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, 2005

OR

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

		For the transition period from to

COMMISSION FILE NUMBER 000-31387

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

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

414 Nicollet Mall

Minneapolis, Minnesota 55401

(Address of principal executive offices)

(Zip Code)

(612) 330-5500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: Notes due July 1, 2042, 8%

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý

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 a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Act). o Large accelerated filer o Accelerated filer

ý Non-accelerated filer

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

As of Feb. 20, 2006, 1,000,000 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota Corporation.

DOCUMENTS INCORPORATED BY REFERENCE: Xcel Energy Inc.’s 2006 Proxy Statement

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

PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

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

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

*Fuel, Purchased Gas and Resource Adjustment Clauses*
FCA		Fuel clause adjustment. A clause included in NSP-Minnesota’s retail electric rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of electric fuel and purchased energy. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent three-month period.
PGA		Purchased gas adjustment. A clause included in NSP-Minnesota’s retail gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased gas. The annual difference between the gas costs collected through PGA rates and the actual gas costs is collected or refunded over the subsequent 12-month period.
RCR		Renewable cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities and other costs incurred to facilitate the purchase of renewable energy (including wind energy) in retail electric rates in Minnesota. The RCR is revised annually.

*Other Terms and Abbreviations*
AFDC		Allowance for funds used during construction. Defined in regulatory accounts as a non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ		Administrative law judge. A judge presiding over regulatory proceedings.
ARO		Asset Retirement Obligation.
C20		Derivatives Implementation Group of FASB Implementation Issue No. C20. Clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended.
Decommissioning		The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.
Deferred energy costs		The amount of fuel costs applicable to service rendered in one accounting period that will not be reflected in billings to customers until a subsequent accounting period.
Derivative instrument		A financial instrument or other contract with all three of the following characteristics: • An underlying and a notional amount or payment provision or both, • Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and • Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement
Distribution		The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
ERISA		Employee Retirement Income Security Act
FASB		Financial Accounting Standards Board
FTRs		Financial Transmission Rights
GAAP		Generally accepted accounting principles
Generation		The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
JOA		Joint operating agreement among the Utility Subsidiaries
LDC		Local distribution company. A company or division that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or natural gas for ultimate consumption.
LIBOR		London Interbank Offered Rate
LNG		Liquefied natural gas. Natural gas that has been converted to a liquid.
Mark-to-market		The process whereby an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in current earnings in the Consolidated Statements of Operations or in Other Comprehensive Income within equity during the current period.
MERP		Metropolitan emissions reduction project.
MGP		Manufactured gas plant.
MISO		Midwest Independent Transmission System Operator, Inc.
Native load		The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
Natural gas		A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
Nonutility		All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
OMOI		FERC Office of Market Oversight and Investigations

PFS		Private Fuel Storage, LLC. A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.
PJM		PJM Interconnection, Inc.
PUHCA		Public Utility Holding Company Act of 1935. Enacted to regulate the corporate structure and financial operations of utility holding companies.
QF		Qualifying facility. As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price equal to that which it would otherwise pay if it were to build its own power plant or buy power from another source.
Rate base		The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
ROE		Return on equity
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utility’s 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
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.

COMPANY OVERVIEW

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. Prior to 2000, the regulated utility operations were conducted by the legal entity now operating under the name Xcel Energy Inc. NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. NSP-Minnesota also purchases, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.3 million customers and gas utility service to approximately 457,000 customers.

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

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

Xcel Energy was incorporated under the laws of Minnesota. Historically, Xcel Energy has been a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). As a registered holding company, Xcel Energy, its utility subsidiaries and certain of its non-utility subsidiaries have been subject to extensive regulation by the SEC under PUHCA with respect to numerous matters, including issuances and sales of securities, acquisitions and sales of certain utility properties, payments of dividends out of capital and surplus, and intra-system sales of certain non-power goods and services. In addition, the PUHCA generally limited the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.

On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act), significantly changing many federal statutes and repealing PUHCA as of February 8, 2006. As part of the repeal of PUHCA, FERC was given more authority over the merger and acquisition of public utilities and more authority over the books and records of public utilities. Despite these increases in FERC’s authority, NSP-Minnesota believes that the repeal of PUHCA will lessen its regulatory burdens and give it more flexibility in the event it were to choose to expand its utility or non-utility businesses.

Besides repealing PUHCA, the Energy Act is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and DOE. FERC and DOE are in various stages of rulemaking in implementing the Energy Act. While the precise impact of these rulemakings cannot be determined at this time, NSP-Minnesota generally views the Energy Act as legislation that will enhance the utility industry going forward.

In 2005, Xcel Energy’s continuing operations included the activity of four wholly owned utility subsidiaries, including NSP-Minnesota, that serve electric and natural gas customers in 10 states. The other utility subsidiaries are NSP-Wisconsin, PSCo, and SPS. These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin.

ELECTRIC UTILITY OPERATIONS

Overview

Utility Industry Growth — NSP-Minnesota intends to focus on growing through investments in electric and natural gas rate base to meet growing customer demands and to maintain or increase reliability and quality of service to customers and through 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 has been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future. Beginning in the late 1990s, many states began studying or implementing some form of retail electric utility competition.

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

Summary of Recent Federal Regulatory Developments

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

FERC Rules Implementing Energy Act - As noted previously, the Energy Act repealed PUHCA effective Feb. 8, 2006. In addition, the Energy Act required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act. Since Aug. 2005, the FERC has completed or initiated the proceedings to modify its regulations on a number of subjects, including:

• Adopting new regulations to implement the Energy Act repeal of PUHCA by establishing rules for accounting procedures for holding company systems, including cost allocation rules for transactions between companies within a holding company system;

• Adopting new regulations to implement changes to the FERC’s merger and asset transfer authority under Section 203 of the Federal Power Act;

• Adopting new “market manipulation regulations” prohibiting any “manipulative or deceptive device or contrivance” in wholesale natural gas and electricity commodity and transportation or transmission markets and interpreting this standard in a manner consistent with Rule 10b-5 of the SEC; violations are subject to potential civil penalties of up to $1 million per day;

• Adopting regulations to establish a national Electric Reliability Organization (ERO) to replace the voluntary North American Electric Reliability Council (NERC) structure, and requiring the ERO to establish mandatory reliability standards and imposition of financial or other penalties for violations of adopted standards; NERC is expected to apply to become designated as the ERO later in 2006;

• Adopting rules to implement changes to the Public Regulatory Policy Act of 1978 (PURPA) to allow utility ownership of Qualifying Facilities (QFs) and strengthening the thermal energy requirements for entities seeking to be QFs;

• Proposing rules that would allow a utility to seek to eliminate its mandatory QF power purchase obligation for utilities in organized wholesale energy markets;

• Proposing rules to establish incentives for investment in new electric transmission infrastructure.

NSP-Minnesota generally supports the regulations adopted or proposed by FERC to date, but cannot predict the ultimate impact the new regulations will have on its operations or financial results.

Market-Based Rate Authority — The FERC regulates the wholesale sale of electricity. In order to obtain market-based rate authorization from the FERC, utilities such as NSP-Minnesota, are required to submit analyses demonstrating that they did not have market power in the relevant markets. NSP-Minnesota was previously granted market-based rate authority by the FERC. However, the FERC has subsequently modified its standards making it more difficult for utilities to demonstrate that they do not have market power and thus more difficult to obtain market-based rate authority, particularly in their own service territories.

On Feb. 7, 2005, Xcel Energy on behalf of itself and the utility subsidiaries filed an updated market-power analysis that applied FERC’s new standards. This analysis demonstrated that NSP-Minnesota passed the pivotal supplier analysis in its own control area and all adjacent markets, but 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.

In June 2005, the FERC initiated a proceeding regarding the market-based rate authority application. Because of the commencement of the MISO Day 2 market, discussed below, and the FERC’s decision consistent with other precedent to analyze NSP-Minnesota and NSP- Wisconsin as part of that larger market, FERC authorized continuation of NSP-Minnesota’s and NSP-Wisconsin’s market-based rate authority. However, the FERC required that Xcel Energy make a compliance filing providing information, including information regarding the FERC’s affiliate abuse component of its market power analysis and the allegations regarding that component made by an intervenor within 30 days of the date of issuance of its order. The latter compliance filing was submitted on July 5, 2005.

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

Centralized Regional Wholesale Markets – FERC rules require RTO’s to operate centralized regional wholesale energy markets. The FERC required the MISO to begin operation of a “Day 2” energy market on April 1, 2005. MISO uses security constrained regional economic dispatch and congestion management using locational marginal pricing (LMP) and FTR’s. The Day 2 market is intended to provide more efficient generation dispatch over the 15 state MISO region.

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion) and is a transmission-owner member of the MISO RTO.

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

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA that provides for monthly adjustments to billings and revenues for changes in prudently incurred cost of fuel, fuel related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms individually approved by the regulators in each jurisdiction. The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers. With NSP-Minnesota’s participation in the MISO Day 2 market, questions have been raised regarding the inclusion of certain MISO charges in the FCA. For further discussion, see NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings – MPUC. In general, capacity costs are not recovered through the FCA. NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.

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

Performance-Based Regulation — In December 2003, the MPUC voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. All three plants are located in the Minneapolis - St. Paul metropolitan area. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion. The MPUC also approved NSP-Minnesota’s proposal to recover prudent costs of the projects through a rate adjustment provision applicable to retail electric rates beginning Jan. 1, 2006, including a rate of return on the construction work in progress. The MPUC approval has a sliding ROE scale based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and a debt ratio of 51.5 percent) to incentivize NSP-Minnesota to control construction costs.

Actual Costs as a Percent of Target Costs	ROE
Less than or equal to 75%	11.47	%
Over 75% and up through 85%	11.22	%
Over 85% and up through 95%	11.00	%
Over 95% and up through 105%	10.86	%
Over 105% and up through 115%	10.55	%
Over 115% and up through 125%	10.22	%
Over 125%	9.97	%

Pending and Recently Concluded Regulatory Proceedings - FERC

MISO Operations —NSP-Minnesota is a member of the MISO. The MISO is an RTO that provides regional transmission tariff administration services for electric transmission systems, including those of NSP-Minnesota. In 2002, NSP-Minnesota 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 April 1, 2005, MISO initiated a regional wholesale energy market using LMP and FTR’s Day 2 market pursuant to its TEMT. While it is anticipated the Day 2 market will provide efficiencies through a region-wide generation dispatch and increased reliability, as well as long-term benefits through dispatch of power from the most cost-effective sources of generation or transmission, there are

costs associated with the Day 2 market. NSP-Minnesota has requested recovery of these costs within their respective jurisdictions. For further discussion, see Pending and Recently Concluded Regulatory Proceedings — MPUC.

Within MISO, an independent market monitor reviews market bids and prices to identify any unusual activity. The FERC has notified Xcel Energy that it is investigating pricing and market-related issues. Xcel Energy and other market participants continue to work with MISO, the independent market monitor and the FERC to resolve Day 2 market implementation issues such as dispatch methods and settlement calculation details. Xcel Energy also intends to work with these parties to resolve any identified issues.

New business processes, systems and internal controls over financial reporting were planned and implemented by Xcel Energy and MISO during the second quarter of 2005 to conduct business within the MISO Day 2 market. Xcel Energy continues to validate these changes and to review the energy costs and revenues determined by MISO. Xcel Energy and other market participants have disputed certain transactions.

MISO Long Term Transmission Pricing - On Oct. 7, 2005, MISO filed proposed tariff revisions that would allow MISO to regionalize the cost of certain future high voltage transmission lines owned by specific transmission owners but constructed pursuant to the MISO transmission expansion plan. The proposed tariffs reflect stakeholder input to MISO. MISO proposed the tariff revisions be effective on Feb. 4, 2006. Xcel Energy generally supports the proposed tariff revisions, which should encourage transmission construction by regionalizing a share of the cost of projects providing regional benefits. Comments on or protests to the proposed tariff revisions were filed at FERC in late 2005. In February 2006, the FERC issued an order accepting the tariff revisions, subject to modifications and additional procedures. Xcel Energy cannot predict the ultimate impact of the MISO tariff proposed at this time.

MISO/PJM SECA - 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 to compensate transmission owners for reductions in transmission revenues. FERC instead ordered the MISO and PJM to file a Seams Elimination Charge Adjustment (SECA) transition mechanism. The replacement compliance filings were effective Dec. 1, 2004. The FERC order eliminates any transition payments and the SECA filings instead provide for both revenues and payments that net to approximately $86,000 in revenues per month to NSP-Minnesota and NSP-Wisconsin in 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. The SECA proposals are now in hearings at the FERC. Certain parties have proposed a regional average transition charge, which could shift costs to NSP-Minnesota and NSP-Wisconsin, effective Dec. 1, 2004. Xcel Energy has opposed these regionalized approaches. The final FERC decision is expected to be issued by year-end 2006. Under the FERC orders, the SECA transition charges are set to expire Mar. 31, 2006.

Pending and Recently Concluded Regulatory Proceedings - MPUC

NSP-Minnesota Electric Rate Case – In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent. This increase was based on a requested 11 percent return on common equity, a projected common equity ratio to total capitalization of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006. The anticipated procedural schedule is as follows:

• March 2^nd – Intervenor Direct Testimony

• March 30^th – Rebuttal Testimony

• April 13^th – Surrebuttal Testimony

• April 20^th – April 28^th – Evidentiary Hearings

• May 24^th – Initial Briefs

• June 6^th – Reply Briefs

• July 6^th – Administrative Law Judge Report

• September 5^th – MPUC Order

Renewable Transmission Cost Recovery — In 2002, NSP-Minnesota filed for MPUC approval to establish an RCR adjustment mechanism to recover the costs of transmission investments incurred to deliver renewable energy resources. The RCR adjustment mechanism provides for annual filings to set the RCR adjustment rates using updated transmission cost information. The MPUC approved the RCR adjustment mechanism and the two-phase filing mechanism in April 2003. In February 2004, the MPUC conditionally approved the initial Phase 1 facility eligibility determination filing. NSP-Minnesota then filed for approval to recover annual additional transmission costs from May 2004 to December 2004, which were approximately $6 million. The request was approved and the RCR was implemented Dec. 1, 2004. NSP-Minnesota collected approximately $0.2 million in 2004. NSP-Minnesota submitted a filing in February 2005 to determine the eligibility of additional transmission projects and to establish the RCR factors for 2005, seeking recovery of $12.9 million of additional revenues in 2005. The MPUC approved revised factors by order dated Jan. 9, 2006, and NSP-Minnesota submitted its compliance filing in late January 2006 for rates to be effective Mar. 1, 2006. In

Oct. 2005, NSP-Minnesota revised the recoverable expense to $9.3 million, of which $5.4 million has been recovered. Because of the pending Minnesota rate case, the RCR rates in effect in 2006 will recover only the unrecovered 2005 costs of $3.9 million. All 2006 costs are proposed to be recovered in the Minnesota electric rate case discussed above.

