**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

 

**(MarkOne)**

| **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 itscharter)

 

| **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, includingarea code)

 

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

 

Securities registered pursuant toSection 12(g) of the Act:**  Common Stock**

 

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

 

Indicate by check mark if the registrant isnot required to file reports pursuant to Section 13 or Section 15(d) of theExchange Act.  Yes  o    No  ý

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant toItem 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 informationstatements incorporated by reference in Part III of this Form 10-K or anyamendment to this Form 10-K. ý

 

Indicate by check mark whether the registrant is a large acceleratedfiler, an accelerated filer or a non-accelerated filer (as defined in Rule12b-2 of the Act).  oLarge accelerated filer            oAccelerated filer

 ýNon-accelerated filer

 

Indicate by check mark whether the registrant is a shell company (asdefined 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 $0.01per share, were outstanding, all of which were held by Xcel Energy Inc., aMinnesota Corporation.

 

**DOCUMENTS INCORPORATED BY REFERENCE: XcelEnergy Inc.’s 2006 Proxy Statement**

 

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

 

 

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**INDEX**

 
| **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**                                                                                            |   |

 

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

 

2

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**PART I**

 

**Item l — Business**

 

# **DEFINITION OFABBREVIATIONS 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.                                                                                                                                     |
|                                                       |   |                                                                                                                                                                                                                                                                                                                                                                                                                |

 

3

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| ***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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |

 

4

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| 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.                                                                                          |

 

5

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# **COMPANY OVERVIEW**

 

NSP-Minnesota wasincorporated in 2000 under the laws of Minnesota. Prior to 2000, the regulatedutility operations were conducted by the legal entity now operating under thename Xcel Energy Inc. NSP-Minnesota is an operating utility engaged in thegeneration, purchase, transmission, distribution and sale of electricity inMinnesota, North Dakota and South Dakota. NSP-Minnesota also purchases, distributes and sells natural gas toretail customers and transports customer-owned natural gas in Minnesota and NorthDakota.  NSP-Minnesota provides electricutility service to approximately 1.3 million customers and gas utility serviceto approximately 457,000 customers.

 

The electric productionand transmission system of NSP-Minnesota is managed as an integrated systemwith that of NSP-Wisconsin, jointly referred to as the NSP System. The electricproduction and transmission costs of the entire NSP System are shared byNSP-Minnesota and NSP-Wisconsin.  A FERCapproved agreement between the two companies, called the Interchange Agreement,provides for the sharing of all costs of generation and transmission facilitiesof the NSP System, including capital costs.

 

NSP-Minnesota owns thefollowing direct subsidiaries: United Power and Land Co., which holds realestate; and NSP Nuclear Corp., which holds NSP-Minnesota’s interest in theNuclear Management Co. (NMC).  NSPFinancing I, a formal special purpose financing trust of NSP-Minnesota, wasdissolved in September 2003. NSP-Minnesota is a wholly owned subsidiary of Xcel Energy.

 

Xcel Energy was incorporatedunder the laws of Minnesota. Historically, Xcel Energy has been a registered holding company underthe Public Utility Holding Company Act of 1935 (PUHCA).  As a registeredholding company, Xcel Energy, its utility subsidiaries and certain of itsnon-utility subsidiaries have been subject to extensive regulation by the SECunder PUHCA with respect to numerous matters, including issuances and sales ofsecurities, acquisitions and sales of certain utility properties, payments ofdividends out of capital and surplus, and intra-system sales of certainnon-power goods and services.  Inaddition, the PUHCA generally limited the ability of registered holdingcompanies to acquire additional public utility systems and to acquire andretain businesses unrelated to the utility operations of the holding company.

 

On August 8, 2005, PresidentBush signed into law the Energy Policy Act of 2005 (Energy Act), significantlychanging many federal statutes and repealing PUHCA as of February 8, 2006.  As part of the repeal of PUHCA, FERC wasgiven more authority over the merger and acquisition of public utilities andmore 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 regulatoryburdens and give it more flexibility in the event it were to choose to expandits utility or non-utility businesses.

 

Besides repealing PUHCA, theEnergy Act is also expected to have substantial long-term effects on energymarkets, energy investment and regulation of public utilities and holdingcompany systems by the FERC and DOE. FERC and DOE are in various stages of rulemaking in implementing theEnergy Act.  While the precise impact ofthese rulemakings cannot be determined at this time, NSP-Minnesota generallyviews the Energy Act as legislation that will enhance the utility industrygoing forward.

 

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

 

# **ELECTRICUTILITY OPERATIONS**

# ** **

**Overview**

 

***Utility Industry Growth***—NSP-Minnesota intends to focus on growing through investments in electric and natural gas rate base to meet growingcustomer demands and to maintain or increase reliability and quality of serviceto customers and through rate case filings with state and federal regulators toincrease rates congruent with increasing costs of operations associated withsuch investments.

 

***Utility Restructuring and Retail Competition***—The structure of the utility industry has been subject to change.  Merger and acquisition activity has beensignificant as utilities combined to capture economies of scale or establish astrategic niche in preparing for the future. Beginning in the late 1990s, many states began studying or implementingsome form of retail electric utility competition.

 

The retail electricbusiness does face some competition as industrial and large commercialcustomers have some ability to own or operate facilities to generate their ownelectricity. In addition, customers may have the option of substituting otherfuels, such as natural gas or steam/chilled water for heating, cooling andmanufacturing purposes, or the option of relocating their facilities to a lowercost region.  While NSP-Minnesota facesthese challenges, it believes its rates are competitive with currentlyavailable alternatives.

 

6

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# **Summaryof Recent Federal Regulatory Developments**

 

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

 

***FERC RulesImplementing Energy Act*** - As noted previously, theEnergy Act repealed PUHCA effective Feb. 8, 2006.  In addition, the Energy Act required the FERCto conduct several rulemakings to adopt new regulations to implement variousaspects of the Energy Act.  Since Aug.2005, the FERC has completed or initiated the proceedings to modify itsregulations on a number of subjects, including:

 

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

•              Adopting newregulations to implement changes to the FERC’s merger and asset transferauthority under Section 203 of the Federal Power Act;

•              Adopting new “marketmanipulation regulations” prohibiting any“manipulative or deceptive device or contrivance” in wholesale natural gas andelectricity commodity and transportation or transmission markets andinterpreting 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 perday;

•              Adopting regulationsto establish a national Electric Reliability Organization (ERO) to replace thevoluntary North American Electric Reliability Council (NERC) structure, andrequiring the ERO to establish mandatory reliability standards and impositionof financial or other penalties for violations of adopted standards; NERC isexpected to apply to become designated as the ERO later in 2006;

•              Adopting rules toimplement changes to the Public Regulatory Policy Act of 1978 (PURPA) to allowutility ownership of Qualifying Facilities (QFs) and strengthening the thermalenergy requirements for entities seeking to be QFs;

•              Proposing rules thatwould allow a utility to seek to eliminate its mandatory QF power purchaseobligation for utilities in organized wholesale energy markets;

•              Proposing rules toestablish incentives for investment in new electric transmissioninfrastructure.

 

NSP-Minnesota generallysupports the regulations adopted or proposed by FERC to date, but cannotpredict the ultimate impact the new regulations will have on its operations orfinancial results.

 

***Market-Based Rate Authority***— The FERC regulates the wholesale sale ofelectricity.  In order to obtainmarket-based rate authorization from the FERC, utilities such as NSP-Minnesota,are required to submit analyses demonstrating that they did not have marketpower in the relevant markets. NSP-Minnesota was previously granted market-based rate authority by theFERC.  However, the FERC hassubsequently modified its standards making it more difficult for utilities todemonstrate that they do not have market power and thus more difficult toobtain market-based rate authority, particularly in their own serviceterritories.

 

On Feb. 7,2005, Xcel Energy on behalf of itself and the utility subsidiaries filed anupdated market-power analysis that applied FERC’s new standards.  This analysis demonstrated thatNSP-Minnesota passed the pivotal supplier analysis in its own control area andall adjacent markets, but failed the market share analysis in its own controlarea, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointly operatea single control area and accordingly are analyzed as one company, in certainadjacent markets.

 

In June 2005,the FERC initiated a proceeding regarding the market-based rate authorityapplication. Because of the commencement of the MISO Day 2 market, discussedbelow, and the FERC’s decision consistent with other precedent to analyzeNSP-Minnesota and NSP- Wisconsin as part of that larger market, FERC authorizedcontinuation of NSP-Minnesota’s and NSP-Wisconsin’s market-based rateauthority.  However, the FERC requiredthat Xcel Energy make a compliance filing providing information, includinginformation regarding the FERC’s affiliate abuse component of its market poweranalysis and the allegations regarding that component made by an intervenorwithin 30 days of the date of issuance of its order.  The latter compliance filing was submitted onJuly 5, 2005.

 

***Electric Transmission Rate Regulation***— The FERC also regulates the rates chargedand terms and conditions for electric transmission services.  FERC policy encourages utilities to turn overthe functional control over their electric transmission assets and the related responsibilityfor the sale of electric transmission services to an RTO.  NSP-Minnesota is a member of the MISO, whichbegan RTO operations in early 2002.  EachRTO separately files for regional transmission tariff rates for approval byFERC.  All members within that RTO arethen subjected to those rates.

 

***Centralized Regional Wholesale Markets*** – FERC rules require RTO’s to operatecentralized regional wholesale energy markets. The FERC required the MISO to begin operation of a “Day 2” energy marketon April 1, 2005.  MISO uses securityconstrained regional economic dispatch and congestion management usinglocational marginal pricing (LMP) and FTR’s. The Day 2 market is intended to provide more efficient generationdispatch over the 15 state MISO region.

 

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**Ratemaking Principles**

 

***Summary of Regulatory Agencies and Areas of Jurisdiction***— Retail rates, services and other aspects ofNSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUCwithin their respective states. The MPUC has regulatory authority over aspectsof NSP-Minnesota’s financial activities, including security issuances, certainproperty transfers, mergers with other utilities and transactions betweenNSP-Minnesota and its affiliates. In addition, the MPUC reviews and approvesNSP-Minnesota’s electric resource plans for meeting customers’ future energyneeds. The MPUC also certifies the need for generating plants greater than 50MW and transmission lines greater than 100 KV. NSP-Minnesota is subject to thejurisdiction of the FERC with respect to its wholesale electric operations,accounting practices, wholesale sales for resale and the transmission ofelectricity in interstate commerce. NSP-Minnesota has received authorizationfrom the FERC to make wholesale electric sales at market-based prices (seemarket-based rate authority discussion) and is a transmission-owner member ofthe MISO RTO.

 

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

 

***Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms*** — NSP-Minnesota’s retail electric rateschedules in Minnesota, North Dakota and South Dakota include a FCA thatprovides for monthly adjustments to billings and revenues for changes inprudently incurred cost of fuel, fuel related items and purchased energy.  NSP-Minnesota is permitted to recover thesecosts through FCA mechanisms individually approved by the regulators in eachjurisdiction.  The FCA mechanisms allowNSP-Minnesota to bill customers for the cost of fuel and fuel related costsused to generate electricity at its plants and energy purchased from othersuppliers.  With NSP-Minnesota’sparticipation in the MISO Day 2 market, questions have been raised regardingthe inclusion of certain MISO charges in the FCA.  For further discussion, see NSP-MinnesotaPending and Recently Concluded Regulatory Proceedings – MPUC.  In general, capacity costs are not recoveredthrough the FCA.  NSP-Minnesota’selectric wholesale customers also have a FCA provision in their contracts.

 

NSP-Minnesota is required byMinnesota law to spend a minimum of 2 percent of Minnesota electric revenue onconservation improvement programs.  Thesecosts are recovered through an annual cost recovery mechanism for electric conservationand energy management program expenditures. NSP-Minnesota is required torequest a new cost recovery level annually.

