	170,754
Operating income	36,768		14,436		33,765		23,310
Net income	19,214		6,410		17,652		11,109
	Quarter Ended
	March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003
	(Thousands of dollars)
Revenue	$	185,027	$	124,343	$	138,593	$	154,208
Operating income	38,909		13,179		26,138		27,181
Net income	19,854		4,847		12,279		20,490

(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.

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-Wisconsin on accounting principles or practices, financial disclosures or audit scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

NSP-Wisconsin 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-Wisconsin’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-Wisconsin’s internal control over financial reporting has occurred during NSP-Wisconsin’s most recent fiscal quarter that has materially affected, or is reasonably likely to affect, NSP-Wisconsin’s internal control over financial reporting.

Item 9B — Other Information

None

PART III

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

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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

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2005 Annual Meeting of Shareholders, which is incorporated by reference.

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

3.01*	Amended and restated articles of incorporation of NSP-Wisconsin (Exhibit 3.01 to Form S-4 (file no. 333-112033) Jan. 21, 2004).
3.02*	By-Laws of NSP-Wisconsin as amended Dec. 6, 2001 (Exhibit 3.02 to Form Form S-4 (file no. 333-112033) Jan. 21, 2004).
4.01*	Trust Indenture, dated April 1, 1947, From NSP-Wisconsin to Firstar Trust Company (formerly First Wisconsin Trust Company). (Exhibit 7.01 to Registration Statement 2-6982).
4.02*	Supplemental Trust Indenture dated March 1, 1949. (Exhibit 7.02 to Registration Statement 2-7825).
4.03*	Supplemental Trust Indenture dated June 1, 1957. (Exhibit 2.13 to Registration Statement 2-13463).
4.04*	Supplemental Trust Indenture dated Aug. 1, 1964. (Exhibit 4.20 to Registration Statement 2-23726).
4.05*	Supplemental Trust Indenture dated Dec. 1, 1969. (Exhibit 2.03E to Registration Statement 2-36693).
4.06*	Supplemental Trust Indenture dated Sept. 1, 1973. (Exhibit 2.03F to Registration Statement 2-49757).
4.07*	Supplemental Trust Indenture dated Feb. 1, 1982. (Exhibit 4.01G to Registration Statement 2-76146).
4.08*	Supplemental Trust Indenture dated March 1, 1982. (Exhibit 4.08 to Form 10-K (file no. 001-03140) for the year 1982).
4.09*	Supplemental Trust Indenture dated June 1, 1986. (Exhibit 4.09 to Form 10-K (file no. 001-03140) for the year 1986).
4.10*	Supplemental Trust Indenture dated March 1, 1988. (Exhibit 4.10 to Form 10-K (file no. 001-03140) for the year 1988).
4.11*	Supplemental and Restated Trust Indenture dated March 1, 1991. (Exhibit 4.01K to Registration Statement 33-39831).
4.12*	Supplemental Trust Indenture dated April 1, 1991. (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).
4.13*	Supplemental Trust Indenture dated March 1, 1993. (Exhibit to Form 8-K (file no. 001-03140) dated March 3, 1993).
4.14*	Supplemental Trust Indenture dated Oct. 1, 1993. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 21, 1993).

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4.15*	Supplemental Trust Indenture dated Dec. 1, 1996. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
4.16*	Trust Indenture dated Sept. 1, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).
4.17*	Supplemental Trust Indenture dated Sept. 15, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee, creating $80 million principal amount of 7.64 percent Senior Notes, Series due 2008. (Exhibit 4.02 to Form 8-K (file no 001-03140) dated Sept. 25, 2000).
4.18*	Supplemental Trust Indenture dated Sept. 1, 2003 between Northern States Power Co. (a Wisconsin corporation) and US Bank N.A., supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.19*	Exchange and Registration Rights Agreement dated Oct. 2, 2003 among Northern States Power Co. (a Wisconsin corporation) and Goldman, Sachs, & Co. and BNY Capital Markets, Inc. (Exhibit 4.92 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 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).

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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*	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 Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
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.