MISO Cost Recovery — On Dec. 18, 2004, NSP-Minnesota filed with the MPUC a petition to seek recovery of the Minnesota jurisdictional portion of all net costs associated with the implementation of the MISO Day 2 market through its FCA. The MPUC issued an interim order in April 2005 allowing MISO Day 2 charges to be recovered through the NSP-Minnesota FCA mechanism, subject to refund. In December 2005, the MPUC issued a second interim order approving the recovery of certain MISO charges through the FCA mechanism but requiring that additional charges either be recovered as part of a general rate case or through an annual review process outside the FCA mechanism, and requiring refunds of non-FCA costs. The December 2005 MPUC order also suspended the refund obligation until such time as it could reconsider the matter, however. On Feb. 9, 2006, the MPUC voted to reconsider its December 2005 order. The MPUC on reconsideration determined that parties be directed to determine which charges are appropriately in the FCA and which are more appropriately established in base rates and report back to the MPUC in 60 days; to grant deferred accounting treatment for costs ultimately determined to be included in base rates for a period of 36 months, with recovery of deferred amounts to be reviewed in a general rate case; and that amounts collected to date through the FCA under the April and December 2005 interim orders are not subject to refund. As a result, NSP-Minnesota expects to have the opportunity to recover (or seek to recover in a rate case) all of its MISO Day 2 costs.

In addition, in March 2005, NSP-Minnesota filed petitions similar to the December 2004 Minnesota filing with the NDPSC and the SDPUC proposing changes to allow recovery of the applicable North Dakota and South Dakota jurisdictional portions of the MISO Day 2 market costs. The SDPUC approved the proposed tariff changes effective April 1, 2005, as requested. The NDPSC granted interim recovery through the FCA beginning April 1, 2005, but similar to the decision of the MPUC, conditioned the relief as being subject to refund until the merits of the case are determined. To date, the NDPSC has conducted no further proceedings regarding the NSP-Minnesota filing.

Energy Legislation — In 2005, Minnesota Legislature passed and the Governor signed an Omnibus Energy Bill, effective July 1, 2005. Among other things, the new law provides authority for the MPUC to approve rate rider recovery for transmission investments that have been approved through a certificate of need, the biennial transmission plan, or are associated with compliance with the state’s renewable energy objective. The statute provides that the rate rider may include recovery of the revenue requirement associated with qualifying projects, including a current return on construction work in progress. NSP-Minnesota is currently preparing a filing to the MPUC for approval of a new tariff to implement this statute.

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2006, assuming normal weather, are listed below.

	System Peak Demand (in MW)
	2003	2004	2005	2006 Forecast

NSP System	8,868	8,665	9,212	9,401

The peak demand for the NSP System typically occurs in the summer. The 2005 uninterrupted system peak demand for the NSP System occurred on June 23, 2005.

Energy Sources and Related Initiatives

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

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

NSP-Minnesota also makes short-term firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide the 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.

On Dec. 27, 2005, Excelsior Energy Inc. (Excelsior), an independent energy developer, filed a petition with the MPUC seeking to compel NSP-Minnesota to enter into a power purchase agreement related to its proposed integrated gasification, combined-cycle power plant (Mesaba project) that would be located in northern Minnesota. The petition requested the MPUC determine the proposed purchase is in the public interest and that the technology proposed for the Mesaba Project, which Excelsior claims is a “clean energy technology” under Minnesota law, is or is likely to be a least-cost resource pursuant to Minnesota law. NSP-Minnesota has not been provided a full, unredacted copy of the proposed power purchase agreement and has not entered into the power purchase agreement with Excelsior. The petition seeks to compel NSP-Minnesota to purchase at least 13 percent of NSP-Minnesota’s electric energy provided to retail customers from the Mesaba Project, which Excelsior claims would require two units of its Mesaba Project each proposed at 603 MW. Excelsior’s filing asserts much of its proposal is confidential under the MPUC’s rules, including the pricing and other economic terms. NSP-Minnesota is seeking access to the confidential information. The MPUC asked for comments on the process for the filing and comments on the ability to obtain information filed under confidential protection. NSP-Minnesota has asked the MPUC to first resolve issues surrounding the confidential information, then to address legal issues surrounding the proposal and after resolution of those issues, to consider the proposal in light of its legal conclusions.

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

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

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

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

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

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

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

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

On Aug. 1, 2005, the Minnesota Department of Commerce filed comments that NSP-Minnesota had overestimated its forecast and that there was no need for new resources until 2015. Other parties filed various comments relating to the environmental impacts of the plan, the use of renewable fuels, the need to construct a 600 MW integrated gasification combined-cycle facility in Northern Minnesota, and the NSP-Minnesota’s monitoring of the Northern Flood Agreement between the Province of Manitoba and various Canadian First Nations.

On Nov. 23, 2005, NSP-Minnesota filed updated analysis and replies with the MPUC. The updated analysis supported our original forecast and identified upgrades to certain existing facilities that could provide cost-effective base load energy to our customers and defer the need for new base load until 2015. Accompanying these comments was a report detailing our examination of new base load options. On the same day, the Minnesota Department of Commerce filed a proposal to select base load resources through a certificate of need process rather than a bidding process. We expect the MPUC to make a final ruling on the Resource Plan and the bidding process in the first half of 2006.

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

Purchased Transmission Services —NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO to deliver power and energy to NSP System native load customers. Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved. Network transmission services include a charge based on the transmission customer’s monthly peak demand.

Nuclear Power Operations and Waste Disposal - - NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the

Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 12 to the Consolidated Financial Statements.

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

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

High-Level Radioactive Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high level waste management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent Federal storage or disposal facility. To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel. See Item 3 — Legal Proceedings and Note 11 to the Consolidated Financial Statements for further discussion of this matter.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. In 1993, the Prairie Island plant was licensed by the federal NRC to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state. On May 29, 2003, the Minnesota Legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its current licenses with NRC expire in 2013 and 2014. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. It is estimated that operation through the end of the current license will require 12 additional storage casks to be stored at the plant, for a total of 29 casks. As of Dec. 31, 2005, there were 20 casks loaded and stored at the Prairie Island plant. See Note 11 in the Consolidated Financial Statements for further discussion of the matter.

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

Private Fuel Storage (PFS) — NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, PFS filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. The NRC license review process includes formal evidentiary hearings before the ASLB and opportunities for public input. On Sept. 9, 2005, the NRC Commissioners directed the NRC staff to issue the license for PFS, ending the 8-year effort to gain a license for the site. In December 2005, the U.S. Supreme Court denied Utah’s petition for a writ of certiorari to hear an appeal of a lower court’s ruling on a series of state statutes aimed at blocking the storage and transportation of spent fuel to PFS. Also in December 2005, NSP-Minnesota forwarded a letter to Senator Hatch (UT) indicating that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation’s spent nuclear fuel.

Prairie Island Steam Generator Replacement — In the fall of 2004, NSP-Minnesota spent approximately $132 million to successfully replace the Prairie Island Unit 1 steam generators. The Unit 2 steam generators have not yet been replaced but received the required inspections during the scheduled 2005 outage. Based on current rates of degradation and available repair processes, NSP-Minnesota plans to replace these steam generators in the 2013 regular refueling outage. Due to the potential shortages in the world markets for materials and shop capabilities, NSP-Minnesota expects to begin the approval process in 2006 for long-lead time materials.

NSP-Minnesota Nuclear Plant Re-licensing — Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014. In March 2005, NSP-Minnesota filed its application with the NRC for an operating license extension for Monticello of up to 20 years. NSP-Minnesota filed its application with the MPUC for Monticello in January 2005 seeking a certificate of need for dry spent fuel storage. Decisions by both the federal and state agencies regarding Monticello re-licensing are expected in early 2007. Prairie Island has initiated the necessary plant assessments and aging analysis to support submittal of similar applications to the NRC and Minnesota, currently planned for submittal in early 2008.

Nuclear Management Co. (NMC) — During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service

Corporation (WPS) and Alliant Energy Corp. established NMC. The Consumers Power subsidiary of CMS Energy Corp. joined the NMC during 2000.

NMC manages the operations and maintenance at the plants, and is responsible for physical security. NMC’s responsibilities also include oversight of on-site dry storage facilities for used nuclear fuel at the Prairie Island nuclear plant. Utility plant owners, including NSP-Minnesota, continue to own the plants, control all energy produced by the plants, and retain responsibility for nuclear liability insurance and decommissioning costs.

In 2005 and 2006, as a result of selling their nuclear plants, WPS and Alliant Energy ended thier participation in NMC. In December 2005, Consumer Power announced its intent to sell its nuclear plant, which will leave NSP-Minnesota and Wisconsin Electric Power Co. as the remaining members of the NMC, with a combined total of 3 sites and 5 reactors. NMC is in the process of identifying and marketing its services to other potential nuclear utility candidates to replace the departing members.

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

Fuel Supply and Costs

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

NSP System Generating Plants	Coal*				Nuclear				Natural Gas				Average Fuel Cost
NSP System Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent		Average Fuel Cost

2005	$	1.04	60	%	$	0.46	36	%	$	8.32	3	%	$	1.11
2004	$	0.99	61	%	$	0.44	37	%	$	6.48	2	%	$	0.92
2003	$	0.99	61	%	$	0.43	36	%	$	5.80	2	%	$	0.90

*Includes refuse-derived fuel and wood

See additional discussion of fuel supply and costs under Risks associated with Our Business under Item 1A.

Fuel Sources — Coal inventory levels may vary widely among plants. However, the NSP System normally maintains no less than 30 days of coal inventory at each plant site. Estimated coal requirements at NSP-Minnesota and NSP-Wisconsin’s major coal-fired generating plants are approximately 13.3 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 99 percent of 2006 coal 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 2006 will have an average sulfur content of less than 0.75 percent. The NSP System has contracts for a maximum of 35.8 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 in 2006 and 2007.

To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion and enrichment.

• Current nuclear fuel supply contracts cover 100 percent of uranium requirements through 2006 and 91.8 percent of the 2007 requirements with no coverage of requirements for 2008 and beyond. Contracts with additional uranium concentrates suppliers are currently in various stages of negotiation that are expected to provide a portion of the requirements through 2016.

• Current contracts for conversion services requirements cover 100 percent of the requirements for 2006 and 53 percent for 2007. Approximately 43 percent of the requirements are covered for 2008 through 2010 with no current coverage of requirements for 2011 and beyond. A contract with an additional conversion services supplier is nearing completion that is expected to provide additional coverage for 2007 through 2011.

• Current enrichment services contracts cover 100 percent of the 2006 requirements. Approximately 30 percent of the 2007 through 2010 requirements are currently covered with no coverage of requirements for 2011 and beyond. These current contracts expire at varying times between 2006 and 2010. Contracts with additional enrichment services suppliers are currently in various stages of negotiation that are expected to supply additional coverage from 2007 through 2010.

• Fuel fabrication for Monticello is covered through 2010. Fuel fabrication is 100 percent committed for Prairie Island Unit 1 through 2006 and Prairie Island Unit 2 is covered for the 2006 fuel fabrication services under an amendment signed in 2005. NSP-Minnesota and NMC are currently in negotiations with Westinghouse to pursue fuel fabrication for Prairie Island plant needs beyond the current fuel contracts.

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Contracts for additional uranium and enrichment services are currently being negotiated that would provide additional supply requirements through 2016 for uranium and 2010 for enrichment services.

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-, intermediate- and long-term contracts which expire in various years from 2006 through 2027 in order to provide an adequate supply of fuel. Certain natural gas supply and transportation agreements 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, 2005, NSP-Minnesota’s commitments related to these contracts were approximately $127 million. The NSP System has current fuel oil inventory adequate to meet anticipated 2006 requirements and also has access to the spot market to buy more oil, if needed.

Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of NSP-Minnesota. NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers. NSP-Minnesota also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices. See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

NSP-Minnesota Electric Operating Statistics

	Year Ended Dec. 31,
	2005			2004			2003
Electric Sales (Millions of Kwh)
Residential	10,177			9,558			9,778
Commercial and Industrial	25,207			24,323			24,087
Public Authorities and Other	272			284			281
Total Retail	35,656			34,165			34,146
Sales for Resale	3,300			4,635			4,750
Total Energy Sold	38,956			38,800			38,896

Number of customers at end of period
Residential	1,184,620			1,201,560			1,180,558
Commercial and Industrial	141,384			144,631			141,584
Public Authorities and Other	5,904			5,984			5,496
Total Retail	1,331,908			1,352,175			1,327,638
Wholesale	56			69			59
Total Customers	1,331,964			1,352,244			1,327,697

Electric revenues (Thousands of Dollars)
Residential	$	865,738		$	747,288		$	743,986
Commercial and Industrial	1,527,149			1,306,486			1,251,197
Public Authorities and Other	27,369			31,524			31,024
Total Retail	2,420,256			2,085,298			2,026,207
Wholesale	212,152			165,993			146,187
Interchange Revenue from NSP-Wisconsin	305,202			217,127			225,021
Other Electric Revenues	73,347			81,246			56,413
Total Electric Revenues	$	3,010,957		$	2,549,664		$	2,453,828

Kwh Sales per Retail Customer	26,771			25,267			25,719
Revenue per Retail Customer	$	1,817.13		$	1,542.18		$	1,526.17
Residential Revenue per Kwh	8.51		¢	7.82		¢	7.61		¢
Commercial and Industrial Revenue per Kwh	6.06		¢	5.37		¢	5.19		¢
Wholesale Revenue per Kwh	6.43		¢	3.58		¢	3.08		¢

NATURAL GAS UTILITY OPERATIONS

Summary of Recent Regulatory Developments

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

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

As an LDC, NSP-Minnesota provides unbundled transportation service to large customers. Transportation service does not have an adverse effect on earnings because the sales and transportation rates have been designed to make them economically indifferent to whether natural gas has been sold and transported or merely transported. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDC’s distribution system.

The most significant recent developments in the natural gas operations of NSP-Minnesota 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 1995 to 2005, average annual sales to the typical NSP-Minnesota residential customer declined from 112 Dth per year to 96 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 — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC and the NDPSC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s gas supply plans for meeting customers’ future energy needs.