 

***Performance-Based Regulation***— In December 2003, the MPUC voted to approveNSP-Minnesota’s MERP proposal to convert two coal-fueled electric generatingplants to natural gas, and to install advanced pollution control equipment at athird coal-fired plant.  All three plantsare located in the Minneapolis - St. Paul metropolitan area. These improvementsare expected to significantly reduce air emissions from these facilities, whileincreasing the capacity at system peak by 300 MW. The projects are expected tocome on line between 2007 and 2009, at a cumulative investment of approximately$1 billion.  The MPUC also approvedNSP-Minnesota’s proposal to recover prudent costs of the projects through arate 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 scalebased on actual construction cost compared with a target level of constructioncosts (based on an equity ratio of 48.5 percent and a debt ratio of 51.5percent) 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    | %          |

 

***Pendingand Recently Concluded Regulatory Proceedings***- FERC

*** ***

***MISO Operations —***NSP-Minnesota is a member of the MISO. TheMISO is an RTO that provides regional transmission tariff administrationservices for electric transmission systems, including those ofNSP-Minnesota.  In 2002, NSP-Minnesotareceived all required regulatory approvals to transfer functional control oftheir high voltage (100 KV and above) transmission systems to the MISO.  The MISO membership grants MISO functionalcontrol over the operations of these facilities and the facilities of certainneighboring electric utilities.

 

On April 1, 2005, MISO initiated a regional wholesale energymarket using LMP and FTR’s Day 2 market pursuant to its TEMT.  While it is anticipated the Day 2 market willprovide efficiencies through a region-wide generation dispatch and increasedreliability, as well as long-term benefits through dispatch of power from themost cost-effective sources of generation or transmission, there are 

 

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

 

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

 

New business processes, systems and internal controls over financialreporting were planned and implemented by Xcel Energy and MISO during thesecond quarter of 2005 to conduct business within the MISO Day 2 market.  Xcel Energy continues to validate thesechanges and to review the energy costs and revenues determined by MISO.  Xcel Energy and other market participantshave disputed certain transactions.

 

***MISO Long Term Transmission Pricing***-On Oct. 7, 2005, MISO filed proposed tariff revisions that would allow MISO toregionalize the cost of certain future high voltage transmission lines owned byspecific transmission owners but constructed pursuant to the MISO transmissionexpansion plan.  The proposed tariffsreflect stakeholder input to MISO.  MISOproposed the tariff revisions be effective on Feb. 4, 2006.  Xcel Energy generally supports the proposedtariff revisions, which should encourage transmission construction byregionalizing a share of the cost of projects providing regional benefits.  Comments on or protests to the proposedtariff revisions were filed at FERC in late 2005.  In February 2006, the FERC issued an orderaccepting the tariff revisions, subject to modifications and additionalprocedures.  Xcel Energy cannot predictthe 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 planproviding for continued use of “license plate” rates for the MISO/PJM region,but rejecting proposed transition payments to compensate transmission ownersfor reductions in transmission revenues. FERC instead ordered the MISO and PJM to file a Seams Elimination ChargeAdjustment (SECA) transition mechanism. The replacement compliance filings were effective Dec. 1, 2004.  The FERC order eliminates any transitionpayments and the SECA filings instead provide for both revenues and paymentsthat net to approximately $86,000 in revenues per month to NSP-Minnesota andNSP-Wisconsin in 2005.

 

Various parties soughtrehearing 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 theFERC.  Certain parties have proposed aregional average transition charge, which could shift costs to NSP-Minnesotaand NSP-Wisconsin, effective Dec. 1, 2004. Xcel Energy has opposed these regionalized approaches.  The final FERC decision is expected to beissued by year-end 2006.  Under the FERCorders, the SECA transition charges are set to expire Mar. 31, 2006.

 

***Pendingand Recently Concluded Regulatory Proceedings***- MPUC

*** ***

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

 

•              March 2nd– Intervenor Direct Testimony

•              March 30th– Rebuttal Testimony

•              April 13th– Surrebuttal Testimony

•              April 20th– April 28th – Evidentiary Hearings

•              May 24th –Initial Briefs

•              June 6th –Reply Briefs

•              July 6th –Administrative Law Judge Report

•              September5th – MPUC Order

 

***Renewable Transmission Cost Recovery****—*In 2002, NSP-Minnesota filed for MPUCapproval to establish an RCR adjustment mechanism to recover the costs oftransmission investments incurred to deliver renewable energy resources.  The RCR adjustment mechanism provides forannual filings to set the RCR adjustment rates using updated transmission costinformation.  The MPUC approved the RCRadjustment mechanism and the two-phase filing mechanism in April 2003.  In February 2004, the MPUC conditionallyapproved the initial Phase 1 facility eligibility determination filing.  NSP-Minnesota then filed for approval torecover annual additional transmission costs from May 2004 to December 2004,which were approximately $6 million. The request was approved and the RCR wasimplemented Dec. 1, 2004.  NSP-Minnesotacollected approximately $0.2 million in 2004. NSP-Minnesota submitted a filing in February 2005 to determine theeligibility of additional transmission projects and to establish the RCRfactors for 2005, seeking recovery of $12.9 million of additional revenues in2005.  The MPUC approved revised factorsby order dated Jan. 9, 2006, and NSP-Minnesota submitted its compliance filingin late January 2006 for rates to be effective Mar. 1, 2006.  In 

 

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

 

***MISO Cost Recovery***—On Dec. 18, 2004, NSP-Minnesota filed with the MPUC a petition to seek recoveryof the Minnesota jurisdictional portion of all net costs associated with theimplementation of the MISO Day 2 market through its FCA.  The MPUC issued an interim order in April2005 allowing MISO Day 2 charges to be recovered through the NSP-Minnesota FCAmechanism, subject to refund. In December 2005, the MPUC issued a secondinterim order approving the recovery of certain MISO charges through the FCAmechanism but requiring that additional charges either be recovered as part ofa general rate case or through an annual review process outside the FCAmechanism, and requiring refunds of non-FCA costs.  The December 2005 MPUC order also suspendedthe refund obligation until such time as it could reconsider the matter,however.  On Feb. 9, 2006, the MPUC votedto reconsider its December 2005 order. The MPUC on reconsideration determined that parties be directed todetermine which charges are appropriately in the FCA and which are moreappropriately established in base rates and report back to the MPUC in 60 days;to grant deferred accounting treatment for costs ultimately determined to beincluded in base rates for a period of 36 months, with recovery of deferredamounts to be reviewed in a general rate case; and that amounts collected todate through the FCA under the April and December 2005 interim orders are notsubject to refund.  As a result,NSP-Minnesota expects to have the opportunity to recover (or seek to recover ina rate case) all of its MISO Day 2 costs.

 

In addition, in March 2005, NSP-Minnesota filed petitions similar tothe December 2004 Minnesota filing with the NDPSC and the SDPUC proposingchanges to allow recovery of the applicable North Dakota and South Dakotajurisdictional portions of the MISO Day 2 market costs.  The SDPUC approved the proposed tariffchanges effective April 1, 2005, as requested. The NDPSC granted interim recovery through the FCA beginningApril 1, 2005, but similar to the decision of the MPUC, conditioned therelief as being subject to refund until the merits of the case aredetermined.  To date, the NDPSC hasconducted no further proceedings regarding the NSP-Minnesota filing.

 

***Energy Legislation***—******In 2005, MinnesotaLegislature passed and the Governor signed an Omnibus Energy Bill, effectiveJuly 1, 2005.  Among other things,the new law provides authority for the MPUC to approve rate rider recovery fortransmission investments that have been approved through a certificate of need,the biennial transmission plan, or are associated with compliance with thestate’s renewable energy objective.  Thestatute provides that the rate rider may include recovery of the revenuerequirement associated with qualifying projects, including a current return onconstruction work in progress. NSP-Minnesota is currently preparing a filing to the MPUC for approvalof a new tariff to implement this statute.

 

**Capacityand Demand**

 

Uninterrupted system peakdemand for the NSP System’s electric utility for each of the last three yearsand 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 NSPSystem typically occurs in the summer. The 2005 uninterrupted system peakdemand for the NSP System occurred on June 23, 2005.

 

**Energy Sources and Related Initiatives**

 

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

 

***Purchased Power***— NSP-Minnesota has contractual arrangements to purchase power fromother utilities and nonregulated energy suppliers. Capacity, typically measuredin KW or MW, is the measure of the rate at which a particular generating sourceproduces electricity. Energy, typically measured in Kwh or Mwh, is a measure ofthe amount of electricity produced from a particular generating source over aperiod of time. Long-term purchase power contracts typically require a periodicpayment to secure the capacity from a particular generating source and a chargefor the associated energy actually purchased from such generating source.

 

NSP-Minnesota also makes short-termfirm and non-firm purchases to replace generation from company-owned units thatare unavailable due to maintenance and unplanned outages, to provide theutility’s reserve obligation, to obtain energy at a lower cost than that whichcould be produced by other resource options, including company-owned generationand/or long-term purchase power contracts, and for various other operatingrequirements.

 

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On Dec. 27,2005, Excelsior Energy Inc. (Excelsior), an independent energy developer, fileda petition with the MPUC seeking to compel NSP-Minnesota to enter into a powerpurchase agreement related to its proposed integrated gasification,combined-cycle power plant (Mesaba project) that would be located in northernMinnesota.  The petition requested theMPUC determine the proposed purchase is in the public interest and that thetechnology proposed for the Mesaba Project, which Excelsior claims is a “cleanenergy technology” under Minnesota law, is or is likely to be a least-costresource pursuant to Minnesota law. NSP-Minnesota has not been provided a full, unredacted copy of theproposed power purchase agreement and has not entered into the power purchaseagreement with Excelsior.  The petitionseeks to compel NSP-Minnesota to purchase at least 13 percent of NSP-Minnesota’selectric energy provided to retail customers from the Mesaba Project, whichExcelsior claims would require two units of its Mesaba Project each proposed at603 MW.  Excelsior’s filing asserts muchof its proposal is confidential under the MPUC’s rules, including the pricingand other economic terms.  NSP-Minnesotais seeking access to the confidential information.  The MPUC asked for comments on the processfor the filing and comments on the ability to obtain information filed underconfidential protection.  NSP-Minnesotahas asked the MPUC to first resolve issues surrounding the confidentialinformation, then to address legal issues surrounding the proposal and afterresolution of those issues, to consider the proposal in light of its legalconclusions.

 

***NSP System Resource Plan***— On Nov. 1, 2004, NSP-Minnesota filed its 2004 resource plan withMPUC.  The resource plan projects a needfor 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, orapproximately 170 MW per year, during the period.  The resource plan:

 

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

•              recommends a new resource acquisition processthat includes multiple options for consideration, including generation built byNSP-Minnesota;

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

•              recommends extending the operating licensesfor 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 dryspent-fuel storage facility at the Monticello plant, and plans to file anapplication with the federal government to extend the Monticello plant’slicense and to make similar filings for the Prairie Island plant in 2008);

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

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

•              cites the importance of ensuring thatsufficient transmission resources are available to move electricity fromgeneration sources.

 

On Aug. 1, 2005, theMinnesota Department of Commerce filed comments that NSP-Minnesota hadoverestimated its forecast and that there was no need for new resources until2015.  Other parties filed variouscomments relating to the environmental impacts of the plan, the use ofrenewable fuels, the need to construct a 600 MW integrated gasificationcombined-cycle facility in Northern Minnesota, and the NSP-Minnesota’smonitoring of the Northern Flood Agreement between the Province of Manitoba andvarious Canadian First Nations.

 

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

 

***NSP-Minnesota Transmission Certificates of Need***— In December 2001, NSP-Minnesota proposedconstruction of various transmission system upgrades to provide transmissionoutlet capacity for up to 825 MW of renewable energy generation (wind andbiomass) being constructed in southwest and western Minnesota.  In March 2003, the MPUC granted fourcertificates of need to NSP-Minnesota, thereby approving construction, subjectto certain conditions. The initial projected cost of the transmission upgradeswas approximately $160 million.  The MEQBgranted a routing permit for the first major transmission facilities in thedevelopment program in 2004.  Theremaining route permit proceedings were completed in 2005.  In 2003, the MPUC also approved an RCRadjustment that allows NSP-Minnesota to recover the revenue requirementsassociated with certain transmission investments associated with delivery ofrenewable energy resources through an automatic adjustment mechanism thatstarted in 2004.  See the Pending andRecently Concluded Regulatory Proceedings — MPUC, Renewable Transmission CostRecovery section for further discussion.