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SCHEDULE II

NSP-WISCONSIN

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	$	1,212	$	1,937	$	1,294	$	3,185	$	1,258
2003	$	1,373	$	2,227	$	724	$	3,112	$	1,212
2002	$	969	$	2,036	$	1,083	$	2,715	$	1,373

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

50

SIGNATURES

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

	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

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

/s/ MICHAEL L. SWENSON	/s/ WAYNE H. BRUNETTI
Michael L. Swenson	Wayne H. Brunetti
President, Chief Executive Officer and Director	Chairman and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN	/s/ GARY R. JOHNSON
Teresa S. Madden	Gary R. Johnson
Vice President and Controller	Vice President, General Counsel and Director
(Principal Accounting Officer)
/s/ RICHARD C. KELLY	/s/ PATRICIA K. VINCENT
Richard C. Kelly	Patricia K. Vincent
Vice President and Director	Vice President and Director
/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer
(Principal Financial Officer)

51

EX-12.01

Exhibit 12.01

NORTHERN STATES POWER COMPANY — WISCONSIN

COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS

TO CONSOLIDATED FIXED CHARGES

	YEAR ENDED DEC. 31,
	2004			2003		2002		2001		2000
	(IN THOUSANDS, EXCEPT RATIOS)
EARNINGS:
Net income	$	54,385		$	57,470	$	54,373	$	36,392	$	30,296
Provisions for Federal and state taxes on income	35,215			27,036		36,925		21,158		20,690
Fixed charges as below	21,871			23,249		23,467		23,139		21,557
Less: Undistributed equity in earnings of unconsolidated affiliates	(10		)	21		232		553		411
Total	$	111,481		$	107,734	$	114,533	$	80,136	$	72,132
FIXED CHARGES:
Interest charges, excluding AFUDC – debt	$	21,871		$	23,249	$	23,467	$	23,139	$	21,557
Distributions on redeemable preferred securities of subsidiary trust	—			—		—		—		—
Total	$	21,871		$	23,249	$	23,467	$	23,139	$	21,557
RATIO OF EARNINGS TO FIXED CHARGES	5.1			4.6		4.9		3.5		3.3

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EX-31.01

Exhibit 31.01

CERTIFICATION

I, Michael L. Swenson, certify that:

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

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

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

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

a)designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

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

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial data; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ MICHAEL L. SWENSON
	Michael L. Swenson
	President and Chief Executive Officer
Date: March 3, 2005

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Benjamin G.S. Fowke III, certify that:

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

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

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

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

a)designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

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

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial data; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III
	Vice President and Chief Financial Officer
Date: March 3, 2005

1

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of NSP-Wisconsin on Form 10-K for the year 2004, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K), each of the undersigned officers of the NSP-Wisconsin certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1)The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of NSP-Wisconsin as of the dates and for the periods expressed in the Form 10-K.

Date: March 3, 2005

/s/ MICHAEL L. SWENSON

Michael L. Swenson

President and Chief Executive Officer

/s/ BENJAMIN G.S. FOWKE III

Benjamin G.S. Fowke III

Vice President and Chief Financial Officer

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NSP-Wisconsin and will be retained by NSP-Wisconsin and furnished to the Securities and Exchange Commission or its staff upon request.

1

EX-99.01

Exhibit 99.01

NSP-WISCONSIN CAUTIONARY FACTORS

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of NSP-Wisconsin. These statements are based on management’s beliefs as well as assumptions and information currently available to management. When used in NSP-Wisconsin’s documents or oral presentations, the words “anticipate,” “estimate,” “expect,” “projected,” objective,” “outlook,” “forecast,” “possible,” “potential” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause NSP-Wisconsin’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

•Economic conditions, including their impact on capital expenditures and the ability of NSP-Wisconsin to obtain financing on favorable terms, inflation rates and monetary fluctuations;

•Business conditions in the energy business;

•Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where NSP-Wisconsin has a financial interest;

•Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

•Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

•Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, NSP-Wisconsin; or security ratings;

•Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or natural gas pipeline constraints;

•Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

•Increased competition in the utility industry or additional competition in the markets served by NSP-Wisconsin;

•State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

•Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

•Social attitudes regarding the utility and power industries;

•Risks associated with the California power market;

•Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

•Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

•Significant slowdown in growth or decline in the U.S. economy, delay in growth or recovery of the U.S. economy or increased cost for insurance premiums, security and other items as a consequence of the Sept. 11, 2001 terrorist attacks;

•Risks associated with implementation of new technologies; and

•Other business or investment considerations that may be disclosed from time to time in NSP-Wisconsin’s SEC filings or in other publicly disseminated written documents.

NSP-Wisconsin undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exhaustive.

1