Purchased Gas and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail natural gas rate schedules for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs are collected or refunded over the subsequent 12-month period. The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.

NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5 percent of Minnesota natural gas revenue on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for natural gas conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

Pending and Recently Concluded Regulatory Proceedings

NSP-Minnesota Natural Gas Rate Case - In September 2004, NSP-Minnesota filed a natural gas rate case for its Minnesota retail customers, seeking a rate increase of $9.9 million, based on a return on equity of 11.5 percent. In August 2005, the MPUC approved an annual rate increase of $5.8 million, based on a return on equity of 10.4 percent. Final rates became effective Dec. 1, 2005.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 611,950 MMBtu for 2005, which occurred on Jan. 5, 2005.

NSP-Minnesota purchases natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 521,854 MMBtu/day. In addition, NSP-Minnesota 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 26 percent of peak day, firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.13 Bcf equivalent and three propane-air plants

NSP-Minnesota Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2005		2004		2003
Natural gas deliveries (Thousands of MMBtu)
Residential	38,224		39,168		40,608
Commercial and Industrial	37,215		39,186		40,597
Other	2,195		1,334		1,674
Total Retail	77,634		79,688		82,879
Transportation and Other	8,203		7,727		6,477
Total Deliveries	85,837		87,415		89,356

Number of customers at end of period
Residential	418,827		414,782		402,893
Commercial and Industrial	38,275		39,190		38,078
Total Retail	457,102		453,972		440,971
Transportation and Other	14		10		10
Total Customers	457,116		453,982		440,981

Natural gas revenues (Thousands of Dollars)
Residential	$	449,724	$	372,455	$	356,361
Commercial and Industrial	359,634		304,282		288,193
Total Retail	809,358		676,737		644,554
Transportation and Other	12,564		30,321		22,398
Total Gas Revenues	$	821,922	$	707,058	$	666,952

MMBtu Sales per Retail Customer	169.84		175.54		187.95
Revenue per Retail Customer	$	1,770.63	$	1,490.70	$	1,461.67
Residential Revenue per MMBtu	$	11.77	$	9.51	$	8.78
Commercial and Industrial Revenue per MMBtu	$	9.66	$	7.77	$	7.10
Transportation and Other Revenue per MMBtu	$	1.53	$	3.92	$	3.46

ENVIRONMENTAL MATTERS

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

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

EMPLOYEES

The number of full-time NSP-Minnesota employees on Dec. 31, 2005 was 2,642. Of these full-time employees, 2,144, or 81 percent, are covered under collective bargaining agreements. NSP-Minnesota full-time employees include 347 employees loaned to the NMC. In addition, the NMC has 712 full-time employees of its own. See Note 7 to the Consolidated Financial Statements for further discussion. Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, provide services to NSP-Minnesota.

Item 1A — Risk Factors

Risks Associated with Our Business

Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers

We are subject to comprehensive regulation by federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The state utility commissions regulate many aspects of our operations including siting and construction of facilities, customer service and the rates that we can charge customers.

Our profitability is dependent on our ability to recover costs related to providing energy and utility services to our customers. We currently provide service at rates approved by several regulatory commissions. These rates are generally regulated based on an analysis of the utility’s expenses incurred in a test year. Thus, the rates we are allowed to charge may or may not match our expenses at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that our regulatory commissions will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs. Although we believe that the current regulatory environment applicable to our business would permit us to recover the costs of our utility services, it is possible that there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.

The FERC has jurisdiction over wholesale rates for electric transmission service, electric energy sold at wholesale in interstate commerce, hydro facility licensing and certain other activities. Federal, state and local agencies also have jurisdiction over many of our other activities, including regulation of retail rates and environmental matters.

We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations.

We are subject to commodity price risk, credit risk and other risks associated with energy markets.

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and, accordingly, are subject to commodity price risk, credit risk and other risks associated with these activities.

We are exposed to market and credit risks in our generation, distribution, commodity acquisition, short-term wholesale and commodity trading activities. To minimize the risk of market price fluctuations and product availability, we enter into physical and financial contracts to hedge both price and availability risk associated with purchase and sale commitments, fuel requirements and inventories of coal, natural gas, fuel oil and energy and energy-related products. However, these contracts do not completely eliminate risks, including commodity price changes, market supply shortages, credit risk and interest rate changes. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales commitments or increased interest expense.

Credit and performance risk includes the risk that counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

We mark commodity trading derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Quoted market prices are utilized in determining the value of these derivative commodity instruments. For positions for which market prices are not available, we utilize models based on forward price curves. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions.

We are subject to environmental laws and regulations, compliance with which could be difficult and costly.

We are subject to a number of environmental laws and regulations affecting many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the management of wastes and hazardous substances. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to perform environmental remediations and to install pollution control equipment at our facilities. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We must pay all or a portion of the cost to remediate sites where our past activities, or the activities of certain other parties, caused environmental contamination. At December 31, 2005, these sites included:

• the site of a former federal uranium enrichment facility;

• the site of former manufactured gas plants operated by us or our predecessors; and

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

In addition, we cannot assure you that existing environmental laws or regulations will not be revised or that new laws or regulations seeking to protect the environment will not be adopted or become applicable to us or that we will not identify in the future conditions that will result in obligations or liabilities under existing environmental laws and regulations. Revised or additional laws or

regulations which result in increased compliance costs or additional operating restrictions, or currently unanticipated costs or restrictions under existing laws or regulations, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.

We are subject to the risks of nuclear generation.

NSP-Minnesota’s two nuclear stations, Prairie Island and Monticello, subject it to the risks of nuclear generation, which include:

• the risks associated with storage, handling and disposal of radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

• limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and

• uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at NSP-Minnesota’s nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident, if an incident did occur, it could have a material adverse effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations of its facilities.

Recession, grid disturbances, acts of war or terrorism could negatively impact our business.

The consequences of a prolonged recession and adverse market conditions may include the continued uncertainty of energy prices and the capital and commodity markets. We cannot predict the impact of any economic slowdown or fluctuating energy prices. However, such impact could have a material adverse effect on our financial condition and results of operations.

Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility, similar to the Aug. 14, 2003 black-out in portions of the eastern U.S. and Canada. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operations.

The conflict in Iraq and any other military strikes or sustained military campaign may affect our operations in unpredictable ways and may cause changes in the insurance markets, force us to increase security measures and cause disruptions of fuel supplies and markets, particularly with respect to natural gas and purchased energy. The possibility that infrastructure facilities, such as electric generation, transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of war may affect our operations. War and the possibility of further war may have an adverse impact on the economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets as a result of war may also affect our ability to raise capital.

Further, like other operators of major industrial facilities, our generation plants, fuel storage facilities and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, including our nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security and additional security personnel.

The insurance industry has also been affected by these events. To date, we have been able to obtain insurance at satisfactory levels and terms; however, the availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

Reduced coal availability could negatively impact our business.

NSP-Minnesota’s coal generation portfolio is heavily dependent on coal supplies located in the Powder River Basin of Wyoming. Approximately 60 percent of our annual coal requirement comes from this area. Coal generation comprises approximately 60 percent of our annual generation for the NSP-Minnesota. In the first half of 2005, we began experiencing disruptions in our coal deliveries

from the Powder River Basin, which continued throughout the year and are expected to continue at least through part of 2006. In response to these disruptions NSP-Minnesota mitigated the impact of reduced coal deliveries, by modifying the dispatch of certain facilities to conserve coal inventories. Despite, these efforts, coal inventories have declined to below target levels. While we have secured under contract approximately 99 percent of our anticipated 2006 coal requirements, we cannot predict with any certainty the likelihood of receiving the required coal. This factor, combined with the currently low inventory levels, has led us to continue coal mitigation. While we are planning to rebuild inventories during 2006, there is no guarantee that we will be able to do so. The ultimate impact of coal availability cannot be fully assessed at this time, but could impact our future results.

Rising energy prices could negatively impact our business.

A variety of market factors have contributed to higher natural gas prices. The direct impact of these higher costs is generally mitigated for NSP-Minnesota through recovery of such costs from customers through various fuel cost recovery mechanisms. However, higher fuel costs could significantly impact the results of operations, if requests for recovery are unsuccessful. In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on NSP-Minnesota’s results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases are expected to have an impact on the cash flows of NSP-Minnesota. NSP-Minnesota is unable to predict the future natural gas prices or the ultimate impact of such prices on its results of operations or cash flows.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric and natural gas utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. We expect that unusually mild winters and summers would have an adverse effect on our financial condition and results of operations.

Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs.

There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.

Increasing costs associated with our defined benefit retirement plans, health care plans and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.

We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our earnings and funding requirements. Based on our assumptions at Dec. 31, 2005 and assuming continuation of the current federal interest rate relief beyond 2005, in order to maintain required funding levels for our pension plans, we do not expect to make required future contributions. However, contributions could be required in the future.

In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements with our defined benefit retirement plan, health care plans and other employee benefits may adversely affect our results of operations, financial position, or liquidity.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot assure you that any of our current ratings or those of our affiliates will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Adverse developments at our affiliates could have an impact on our credit ratings. Any future downgrade could increase the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any downgrade could also lead to higher long-term borrowing costs.

As we are a subsidiary of Xcel Energy, we may be negatively affected by events at Xcel Energy and its affiliates. If Xcel Energy were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if Xcel Energy’s credit ratings and access to capital were restricted, this could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2005, the Xcel Energy holding company had approximately $5.9 billion of long-term debt and $1.6 million of short-term debt or current maturities. Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions. Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2005, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $52.4 million and no known exposure. Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries. The total amount of bonds with these indemnities outstanding as of Dec. 31, 2005, was approximately $132.9 million. Xcel Energy’s total exposure under these indemnities cannot be determined at this time. Xcel Energy believes that the exposure is significantly less than the total amount of bonds outstanding. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek, within certain regulatory and other limitations and the limitations provided by corporate law, additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s credit rating below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debt securities below investment grade, it would increase Xcel Energy’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such even were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We rely on Xcel Energy Services Inc., a subsidiary service company of Xcel Energy, for many administrative services. If Xcel Energy were to experience severe financial difficulties, it could temporarily disrupt the provision of these services or require us to provide these services ourselves, at potentially greater cost.

We are a wholly owned subsidiary of Xcel Energy. Xcel Energy can exercise, within certain regulatory and other limitations and the limitations provided by corporate law, substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

Our board of directors, as well as many of our executive officers, are officers of Xcel Energy. Our board makes determinations with respect to the following:

• our payment of dividends;

• decisions on our financings and our capital raising activities;

• mergers or other business combinations; and

• our acquisition or disposition of assets.

We have historically paid quarterly dividends to Xcel Energy. In 2005, 2004 and 2003 we paid $215.3 million, $213.0 million and $212.6 million of dividends to Xcel Energy, respectively. Our board of directors could decide to increase dividends, within the limitations of our approved capital structure, financial covenants and credit rating objectives, to Xcel Energy to support its cash needs. This could adversely affect our liquidity. The amount of dividends that we can pay is also limited to some extent by our indenture for our first mortgage bonds.

Item 1B — Unresolved SEC Staff Comments

None

Item 2 — Properties

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

Electric utility generating stations:

Station, City and Unit	Fuel	Installed	Summer 2005 Net Dependable Capability (MW)
Steam:
Sherburne — Becker, MN
Unit 1	Coal	1976	697
Unit 2	Coal	1977	682
Unit 3(a)	Coal	1987	504
Prairie Island — Welch, MN
Unit 1	Nuclear	1973	523
Unit 2	Nuclear	1974	522
Monticello — Monticello, MN	Nuclear	1971	572
King — Bayport, MN	Coal	1968	528
Black Dog — Burnsville, MN
2 Units	Coal/Natural Gas	1955 - 1960	282
2 Units	Natural Gas	2002	298
High Bridge — St. Paul, MN
2 Units	Coal	1956 - 1959	271
Riverside — Minneapolis, MN
2 Units	Coal	1964 - 1987	381
Combustion Turbine:
Angus Anson — Sioux Fall, SD
3 Units	Natural Gas	1994 — 2005	384
Inver Hills — Inver Grove
Heights, MN
6 Units	Natural Gas	1972	350
Blue Lake — Shakopee, MN
6 Units	Natural Gas	1974 - 2005	490
Other	Various	Various	261
Total			6,745

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

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2005:

Conductor Miles
500 kilovolt (KV)		2,917
345 KV		5,648
230 KV		1,704
161 KV		295
115 KV		6,443
Less than 115 KV		80,534

NSP-Minnesota had 363 electric utility transmission and distribution substations at Dec. 31, 2005.

Natural gas utility mains at Dec. 31, 2005:

		Miles
Transmission		120
Distribution		9,173

Item 3 — Legal Proceedings

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

Nuclear Waste Disposal Litigation — The federal government has the responsibility to dispose of domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act (The Act) requires the DOE to implement this disposal program. This includes the siting, licensing, construction and operation of a permanent repository for domestically produced spent

Other Matters

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

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

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

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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

NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $854 million in additional cash dividends on common stock at Dec. 31, 2005. In addition, NSP-Minnesota had dividend restrictions imposed by state regulatory commissions,debt agreements and the SEC under the PUHCA limiting the amount of dividends NSP-Minnesota can pay to Xcel Energy. These restrictions included, but may not have been limited to, the following:

• maintenance of an equity ratio of 45.99 percent to 56.21 percent;

• payment of dividends only from retained earnings; and

• debt covenant restrictions under the credit agreement for debt to total capital ratio.

With the repeal of the PUHCA, restrictions on the ability of NSP-Minnesota to declare dividends set out in that statute will no longer apply. However, dividends will be subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts.

The dividends declared during 2005 and 2004 were as follows:

(Thousands of Dollars) Quarter Ended
March 31, 2005		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005
$	54,672	$	52,969	$	54,668	$	54,613

March 31, 2005		June 30, 2005		Sept. 30, 2004		Dec. 31, 2004
$	52,294	$	53,598	$	53,289	$	53,033

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-Minnesota 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-Minnesota 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 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-Minnesota in reports filed with the SEC, including Exhibit 99.01 to this Annual Report on Form 10-K for the year ended Dec. 31, 2005.

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

Results of Operations

NSP-Minnesota’s net income was approximately $237.7 million for 2005, compared with approximately $230.3 million for 2004.