 

***Purchased Transmission Services***—NSP-Minnesota and NSP-Wisconsin havecontractual arrangements with MISO to deliver power and energy to NSP Systemnative load customers.  Point-to-pointtransmission services typically include a charge for the specific amount oftransmission capacity being reserved. Network transmission services include acharge based on the transmission customer’s monthly peak demand.

 

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

 

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Prairie Island plant. Seeadditional discussion regarding the nuclear generating plants at Note 12 to theConsolidated Financial Statements.

 

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

 

*Low-LevelRadioactive Waste Disposal**—***Federal law places responsibility on eachstate for disposal of its low-level radioactive waste generated within itsborders. Low-level radioactive waste from NSP-Minnesota’s Monticello andPrairie Island nuclear plants is currently disposed at the Barnwell facilitylocated in South Carolina (all classes of low-level waste)and at the Clivefacility located in Utah (class A low-level substance only). Chem Nuclear isthe owner and operator of the Barnwell facility, which has been givenauthorization by South Carolina to accept low-level radioactive waste fromstates that are not a member of South Carolina’s state compact.  Envirocare, Inc. operates the Clivefacility.  NSP-Minnesota has an annualcontract with Barnwell, but is also able to utilize the Envirocare facilitythrough various low-level waste processors. NSP-Minnesota has low-level storage capacity available on-site atPrairie Island and Monticello that would allow both plants to continue tooperate until the end of their licensed lives, if off-site low-level disposalfacilities were not available to NSP-Minnesota.

 

*High-LevelRadioactive Waste Disposal**—***The federal government has the responsibilityto dispose of, or permanently store, domestic spent nuclear fuel and otherhigh-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE toimplement a program for nuclear high level waste management. This includes thesiting, licensing, construction and operation of a repository for domesticallyproduced spent nuclear fuel from civilian nuclear power reactors and otherhigh-level radioactive wastes at a permanent Federal storage or disposalfacility. To date, the DOE has not accepted any of NSP-Minnesota’s spentnuclear fuel.  See Item 3 — LegalProceedings and Note 11 to the Consolidated Financial Statements for furtherdiscussion of this matter.

 

NSP-Minnesota has on-sitestorage for spent nuclear fuel at its Monticello and Prairie Island nuclearplants. In 1993, the Prairie Island plant was licensed by the federal NRC tostore up to 48 casks of spent fuel at the plant. In 1994, the MinnesotaLegislature adopted a limit on dry cask storage of 17 casks for the entirestate.  On May 29, 2003, the MinnesotaLegislature enacted revised legislation that will allow NSP-Minnesota tocontinue to operate the facility and store spent fuel there until its currentlicenses with NRC expire in 2013 and 2014. The legislation transfers theprimary authority concerning future spent-fuel storage issues from the stateLegislature to the MPUC. It also allows for additional storage without therequirement of an affirmative vote from the state Legislature, if the NRCextends the licenses of the Prairie Island and Monticello plants and the MPUCgrants a certificate of need for such additional storage. It is estimated thatoperation through the end of the current license will require 12 additionalstorage casks to be stored at the plant, for a total of 29 casks.  As of Dec. 31, 2005, there were 20 casksloaded and stored at the Prairie Island plant. See Note 11 in the ConsolidatedFinancial Statements for further discussion of the matter.

 

*VisualInspections**—***Required visual inspections have beenperformed 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 bein compliance with all NRC requirements. The reactor vessel upper head forPrairie Island Unit 2 was replaced during the 2005 refueling outage, and XcelEnergy expects to replace the reactor vessel upper head for Prairie Island Unit1 in early 2006.

 

*PrivateFuel Storage (PFS)**—***NSP-Minnesota is part of a consortium ofprivate parties working to establish a private facility for interim storage ofspent nuclear fuel. In 1997, PFS filed a license application with the NRC for atemporary storage site for spent nuclear fuel on the Skull Valley IndianReservation in Utah. The NRC license review process includes formal evidentiaryhearings 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 Courtdenied Utah’s petition for a writ of certiorari to hear an appeal of a lowercourt’s ruling on a series of state statutes aimed at blocking the storage andtransportation of spent fuel to PFS. Also in December 2005, NSP-Minnesotaforwarded a letter to Senator Hatch (UT) indicating that it would hold inabeyance future investments in the construction of PFS as long as there isapparent and continuing progress in federally sponsored initiatives forstorage, reuse, and/or disposal for the nation’s spent nuclear fuel.

 

*PrairieIsland Steam Generator Replacement**—***In the fall of 2004, NSP-Minnesota spent approximately$132 million to successfully replace the Prairie Island Unit 1 steamgenerators.  The Unit 2 steam generatorshave not yet been replaced but received the required inspections during thescheduled 2005 outage. Based on current rates of degradation and availablerepair processes, NSP-Minnesota plans to replace these steam generators in the2013 regular refueling outage. Due to the potential shortages in the worldmarkets for materials and shop capabilities, NSP-Minnesota expects to begin theapproval process in 2006 for long-lead time materials.

 

*NSP-Minnesota Nuclear Plant Re-licensing* — Monticello’s current 40-year licenseexpires in 2010, and Prairie Island’s licenses for its two units expire in 2013and 2014.  In March 2005, NSP-Minnesotafiled its application with the NRC for an operating license extension forMonticello of up to 20 years. NSP-Minnesota filed its application with the MPUC for Monticello inJanuary 2005 seeking a certificate of need for dry spent fuel storage.Decisions by both the federal and state agencies regarding Monticellore-licensing are expected in early 2007. Prairie Island has initiated thenecessary plant assessments and aging analysis to support submittal of similarapplications to the NRC and Minnesota, currently planned for submittal in early2008.

 

*NuclearManagement Co. (NMC)*****—During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin PublicService 

 

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Corporation (WPS) andAlliant Energy Corp. established NMC. The Consumers Power subsidiary of CMSEnergy Corp. joined the NMC during 2000.

 

NMC manages the operationsand maintenance at the plants, and is responsible for physical security. NMC’sresponsibilities also include oversight of on-site dry storage facilities forused nuclear fuel at the Prairie Island nuclear plant. Utility plant owners,including NSP-Minnesota, continue to own the plants, control all energyproduced by the plants, and retain responsibility for nuclear liabilityinsurance and decommissioning costs.

 

In 2005 and 2006, as aresult of selling their nuclear plants, WPS and Alliant Energy ended thierparticipation in NMC.  In December 2005,Consumer Power announced its intent to sell its nuclear plant, which will leaveNSP-Minnesota and Wisconsin Electric Power Co. as the remaining members of theNMC, with a combined total of 3 sites and 5 reactors. NMC is in the process ofidentifying and marketing its services to other potential nuclear utilitycandidates to replace the departing members.

 

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

 

**Fuel Supplyand Costs**

 

The following table showsthe delivered cost per MMBtu of each significant category of fuel consumed forelectric generation, the percentage of total fuel requirements represented byeach category of fuel and the total weighted average cost of all fuels duringsuch years.

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

 

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*Includes refuse-derivedfuel and wood

 

See additionaldiscussion of fuel supply and costs under Risks associated with Our Businessunder Item 1A.

 

***Fuel Sources***— Coal inventory levels may vary widely among plants.  However, the NSP System normally maintains noless than 30 days of coal inventory at each plant site.  Estimated coal requirements at NSP-Minnesotaand NSP-Wisconsin’s major coal-fired generating plants are approximately 13.3million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contractsproviding for the delivery of up to 99 percent of 2006 coal requirements. Coaldelivery may be subject to short-term interruptions or reductions due totransportation problems, weather, and availability of equipment.

 

NSP-Minnesota andNSP-Wisconsin expect that all of the coal burned in 2006 will have an averagesulfur content of less than 0.75 percent. The NSP System has contracts for a maximum of 35.8 million tons oflow-sulfur coal for the next 3 years. The contracts are with 1 Montana coal supplier, 3 Wyoming suppliers and 1Minnesota oil refinery, with expiration dates in 2006 and 2007.

 

To operate NSP-Minnesota’snuclear generating plants, NSP-Minnesota secures contracts for uraniumconcentrates, uranium conversion, uranium enrichment and fuel fabrication. Thecontract strategy involves a portfolio of spot purchases and medium- andlong-term contracts for uranium, conversion and enrichment.

 

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

•              Current contracts for conversion servicesrequirements cover 100 percent of the requirements for 2006 and 53 percent for2007.  Approximately 43 percent of the requirementsare covered for 2008 through 2010 with no current coverage of requirements for2011 and beyond.  A contract with anadditional conversion services supplier is nearing completion that is expectedto provide additional coverage for 2007 through 2011.

•              Current enrichment services contracts cover100 percent of the 2006 requirements. Approximately 30 percent of the 2007 through 2010 requirements arecurrently covered with no coverage of requirements for 2011 and beyond.  These current contracts expire at varyingtimes between 2006 and 2010.  Contractswith additional enrichment services suppliers are currently in various stagesof negotiation that are expected to supply additional coverage from 2007through 2010.

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

 

NSP-Minnesota expectssufficient uranium, conversion and enrichment to be available for the totalfuel requirements of its nuclear generating plants. Contracts for additionaluranium and enrichment services are currently being negotiated that wouldprovide additional supply requirements through 2016 for uranium and 2010 for enrichmentservices.

 

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The NSP System uses bothfirm and interruptible natural gas and standby oil in combustion turbines andcertain boilers.  Natural gas suppliesfor power plants are procured under short-, intermediate- and long-termcontracts which expire in various years from 2006 through 2027 in order toprovide an adequate supply of fuel. Certain natural gas supply and transportation agreements includeobligations for the purchase and/or delivery of specified volumes of naturalgas or to make payments in lieu of delivery. At Dec. 31, 2005, NSP-Minnesota’s commitments related to these contractswere approximately $127 million.  The NSPSystem has current fuel oil inventory adequate to meet anticipated 2006requirements and also has access to the spot market to buy more oil, if needed.

 

**CommodityMarketing Operations**

 

NSP-Minnesota conductsvarious wholesale marketing operations, including the purchase and sale ofelectric capacity, energy and energy related products. Participation inshort-term wholesale energy markets provides market intelligence andinformation that supports the energy management of NSP-Minnesota.  NSP-Minnesota uses physical and financialinstruments to minimize commodity price and credit risk and hedge supplies andpurchases. Engaging in short-term sales and purchase commitments results in anefficient use of our plants and the capturing of additional margins fromnon-traditional customers. NSP-Minnesota also uses these marketing operationsto 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 | ¢ |

 

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**NATURAL GAS UTILITY OPERATIONS**

 

# **Summaryof Recent Regulatory Developments**

 

Changes in regulatorypolicies and market forces have shifted the industry from traditional bundlednatural gas sales service to an unbundled transportation and market-basedcommodity service at the wholesale level and for larger commercial andindustrial retail customers. These customers have greater ability to buynatural gas directly from suppliers and arrange their own pipeline and retailLDC transportation service.

 

The natural gas deliveryand transportation business has remained competitive as industrial and largecommercial customers have the ability to bypass the local natural gas utilitythrough the construction of interconnections directly with interstatepipelines, thereby avoiding the delivery charges added by the local natural gasutility.

 

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

 

The most significant recentdevelopments in the natural gas operations of NSP-Minnesota are the substantialand continuing increases in wholesale natural gas market prices and thecontinued trend toward declining use per customer by residential customers as aresult of improved building construction technologies and higher applianceefficiencies.  From 1995 to 2005, averageannual sales to the typical NSP-Minnesota residential customer declined from112 Dth per year to 96 Dth per year on a weather-normalized basis.  Although recent wholesale price increases donot directly affect earnings because of gas cost recovery mechanisms, the highprices are expected to encourage further efficiency efforts by customers.