Electric Utility, Short-Term Wholesale and Commodity Trading Margins

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

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

Margins from commodity trading activity conducted at NSP-Minnesota are partially redistributed among PSCo and SPS, both wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenues. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net of trading costs (i.e., on a margin basis) in the Consolidated Statements of Income. Commodity trading costs include purchased power, transmission, broker fees and other related costs.

The following table details base electric utility, short-term wholesale and commodity trading activities:

	Base Electric Utility						Short-Term Wholesale			Commodity Trading			Consolidated Totals
	(Millions of Dollars)
2005
Electric utility revenue (excluding commodity trading)	$				2,828		$	177		$	—		$	3,005
Electric fuel and purchased power	(1,227					)	(103		)	—			(1,330		)
Commodity trading revenue	—						—			143			143
Commodity trading costs	—						—			(137		)	(137		)
Gross margin before operating expenses	$			1,601			$	74		$	6		$	1,681
Margin as a percentage of revenue	56.6					%	41.8		%	4.2		%	53.4		%

2004
Electric utility revenue (excluding commodity trading)	$		2,398				$	149		$	—		$	2,547
Electric fuel and purchased power	(917					)	(60		)	—			(977		)
Commodity trading revenue	—						—			123			123
Commodity trading costs	—						—			(120		)	(120		)
Gross margin before operating expenses	$	1,481					$	89		$	3		$	1,573
Margin as a percentage of revenue	61.8					%	59.7		%	2.4		%	58.9		%

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)	2005 vs 2004
Fuel and purchased power cost recovery	$	242
Sales growth (excluding weather impact)	38
Estimated impact of weather	49
Conservation and non-fuel riders	17
Interchange agreement billing with NSP-Wisconsin	85
Quality of service obligations	(4		)
Firm wholesale	12
Transmission and other	(9		)
Total base electric revenue increase	$	430

Base Electric Margin

(Millions of Dollars)	2005 vs 2004
Sales growth (excluding weather impact)	$	29
Estimated impact of weather	39
Conservation and non-fuel riders	16
Interchange agreement billing with NSP-Wisconsin	24
Interchange agreement billing - prior period fixed charge adjustments	13
Quality of service obligations	(4		)
Purchased capacity costs	16
Firm wholesale	5
Under-recovery of MISO schedule 16 & 17 costs	(5		)
Transmission and other	(13		)
Total base electric increase	$	120

Short-term wholesale and commodity trading margins decreased in 2005 compared with 2004. The higher 2004 results reflect the impact of more favorable market conditions and higher levels of surplus generation available to sell. In addition, a preexisting contract contributed $17 million of margin in the first quarter of 2004 and expired at that time.

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.

	2005			2004
	(Millions of Dollars)
Natural gas utility revenue	$	822		$	707
Cost of natural gas sold and transported	(665		)	(557		)
Natural gas utility margin	$	157		$	150

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)	2005 vs 2004
Purchased gas adjustment clause recovery	$	133
Off system sales	(20		)
Estimated impact of weather on firm sales volume	(5		)
Sales growth (excluding weather impact)	(2		)
Base rate changes	6
Conservation revenue and incentive	2
Transportation and other	1
Total natural gas revenue increase	$	115

Natural gas revenue increased primarily due to higher natural gas costs in 2005, which are recovered from customers. Retail gas weather-normalized sales declined in 2005, largely due to the rising cost of natural gas and its impact on customer usage.

Natural Gas Margin

(Millions of Dollars)	2005 vs 2004
Sales growth (excluding weather impact)	$	(1	)
Estimated impact of weather on firm sales volume	(2		)
Base rate changes	6
Conservation revenue and incentive	2
Off system sales	(4		)
Transportation	1
Other	5
Total natural gas margin increase	$	7

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)	2005 vs 2004
Higher nuclear plant outage costs	$	26
Higher employee benefit costs	9
Costs offset in revenue	4
Other	6
Total other utility operating and maintenance expense increase	$	45

Depreciation and amortization expense increased by approximately $36.2 million, or 10.8 percent, for 2005 compared with 2004. The increase is largely due to the installation of new steam generators at Unit 1 of the Prairie Island nuclear plant and software system additions during 2004 and early 2005, both of which have relatively short depreciable lives compared with other capital additions. The Prairie Island steam generators are being depreciated over the remaining life of the plant operating license, which expires in 2013. In addition, the Minnesota Renewable Development Fund and renewable cost recovery amortization, which is recovered in revenue and does not have an impact on net income, increased over 2004. The increase was partially offset by the changes in useful lives and net salvage rates approved by Minnesota regulators in August 2005.

Interest charges and financing costs increased by approximately $7.6 million, or 5.9 percent, for 2005, compared with 2004. The increase is due to the issuance of $250 million of long-term debt in 2005, as well as increased credit facility borrowings.

Income Taxes — Income tax expense increased by approximately $17.2 million in 2005, compared with 2004. . The effective tax rate was 32.0 percent for the period ended Dec. 31, 2005, compared with 29.1 percent for the same period in 2004. The increase in tax expense and the higher effective tax rate in 2005 compared with 2004 were primarily due to lower income levels in 2004 and income tax benefits recorded in 2004 related to successful resolution of audit issues and other adjustments to current and deferred taxes.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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

Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in its generation and retail distribution operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric

capacity, energy, and energy-related products, and for various fuels used in the generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. NSP-Minnesota’s risk-management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulation.

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

Certain contracts within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133).

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

NSP-Minnesota’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. NSP-Minnesota utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas.

VaR is calculated on a consolidated basis. As of Dec. 31, 2005, the VaRs for the commodity trading operations were:

(Millions of Dollars)	Year ended Dec. 31, 2005		During 2005
(Millions of Dollars)	Year ended Dec. 31, 2005		Average		High		Low

Commodity trading (a)	$	2.06	$	1.44	$	4.43	$	0.26

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

VaR is calculated on a consolidated basis. As of Dec. 31, 2004, the VaRs for the commodity trading operations were:

(Millions of Dollars)	Year ended Dec. 31, 2004		During 2004
(Millions of Dollars)	Year ended Dec. 31, 2004		Average		High		Low

Electric commodity trading (a)	$	0.29	$	0.97	$	2.09	$	0.27

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

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

NSP-Minnesota may engage in hedges of cash flow exposure. The fair value of interest rate swaps designated as cash flow hedges is initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument, and generally offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or firm commitment. Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. To test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis, if required. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

At Dec. 31, 2005 and 2004, a 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense by approximately $1.5 million and $0.3 million, respectively.

NSP-Minnesota also maintains trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning, which are

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars)

	Year Ended Dec. 31
	2005			2004			2003
Operating revenues
Electric utility	$	3,010,957		$	2,549,664		$	2,453,828
Natural gas utility	821,922			707,058			666,952
Other	20,705			19,135			17,180
Total operating revenues	3,853,584			3,275,857			3,137,960

Operating expenses
Electric fuel and purchased power	1,329,553			976,639			888,274
Cost of natural gas sold and transported	664,551			556,662			516,631
Operating and maintenance expenses	890,314			845,209			853,656
Depreciation and amortization	372,956			336,744			353,341
Taxes (other than income taxes)	129,928			128,970			130,826
Total operating expenses	3,387,302			2,844,224			2,742,728

Operating income	466,282			431,633			395,232

Interest and other income (expense) – net (see Note 8)	2,964			1,089			(2,800		)
Allowance for funds used during construction – equity	16,416			20,747			12,674

Interest charges and financing costs
Interest charges — including financing costs of $7,292, $8,258 and $8,989, respectively	150,261			142,147			135,764
Allowance for funds used during construction – debt	(14,126		)	(13,565		)	(9,311		)
Distributions on redeemable preferred securities of subsidiary trust	—			—			9,187
Total interest charges and financing costs	136,135			128,582			135,640

Income before income taxes	349,527			324,887			269,466
Income taxes	111,783			94,613			76,524
Net income	$	237,744		$	230,274		$	192,942

See Notes to Consolidated Financial Statements

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

	Year Ended Dec. 31
	2005			2004			2003
Operating activities
Net income	$	237,744		$	230,274		$	192,942
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	378,884			351,887			352,630
Nuclear fuel amortization	45,158			43,296			43,401
Deferred income taxes	28,846			20,545			1,561
Amortization of investment tax credits	(6,611		)	(7,150		)	(7,365		)
Allowance for equity funds used during construction	(16,416		)	(20,747		)	(12,674		)
Impairment of assets	2,887			—			—
Change in accounts receivable	(102,347		)	(18,185		)	(46,150		)
Change in accounts receivable from affiliates	(45,064		)	40,466			(30,923		)
Change in inventories	(27,855		)	(12,622		)	(6,206		)
Change in other current assets	(89,350		)	(73,706		)	(45,026		)
Change in accounts payable	121,975			27,032			17,757
Change in other current liabilities	(22,933		)	(24,204		)	(75,155		)
Change in other noncurrent assets	(46,721		)	(9,396		)	(8,205		)
Change in other noncurrent liabilities	30,521			88,316			(4,649		)
Net cash provided by operating activities	488,718			635,806			371,938

Investing activities
Utility capital/construction expenditures	(693,028		)	(641,476		)	(352,389		)
Allowance for equity funds used during construction	16,416			20,747			12,674
Purchase of investments in external decommissioning fund	(576,001		)	(305,328		)	(144,367		)
Proceeds from sale of investments in external decommissioning fund	494,529			228,676			61,031
Proceeds from sale of assets	11,228			—			—
Investments in and advances to affiliates	(32,500		)	(7,790		)	(16,830		)
Restricted cash	—			—			23,000
Other investments	(13,929		)	(1,293		)	(4,138		)
Net cash used in investing activities	(793,285		)	(706,464		)	(421,019		)

Financing activities
Short-term borrowings — net	(90,000		)	32,000			57,931
Proceeds from issuance of long-term debt	250,000			10			372,943
Borrowings under 5-year unsecured credit facility	1,000,000			—			—
Repayment of long-term debt and trust preferred securities, including reacquisition premiums	(82,031		)	(4,508		)	(426,568		)
Repayments under 5-year unsecured credit facility	(750,000		)	—			—
Capital contributions from parent	224,247			180,408			29,100
Dividends and cash distributions paid to parent	(215,341		)	(213,033		)	(212,648		)
Net cash provided by (used in) financing activities	336,875			(5,123		)	(179,242		)

Net increase (decrease) in cash and cash equivalents	32,308			(75,781		)	(228,323		)
Cash and cash equivalents at beginning of year	6,234			82,015			310,338
Cash and cash equivalents at end of year	$	38,542		$	6,234		$	82,015

Supplemental disclosure of cash flow information
Cash paid for interest (net of amounts capitalized)	$	124,516		$	123,705		$	120,993
Cash paid for income taxes (net of refunds received)	$	122,456		$	32,796		$	181,701

See Notes to Consolidated Financial Statements

NSP-MINNESOTA

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

	Dec. 31, 2005			Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	38,542		$	6,234
Notes receivable from affiliates	64,000			31,500
Accounts receivable — net of allowance for bad debts: $10,128 and $7,845, respectively	398,678			296,331
Accounts receivable from affiliates	53,414			8,350
Accrued unbilled revenues	258,028			172,512
Materials and supplies inventories — at average cost	94,395			96,953
Fuel inventory — at average cost	33,609			31,483
Natural gas inventory — at average cost	83,977			55,689
Derivative instruments valuation — at market	107,786			62,272
Prepayments and other	34,602			32,719
Total current assets	1,167,031			794,043

Property, plant and equipment, at cost:
Electric utility plant	8,018,167			7,586,873
Natural gas utility plant	829,522			778,256
Construction work in progress	496,884			438,474
Other	467,215			406,229
Total property, plant and equipment	9,811,788			9,209,832
Less accumulated depreciation	(4,454,408		)	(4,175,557		)
Nuclear fuel — net of accumulated amortization: $1,190,386 and $1,145,228, respectively	102,409			74,308
Net property, plant and equipment	5,459,789			5,108,583

Other assets:
Nuclear decommissioning fund investments	1,047,592			918,442
Regulatory assets	593,596			476,485
Prepaid pension asset	379,808			361,446
Derivative instruments valuation — at market	198,044			234,509
Other investments	37,331			24,039
Other	51,589			47,968
Total other assets	2,307,960			2,062,889
Total assets	$	8,934,780		$	7,965,515
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	204,833		$	82,185
Short-term debt	-			90,000
Accounts payable	379,950			287,531
Accounts payable to affiliates	60,419			23,013
Taxes accrued	123,384			147,144
Accrued interest	49,122			42,998
Dividends payable to parent	54,613			53,033
Derivative instruments valuation — at market	93,544			58,366
Other	57,852			51,560
Total current liabilities	1,023,717			835,830

Deferred credits and other liabilities:
Deferred income taxes	821,417			785,046
Deferred investment tax credits	52,500			59,119
Regulatory liabilities	989,591			944,364
Asset retirement obligations (see Note 11)	1,242,919			1,091,089
Derivative instruments valuation — at market	246,951			246,872
Benefit obligations and other	149,749			136,131
Total deferred credits and other liabilities	3,503,127			3,262,621

Commitments and contingencies (see Note 11)
Long-term debt	2,155,540			1,859,737
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10			10
Premium on common stock	1,247,624			1,023,377
Retained earnings	1,004,762			983,940
Total common stockholder’s equity	2,252,396			2,007,327

Total liabilities and equity	$	8,934,780		$	7,965,515

See Notes to Consolidated Financial Statements

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

(Dollars in Thousands)

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

Balance at Dec. 31, 2002	1,000,000	$	10	$	813,869	$	987,158		$	(9	)	$	1,801,028
Net income						192,942						192,942
Unrealized gain-marketable securities, net of tax of $(4)									5			5
Comprehensive income for 2003												192,947
Common dividends declared to parent						(214,220		)				(214,220		)
Contribution of capital by parent				29,100								29,100
Balance at Dec. 31, 2003	1,000,000	$	10	$	842,969	$	965,880		$	(4	)	$	1,808,855

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

Net income						237,744						237,744
Unrealized gain-marketable securities									—			—
Comprehensive income for 2005												237,744
Common dividends declared to parent						(216,922		)				(216,922		)
Contribution of capital by parent				224,247								224,247
Balance at Dec. 31, 2005	1,000,000	$	10	$	1,247,624	$	1,004,762		$	—		$	2,252,396

See Notes to Consolidated Financial Statements

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Thousands of Dollars)

	Dec. 31
	2005			2004
Long-Term Debt
First Mortgage Bonds, Series due:
Dec. 1, 2005, 6.125%	$	—		$	70,000
Dec. 1, 2006, 4.1% (a)	2,420			4,750
Dec. 1, 2006-2008, 4.5%-5% (a)	7,490			9,790
Aug. 1, 2006, 2.875%	200,000			200,000
Aug. 1, 2010, 4.75%	175,000			175,000
Aug. 28, 2012, 8%	450,000			450,000
March 1, 2019, 8.5% (b)	27,900			27,900
Sept. 1, 2019, 8.5% (b)	100,000			100,000
July 1, 2025, 7.125%	250,000			250,000
March 1, 2028, 6.5%	150,000			150,000
April 1, 2030, 8.5% (b)	69,000			69,000
July 15, 2035, 5.25%	250,000			—
Senior Notes due Aug. 1, 2009, 6.875%	250,000			250,000
Borrowings under credit facility, due April 2010, 5.05%	250,000			—
Retail Notes due July 1, 2042, 8%	185,000			185,000
Other	841			8,241
Unamortized discount	(7,278		)	(7,759		)
Total	2,360,373			1,941,922
Less current maturities	204,833			82,185
Total long-term debt	$	2,155,540		$	1,859,737

Common Stockholder’s Equity
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares in 2005 and 2004	$	10		$	10
Capital in excess of par value on common stock	1,247,624			1,023,377
Retained earnings	1,004,762			983,940
Total common stockholder’s equity	$	2,252,396		$	2,007,327

(a) Resource recovery financing

(b) Pollution control financing

See Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — NSP-Minnesota is engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. NSP-Minnesota was subject to the regulatory provisions of the PUHCA. NSP-Minnesota is also subject to regulation by the FERC and state utility commissions. All of NSP-Minnesota’s accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

On Aug. 8, 2005, President Bush signed into law the Energy Act, significantly changing many federal energy statutes. The Energy Act is expected to have a substantial long-term effect on energy markets, energy investment, and regulation of public utilities and holding company systems by the FERC, the SEC and the DOE. The FERC was directed by the Energy Act to address many areas previously regulated by other governmental entities under the statutes and determine whether changes to such previous regulations are warranted. The issues that the FERC has been required to consider associated with the repeal of the PUHCA include, but are not limited to, the expansion of the FERC authority to review mergers and sales of public utility companies and the expansion of the FERC authority over the books and records of holding companies and public utility companies previously governed by the SEC and the appropriate cost standard for the provision of non-power goods and services by service companies. The FERC is in various stages of rulemaking on these and other issues. Xcel Energy cannot predict the impact the new rulemakings will have on its operations or financial results, if any.

Principles of Consolidation — NSP-Minnesota has subsidiaries, which have been consolidated and for which all significant intercompany transactions and balances are eliminated.

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

NSP-Minnesota has various rate adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. In addition, NSP-Minnesota presents its revenue, net of any excise or other fiduciary-type taxes or fees. A summary of significant rate adjustment mechanisms follows:

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

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

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

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

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

Derivative Financial Instruments — NSP-Minnesota utilizes physical and financial commodity based contracts to reduce exposure to commodity price risk. These contracts consist mainly of commodity forwards, futures and options. For further discussion of NSP-Minnesota’s risk management and derivative activities, see Note 9 to the Consolidated Financial Statements.

Property, Plant, Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Removal costs associated with regulatory obligations are recorded 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 as incurred. Property, plant and equipment also include costs associated with property held for future use.

NSP-Minnesota determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense for NSP-Minnesota, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2005, 2004 and 2003 was 3.9 percent, 3.8 percent and 3.5 percent, respectively.

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

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

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

Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota is liable for the costs and the liability can be reasonably estimated. Costs may be deferred as a regulatory asset if it is probable 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 emission-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 NSP-Minnesota’s 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 may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.

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

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

Investment tax credits are deferred and their benefits amortized over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13 to the Consolidated Financial Statements. For more information on income taxes, see Note 8 to the Consolidated Financial Statements.

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

Cash and Cash Equivalents — NSP-Minnesota considers investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Those instruments are primarily commercial paper and money market funds.

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

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

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

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

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

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

Deferred Financing Costs — Other assets include deferred financing costs, which are amortized over the remaining maturity periods of the related debt. NSP-Minnesota’s deferred financing costs, net of amortization at Dec. 31, 2005 and 2004 are $17.2 million and $15.8 million, respectively.

Accounts Receivable and Allowance for Uncollectibles — Accounts receivable are stated at the actual billed amount net of write-offs and allowance for uncollectibles. We establish an allowance for uncollectibles based on a reserve policy that reflects our expected exposure to the credit risk of customers.

Reclassifications — Fees collected from customers on behalf of governmental agencies were reclassified to be presented net of the related payments made to the agencies.

2. Short-Term Borrowings

Notes Payable — At Dec. 31, 2005 and 2004, NSP-Minnesota had $0 million and $90 million, respectively, in notes payable to banks. The weighted average interest rate at Dec. 31, 2004 was 5.25 percent.

Money Pool - Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals. The utility money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company. NSP-Minnesota has approval to borrow up to $250 million under the arrangement. NSP-Minnesota had no borrowings or loans outstanding under the arrangement at Dec. 31, 2005. As a consequence of the repeal of PUHCA and the recent amendments to the Federal Power Act, it may be necessary for NSP-Minnesota to submit its existing money pool arrangement to FERC for its approval. NSP-Minnesota is presently evaluating the situation.

3. Long-Term Debt

Credit Facilities — At Dec. 31, 2005, NSP-Minnesota had the following committed credit facility in effect, in millions of dollars:

Facility		Available*		Term	Maturity
$	450	$	190.3	5 year	April 2010

* Net of credit facility borrowings, issued and outstanding letters of credit and commercial paper borrowings.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. NSP-Minnesota has the right to request an extension of the final maturity date by one year. The maturity extension is subject to majority bank group approval. The credit facility has one financial covenant requiring that NSP-Minnesota’s debt to total capitalization ratio be less than or equal to 65 percent with which NSP-Minnesota is in compliance. The interest rate is based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as determined by NSP-Minnesota’s senior unsecured credit ratings from Moody, Standard & Poor and Fitch.

As of Dec. 31, 2005, NSP-Minnesota had $250 million drawn on this line of credit at a weighted average interest rate of 5.05 percent. Also, $10.5 million of letters of credit were outstanding at Dec. 31, 2005, as discussed in Note 10 to the Consolidated Financial Statements, of which $9.7 million were outstanding under the above credit facility and are included in the above table.

All property of NSP-Minnesota is subject to the lien of its first mortgage indenture. NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $854 million in additional cash dividends on common stock at Dec. 31, 2005.

Maturities of long-term debt are:

(Millions of Dollars)
2006	$	205
2007	3
2008	3
2009	250
2010	425

4. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

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

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

5. Joint Plant Ownership

Following are the investments by NSP-Minnesota in jointly owned plants and the related ownership percentages as of Dec. 31, 2005:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership%
Sherco Unit 3	$	500,266	$	282,145	$	665	59.0
Sherco Common Facilities Units 1, 2 & 3	102,988		53,552		1,196		65.6
Transmission facilities, including substations	4,832		1,878		—		59.0
Total NSP-Minnesota	$	608,086	$	337,575	$	1,861

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

6. Income Taxes

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following is a table reconciling such differences for the years ending Dec. 31:

	2005		2004		2003
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.6		4.2		3.6
Life insurance policies	(0.2	)	(0.3	)	(0.4	)
Tax credits recognized	(2.8	)	(2.9	)	(3.0	)
Regulatory differences — utility plant items	(1.4	)	(2.2	)	(1.2	)
Resolution of income tax audits	(1.2	)	(3.8	)	(5.1	)
Other — net	(2.0	)	(0.9	)	(0.5	)
Effective income tax rate	32.0	%	29.1	%	28.4	%

Income taxes comprise the following expense (benefit) items for the years ending Dec. 31:

(Thousands of Dollars)	2005			2004			2003
Current federal tax expense	$	81,518		$	53,166		$	74,954
Current state tax expense	8,065			29,826			8,013
Current tax credits	(35		)	(1,774		)	(639		)
Deferred federal tax expense	21,456			26,266			5,212
Deferred state tax expense (benefit)	10,629			(5,194		)	(3,651		)
Deferred tax credits	(3,239		)	(527		)	—
Deferred investment tax credits	(6,611		)	(7,150		)	(7,365		)
Total income tax expense	$	111,783		$	94,613		$	76,524

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

(Thousands of Dollars)	2005			2004
Deferred tax expense excluding items below	$	46,863		$	53,280
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(21,600		)	(32,732		)
Tax expense allocated to other comprehensive income and other	3,583			(3		)
Deferred tax expense	$	28,846		$	20,545

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

(Thousands of Dollars)	2005		2004
Deferred tax liabilities:
Differences between book and tax bases of property	$	771,495	$	730,792
Regulatory assets	172,594		165,157
Other	27,232		14,723
Total deferred tax liabilities	$	971,321	$	910,672

Deferred tax assets:
Regulatory liabilities	$	21,282	$	20,903
Employee benefits	54,861		47,417
Deferred investment tax credits	21,353		24,069
Tax credit carryforward	12,184		2,965
Other	21,186		21,727
Total deferred tax assets	$	130,866	$	117,081
Net deferred tax liability	$	840,455	$	793,591

7. Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota.

Xcel Energy offers various benefit plans to its benefit employees, including those of NSP-Minnesota. Approximately 56 percent of Xcel Energy benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2005, NSP-Minnesota had 2,144 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2007.

Pension Benefits

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

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

Pension Plan Assets — Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. In 2004, Xcel Energy completed a review of its pension plan asset allocation and adopted revised asset allocation targets. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments 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:

	2005		2004
Equity securities	65	%	69	%
Debt securities	20		19
Real estate	4		4
Cash	1		1
Nontraditional investments	10		7
	100	%	100	%

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 12.0 percent, which is greater than 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 and 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 2005, 2004 and 2003 exceeded the assumed levels of 8.75 percent, 9.0 percent and 9.25 percent, respectively. Xcel Energy continually reviews its pension assumptions. In 2006, Xcel Energy will continue to use an investment return assumption of 8.75 percent.

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)	2005			2004
Accumulated Benefit Obligation at Dec. 31	$	2,642,177		$	2,575,317

Change in Projected Benefit Obligation
Obligation at Jan. 1	$	2,732,263		$	2,632,491
Service cost	60,461			58,150
Interest cost	160,985			165,361
Plan amendments	300			—
Actuarial loss	85,558			133,552
Settlements	—			(27,627		)
Benefit payments	(242,787		)	(229,664		)
Obligation at Dec. 31	$	2,796,780		$	2,732,263

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	3,062,016		$	3,024,661
Actual return on plan assets	254,307			284,600
Employer contributions	20,000			10,046
Settlements	—			(27,627		)
Benefit payments	(242,787		)	(229,664		)
Fair value of plan assets at Dec. 31	$	3,093,536		$	3,062,016

Funded Status of Plans at Dec. 31
Net asset	$	296,756		$	329,753
Unrecognized prior service cost	214,702			244,437
Unrecognized loss	281,519			176,957
Xcel Energy net pension amounts recognized on balance sheet	$	792,977		$	751,147

NSP-Minnesota prepaid pension asset recorded	$	379,808		$	361,446

Measurement Date	Dec. 31, 2005			Dec. 31, 2004

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	5.75		%	6.00		%
Expected average long-term increase in compensation level	3.50		%	3.50		%

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2003 through 2005 for Xcel Energy’s pension plans and is not expected to require cash

funding in 2006.

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

(Thousands of Dollars)	2005			2004			2003
Service cost	$	60,461		$	58,150		$	67,449
Interest cost	160,985			165,361			170,731
Expected return on plan assets	(280,064		)	(302,958		)	(322,011		)
Curtailment gain	—			—			(17,363		)
Settlement gain	—			(926		)	(1,135		)
Amortization of transition asset	—			(7		)	(1,996		)
Amortization of prior service cost	30,035			30,009			28,230
Amortization of net (gain) loss	6,819			(15,207		)	(44,825		)
Net periodic pension credit under SFAS No. 87	$	(21,764	)	$	(65,578	)	$	(120,920	)

NSP-Minnesota
Net periodic pension credit	$	(18,362	)	$	(38,555	)	$	(54,243	)
Credits not recognized due to effects of regulation	19,368			38,967			51,311
Net benefit cost (credit) recognized for financial reporting	$	1,006		$	412		$	(2,932	)

Significant Assumptions Used to Measure Costs
Discount rate	6.00		%	6.25		%	6.75		%
Expected average long-term increase in compensation level	3.50		%	3.50		%	4.00		%
Expected average long-term rate of return on assets	8.75		%	9.00		%	9.25		%

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 2006 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.

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

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for NSP-Minnesota were approximately $3.8 million in 2005, $3.8 million in 2004, and $3.2 million in 2003.

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 Pensions,” Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106. NSP-Minnesota transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.

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

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

	2005		2004
Equity and equity mutual fund securities	61	%	54	%
Fixed income/debt securities	17		21
Cash equivalents	21		25
Nontraditional Investments	1		—
	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. Investment-return volatility is not considered to be a material factor in postretirement health care costs.

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

(Thousands of Dollars)	2005			2004

Change in Benefit Obligation
Obligation at Jan. 1	$	929,125		$	775,230
Service cost	6,684			6,100
Interest cost	55,060			52,604
Plan amendments	—			(1,600		)
Plan participants’ contributions	12,008			9,532
Actuarial gain (loss)	(3,175		)	148,341
Benefit payments	(61,530		)	(61,082		)
Obligation at Dec. 31	$	938,172		$	929,125

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	318,667		$	285,861
Actual return on plan assets	14,507			21,950
Plan participants’ contributions	12,008			9,532
Employer contributions	68,211			62,406
Benefit payments	(61,530		)	(61,082		)
Fair value of plan assets at Dec. 31	$	351,863		$	318,667

Funded Status at Dec. 31
Net obligation	$	586,309		$	610,458
Unrecognized transition obligation	(103,022		)	(117,600		)
Unrecognized prior service cost	15,736			17,914
Unrecognized loss	(364,745		)	(383,026		)
Accrued benefit liability recorded	$	134,278		$	127,746

NSP-Minnesota accrued benefit liability recorded	$	64,052		$	54,801

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	5.75		%	6.00		%

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 also was increased from two years to six years. This trend assumption was used to value the actuarial benefit obligations at year-end 2004 and 2005, and was used in 2005 retiree medical cost determinations. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

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

(Millions of Dollars)
1-percent increase in APBO components at Dec. 31, 2005	$	22.3
1-percent decrease in APBO components at Dec. 31, 2005	(18.6		)
1-percent increase in service and interest components of the net periodic cost	1.6
1-percent decrease in service and interest components of the net periodic cost	(1.3		)

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

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $75 million during 2006.