 

# **RatemakingPrinciples**

# ** **

***Summary of Regulatory Agencies and Areas of Jurisdiction***— Retail rates, services and other aspects ofNSP-Minnesota’s operations are regulated by the MPUC and the NDPSC within theirrespective states. The MPUC has regulatory authority over aspects ofNSP-Minnesota’s financial activities, including security issuances, certain propertytransfers, mergers with other utilities and transactions between NSP-Minnesotaand its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’sgas supply plans for meeting customers’ future energy needs.

 

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

 

NSP-Minnesota is required byMinnesota law to spend a minimum of 0.5 percent of Minnesota natural gasrevenue on conservation improvement programs. These costs are recovered throughan annual cost recovery mechanism for natural gas conservation and energymanagement program expenditures. NSP-Minnesota is required to request a newcost recovery level annually.

 

***Pending and RecentlyConcluded Regulatory Proceedings***

*** ***

***NSP-MinnesotaNatural 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 11.5percent.  In August 2005, the MPUCapproved an annual rate increase of $5.8 million, based on a return on equityof 10.4 percent.  Final rates becameeffective Dec. 1, 2005.

 

**Capabilityand Demand**

 

Natural gas supplyrequirements are categorized as firm or interruptible (customers with analternate 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 purchasesnatural gas from independent suppliers. The natural gas is delivered undernatural gas transportation agreements with interstate pipelines. Theseagreements provide for firm deliverable pipeline capacity of 521,854 MMBtu/day.In addition, NSP-Minnesota has contracted with providers of underground naturalgas storage services. These storage agreements provide storage for approximately21 percent of winter natural gas requirements and 26 percent of peak day, firmrequirements of NSP-Minnesota.

 

NSP-Minnesota also owns andoperates one LNG plant with a storage capacity of 2.13 Bcf equivalent and threepropane-air plants 

 

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with a storage capacity of1.4 Bcf equivalent to help meet its peak requirements. These peak-shavingfacilities have production capacity equivalent to 250,300 MMBtu of natural gasper day, or approximately 34 percent of peak day firm requirements. LNG andpropane-air plants provide a cost-effective alternative to annual fixedpipeline transportation charges to meet the peaks caused by firm space heatingdemand on extremely cold winter days.

 

NSP-Minnesota is required tofile for a change in natural gas supply contract levels to meet peak demand, toredistribute demand costs among classes or to exchange one form of demand foranother. NSP-Minnesota’s 2004-2005 entitlement levels were approved on July 12,2005 which allow NSP-Minnesota to recover the demand entitlement costsassociated with the increase in transportation, supply, and storage levels inits monthly PGA. In June 2005, NSP-Minnesota also filed to add incrementalstorage to its portfolio.  The increase instorage was approved by the MPUC on Nov. 18, 2005.  The 2005-2006 entitlement levels are pendingMPUC action.

 

**Natural Gas Supply and Costs**

 

NSP-Minnesota actively seeksnatural gas supply, transportation and storage alternatives to yield adiversified portfolio that provides increased flexibility, decreasedinterruption and financial risk, and economical rates. This diversificationinvolves numerous domestic and Canadian supply sources with varied contractlengths.

 

The following tablesummarizes the average cost per MMBtu of natural gas purchased for resale byNSP-Minnesota’s regulated retail natural gas distribution business:

 
| 2005 |   | $ | 8.90 |   |
|------|--------|---|------|--------|
| 2004 |   | $ | 6.88 |   |
| 2003 |   | $ | 5.47 |   |

 

The cost of natural gassupply, transportation service and storage service is recovered through the PGAcost recovery mechanism.

 

NSP-Minnesota has firmnatural gas transportation contracts with several pipelines, which expire invarious years from 2006 through 2027.

 

NSP-Minnesota has certainnatural gas supply and transportation agreements that include obligations forthe purchase and/or delivery of specified volumes of natural gas or to makepayments in lieu of delivery. At Dec. 31, 2005, NSP-Minnesota was committed toapproximately $810 million in such obligations under these contracts.

 

NSP-Minnesota purchases firmnatural gas supply utilizing long-term and short-term agreements fromapproximately 25 domestic and Canadian suppliers. This diversity of suppliersand contract lengths allows NSP-Minnesota to maintain competition fromsuppliers and minimize supply costs.

 

See additional discussion ofnatural gas costs under Factors Affecting Results of Continuing Operations inManagement’s Discussion and Analysis under Item 7.

 

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**NSP-MinnesotaNatural 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’sfacilities are regulated by federal and state environmental agencies. Theseagencies have jurisdiction over air emissions, water quality, wastewaterdischarges, solid wastes and hazardous substances. Various company activitiesrequire registrations, permits, licenses, inspections and approvals from theseagencies.  NSP-Minnesota has received allnecessary authorizations for the construction and continued operation of itsgeneration, transmission and distribution systems. Company facilities have beendesigned and constructed to operate in compliance with applicable environmentalstandards.

 

NSP-Minnesota strives tocomply with all environmental regulations applicable to its operations.However, it is not possible at this time to determine when or to what extentadditional facilities or modifications of existing or planned facilities willbe required as a result of changes to environmental regulations,interpretations or enforcement policies or, generally, what effect future lawsor regulations may have upon NSP-Minnesota’s operations. For more informationon environmental contingencies, see Note 11 to the Consolidated FinancialStatements and the matters discussed below.

 

# **EMPLOYEES**

# ** **

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

 

**Item 1A —Risk Factors**

 

**RisksAssociated with Our Business**

 

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

 

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We are subjectto comprehensive regulation by federal and state utility regulatory agencies,which significantly influences our operating environment and our ability torecover our costs from utility customers. The state utility commissionsregulate many aspects of our operations including siting and construction offacilities, customer service and the rates that we can charge customers.

 

Ourprofitability is dependent on our ability to recover costs related to providingenergy and utility services to our customers. We currently provide service atrates approved by several regulatory commissions.  These rates are generally regulated based onan analysis of the utility’s expenses incurred in a test year.  Thus, the rates we are allowed to charge mayor may not match our expenses at any given time.  While rate regulation is premised onproviding a reasonable opportunity to earn a reasonable rate of return oninvested capital, there can be no assurance that our regulatory commissionswill judge all of our costs to have been prudently incurred or that theregulatory process in which rates are determined will always result in ratesthat will produce full recovery of our costs.  Although we believe that the current regulatory environment applicableto 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 thatwould impair our ability to recover costs historically collected from ourcustomers.

 

The FERC hasjurisdiction over wholesale rates for electric transmission service, electricenergy sold at wholesale in interstate commerce, hydro facility licensing andcertain other activities. Federal, state and local agencies also havejurisdiction over many of our other activities, including regulation of retailrates and environmental matters.

 

We are unableto predict the impact on our operating results from the future regulatoryactivities of any of these agencies. Changes in regulations or the impositionof additional regulations could have an adverse impact on our results ofoperations and hence could materially and adversely affect our ability to meetour financial obligations.

 

***We are subject to commodity price risk, credit risk and other risksassociated with energy markets.***

 

We engage in wholesalesales and purchases of electric capacity, energy and energy-related productsand, accordingly, are subject to commodity price risk, credit risk and otherrisks associated with these activities.

 

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

 

Credit andperformance risk includes the risk that counterparties that owe us money orproduct will breach their obligations. Should the counterparties to thesearrangements fail to perform, we may be forced to enter into alternativearrangements. In that event, our financial results could be adversely affectedand we could incur losses.

 

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

 

***We are subject to environmental laws and regulations, compliance withwhich could be difficult and costly.***

 

We are subject to anumber of environmental laws and regulations affecting many aspects of ourpast, present and future operations, including air emissions, water quality,wastewater discharges and the management of wastes and hazardoussubstances.  These laws and regulationsgenerally require us to obtain and comply with a wide variety of environmentalregistrations, licenses, permits, inspections and other approvals.  Environmental laws and regulations can alsorequire us to perform environmental remediations and to install pollutioncontrol equipment at our facilities. Both public officials and private individuals may seek to enforce theapplicable environmental laws and regulations against us.  We must pay all or a portion of the cost toremediate sites where our past activities, or the activities of certain otherparties, caused environmental contamination. At December 31, 2005, these sites included:

 

• the site of a former federal uraniumenrichment facility;

• the site of former manufactured gasplants 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 senthazardous materials and   wastes.

 

In addition, we cannotassure you that existing environmental laws or regulations will not be revisedor that new laws or regulations seeking to protect the environment will not beadopted or become applicable to us or that we will not identify in the futureconditions that will result in obligations or liabilities under existingenvironmental laws and regulations. Revised or additional laws or 

 

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

 

***We are subject to the risks of nuclear generation.***

 

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

 

•              the risks associatedwith storage, handling and disposal of radioactive materials and the currentlack of a long-term disposal solution for radioactive materials;

•              limitations on theamounts and types of insurance commercially available to cover losses thatmight arise in connection with nuclear operations; and

•              uncertainties withrespect to the technological and financial aspects of decommissioning nuclearplants at the end of their licensed lives.

 

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

 

***Recession, grid disturbances, acts of war or terrorism could negativelyimpact our business.***

 

Theconsequences of a prolonged recession and adverse market conditions may includethe continued uncertainty of energy prices and the capital and commoditymarkets. We cannot predict the impact of any economic slowdown or fluctuatingenergy prices. However, such impact could have a material adverse effect on ourfinancial condition and results of operations.

 

Also, becauseour generation and transmission systems are part of an interconnected regionalgrid, we face the risk of possible loss of business due to a disruption orblack-out caused by an event (severe storm, generator or transmission facilityoutage) 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. andCanada. Any such disruption could result in a significant decrease in revenuesand significant additional costs to repair assets, which could have a materialadverse impact on our financial condition and results of operations.

 

The conflictin Iraq and any other military strikes or sustained military campaign mayaffect our operations in unpredictable ways and may cause changes in the insurancemarkets, force us to increase security measures and cause disruptions of fuelsupplies and markets, particularly with respect to natural gas and purchasedenergy. The possibility that infrastructure facilities, such as electricgeneration, transmission and distribution facilities, would be direct targetsof, or indirect casualties of, an act of war may affect our operations. War andthe possibility of further war may have an adverse impact on the economy ingeneral. A lower level of economic activity might result in a decline in energyconsumption, which may adversely affect our revenues and future growth.Instability in the financial markets as a result of war may also affect ourability to raise capital.

 

Further, likeother operators of major industrial facilities, our generation plants, fuelstorage facilities and transmission and distribution facilities may be targetsof terrorist activities that could result in disruption of our ability toproduce or distribute some portion of our energy products. Any such disruptioncould result in a significant decrease in revenues and significant additionalcosts to repair and insure our assets, which could have a material adverseimpact on our financial condition and results of operations.  The potential for terrorism has subjected ouroperations to increased risks and could have a material adverse effect on ourbusiness.  While we have already incurredincreased costs for security and capital expenditures in response to theserisks, we may experience additional capital and operating costs to implementsecurity for our plants, including our nuclear power plants under the NRC’sdesign basis threat requirements, such as additional physical plant securityand additional security personnel.

 

The insuranceindustry has also been affected by these events.  To date, we have been able to obtaininsurance at satisfactory levels and terms; however, the availability ofinsurance covering risks we and our competitors typically insure against maydecrease.  In addition, the insurance weare able to obtain may have higher deductibles, higher premiums and morerestrictive policy terms.