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

(Thousands of Dollars)	2005			2004			2003

Service cost	$	6,684		$	6,100		$	5,893
Interest cost	55,060			52,604			52,426
Expected return on plan assets	(25,700		)	(23,066		)	(22,185		)
Curtailment gain	—			—			(2,128		)
Settlement gain	—			—			(916		)
Amortization of transition obligation	14,578			14,578			15,426
Amortization of prior service credit	(2,178		)	(2,179		)	(1,533		)
Amortization of net loss	26,246			21,651			15,409
Net periodic postretirement benefit cost under SFAS No. 106	$	74,690		$	69,688		$	62,392

NSP-Minnesota
Net periodic postretirement benefit cost recognized – SFAS No. 106	$	17,569		$	15,936		$	16,897

Significant assumptions used to measure costs (income)
Discount rate	6.00		%	6.25		%	6.75		%
Expected average long-term rate of return on assets (before tax)	5.5%-8.5		%	5.5%-8.5		%	8.0 - 9.0		%

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
2006	$	218,093	$	63,966	$	4,777	$	59,189
2007	221,166		65,851		5,196		60,655
2008	228,196		67,635		5,582		62,053
2009	234,663		69,303		5,936		63,367
2010	239,730		70,851		6,248		64,603
2011-2015	1,216,821		366,454		34,719		331,735

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

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

(Thousands of Dollars)	2005			2004			2003

Interest income	$	7,805		$	8,681		$	7,745
Other nonoperating income	1,419			557			193
Loss on disposal of assets	(346		)	(1,888		)	(1,125		)
Interest expense on employee-related insurance policies	(5,914		)	(6,261		)	(6,622		)
Other nonoperating expense	—			—			(2,991		)
Total interest and other income, net of nonoperating expenses	$	2,964		$	1,089		$	(2,800	)

9. Derivative Instruments

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

Utility Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in their generation and retail distribution operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy and other energy-related products, and for various fuels used in the generation and natural gas utility operation. Commodity risk also is managed through the use of financial derivative instruments. NSP-Minnesota utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of our retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments is done consistently with the local jurisdictional cost recovery mechanism. NSP-Minnesota’s risk-management policy allows it to manage market price risk to the extent such exposure exists, as allowed by regulation.

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

Types of and Accounting for Derivative Instruments

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

SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. NSP-Minnesota formally documents hedging relationships, including, among other things, the identification of the hedging instrument and the hedged transaction, as well as the risk-management objectives and strategies for undertaking the hedged transaction. NSP-Minnesota also formally assesses, both at inception and on an ongoing basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; and hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs. NSP-Minnesota is allowed to recover in natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility.

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

Minnesota is currently engaged in are discussed below.

Cash Flow Hedges

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

Commodity Cash Flow Hedges — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes. At Dec. 31, 2005, NSP-Minnesota had various commodity-related contracts classified as cash flow hedges extending through November 2006. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanism in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or natural gas purchased for resale.

As of Dec. 31, 2005, NSP-Minnesota had no amounts in Accumulated Other Comprehensive Income that is expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

NSP-Minnesota had no ineffectiveness related to commodity cash flow hedges during the years ended Dec. 31, 2005 and 2004.

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

(Millions of Dollars)
Accumulated other comprehensive income related to hedges at Dec. 31, 2002	$	—
After-tax net unrealized losses related to derivative accounted for as hedges	(0.2		)
After-tax net realized losses on derivative transactions reclassified into earnings	0.2
Accumulated other comprehensive income related to hedges at Dec. 31, 2003	$	—

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

After-tax net unrealized losses related to derivatives accounted for as hedges	—
After-tax net realized losses on derivative transactions reclassified into earnings	—
Accumulated other comprehensive income related to hedges at Dec. 31, 2005	$	—

Fair Value Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings. At Dec. 31, 2005, NSP-Minnesota had no fair value hedges.

Normal Purchases or Normal Sales Contracts

NSP-Minnesota enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as 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.

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

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

The fair value of the commodity trading contracts as of Dec. 31, 2005 and 2004 was $1.9 million and $0.9 million, respectively.

The fair value of qualifying cash flow hedges at Dec. 31, 2005 and 2004 was $2.3 million and $(7.2) million, respectively.

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

10. Financial Instruments

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

	2005				2004
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Nuclear decommissioning fund	$	1,047,592	$	1,047,592	$	918,442	$	918,442
Other investments	$	2,544	$	2,544	$	4,129	$	4,129
Long-term debt, including current portion	$	2,360,373	$	2,549,257	$	1,941,922	$	2,193,546

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

The fair value estimates presented are based on information available to management as of Dec. 31, 2005 and 2004. 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.

The following tables provide the external decommissioning fund’s approximate gains, losses and proceeds from the sale of securities for the years ended Dec. 31:

(Thousands of Dollars)	2005		2004		2003
Realized gains	$	8,967	$	16,578	$	4,999
Realized losses	$	8,990	$	20,180	$	6,025
Proceeds from sale of securities	$	489,697	$	223,135	$	57,768

(Thousands of Dollars)	2005		2004
Unrealized gains	$	253,991	$	240,960
Unrealized losses	$	10,558	$	2,703

NSP-Minnesota provides guarantees that guarantee payment or performance under specified agreements or transactions. As a result, NSP-Minnesota’s exposure under the guarantees is based upon the net liability under the specified agreements or transactions. The guarantees issued by NSP-Minnesota limit the exposure of NSP-Minnesota to a maximum amount stated in the guarantees. The guarantees require no liability to be recorded and contain no recourse provisions. On Dec. 31, 2005, NSP-Minnesota had the following guarantees and exposures related to those guarantees:

(Millions of Dollars)
Nature of Guarantee

Guarantor

Guarantee
Amount

Current
Exposure

Term or
Expiration Date

Triggering
Event
Requiring
Performance

Assets Held as
Collateral

NSP-Minnesota sold a portion of its receivables (consisting of customer loans to local and state government entities for energy efficiency improvements) to a third party. Under the loan agreements, NSP-Minnesota is required to guarantee repayment to the third party of the remaining loan balances. Based on prior collection experience of these loans, losses under the loan guarantees, if any, are not expected to have a material impact on the results of operations

NSP-Minnesota

0.12

2006

)

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

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

Letters of Credit

NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2005, there was $10.5 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

11. Commitments and Contingent Liabilities

Legislative Resource Commitments — In 1994 , NSP-Minnesota received Minnesota legislative approval for on-site temporary spent-fuel storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. Commitments related to the 17 dry cask storage containers approved in 1994 have been fulfilled. As the result of legislative amendments in 2003, NSP-Minnesota is authorized to use as many dry cask storage containers as necessary to operate the plant through 2014. Current estimates indicate that this will require 29 dry cask storage containers. As of Dec. 31, 2005, NSP-Minnesota had filled and placed 20 dry cask containers in storage at Prairie Island.

The 2003 legislation transfers the primary authority concerning future spent-fuel storage issues from the Legislature to the MPUC. In January 2005, NSP-Minnesota filed an application with the MPUC for a certificate of need for up to 30 dry cask storage containers at the Monticello nuclear plant so that it can continue to operate beyond 2010. NSP-Minnesota expects a decision from the MPUC later this year. NSP-Minnesota also filed its request with the NRC on March 24, 2005, for a 20-year extension to Monticello’s operating license. If a certificate of need is granted, it is stayed until the following June to provide the Minnesota Legislature the opportunity to review the MPUC’s action if it is determined appropriate. The 2003 legislation also requires NSP-Minnesota to add at least 300 MWs of additional wind power by 2010, with an option to own 100 MWs of this power.

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

Capital Commitments — The estimated cost, as of Dec. 31, 2005, of the capital expenditure programs and other capital requirements of NSP-Minnesota is approximately $879 million in 2006, $697 million in 2007 and $564 million in 2008.

NSP-Minnesota’s capital expenditure forecast includes environmental improvements related to modifications to reduce the emissions

of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area pursuant to the Minnesota emissions reduction project (MERP). The MERP project is expected to cost approximately $1 billion, with major construction starting in 2005 and finishing in 2009. NSP-Minnesota expects cash recovery of the costs of the emission-reduction project through customer rates beginning in 2006.

The capital expenditure programs of NSP-Minnesota are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting NSP-Minnesota’s long-term energy needs. In addition, NSP-Minnesota’s ongoing evaluation of compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Leases — NSP-Minnesota leases a variety of equipment and facilities used in the normal course of business. The leases are accounted for as operating leases. Rental expense under operating lease obligations was approximately $26.1 million, $27.3 million and $27.1 million for 2005, 2004 and 2003, respectively.

Future commitments under operating leases are:

2006		2007		2008		2009		2010		Thereafter
(Millions of Dollars)
$	15.5	$	12.6	$	12.1	$	10.2	$	5.4	$	8.4

Fuel Contracts — NSP-Minnesota has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2006 and 2027. In addition, NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provides for pass through of most fuel, storage and transportation costs.

The estimated minimum purchase for NSP-Minnesota under these contracts as of Dec. 31, 2005, is as follows:

Coal		Nuclear Fuel		Natural Gas Supply		Gas Storage & Transportation
(Millions of Dollars)
$	310	$	118	$	394	$	543

Purchased Power Agreements — NSP-Minnesota has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota has various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indexes. However, the effect of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

At Dec. 31, 2005, the estimated future payments for capacity that NSP-Minnesota is obligated to purchase, subject to availability, is as follows (Thousands of Dollars):

2006		$	132,654
2007		135,098
2008		151,573
2009		161,876
2010		164,758
2011 and thereafter		1,707,484
Total	*	$	2,453,443

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

Environmental Contingencies

NSP-Minnesota has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Minnesota is pursuing, or intends to pursue, insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the rate regulatory process. To

the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an expense for such unrecoverable amounts in its Consolidated Financial Statements.

Site Remediation — NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota and some other parties have caused environmental contamination. Environmental contingencies could arise from various situations including the following categories of sites:

• the site of a former federal uranium enrichment facility,

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

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

NSP-Minnesota records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially.

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

Estimates are revised as facts become known. At Dec. 31, 2005, the liability for the cost of remediating sites was estimated to be $6.1 million, of which $5.3 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. Estimates have been recorded for NSP-Minnesota’s future costs for these sites.

Federal Uranium Enrichment Facility

Approximately $4.8 million of the current liability for NSP-Minnesota relates to a DOE assessment for decommissioning a federal uranium enrichment facility. This environmental liability does not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota’s nuclear generating plants. See Note 12 to Consolidated Financial Statements for further discussion of nuclear obligations.

Manufactured Gas Plant Sites

Levee Station Manufactured Gas Plant Site — A portion of NSP-Minnesota’s High Bridge plant coal yard is located on the site of the former Levee Station MGP site. The Levee Station was a coke-oven gas purification, storage and distribution facility. The Levee Station supplied manufactured gas to the city of St. Paul from 1918 to the early 1950s. In the 1950s, the facility was demolished, and the High Bridge coal yard was extended onto the property. In the 1990s, the site was investigated and partially remediated at a cost of approximately $2.9 million. In 2006, NSP-Minnesota plans to commence construction of the High Bridge Combined Cycle Generating Plant, as part of the MERP, on the site of the Levee Station. The construction of the new plant requires the removal of buried structures and soil and groundwater remediation. Remediation activities began in 2005. The cost of the additional remediation is estimated to be $0.2 million, which will be accounted for as a capital expenditure of the MERP project.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. NSP-Minnesota has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations elsewhere in Note 11. 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.

Other Environmental Requirements

Clean Air Interstate and Mercury Rules — In March 2005, the Environmental Protection Agency (EPA) issued two significant new air quality rules. The Clean Air Interstate Rule (CAIR) further regulates sulfur dioxide (SO₂) and nitrogen oxide (NOx) emissions, and the Clean Air Mercury Rule (CAMR) regulates mercury emissions from power plants for the first time.

The objective of CAIR is to cap emissions of SO₂ and NOx in the eastern United States, including Minnesota. When fully implemented, CAIR will reduce SO₂ emissions in 28 eastern states and the District of Columbia by over 70 percent and NOx emissions by over 60 percent from 2003 levels. It is designed to address the transportation of fine particulates, ozone and emission precursors to non-attainment downwind states. CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO₂, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO₂ and NO_X that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

Minnesota and Wisconsin will be included in CAIR, and Xcel Energy has generating facilities in these states that will be impacted. Preliminary estimates of capital expenditures associated with compliance with CAIR for the NSP System range from $30 million to $40 million, which would be a cost sharable through the Interchange Agreement. Xcel Energy is not challenging CAIR in these states.

There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to project the ultimate amount and timing of capital expenditure and operating expenses.

While NSP-Minnesota expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. NSP-Minnesota believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

The EPA’s CAMR also uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country that are greater than 25 megawatts. Compliance with this rule also occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. Similar to CAIR, states can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

Under CAMR, NSP-Minnesota can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Estimating the cost of compliance with CAMR is difficult because technologies specifically designed for control of mercury are in the early stages of development and there is no established market on which to base the cost of mercury allowances. NSP-Minnesota’s preliminary analysis for Phase I compliance suggests capital costs of approximately $7.1 million and increased operating and maintenance expenses of approximately $6.1 million, beginning in 2010. Further testing is planned during 2006 to confirm these costs or determine whether different measures will be necessary, which could result in higher costs. Additional costs will be incurred to meet Phase II requirements in 2018.

The Minnesota Legislature is expected to consider legislation in the 2006 session that could require up to a 90 percent reduction in mercury emissions from coal-fueled power plants provided the MPUC determines that it is technically feasible and economically reasonable to do so. The cost impact of this potential legislation is unknown. The legislation is expected to allow for cost recovery by the utility

Regional Haze Rules — On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls known as best available retrofit technology (BART) for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. NSP-Minnesota generating facilities will be subject to BART requirements. Some of these facilities are located in regions where the CAIR is effective. CAIR has precedence over BART. Therefore, BART requirements will be deemed to be met through compliance with CAIR requirements.

States must develop their implementation plans by December 2007. States will identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities. Due to the uncertainties of the many decisions involved in this process, NSP-Minnesota is not able to estimate the cost impact at this time.