 

***Reduced coalavailability could negatively impact our business.***

 

NSP-Minnesota’s coal generation portfolio is heavily dependent on coalsupplies located in the Powder River Basin of Wyoming.  Approximately 60 percent of our annual coalrequirement comes from this area.  Coalgeneration comprises approximately 60 percent of our annual generation for theNSP-Minnesota.  In the first half of2005, we began experiencing disruptions in our coal deliveries 

 

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from the Powder River Basin, which continued throughout the year andare expected to continue at least through part of 2006.  In response to these disruptionsNSP-Minnesota mitigated the impact of reduced coal deliveries, by modifying thedispatch of certain facilities to conserve coal inventories. Despite, theseefforts, coal inventories have declined to below target levels. While we havesecured under contract approximately 99 percent of our anticipated 2006 coalrequirements, we cannot predict with any certainty the likelihood of receivingthe required coal.  This factor, combinedwith the currently low inventory levels, has led us to continue coalmitigation.  While we are planning torebuild inventories during 2006, there is no guarantee that we will be able todo so.   The ultimate impact of coalavailability cannot be fully assessed at this time, but could impact our futureresults.

 

***Rising energy prices could negatively impact our business.***

 

A variety of marketfactors have contributed to higher natural gas prices.  The direct impact of these higher costs isgenerally mitigated for NSP-Minnesota through recovery of such costs fromcustomers through various fuel cost recovery mechanisms.  However, higher fuel costs couldsignificantly impact the results of operations, if requests for recovery areunsuccessful.  In addition, the higherfuel costs could reduce customer demand or increase bad debt expense, whichcould also have a material impact on NSP-Minnesota’s results ofoperations.  Delays in the timing of thecollection of fuel cost recoveries as compared with expenditures for fuelpurchases are expected to have an impact on the cash flows of NSP-Minnesota.  NSP-Minnesota is unable to predict the futurenatural gas prices or  the ultimateimpact of such prices on its results of operations or cash flows.

 

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

 

Our electricand natural gas utility businesses are seasonal businesses and weather patternscan have a material impact on our operating performance. Demand for electricityis often greater in the summer and winter months associated with cooling andheating. Because natural gas is heavily used for residential and commercialheating, the demand for this product depends heavily upon weather patternsthroughout our service territory and a significant amount of natural gasrevenues are recognized in the first and fourth quarters related to the heatingseason. Accordingly, our operations have historically generated less revenuesand income when weather conditions are milder in the winter and cooler in thesummer. We expect that unusually mild winters and summers would have an adverseeffect on our financial condition and results of operations.

 

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

 

There areinherent in our natural gas distribution activities a variety of hazards andoperating risks, such as leaks, explosions and mechanical problems, that couldcause substantial financial losses.  Inaddition, these risks could result in loss of human life, significant damage toproperty, environmental pollution, impairment of our operations and substantiallosses to us.  In accordance withcustomary industry practice, we maintain insurance against some, but not all,of these risks and losses.  Theoccurrence of any of these events not fully covered by insurance could have amaterial adverse effect on our financial position and results ofoperations.  For our distribution lineslocated near populated areas, including residential areas, commercial businesscenters, industrial sites and other public gathering areas, the level ofdamages 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 ourresults of operations, financial position, or liquidity.***

 

We havedefined benefit and postretirement plans that cover substantially all of ouremployees.  Assumptions related to futurecosts, return on investments, interest rates and other actuarial assumptionshave a significant impact on our earnings and funding requirements.  Based on our assumptions at Dec. 31, 2005 andassuming continuation of the current federal interest rate relief beyond 2005,in order to maintain required funding levels for our pension plans, we do notexpect to make required future contributions. However, contributions could be required in the future.

 

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

 

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

 

We cannotassure you that any of our current ratings or those of our affiliates willremain in effect for any given period of time or that a rating will not belowered 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 ourcredit ratings.  Any future downgradecould increase the cost of short-term borrowings but would not result in anydefaults or accelerations as a result of the rating changes.  Any downgrade could also lead to higherlong-term borrowing costs.

 

***As we are a subsidiary of XcelEnergy, we may be negatively affected by events at Xcel Energy and itsaffiliates. If Xcel Energy were to become obligated to make payments undervarious guarantees and bond indemnities or to fund its other contingentliabilities, or if Xcel Energy’s credit ratings and access to capital wererestricted, this could limit Xcel Energy’s ability to contribute equity or makeloans to us, or may cause Xcel Energy to seek additional or accelerated fundingfrom us in the form of dividends. If such event were to occur, we may need toseek 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 currentmaturities. Xcel Energy provides various guarantees and bond indemnitiessupporting some of its subsidiaries by guaranteeing the payment or performanceby these subsidiaries of specified agreements or transactions. Xcel Energy alsohas other contingent liabilities resulting from various tax disputes and othermatters. Xcel Energy’s exposure under the guarantees is based upon the netliability of the relevant subsidiary under the specified agreements ortransactions. The majority of Xcel Energy’s guarantees limit its exposure to amaximum amount that is stated in the guarantees. As of Dec. 31, 2005, XcelEnergy had guarantees outstanding with a maximum stated amount of approximately$52.4 million and no known exposure. Xcel Energy has also provided indemnitiesto sureties in respect of bonds for the benefit of its subsidiaries. The totalamount of bonds with these indemnities outstanding as of Dec. 31, 2005, wasapproximately $132.9 million. Xcel Energy’s total exposure under theseindemnities cannot be determined at this time. Xcel Energy believes that theexposure is significantly less than the total amount of bonds outstanding. IfXcel Energy were to become obligated to make payments under these guaranteesand bond indemnities or become obligated to fund the other contingentliabilities, it could limit Xcel Energy’s ability to contribute equity or makeloans to us, or may cause Xcel Energy to seek, within certain regulatory andother limitations and the limitations provided by corporate law, additional oraccelerated funding from us in the form of dividends. If such event were tooccur, 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 XcelEnergy’s credit rating below investment grade, Xcel Energy may be required toprovide credit enhancements in the form of cash collateral, letters of creditor other security to satisfy part or potentially all of these exposures. Ifeither Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debtsecurities below investment grade, it would increase Xcel Energy’s cost ofcapital and restrict its access to the capital markets. This could limit XcelEnergy’s ability to contribute equity or make loans to us, or may cause XcelEnergy to seek additional or accelerated funding from us in the form ofdividends. If such even were to occur, we may need to seek alternative sourcesof funds to meet our cash needs.

 

We rely on Xcel Energy ServicesInc., a subsidiary service company of Xcel Energy, for many administrativeservices. If Xcel Energy were to experience severe financial difficulties, itcould temporarily disrupt the provision of these services or require us toprovide these services ourselves, at potentially greater cost.

 

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

 

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

 

•      our payment of dividends;

 

•      decisions on our financings and ourcapital raising activities;

 

•      mergers or other business combinations;and

 

•      our acquisition or disposition of assets.

 

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

 

**Item 1B —Unresolved SEC Staff Comments**

 

None

 

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**Item 2 — Properties**

 

Virtually all of the utilityplant of NSP-Minnesota is subject to the lien of its first mortgage bondindenture.

 

Electric utility generatingstations:

 
| **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                                            |       |

 

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

 

Electric utility overheadand underground transmission and distribution lines (measured in conductormiles) 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 363electric utility transmission and distribution substations at Dec. 31, 2005.

Natural gas utility mains atDec. 31, 2005:

 
| ** **   | ** ** | **Miles** | ** ** |
|--------------|------------|-----------|------------|
| Transmission |       | 120       |       |
| Distribution |       | 9,173     |       |

 

**Item 3 — Legal Proceedings**

 

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

 

***Nuclear Waste Disposal Litigation***—The federal government has the responsibility to dispose of domestic spentnuclear fuel and other high-level radioactive substances. The Nuclear WastePolicy Act (The Act) requires the DOE to implement this disposal program. Thisincludes the siting, licensing, construction and operation of a permanentrepository for domestically produced spent 

 

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nuclear fuel fromcivilian nuclear power reactors and other high-level radioactive substances.The Act and contracts between DOE and domestic utilities obligated DOE to beginto dispose of these materials by Jan. 31, 1998. The federal government has designated the site as Yucca Mountain inNevada. The nuclear waste disposal program has resulted in extensive litigation.

 

On June 8, 1998,NSP-Minnesota filed a complaint in U.S. Court of Federal Claims against theUnited States requesting breach of contract damages in excess of $1 billion forthe DOE’s failure to meet the 1998 deadline. NSP-Minnesota has demanded damages consisting of the added costs ofstorage of spent nuclear fuel at the Prairie Island and Monticello nucleargenerating plants, costs related to the Private Fuel Storage, LLC and certaincosts relating to the 1994 and 2003 state legislation relating to the storageof spent nuclear fuel at Prairie Island. On July 31, 2001, the Court granted NSP-Minnesota’s motion forpartial summary judgment on liability. The Court has set the start of the trial on Oct. 23, 2006.

 

On July 9, 2004, the U.S. Court of Appeals for the District ofColumbia Circuit issued a decision in consolidated cases challengingregulations and decisions on the federal nuclear waste program. The Court ofAppeals rejected challenges by the state of Nevada and other intervenors withrespect to most of the challenged NRC’s repository licensing regulations of theNRC, the congressional resolution approving Yucca Mountain as the site of thepermanent repository, and the DOE and presidential actions leading to theapproval of the Yucca Mountain site. The Court of Appeals vacated the 10,000year compliance period adopted by EPA regulations governing spent nuclear fueldisposal at Yucca Mountain and incorporated in the NRC regulations.NSP-Minnesota cannot predict the impact of the decision on its nuclearoperations and storage of spent nuclear fuel; however, the decision may resultin additional delay and uncertainty around disposal of spent nuclear fuel.

 

***SchlumbergerSema, Inc. vs. Xcel Energy Inc.****—*Under a 1996data services agreement, as amended, SchlumbergerSema, Inc. (SLB) providedautomated meter reading, distribution automation and other data services toNSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLBcommitted events of default under the agreement, including SLB’s nonpayment ofapproximately $7.4 million for distribution automation assets. In November2002, SLB demanded arbitration and asserted various claims againstNSP-Minnesota totaling approximately $24 million for alleged breach of anexpansion contract and a meter purchasing contract. In the arbitration,NSP-Minnesota asserted counterclaims against SLB, including those related toSLB’s failure to meet performance criteria, improper billing, failure to payfor use of NSP-Minnesota owned property and failure to pay $7.4 million forNSP-Minnesota distribution automation assets, for total claims of approximately$41 million. NSP-Minnesota also sought a declaratory judgment from thearbitrators that would terminate SLB’s rights under the data servicesagreement. In August 2004, the U.S. Bankruptcy Court for the District ofDelaware ruled that claims related to use of certain equipment are barredunless NSP-Minnesota can establish a basis for the claims in SLB’s conductsubsequent to the time of the assumption of this contract by SLB in May2000.  In June 2005, the U.S. BankruptcyCourt ruled that NSP-Minnesota is barred from asserting any claim or defenseagainst SLB that is based, in whole or in part, on any pre-May 2000 act oromission, including, but not limited to, any act or omission resulting indesign or performance defects, by Cellnet Data Systems Inc., the party withwhich NSP-Minnesota originally contracted and from which SLB assumed therelevant agreements, which act or omission could have been a basis forNSP-Minnesota to assert a breach of contract against Cellnet Data Systems Inc.    On Oct. 31, 2005, the parties submittedthis dispute to mediation, and reached a confidential settlement that did nothave a material financial impact on NSP-Minnesota.

 

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***Other Matters***

 

For more discussion of legalclaims and environmental proceedings, see Note 11 to the Consolidated FinancialStatements under Item 8, incorporated by reference. For a discussion ofproceedings involving utility rates, see Pending and Recently ConcludedRegulatory Proceedings under Item 1, incorporated by reference.

 

**Item 4 — Submission of Matters to a Vote of SecurityHolders**

 

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

 

**PART II**

 

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

 

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

 

NSP-Minnesota’s firstmortgage indenture places certain restrictions on the amount of cash dividendsit can pay to Xcel Energy, the holder of its common stock. Even with theserestrictions, NSP-Minnesota could have paid more than $854 million inadditional cash dividends on common stock at Dec. 31, 2005. In addition,NSP-Minnesota had dividend restrictions imposed by state regulatorycommissions,debt agreements and the SEC under the PUHCA limiting the amount ofdividends 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 45.99percent to 56.21 percent;

 

•            payment of dividends only from retainedearnings; and

 

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

 

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

 

The dividends declaredduring 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 perconditions set forth in general instructions I(1)(a) and (b) of Form 10-K forwholly owned subsidiaries (reduced disclosure format).

 

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

 

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

 

**ForwardLooking Information**

 

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

 

Except for the historicalstatements contained in this report, the matters discussed in the followingdiscussion and analysis are 

 

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forward-looking statementsthat are subject to certain risks, uncertainties and assumptions. Suchforward-looking statements are intended to be identified in this document bythe words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,”“outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similarexpressions. Actual results may vary materially. Factors that could causeactual results to differ materially include, but are not limited to:

 

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

 

•              rating agency actions;

 

•              business conditions in the energy industry;

 

•              competitive factors including the extent andtiming of the entry of additional competition;

 

•              unusual weather;

 

•              changes in federal or state legislation;

 

•              geopolitical events, including war and actsof terrorism;

 

•              regulation; and

 

•              the other risk factors listed from time totime by NSP-Minnesota in reports filed with the SEC, including Exhibit 99.01 tothis Annual Report on Form 10-K for the year ended Dec. 31, 2005.

 

**Management’s Discussion and Analysis of Financial Condition and Resultsof Operations**

 

**Results ofOperations**

 

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

 

***Electric Utility, Short-Term Wholesale and Commodity Trading Margins***

 

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

 

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

 

Margins fromcommodity trading activity conducted at NSP-Minnesota are partiallyredistributed among PSCo and SPS, both wholly owned subsidiaries of XcelEnergy, pursuant to the joint operating agreement (JOA) approved by the FERC.Margins received pursuant to the JOA are reflected as part of Base ElectricUtility Revenues.  Trading revenues, asdiscussed in Note 1 to the Consolidated Financial Statements, are reported netof trading costs (i.e., on a margin basis) in the Consolidated Statements ofIncome.  Commodity trading costs includepurchased power, transmission, broker fees and other related costs.

 

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

 

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| ** **                                              | ** ** | **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 thecomponents of the changes in base electric revenue and base electric margin forthe 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 2005compared with 2004.  The higher 2004results reflect the impact of more favorable market conditions and higherlevels of surplus generation available to sell. In addition, a preexisting contract contributed $17 million of margin inthe first quarter of 2004 and expired at that time.

 

***Natural Gas Utility Margins*****— The following table details the change innatural gas revenue and margin. The cost of natural gas tends to vary withchanging 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 gasmargin.

 
| ** **                               | ** ** | **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 thecomponents of the changes in natural gas revenue and margin for the year endedDec. 31:

 

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***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 revenueincreased primarily due to higher natural gas costs in 2005, which arerecovered from customers.  Retail gasweather-normalized sales declined in 2005, largely due to the rising cost ofnatural 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 ofthe changes in other utility operating and maintenance expense for the yearended 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         |   |

 

Depreciationand amortization expense increased by approximately $36.2 million, or 10.8percent, for 2005 compared with 2004. The increase is largely due to the installation of new steamgenerators at Unit 1 of the Prairie Island nuclear plant and software systemadditions during 2004 and early 2005, both of which have relatively shortdepreciable lives compared with other capital additions.  The Prairie Island steam generators are beingdepreciated over the remaining life of the plant operating license, whichexpires in 2013.  In addition, theMinnesota 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 waspartially offset by the changes in useful lives and net salvage rates approvedby Minnesota regulators in August 2005.

 

Interest charges and financingcosts increased by approximately $7.6 million, or 5.9 percent, for 2005,compared with 2004. The increase is due to the issuance of $250 millionof 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 forthe period ended Dec. 31, 2005, compared with 29.1 percent for the same periodin 2004.  The increase in tax expense andthe higher  effective tax rate in 2005compared with 2004 were primarily due to lower income levels in 2004 and incometax benefits recorded in 2004 related to successful resolution of audit issuesand other adjustments to current and deferred taxes.

 

**Item7A — 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 varietyof market risks.  Market risk is thepotential loss that may occur as a result of changes in the market or fairvalue 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 pricerisk in its generation and retail distribution operations.  Commodity price risk is managed by enteringinto both long- and short-term physical purchase and sales contracts for electric

 

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

 

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

 

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

 

See Note 9 to theConsolidated Financial Statements for a discussion of the various trading andhedging contracts of NSP-Minnesota.

 

NSP-Minnesota’s short-termwholesale and commodity trading operations measure the outstanding riskexposure to price changes on transactions, contracts and obligations that havebeen entered into, but not closed, using an industry standard methodology knownas VaR. VaR expresses the potential change in fair value on the outstandingtransactions, contracts and obligations over a particular period of time, witha given confidence interval under normal market conditions. NSP-Minnesotautilizes the variance/covariance approach in calculating VaR. The VaR modelemploys a 95-percent confidence interval level based on historical pricemovement, lognormal price distribution assumption, delta half-gamma approachfor non-linear instruments and a three-day holding period for both electricityand natural gas.

 

VaR is calculated on aconsolidated basis. As of Dec. 31, 2005, the VaRs for the commodity tradingoperations were:

 
| **(Millions  of Dollars)** | ** ** | **Year ended  Dec. 31, 2005** | ** ** | **During 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 aconsolidated basis. As of Dec. 31, 2004, the VaRs for the commodity tradingoperations were:

 
| **(Millions  of Dollars)**     | ** ** | **Year ended  Dec. 31, 2004** | ** ** | **During 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 offluctuating interest rates in the normal course of business.  NSP-Minnesota’s risk management policy allowsinterest rate risk to be managed through the use of fixed rate debt, floatingrate debt and interest rate derivatives such as swaps, caps, collars and put orcall options, subject to regulatory approval when required.

 

NSP-Minnesotamay engage in hedges of cash flow exposure. The fair value of interest rate swaps designated as cash flow hedges isinitially recorded in Other Comprehensive Income.  Reclassification of unrealized gains orlosses on cash flow hedges of variable rate debt instruments from OtherComprehensive Income into earnings occurs as interest payments are accrued onthe debt instrument, and generally offsets the change in the interest accruedon the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair valueof a recognized asset, liability or firm commitment.  Changes in the derivative fair values thatare designated as fair value hedges are recognized in earnings as offsets tothe changes in fair values of related hedged assets, liabilities or firmcommitments.  To test the effectivenessof such swaps, a hypothetical swap is used to mirror all the critical terms ofthe underlying debt and regression analysis is utilized to assess theeffectiveness of the actual swap at inception and on an ongoing basis, ifrequired.  The fair value of interestrate swaps is determined through counterparty valuations, internal valuationsand broker quotes.  There have been nomaterial changes in the techniques or models used in the valuation of interestrate swaps during the periods presented.

 

AtDec. 31, 2005 and 2004, a 100-basis-point change in the benchmark rate onNSP-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, tofund certain costs of nuclear decommissioning, which are 

 

27

----

 

subject to interest rate risk and equity price risk.  As of Dec. 31, 2005 and 2004, these fundswere invested primarily in domestic and international equity securities andfixed-rate fixed-income securities.  PerNRC mandates, these funds may be used only for activities related to nucleardecommissioning.  The accounting fornuclear decommissioning recognizes that costs are recovered through rates;therefore fluctuations in equity prices, or interest rates do not have animpact on earnings.

 

***Credit Risk —***In addition to the risks discussed previously, NSP-Minnesota is exposedto credit risk. Credit risk relates to the risk of loss resulting from thenonperformance by a counterparty of its contractual obligations. NSP-Minnesotamaintains credit policies intended to minimize overall credit risk and activelymonitors these policies to reflect changes and scope of operations.

 

NSP-Minnesota conductsstandard credit reviews for all counterparties. NSP-Minnesota employsadditional credit risk control mechanisms when appropriate, such as letters ofcredit, parental guarantees, standardized master netting agreements andtermination provisions that allow for offsetting of positive and negativeexposures. The credit exposure is monitored and, when necessary, the activitywith a specific counterparty is limited until credit enhancement is provided.

 

28

----

 

**Item 8 — Financial Statements and Supplementary Data**

 

# **REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

Board of Directors and Stockholder

Northern States Power Company—Minnesota

 

We have audited the accompanying consolidated balance sheets andstatements of capitalization of Northern States Power Company—Minnesota andsubsidiaries (the “Company”) as of December 31, 2005 and 2004, and therelated consolidated statements of income, common stockholder’s equity andcomprehensive income and cash flows for each of the three years in the periodended December 31, 2005. Our audits also included the financial statementschedule listed in the Index at Item 15. These financial statements andfinancial statement schedule are the responsibility of the Company’smanagement. Our responsibility is to express an opinion on the financialstatements and financial statement schedule based on our audits.

 

We conducted our audits in accordance with the standards of the PublicCompany Accounting Oversight Board (United States). Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whetherthe financial statements are free of material misstatement. The Company is notrequired to have, nor were we engaged to perform, an audit of its internalcontrol over financial reporting.  Ouraudits included consideration of internal control over financial reporting as abasis for designing audit procedures that are appropriate in the circumstances,but not for the purpose of expressing an opinion on the effectiveness of theCompany’s internal control over financial reporting. Accordingly, we express nosuch opinion. An audit also includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements, assessingthe accounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation. We believethat our audits provide a reasonable basis for our opinion.

 

In our opinion, such consolidated financial statements present fairly,in all material respects, the financial position of Northern States PowerCompany—Minnesota and subsidiaries as of December 31, 2005 and 2004, andthe results of their operations and their cash flows for each of the threeyears in the period ended December 31, 2005, in conformity with accountingprinciples generally accepted in the United States of America. Also, in ouropinion, such financial statement schedule, when considered in relation to thebasic consolidated financial statements taken as a whole, presents fairly inall material respects the information set forth therein.

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

 

29

----

 

**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 |   |

 

SeeNotes to Consolidated Financial Statements

 

30

----

 

**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 |   |

 

SeeNotes to Consolidated Financial Statements

 

31

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**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 |   |

 

SeeNotes to Consolidated Financial Statements

 

32

----

 

**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**                  | ** ** |
| ** **                                                 | ** ** | ** **       | ** ** | ** **                  | ** ** | ** **            | ** ** | ** **                                             | ** ** | ** **                              | ** ** | ** ** | ** ** |
| **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 |   |

 

SeeNotes to Consolidated Financial Statements

 

33

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**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 |   |

 

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(a)      Resource recovery financing

(b)      Pollution control financing

 

SeeNotes to Consolidated Financial Statements

 

34

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**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**1. Summaryof Significant Accounting Policies**

 

***Business and System of Accounts*****— NSP-Minnesota is engaged principally in thegeneration, purchase, transmission, distribution and sale of electricity and inthe 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 utilitycommissions. All of NSP-Minnesota’s accounting records conform to the FERCuniform system of accounts or to systems required by various state regulatorycommissions, 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 asubstantial long-term effect on energy markets, energy investment, andregulation of public utilities and holding company systems by the FERC, the SECand the DOE.  The FERC was directed bythe Energy Act to address many areas previously regulated by other governmentalentities under the statutes and determine whether changes to such previousregulations are warranted.  The issuesthat the FERC has been required to consider associated with the repeal of thePUHCA include, but are not limited to, the expansion of the FERC authority toreview mergers and sales of public utility companies and the expansion of theFERC authority over the books and records of holding companies and publicutility companies previously governed by the SEC and the appropriate coststandard for the provision of non-power goods and services by servicecompanies.  The FERC is in various stagesof rulemaking on these and other issues. Xcel Energy cannot predict the impact the new rulemakings will have onits operations or financial results, if any.

 

***Principles of Consolidation*****— NSP-Minnesota has subsidiaries, which havebeen consolidated and for which all significant intercompany transactions andbalances are eliminated.

 

***Revenue Recognition*****—Revenues related to the sale of energy are generally recorded when service isrendered or energy is delivered to customers. However, the determination of theenergy 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 eachmonth, amounts of energy delivered to customers since the date of the lastmeter reading are estimated and the corresponding unbilled revenue isestimated.