Federal Clean Water Act — The federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004,

the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require NSP-Minnesota to perform additional environmental studies at several power plants in Minnesota to determine the impact the facilities may be having on aquatic organisms vulnerable to injury. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these plants. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved, including unresolved third party legal challenges to the Federal rule. Based on the limited information available, total capital and operating and maintenance costs to the NSP System are estimated at approximately $29.5 million. After costs are shared through the Interchange Agreement, NSP-Minnesota’s estimated cost is $28.0 million over the next five to 10 years. Actual costs may be higher or lower depending on the final resolution of legal challenges to the rule, as well as pending state and federal decisions regarding interpretation of specific rule requirements.

Asset Retirement Obligations

NSP-Minnesota adopted Statement of Financial Accounting Standard SFAS No. 143 – “Accounting for Asset Retirement Obligations” (SFAS No. 143) effective Jan. 1, 2003. NSP-Minnesota records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47 – “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47) to clarify the scope and timing of liability recognition for conditional asset retirement obligations pursuant to SFAS No. 143. The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the fair value is estimable, even when the obligation is dependent on a future event. FIN No. 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized. NSP-Minnesota implemented FIN No. 47 as of Dec. 31, 2005. Included in these financial statements are the recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis.

Recorded Asset Retirement Obligations (ARO) — Asset retirement obligations have been recorded for nuclear production, steam production, electric transmission and distribution systems, gas distribution systems and office buildings. The steam production obligation includes asbestos, ash containment facilities and decommissioning. The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota. NSP-Minnesota also recorded asbestos recognition for its general office building. Generally, this asbestos abatement removal obligation originated in 1973 with the Clean Air Act, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. Asset retirement obligations also have been recorded for NSP-Minnesota steam production related to ash containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination date on the ARO recognition for ash containment facilities at steam plants was the in-service date of various facilities.

NSP-Minnesota recognized an ARO for the retirement costs of natural gas mains and for the removal of electric transmission and distribution equipment. The electric transmission and distribution ARO consists of many small potential obligations associated with polychlorinated biphenyls (PCBs), mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. These electric and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured at Dec. 31, 2005. The asset retirement cost was set to this recognized obligation and no cumulative effect adjustment was shown.

A liability has also been recorded in previous years for nuclear decommissioning of an NSP-Minnesota steam production plant. This plant began operating as a nuclear production facility in 1964 before being converted to a steam peaking facility in 1969. For the nuclear assets, the asset retirement obligation associated with the decommissioning of two NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originates with the in-service date of the facility. Monticello began operation in 1971. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively. See Note 12 to the Consolidated Financial Statements for further discussion of nuclear obligations.

A reconciliation of the beginning and ending aggregate carrying amount of NSP-Minnesota’s asset retirement obligations is shown in the table below for the 12 months ended Dec. 31, 2005 and Dec. 31, 2004, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2005		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates		Ending Balance Dec. 31, 2005

Electric Utility Plant:
Steam production asbestos	$	—	$	3,890	$	—	$	17,829	$	—	$	21,719
Steam production ash containment	—		3,953		—		12,934		—		16,887
Steam production retirement	3,002		—		—		150		—		3,152
Nuclear production decommissioning	1,088,087		—		—		70,736		26,145		1,184,968
Electric transmission and distribution	—		1,100		—		—		—		1,100
Gas Utility Plant:
Gas transmission and distribution	—		12,059		—		—		—		12,059
Common Utility and Other Property:
Common general plant asbestos	—		575				2,459		—		3,034
Total liability	$	1,091,089	$	21,577	$	—	$	104,108	$	26,145	$	1,242,919

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

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

The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $1.1 billion as of Dec. 31, 2005, including external nuclear decommissioning investment funds and internally funded amounts.

Cumulative Effect of FIN No. 47 — In March 2005, the FASB issued FIN No. 47. The interpretation clarified the term “conditional asset retirement obligation” as used in SFAS No. 143. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. If NSP-Minnesota had implemented FIN No. 47 at Jan. 1, 2004, the liability for asset retirement obligations would have increased by $37.4 million. The same liability at Dec. 31, 2004 would have increased by $39.4 million. A summary of the accounting for the initial adoption of FIN No. 47, as of Dec. 31, 2005 is as follows:

(Thousands of Dollars)	Plant Assets			Regulatory Assets		Long-Term Liabilities

Reflect retirement obligation when liability incurred	$	21,577		$	—	$	21,577
Record accretion of liability to adoption date	—			33,222		33,222
Record depreciation of plant to adoption date	(6,589		)	6,589		—
Net impact of FASB Interpretation No. 47	$	14,988		$	39,811	$	54,799

Removal Costs — NSP-Minnesota accrues an obligation for plant removal costs for other generation, transmission and distribution facilities. Generally, the accrual of future non-ARO 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-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs as of Dec. 31, 2005 and 2004 are $334 million and $323 million, respectively.

Nuclear Insurance — NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $10.8 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $10.5 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $100.6 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $15 million per reactor during any one year.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.1 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $14.8 million for business interruption insurance and $26.5 million for property damage insurance if losses exceed accumulated reserve funds.

Legal Contingencies

In the normal course of business, NSP-Minnesota is party to routine claims and litigation arising from prior and current operations. NSP-Minnesota is actively defending these matters and has recorded a liability related to the probable cost of settlement or other disposition when it can be reasonably estimated.

Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota state district court asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties have asserted cross motions for partial summary judgment concerning legal obligations associated with rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves the MAC. This hearing was held in January 2006; the judge has not yet issued his decision. Both sides have scheduled depositions of key witnesses to take place in February and March of 2006. Trial has been set for August 2006, additional summary judgment motions are likely prior to trial.

Siewert v. Xcel Energy — Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action against NSP-Minnesota alleging negligence in the handling, supplying, distributing, and selling of electrical power systems, negligence in the construction and maintenance of distribution systems, and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury and damage to a dairy herd as a result of stray voltage resulting from NSP-Minneosta’s distribution system. Plaintiff’s expert report on the economic damage to their dairy farm that the total present value of plaintiffs’ loss is $6.8 million. Trial is scheduled to commence in March 2007. NSP-Minnesota denies these allegations and will defend this matter vigorously.

Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO₂) emissions. Although NSP-Minnesota is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on NSP-Minnesota. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO₂ is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO₂ emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO₂ emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit should be dismissed because it is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs have filed a notice of appeal.

The issue of global climate change is receiving increased attention. Debate continues in the scientific community concerning the extent to which the earth’s climate is warming, the causes of climate variations that have been observed, and the ultimate impacts that might result from a changing climate. There also is considerable debate regarding public policy for the approach that the United States should follow to address the issue. The United Nations-sponsored Kyoto Protocol, which establishes greenhouse gas reduction targets for developed nations, entered into force on Feb. 16, 2005. President Bush has declared that the United States will not ratify the protocol and is opposed to legislative mandates, preferring a program based on voluntary efforts and research on new technologies. NSP-Minnesota is closely monitoring the issue from both scientific and policy perspectives. While it is not possible to know the eventual outcome, NSP-Minnesota believes the issue merits close attention and is taking actions it believes are prudent to be best positioned for a variety of possible future outcomes. Xcel Energy, including NSP-Minnesota, is participating in a voluntary carbon management program and has established goals to reduce its volume of carbon dioxide emissions by 12 million tons by 2009 and to reduce carbon intensity by 7 percent by 2012. NSP-Minnesota’s evaluation process for future generating resources incorporates the risk of future carbon limits through the use of externality costs. NSP-Minnesota also is involved in other projects to improve available methods for managing carbon.

12. Nuclear Obligations

Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent-nuclear fuel from its nuclear plants. The DOE is

responsible for permanently storing spent-fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $12 million in 2005, $13 million in 2004 and $13 million in 2003. In total, NSP-Minnesota had paid approximately $346 million to the DOE through Dec. 31, 2005. However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.

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

NSP-Minnesota has its own temporary, on-site storage facilities for spent-fuel at its Monticello and Prairie Island nuclear plants, which consists of storage pools and a dry cask facility. With the dry cask storage facility licensed by the NRC, approved in 1994 and again in 2003, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least the end of its license terms in 2013 and 2014. The Monticello nuclear plant has storage capacity in the pool to continue operations until 2010. Storage availability to permit operation beyond these dates is not known at this time. All of the alternatives for spent-fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent-nuclear fuel as part of a consortium of electric utilities.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from 1993 to 2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2005 was $4.7 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $8.3 million at Dec. 31, 2005, is deferred as a regulatory asset.

Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is planned for the period from cessation of operations through 2040, assuming the prompt dismantlement method. NSP-Minnesota is currently accruing the costs for decommissioning over the MPUC approved cost-recovery period and including the accruals in Accumulated Depreciation. Upon implementation of SFAS No. 143, the decommissioning costs in Accumulated Depreciation and ongoing accruals are reclassified to a regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with SFAS No. 143.

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

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

The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in December 2003, using 2002 cost data. In October 2005, NSP-Minnesota filed with the MPUC a nuclear decommissioning study using 2005 cost data. Xcel Energy’s recommendation is to reduce the 2006 funding if approved by the MPUC. Xcel Energy expects the MPUC to approve a new funding amount in 2006.

Internal funding for all retail jurisdictions has been transferred to the external funds by the end of 2005. Based on the last MPUC approval requiring the acceleration of the internal fund transfer, there is a step change in the level of the overall decommissioning expense at the expiration of the transfer beginning Jan. 1, 2006. Expecting to operate Prairie Island through the end of each unit’s licensed life, the approved capital recovery will allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2014. Xcel Energy believes future decommissioning cost accruals will continue to be recovered in

customer rates.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2005, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

At Dec. 31, 2005, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $816 million. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters. These amounts are not those recorded in the financial statements for the asset retirement obligation in accordance with SFAS No. 143:

(Thousands of Dollars)	2005			2004
Estimated decommissioning cost obligation from most recently approved study (2002 dollars)	$	1,716,618		$	1,716,618
Effect of escalating costs (at 4.19 percent per year) to 2005 and 2004 dollars, respectively	224,946			146,866
Estimated decommissioning cost obligation in current dollars	1,941,564			1,863,484
Effect of escalating costs to payment date (at 4.19 percent per year)	1,851,801			1,929,881
Estimated future decommissioning costs (undiscounted)	3,793,365			3,793,365
Effect of discounting obligation (using risk-free interest rate)	(2,026,003		)	(2,139,561		)
Discounted decommissioning cost obligation	1,767,362			1,653,804
Assets held in external decommissioning trust	1,047,592			918,442
Discounted decommissioning obligation in excess of assets currently held in external trust	$	719,770		$	735,362

Decommissioning expenses recognized include the following components:

(Thousands of Dollars)	2005				2004			2003
Annual decommissioning cost accrual reported as depreciation expense:
Externally funded	$		80,582		$	80,582		$	80,582
Internally funded (including interest costs)	(57,561			)	(53,307		)	(35,906		)
Interest cost on externally funded decommissioning obligation	(24,516			)	(19,026		)	(14,952		)
Earnings from external trust funds	24,516				19,026			14,952
Net decommissioning accruals recorded	$	23,021			$	27,275		$	44,676

Decommissioning and interest accruals are included with Regulatory Liabilities on the Consolidated Balance Sheet. Interest costs and trust earnings associated with externally funded obligations are reported in Other Nonoperating Income on the Consolidated Statements of Operations.

Negative accruals for internally funded portions in 2003, 2004 and 2005 reflect the impact of the 2002 decommissioning study, which approved an assumption of 100-percent external funding of future costs. The 2005 nuclear decommissioning filing has not been used for the regulatory presentation because it is effective for 2006. However, the filing and all the updated parameters were used for a new ARO layer for SFAS No. 143 recognition.

13. Regulatory Assets and Liabilities

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

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	2005		2004

Regulatory Assets:
Net nuclear asset retirement obligations	12	End of licensed life	$	282,195	$	221,864
AFDC recorded in plant (a)		Plant lives	96,296		92,080
Contract valuation adjustments (d)	9	Term of contract	53,425		17,700
Losses on reacquired debt	1	Term of related debt	29,081		32,844
Renewable resource costs		One to two years	46,889		38,985
Conservation programs (a)		Generally one year	29,670		23,209
Non-nuclear asset retirement obligations	11	Plant lives	17,015		—
Nuclear decommissioning costs (c)		Up to two years	8,317		12,610
Unrecovered natural gas costs (b)	1	One to two years	12,874		14,553
Other		Various	7,029		9,667
Minnesota renewable cost recovery		Generally one year	3,564		5,292
State commission accounting adjustments (a)		Plant lives	4,240		4,476
Environmental costs	11, 12	Various	3,001		3,205
Total regulatory assets			$	593,596	$	476,485

Regulatory Liabilities:
Pension costs-regulatory differences	7		397,261		377,893
Plant removal costs	11		334,353		323,440
Unrealized gains on decommissioning investments	12		143,396		129,028
Deferred income tax adjustments			57,430		60,521
Investment tax credit deferrals			35,993		40,602
Interest on income tax refunds			5,981		9,315
Contract valuation adjustments (d)			6,631		—
Fuel costs, refunds and other			8,546		3,565
Total regulatory liabilities			$	989,591	$	944,364

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

(b) Excludes current portion expected to be returned to customers within 12 months of $16.3 million for 2005, and expected to be returned to customers within 12 months of $12.4 million for 2004.

(c) These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to DOE assessments to pay for the decommissioning of a federal uranium enrichment facility. See Note 12.

(d) Includes the fair value of certain long-term contracts used to meet native energy requirements.

14. Segment and Related Information

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

• NSP-Minnesota’s Regulated Electric Utility generates, transmits and distributes electricity in Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated Electric Utility also includes NSP-Minnesota’s commodity trading operations.

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

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 appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

To report net income for Regulated Electric and Regulated Natural Gas Utility segments, NSP-Minnesota 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. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery which are separately determined for each segment.