 

NSP-Minnesota has various rateadjustment mechanisms in place that currently provide for the recovery ofcertain purchased natural gas and electric energy costs. These cost adjustmenttariffs may increase or decrease the level of costs recovered through baserates and are revised periodically, as prescribed by the appropriate regulatoryagencies, for any difference between the total amount collected under theclauses and the recoverable costs incurred. In addition, NSP-Minnesota presentsits revenue, net of any excise or other fiduciary-type taxes or fees. A summaryof significant rate adjustment mechanisms follows:

 

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

 

•              NSP-Minnesota operates under various servicestandards, which could require customer refunds if certain criteria are notmet. NSP-Minnesota’s rates include monthly adjustments for the recovery ofconservation and energy management program costs, which are reviewed annually.

 

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

 

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

 

Pursuant to the JOA approvedby the FERC, some of the commodity trading margins from NSP-Minnesota areapportioned to PSCo and SPS. Commodity trading activities are not associatedwith energy produced from NSP-Minnesota’s generation assets or energy andcapacity purchased to serve native load. Commodity trading contracts arerecorded at fair market value in accordance with SFAS 133, as amended. For moreinformation, see Note 9 to the Consolidated Financial Statements.

 

***Derivative Financial Instruments****—*NSP-Minnesota utilizes physical and financialcommodity based contracts to reduce exposure to commodity price risk. Thesecontracts consist mainly of commodity forwards, futures and options. Forfurther discussion of NSP-Minnesota’s risk management and derivativeactivities, see Note 9 to the Consolidated Financial Statements.

 

***Property, Plant, Equipment and Depreciation*****— Property, plant and equipment is stated atoriginal cost. The cost of plant includes direct labor and materials,contracted work, overhead costs and applicable interest expense. The cost ofplant retired is charged to accumulated depreciation and amortization. Removalcosts associated with regulatory obligations are recorded as regulatoryliabilities. Significant additions or improvements extending asset lives arecapitalized, while repairs and maintenance are charged to expense as 

 

35

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incurred. Maintenance andreplacement of items determined to be less than units of property are chargedto operating expenses as incurred. Property, plant and equipment also includecosts associated with property held for future use.

 

NSP-Minnesota determines thedepreciation of its plant by using the straight-line method, which spreads theoriginal cost equally over the plant’s useful life. Depreciation expense forNSP-Minnesota, expressed as a percentage of average depreciable property, forthe years ended Dec. 31, 2005, 2004 and 2003 was 3.9 percent, 3.8 percent and3.5 percent, respectively.

 

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

 

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

 

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

 

***Environmental Costs*****—Environmental costs are recorded when it is probable NSP-Minnesota is liablefor the costs and the liability can be reasonably estimated. Costs may bedeferred as a regulatory asset if it is probable that the costs will berecovered from customers in future rates. Otherwise, the costs are expensed. Ifan environmental expense is related to facilities currently in use, such asemission-control equipment, the cost is capitalized and depreciated over thelife of the plant, assuming the costs are recoverable in future rates or futurecash flow.

 

Estimated remediation costs,excluding inflationary increases, are recorded. The estimates are based onexperience, an assessment of the current situation and the technology currentlyavailable for use in the remediation. The recorded costs are regularly adjustedas estimates are revised and remediation proceeds. If several designatedresponsible parties exist, costs are estimated and recorded only forNSP-Minnesota’s share of the cost. Any future costs of restoring sites whereoperation may extend indefinitely are treated as a capitalized cost of plantretirement. The depreciation expense levels recoverable in rates include aprovision 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 liablefor the costs and the liability can be reasonably estimated.  Legal accruals are recorded net of insurancerecovery.  Legal costs related tosettlements are not accrued, but expensed as incurred.

 

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

 

Investment tax credits aredeferred and their benefits amortized over the estimated lives of the relatedproperty. Utility rate regulation also has created certain regulatory assetsand liabilities related to income taxes, which are summarized in Note 13 to theConsolidated Financial Statements. For more information on income taxes, seeNote 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. Estimatesare 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 andactuarially determined benefit costs. The recorded estimates are revised whenbetter information is obtained or actual amounts are determinable. Thoserevisions can affect operating results. Each year the depreciable lives ofcertain plant assets are reviewed and revised, if appropriate.

 

36

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***Cash and Cash Equivalents*****— NSP-Minnesota considers investments with aremaining maturity of three months or less at the time of purchase to be cashequivalents. Those instruments are primarily commercial paper and money marketfunds.

 

***Inventory*****— Allinventory for NSP-Minnesota is recorded at average cost.

 

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

 

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

 

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

 

Estimates of recoveringdeferred costs and returning deferred credits are based on specific ratemakingdecisions or precedent for each item. Regulatory assets and liabilities are amortizedconsistent with the period of expected regulatory treatment.

 

If restructuring or otherchanges in the regulatory environment occur, NSP-Minnesota may no longer beeligible to apply this accounting treatment, and may be required to eliminatesuch regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect onNSP-Minnesota’s results of operations in the period the write-off isrecorded.  See more discussion ofregulatory assets and liabilities at Note 13 to the Consolidated FinancialStatements.

 

***Deferred Financing Costs*****— Other assets include deferred financingcosts, which are amortized over the remaining maturity periods of the relateddebt. 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 actualbilled amount net of write-offs and allowance for uncollectibles.  We establish an allowance for uncollectiblesbased on a reserve policy that reflects our expected exposure to the creditrisk of customers.

 

***Reclassifications*****—Fees collected from customers on behalf of governmental agencies werereclassified 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 utilitysubsidiaries and received required state regulatory approvals.  The utility money pool allows for short-termloans between the utility subsidiaries and from the holding company to theutility subsidiaries at market-based interest rates. The utility money poolarrangement does not allow loans from the utility subsidiaries to the holdingcompany.  NSP-Minnesota has approval toborrow up to $250 million under the arrangement.  NSP-Minnesota had no borrowings or loansoutstanding under the arrangement at Dec. 31, 2005.  As a consequence of the repeal of PUHCA andthe recent amendments to the Federal Power Act, it may be necessary forNSP-Minnesota to submit its existing money pool arrangement to FERC for itsapproval.  NSP-Minnesota is presentlyevaluating the situation.

 

**3.****    ****Long-Term Debt**

 

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

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

 

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

 

The line of credit provides short-term financing in the form of notespayable to banks, letters of credit and back-up support for commercial paperborrowings.  NSP-Minnesota has the rightto request an extension of the final maturity date by one year.  The maturity extension is subject to majoritybank group approval.  The credit facilityhas one financial covenant requiring that NSP-Minnesota’s debt to totalcapitalization ratio be less than or equal to 65 percent with whichNSP-Minnesota is in compliance.  Theinterest rate is based on either the agent bank’s prime rate or the applicableLIBOR, plus a borrowing margin as determined by NSP-Minnesota’s seniorunsecured credit ratings from Moody, Standard & Poor and Fitch.

 

37

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As of Dec. 31, 2005,NSP-Minnesota had $250 million drawn on this line of credit at a weightedaverage 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, ofwhich $9.7 million were outstanding under the above credit facility and areincluded in the above table.

 

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

 

Maturities of long-term debtare:

 
| **(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 whollyowned, special-purpose subsidiary trust of NSP-Minnesota, had $200 million of7.875-percent trust preferred securities issued and outstanding that wereoriginally scheduled to mature in 2037. The preferred securities were redeemable at the option of NSP-Minnesotaat $25 per share, beginning in 2002. On July 31, 2003, NSP-Minnesotaredeemed the $200 million of trust preferred securities. A certificate ofcancellation was filed to dissolve NSP Financing I on Sept. 15, 2003.

 

Distributions paid topreferred security holders were reflected as a financing cost in the accompanyingConsolidated Statements of Income along with interest expense.

 

**5. JointPlant Ownership**

 

Following are theinvestments by NSP-Minnesota in jointly owned plants and the related ownershippercentages 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 ownerof 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 areincluded in the applicable utility accounts. Each of the respective owners isresponsible for the issuance of its own securities to finance its portion ofthe construction costs.

 

**6.****    ****Income Taxes**

 

Total income tax expensefrom operations differs from the amount computed by applying the statutoryfederal income tax rate to income before income tax expense. The following is atable 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 thefollowing expense (benefit) items for the years ending Dec. 31:

 

38

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| **(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 deferredincome 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 netdeferred 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. BenefitPlans and Other Postretirement Benefits**

 

Pension and otherpostretirement benefit disclosures below generally represent Xcel Energyconsolidated information unless specifically identified as being attributableto NSP-Minnesota.

 

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

 

**PensionBenefits**

 

Xcel Energy has severalnoncontributory, 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’saverage pay and Social Security benefits.

 

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

 

***Pension Plan Assets***— Plan assets principally consist of the common stock of publiccompanies, corporate bonds and U.S. government securities. In 2004, Xcel Energycompleted a review of its pension plan asset allocation and adopted revisedasset allocation targets.  The targetrange for our pension asset allocation is 60 percent in equity investments, 20percent in fixed income investments and 20 percent in nontraditional investments,such as real estate, timber ventures, private equity and a diversifiedcommodities index.

 

The actual composition ofpension plan assets at Dec. 31 was:

 

39

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| ** **                  | ** ** | **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 itsinvestment-return assumption on expected long-term performance for each of theinvestment types included in its pension asset portfolio. Xcel Energy considersthe actual historical returns achieved by its asset portfolio over the past20-year or longer period, as well as the long-term return levels projected andrecommended by investment experts. The historical weighted average annualreturn for the past 20 years for the Xcel Energy portfolio of pensioninvestments is 12.0 percent, which is greater than the current assumptionlevel. The pension cost determinations assume the continued current mix ofinvestment types over the long term. The Xcel Energy portfolio is heavilyweighted toward equity securities and includes nontraditional investments thatcan provide a higher-than-average return. As is the experience in recent years, a higher weighting in equity investmentscan increase the volatility in the return levels actually achieved by pensionassets in any year. Investment returns in 2005, 2004 and 2003 exceeded theassumed levels of 8.75 percent, 9.0 percent and 9.25 percent, respectively.Xcel Energy continually reviews its pension assumptions. In 2006, Xcel Energywill continue to use an investment return assumption of 8.75 percent.

 

***Benefit Obligations***— A comparison of the actuarially computed pension benefit obligationand 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 fundingrequirements of income tax and other pension-related regulations. Theseregulations did not require cash funding in the years 2003 through 2005 for XcelEnergy’s pension plans and is not expected to require cash 

 

40

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funding in 2006.

 

***Benefit Costs***—******Thecomponents 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 anexpected return impact for the current year that may differ from actualinvestment performance in the plan. The return assumption used for 2006 pensioncost calculations will be 8.75 percent. The cost calculation uses a market-relatedvaluation of pension assets, which reduces year-to-year volatility byrecognizing the differences between assumed and actual investment returns overa five-year period.

 

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

 

**DefinedContribution 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.

 

**PostretirementHealth Care Benefits**

 

Xcel Energy has acontributory health and welfare benefit plan that provides health care anddeath benefits to most Xcel Energy retirees. The former NSP discontinuedcontributing toward health care benefits for nonbargaining employees retiringafter 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin whoretired after 1999. Employees of the former NSP who retired after 1998 areeligible to participate in the Xcel Energy health care program with no employersubsidy.

 

In conjunction with the 1993adoption of SFAS No. 106 – “Employers’ Accounting for Postretirement BenefitsOther Than Pensions,” Xcel Energy elected to amortize the unrecognizedaccumulated postretirement benefit obligation (APBO) on a straight-line basisover 20 years.

 

Regulatory agencies fornearly all of Xcel Energy’s retail and wholesale utility customers have allowedrate recovery of accrued benefit costs under SFAS No. 106. NSP-Minnesotatransitioned to full accrual accounting for SFAS No. 106 costs, with regulatorydifferences fully amortized prior to 1997.