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
2005
Operating revenues from external customers	$	3,010,957	$	821,922	$	20,705		$	—		$	3,853,584
Intersegment revenues	297		15,689		—			(15,986		)	—
Total revenues	$	3,011,254	$	837,611	$	20,705		$	(15,986	)	$	3,853,584
Depreciation and amortization	$	341,725	$	30,501	$	730		$	—		$	372,956
Financing costs, mainly interest expense	120,982		14,515		660			(22		)	136,135
Income tax expense (benefit)	116,517		7,717		(12,451		)	—			111,783
Segment net income	$	199,964	$	23,782	$	13,998		$	—		$	237,744

2004
Operating revenues from external customers	$	2,549,664	$	707,058	$	19,135		$	—		$	3,275,857
Intersegment revenues	821		4,658		—			(5,479		)	—
Total revenues	$	2,550,485	$	711,716	$	19,135		$	(5,479	)	$	3,275,857
Depreciation and amortization	$	307,048	$	28,787	$	909		$	—		$	336,744
Financing costs, mainly interest expense	113,405		14,349		875			(47		)	128,582
Income tax expense (benefit)	90,428		7,332		(3,147		)	—			94,613
Segment net income	$	206,726	$	23,131	$	417		$	—		$	230,274

2003
Operating revenues from external customers	$	2,453,828	$	666,952	$	17,180		$	—		$	3,137,960
Intersegment revenues	720		7,245		—			(7,965		)	—
Total revenues	$	2,454,548	$	674,197	$	17,180		$	(7,965	)	$	3,137,960
Depreciation and amortization	$	318,801	$	31,420	$	3,120		$	—		$	353,341
Financing costs, mainly interest expense	117,332		18,004		10,180			(9,876		)	135,640
Income tax expense	67,104		8,965		455			—			76,524
Segment net income	$	177,333	$	17,852	$	(2,243	)	$	—		$	192,942

15. Related Party Transactions

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

Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals. See Note 2 for further discussion of this borrowing arrangement.

Utility Engineering Corp. (UE), a former Xcel Energy subsidiary, provided construction services to NSP-Minnesota, for which it was paid $2.3 million in 2005, $9.3 million in 2004 and $5.3 million in 2003. UE was sold in April 2005.

NMC is an operating company that manages the operations, maintenance and physical security of several nuclear generating units on five sites, including three units/two sites owned by NSP-Minnesota. NSP-Minnesota continues to own the plants, controls all energy produced by the plants, and retains responsibility for nuclear property and liability insurance and decommissioning costs. The Wisconsin Public Service Corporation is no longer participating in NMC after the sale of its Kewaunee nuclear power plant in July 2005. In January 2006, Florida Power & Light purchased the majority interest in the Duane Arnold plant from Alliant Energy and announced it will assume management of the plant. As a result, NSP-Minnesota’s ownership interest in NMC has increased to 25 percent. In accordance with the Nuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays its proportionate share of the operating expenses and capital improvement costs incurred by NMC. NSP-Minnesota paid NMC $257.1 million in 2005, $314.7 million in 2004 and $227.0 million in 2003.

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

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

(Thousands of Dollars)	2005		2004		2003
Operating revenues:
Electric utility	$	305,202	$	220,165	$	227,946
Natural gas utility	386		303		287
Operating expenses:
Purchased power	60,801		55,222		54,965
Transmission expense	37,803		40,794		37,849
Other operations – paid to Xcel Energy Services Inc.	284,906		274,074		266,560

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

	2005				2004
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable

NSP-Wisconsin	$	11,756	$	—	$	2,826	$	—
PSCo	162		22,356		72		12,197
SPS	—		10,282		—		1,576
Other subsidiaries of Xcel Energy Inc.	41,496		27,781		5,452		9,240
	$	53,414	$	60,419	$	8,350	$	23,013

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. At Dec. 31, 2005 and 2004, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in the amount of $64.0 million and $31.5 million, respectively. Interest income related to the NSP-Wisconsin borrowing on NSP-Minnesota’s statement of income was $1.3 million, $0.3 million and $0.1 million for 2005, 2004 and 2003, respectively.

16. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2005 (a)		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005

Revenue	$	943,471	$	854,565	$	976,935	$	1,078,613
Operating income	91,263		70,149		199,167		105,703
Net income	41,627		29,733		115,891		50,493

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

Revenue	$	919,232	$	686,376	$	788,313	$	881,936
Operating income	132,633		77,703		127,182		94,115
Net income	68,357		34,263		68,435		59,219

(a) Revenues for the quarters ended March 31, 2005 and 2004 have been reduced by $6.1 million and $10.4 million, respectively, as

compared to amounts previously reported in the first quarter 2005 10-Q. Revenue for the quarter ended Dec. 31, 2004 has been reduced by $10.3 million as compared to the amount previously reported in the 2004 10-K. These adjustments are a result of fees collected from customers on behalf of governmental agencies that were reclassified to be presented net of the related payments made to the agencies.

(b) 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.

(c) Fourth quarter 2004 results were increased by $10.5 million of income tax benefits, including $4.1 million related to the successful resolution of various IRS audit issues and other adjustments to current and deferred taxes related to prior years.

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

During 2004 and 2005, and through the date of this report, there were no disagreements with the independent public accountants for NSP-Minnesota on accounting principles or practices, financial statement disclosures or auditing scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the NSP-Minnesota’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

No change in NSP-Minnesota’s internal control over financial reporting has occurred during NSP-Minnesota’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’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-Minnesota in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10 — Directors and Executive Officers of the Registrant

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 2006 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, 2005, 2004 and 2003.

Consolidated Statements of Income — For the three years ended Dec. 31, 2005, 2004 and 2003.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2005, 2004 and 2003.

Consolidated Balance Sheets — As of Dec. 31, 2005 and 2004.

2. Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2005, 2004 and 2003.

3. Exhibits

*Indicates incorporation by reference

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

2.01*		Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Co. (a Minnesota corporation) and New Century Energies, Inc. (Exhibit 2.1 to New Century Energies, Inc. Form 8-K (file no. 001-12907) dated March 24, 1999).
3.01*		Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*		By-Laws of Northern States Power Co. (a Minnesota corporation) (Exhibit 3.02 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.01*		Supplemental and Restated Trust Indenture, dated May 1, 1988, from Northern States Power Co. (a Minnesota corporation) to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034). Supplemental Indentures between NSP-Minnesota and said Trustee, supplemental to Exhibit 4.14, dated as follows:
4.02*		July 1, 1989 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated July 7, 1989).
4.03*		June 1, 1990 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 1, 1990).
4.04*		Oct. 1, 1992 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 13, 1992).
4.05*		April 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 30, 1993).
4.06*		Dec. 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 7, 1993).
4.07*		Feb. 1, 1994 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Feb. 10, 1994).
4.08*		Oct. 1, 1994 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 5, 1994).
4.09*		June 1, 1995 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995).
4.10*		April 1, 1997 (Exhibit 4.47 to Form 10-K (file no. 001-03034) for the year 1997).
4.11*		March 1, 1998 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998).
4.12*		May 1, 1999 (Exhibit 4.49 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.13*		June 1, 2000 (Exhibit 4.50 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.14*		Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.15*		June 1, 2002 (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.16*		June 1, 2002 (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.17*		Aug. 1, 2002 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.18*		Aug. 1, 2003 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.19*		May 1, 2003 (Exhibit 4.73 to Form 10-K (file no. 000-03034) for the year ended Dec. 31, 2003).
4.20*		July 1, 2005 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K (file no. 001-31387) dated July 14, 2005).
4.21*		Trust Indenture, dated July 1, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.22*		Supplemental Trust Indenture, dated July 15, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.23*		Supplemental Trust Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.24*		Supplemental Trust Indenture dated June 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.25*		Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.26*		Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indenture dated July 1, 1999, between

		Northern States Power Co. (a Minnesota Corporation) and Wells Fargo Bank Minnesota, National Association, as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated July 8, 2002).
4.27*		Supplemental Trust Indenture dated Aug. 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.28*		Supplemental Trust Indenture dated Aug. 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.29*		Supplemental Trust Indenture dated May 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988.
4.30*		Underwriting Agreement dated July 14, 2005 between NSP-Minnesota, Barclays Capital Inc. and J.P. Morgan Securities Inc., as representatives of the Underwriters named therein, relating to $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 1.01 to NSP-Minnesota Current Report on Form 8-K, dated July 14, 2005).
4.31*		$375,000,000 Credit Agreement among Northern States Power Company, as Borrower, the several lenders from time to time parties hereto, The Bank of Tokyo-Mitsubishi, LTD., Chicago Branch and CITIBANK, N.A., as documentation agents, The Bank of New York and Wells Fargo Bank, National Association, as Syndication Agents, and JPMorgan Chase Bank, N.A., as administrative agent, dated as of April 21, 2005 (Exhibit 4.01 to Xcel Energy Form 10-Q for the quarter ended March 31, 2005 (file number 001-03034)).
4.32*		Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, dated July 14, 2005).
4.33		Amendment to the Credit Agreement dated April 21, 2005 between Northern States Power Company and various lenders dated Oct. 31, 2005.
10.01*+		Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+		Xcel Energy Executive Annual Incentive Award Plan (Exhibit B to 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 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 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, 2004 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 Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.22*		Securities Litigation Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.01 to 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 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 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) for the year ended Dec. 31, 2004).
10.26*+		Compensation and reimbursement practices for Xcel Energy non-employee directors (Exhibit 10.01 to Xcel Energy Form 10-Q (file no. 001-03034) dated Sept. 30, 2005.
10.27*+		Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2005 (Exhibit 10.27 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.28*+		Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.28 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.29*+		Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.30*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.31*+		Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.32*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.33*		Xcel Energy Omnibus 2005 Incentive Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.34*		Xcel Energy Executive Annual Incentive Award Plan (Exhibit 10.02 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.35*		Xcel Energy Amended Employment Agreement, between Xcel Energy Inc. and Wayne H. Brunetti (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated June 29, 2005).
10.36*	Xcel Energy Supplemental Executive Retirement Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated Dec. 13, 2005).
10.37+		Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2006
10.38+		Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy
10.39*	Facilities Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (kv) line. (Exhibit 5.06I to file no. 2-54310).
10.40*	Transactions Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06J to file no. 2-54310).
10.41*	Coordinating Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06K to file no. 2-54310).
10.42*	Ownership and Operating Agreement, dated March 11, 1982, between Northern States Power Co. (a Minnesota corporation), Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.43*	Power Agreement, dated June 14, 1984, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.44*	Power Agreement, dated August 1988, between Northern States Power Co. (a Minnesota corporation) and Minnkota Power Co. (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).
10.45*	Assignment and Assumption Agreement, dated Aug. 18, 2000 between Northern States Power Co. (a Minnesota corporation) and Xcel Energy Inc. (Exhibit 10.08 to Form 10 of NSP-Minnesota, file no. 000-31709).
10.46*	Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly

SCHEDULE II

NSP-MINNESOTA
VALUATION AND QUALIFYING ACCOUNTS
Years Ended Dec. 31, 2005, 2004 and 2003

(Thousands of Dollars)

			Additions
	Balance at beginning of period		Charged to costs & expenses		Charged to other accounts (1)		Deductions from reserves(2)		Balance at end of period
Reserve deducted from related assets:
Provision for uncollectible accounts:
2005	$	7,845	$	13,997	$	4,089	$	15,803	$	10,128
2004	$	7,581	$	15,688	$	4,077	$	19,501	$	7,845
2003	$	5,812	$	11,762	$	4,066	$	14,059	$	7,581

(1) Recovery of amounts previously written off.

(2) Principally uncollectible accounts written off or transferred.

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

COMPANY OVERVIEW

ELECTRIC UTILITY OPERATIONS

Summary of Recent Federal Regulatory Developments

NSP-Minnesota Electric Operating Statistics

Summary of Recent Regulatory Developments

Ratemaking Principles

EMPLOYEES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Projected Benefit Payments

Types of and Accounting for Derivative Instruments

Cash Flow Hedges

Letters of Credit

Environmental Contingencies

Asset Retirement Obligations

SCHEDULE II

NORTHERN STATES POWER COMPANY — MINNESOTA

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

NSP-MINNESOTA CAUTIONARY FACTORS

PART I
Item 1 — Business
DEFINITIONS
COMPANY OVERVIEW
ELECTRIC UTILITY OPERATIONS
Summary of Recent Regulatory Developments
General Electric Utility Pending Regulatory Matters
Ratemaking Principles
Capacity and Demand
Energy Sources
Fuel Supply and Costs
Trading Operations
Nuclear Power Operations and Waste Disposal
Electric Operating Statistics
NATURAL GAS UTILITY OPERATIONS
Summary of Recent Regulatory Developments
Ratemaking Principles
Capability and Demand
Natural Gas Supply and Costs
Natural Gas Operating Statistics
ENVIRONMENTAL MATTERS
EMPLOYEES
Item 2 — Properties
Item 3 — Legal Proceedings
Item 4 — Submission of Matters to a Vote of Security Holders

PART II
Item 5 — Market for Registrant’s Common Equity and Related Stockholder Matters
Item 6 — Selected Financial Data
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Item 8 — Financial Statements and Supplementary Data
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A — Controls and Procedures
Item 9B — Other Information

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

PART IV
Item 15 — Exhibits, Financial Statement Schedules

SIGNATURES

/S/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 24, 2006

		known as Norenco Corp.) and Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.33 to NRG’s Registration on Form S-1, file no. 333-35096).
10.47*		Operations and maintenance agreement dated Nov. 1, 1996 between NRG Energy and Northern States Power Co. (a Minnesota corporation). (Exhibit 10.34 to NRG’s Registration on Form S-1, file no. 333-35096).
10.48*		Amended Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.36 to NRG’s Registration on Form S-1, file no. 333-35096).
10.49*		Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.50*		500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no.001-31387) dated March 25, 2003).
12.01		Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01		Consent of Independent Registered Public Accounting Firm.
31.01		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

	NORTHERN STATES POWER COMPANY

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

February 24, 2006

/s/ RICHARD C. KELLY		/s/ CYNTHIA L. LESHER
Richard C. Kelly Chairman and Director (Principal Executive Officer)		Cynthia L. Lesher President, Chief Executive Officer and Director (Principal Operating Officer)

/s/ GARY R. JOHNSON		/s/ BENJAMIN G.S. FOWKE III
Gary R. Johnson Vice President, General Counsel and Director		Benjamin G.S. Fowke III Vice President, Chief Financial Officer and Director (Principal Financial Officer)

/s/ PAUL J. BONAVIA		/s/ TERESA S. MADDEN
Paul J. Bonavia Vice President and Director		Teresa S. Madden Vice President and Controller (Principal Accounting Officer)

/s/ PATRICIA K. VINCENT
Patricia K. Vincent Vice President and Director

	/s/ CYNTHIA L. LESHER
	Cynthia L. Lesher
	President and Chief Executive Officer

Date: February 24, 2006

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

Date: February 24, 2006

2005	$	8.90
2004	$	6.88
2003	$	5.47