 

***Plan Assets***—Certain state agencies that regulate Xcel Energy’s utility subsidiaries alsohave 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 theexposure to equity funds. Also, a portion of the assets contributed on behalfof non-bargaining retirees has been funded into a sub-account of the XcelEnergy pension plans. These assets are invested in a manner consistent with theinvestment strategy for the pension plan.

 

41

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The actual composition ofpostretirement 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 itsinvestment-return assumption for the postretirement health care fund assets onexpected long-term performance for each of the investment types included in itspostretirement health care asset portfolio. Investment-return volatility is notconsidered to be a material factor in postretirement health care costs.

 

***Benefit Obligations***— A comparison of the actuarially computed benefit obligation and planassets for Xcel Energy postretirement health care plans that benefit employeesof 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 9.0percent and lowered the ultimate trend assumption from 5.5 percent to 5.0percent.  The period until the ultimaterate is reached also was increased from two years to six years.  This trend assumption was used to value theactuarial benefit obligations at year-end 2004 and 2005, and was used in 2005retiree medical cost determinations. Xcel Energy bases its medical trend assumption on the long-term costinflation expected in the health care market, considering the levels projectedand recommended by industry experts, as well as recent actual medical costincreases experienced by Xcel Energy’s retiree medical plan.

 

A 1-percent change in theassumed health care cost trend rate would have the following effects onNSP-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       | )          |
|                                                                                 |            |            |            |  |

 

42

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Curtailment and settlementgains resulted from activities of some of Xcel Energy’s nonregulatedsubsidiaries.

 

***Cash Flows***—The postretirement health care plans have no funding requirements under incometax and other retirement-related regulations other than fulfilling benefitpayment obligations, when claims are presented and approved under the plans.Additional cash funding requirements are prescribed by certain state andfederal rate regulatory authorities, as discussed previously. Xcel Energyexpects 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  | %          |

 

# **ProjectedBenefit Payments**

# ** **

The following table lists Xcel Energy’s projected benefit payments forthe 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                                                           |       |
|                            |            |                                          |            |                                                                     |            |                                         |            |                                                                   |            |  |  |  |  |

 

43

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**8. Detailof Interest and Other Income, Net of Nonoperating Expenses**

 

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

 
| **(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 varietyof market risks.  Market risk is thepotential loss that may occur as a result of changes in the market or fairvalue of a particular instrument or commodity. NSP-Minnesota utilizes, in accordance with approved risk managementpolicies, a variety of derivative instruments to mitigate market risk and toenhance our operations.  The use of thesederivative instruments is discussed in further detail below.

 

***Utility CommodityPrice Risk —***NSP-Minnesota is exposed to commodity price risk in their generation and retaildistribution operations.  Commodity pricerisk is managed by entering into both long- and short-term physical purchaseand sales contracts for electric capacity, energy and other energy-relatedproducts, and for various fuels used in the generation and natural gas utilityoperation.  Commodity risk also ismanaged through the use of financial derivative instruments.  NSP-Minnesota utilizes these derivativeinstruments to reduce the volatility in the cost of commodities acquired onbehalf of our retail customers even though regulatory jurisdiction may providefor a dollar-for-dollar recovery of actual costs.  In these instances, the use of derivativeinstruments is done consistently with the local jurisdictional cost recoverymechanism.  NSP-Minnesota’srisk-management policy allows it to manage market price risk to the extent suchexposure exists, as allowed by regulation.

 

***Short-Term Wholesaleand Commodity Trading Risk —*** NSP-Minnesota conducts various marketing andcommodity trading activities, including the purchase and sale of electriccapacity and energy and other energy-related instruments.  These activities are primarily focused onspecific regions where market knowledge and experience have been obtained andare generally less than one year in length. NSP-Minnesota’s risk-management policy allows management to conduct themarketing activity within approved guideline and limitations as approved by ourrisk management committee, which is made up of management personnel notdirectly involved in the activities governed by this policy.

 

# **Typesof and Accounting for Derivative Instruments**

# ** **

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

 

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

 

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

 

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

 

44

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Minnesota is currently engaged in are discussed below.

 

# **CashFlow Hedges**

# ** **

The effective portion ofthe change in the fair value of a derivative instrument qualifying as a cashflow hedge is recognized in Other Comprehensive Income, and reclassified intoearnings in the same period or periods during which the hedged transactionaffects earnings.  The ineffectiveportion of a derivative instrument’s change in fair value is recognized incurrent earnings.

 

***Commodity Cash FlowHedges******—***NSP-Minnesota enters into derivativeinstruments to manage variability of future cash flows from changes incommodity prices.  These derivativeinstruments are designated as cash flow hedges for accounting purposes.  At Dec. 31, 2005, NSP-Minnesota had variouscommodity-related contracts classified as cash flow hedges extending throughNovember 2006.  The fair value of thesecash flow hedges is recorded in either Other Comprehensive Income or deferredas a regulatory asset or liability.  Thisclassification is based on the regulatory recovery mechanism in place.  Amounts deferred in these accounts arerecorded in earnings as the hedged purchase or sales transaction issettled.  This could include the purchaseor sale of energy or energy-related products, the use of natural gas togenerate electric energy or natural gas purchased for resale.

 

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

 

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

 

***Financial Impacts of Qualifying Cash FlowHedges*** — The impact of qualifying cash flow hedgeson NSP-Minnesota’s Accumulated Other Comprehensive Income, included in theConsolidated Statements of Stockholder’s Equity, is detailed in the followingtable:

 
| **(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 ofthe change in the fair value of a derivative instrument qualifying as a fair valuehedge 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 thederivative instrument to offset, in the same period, the gains and losses ofthe hedged item.  The ineffective portionof a derivative instrument’s change in fair value is recognized in currentearnings. At Dec. 31, 2005, NSP-Minnesota had no fair value hedges.

 

**NormalPurchases or Normal Sales Contracts**

 

NSP-Minnesota enters intocontracts for the purchase and sale of various commodities for use in itsbusiness operations.  SFAS No. 133requires a company to evaluate these contracts to determine whether thecontracts are derivatives.  Certaincontracts that literally meet the definition of a derivative may be exemptedfrom SFAS No. 133 as normal purchases or normal sales.  Normal purchases and normal sales arecontracts that provide for the purchase or sale of something other than afinancial instrument or derivative instrument that will be delivered inquantities expected to be used or sold over a reasonable period in the normalcourse of business.  In addition, normalpurchases and normal sales contracts must have a price based on an underlyingthat 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 orrates, or other variable, including the occurrence or nonoccurrence of aspecified event, such as a scheduled payment under a contract.

 

NSP-Minnesota evaluatesall of its contracts when such contracts are entered to determine if they arederivatives and, if so, if they qualify to meet the normal designationrequirements under SFAS No. 133.  None ofthe contracts entered into within the commodity trading operations qualify fora normal designation.

 

45

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Normal purchases andnormal sales contracts are accounted for as executory contracts as requiredunder GAAP.

 

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

 

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

 

For a further discussionof other financial instruments at NSP-Minnesota, see Note 10 to theConsolidated Financial Statements.

 

**10.Financial Instruments**

 

The estimated Dec. 31 fairvalues 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 cashand cash equivalents, notes and accounts receivable and notes and accountspayable are not materially different from their carrying amounts because of theshort-term nature of these instruments or because the stated rates approximatemarket rates.  The fair values ofNSP-Minnesota’s debt securities in an external nuclear decommissioning fund andother investments are estimated based on quoted market prices for those orsimilar investments. The fair value of NSP-Minnesota’s long-term debt isestimated based on the quoted market prices for the same or similar issues, orthe current rates for debt of the same remaining maturities and credit quality.

 

The fair value estimatespresented are based on information available to management as of Dec. 31, 2005and 2004. These fair value estimates have not been comprehensively revalued forpurposes of these Consolidated Financial Statements since that date, andcurrent estimates of fair values may differ significantly.

 

The following tables providethe external decommissioning fund’s approximate gains, losses and proceeds fromthe 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 providesguarantees that guarantee payment or performance under specified agreements ortransactions.  As a result, NSP-Minnesota’sexposure under the guarantees is based upon the net liability under thespecified agreements or transactions. The guarantees issued by NSP-Minnesota limit the exposure ofNSP-Minnesota to a maximum amount stated in the guarantees.  The guarantees require no liability to berecorded and contain no recourse provisions. On Dec. 31, 2005, NSP-Minnesota had the following guarantees andexposures related to those guarantees:

 

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| **(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       |                  | $          | 0.12                         |       | 2006                                            |       | (a                             | )          | (b | ) |
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |            |               |            |                       |            |                       |            |                              |            |                                                 |            |                                |            |  |  |

 

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(a)  Nonpayment by the government entity on theunderlying debt

(b)  Security interest in underlying loanagreements, contracts and arrangements between NSP-Minnesota and the governmententities

# ** **

# **Lettersof Credit**

 

NSP-Minnesota uses lettersof credit, generally with terms of one year, to provide financial guaranteesfor certain operating obligations.  AtDec. 31, 2005, there was $10.5 million of letters of credit outstanding.  The contract amounts of these letters ofcredit approximate their fair value and are subject to fees determined in themarketplace.

 

**11.Commitments and Contingent Liabilities**

 

***Legislative Resource Commitments —***In 1994 , NSP-Minnesota received Minnesotalegislative approval for on-site temporary spent-fuel storage facilities at itsPrairie Island nuclear power plant, provided NSP-Minnesota satisfies certainrequirements.  Commitments related to the17 dry cask storage containers approved in 1994 have been fulfilled.  As the result of legislative amendments in2003, NSP-Minnesota is authorized to use as many dry cask storage containers asnecessary to operate the plant through 2014. Current estimates indicate that this will require 29 dry cask storagecontainers.  As of Dec. 31, 2005,NSP-Minnesota had filled and placed 20 dry cask containers in storage atPrairie Island.

 

The 2003 legislationtransfers the primary authority concerning future spent-fuel storage issuesfrom the Legislature to the MPUC.  InJanuary 2005, NSP-Minnesota filed an application with the MPUC for a certificateof need for up to 30 dry cask storage containers at the Monticello nuclearplant so that it can continue to operate beyond 2010.  NSP-Minnesota expects a decision from theMPUC later this year.  NSP-Minnesota alsofiled its request with the NRC on March 24, 2005, for a 20-year extension toMonticello’s operating license.  If acertificate of need is granted, it is stayed until the following June toprovide the Minnesota Legislature the opportunity to review the MPUC’s actionif it is determined appropriate. The 2003 legislation also requiresNSP-Minnesota to add at least 300 MWs of additional wind power by 2010, with anoption to own 100 MWs of this power.

 

Furthermore, payments during the remaining operating life of thePrairie Island plant are required. These payments include: $2.25 million peryear to the Prairie Island Tribal Community beginning in 2004; 5 percent ofNSP-Minnesota’s conservation program expenditures (estimated at $2 million peryear) to the University of Minnesota for renewable energy research; and anincrease in funding commitments to the previously established RenewableDevelopment Fund to $16 million per year beginning in 2003.  All of the cost increases to NSP-Minnesotafrom these required payments and funding commitments are expected to berecoverable in Minnesota retail customer rates, mainly through existingcost-recovery mechanisms. Funding commitments to the Renewable Development Fundwould terminate after the Prairie Island plant discontinues operation unlessthe MPUC determines that NSP-Minnesota failed to make a good faith effort tostore or dispose of the spent fuel out of state, in which case, NSP-Minnesotawould 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 expenditureprograms and other capital requirements of NSP-Minnesota is approximately $879million in 2006, $697 million in 2007 and $564 million in 2008.

 

NSP-Minnesota’s capitalexpenditure forecast includes environmental improvements related tomodifications to reduce the emissions 

 

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

 

The capital expenditureprograms of NSP-Minnesota are subject to continuing review and modification.Actual utility construction expenditures may vary from the estimates due tochanges in electric and natural gas projected load growth, the desired reservemargin and the availability of purchased power, as well as alternative plansfor meeting NSP-Minnesota’s long-term energy needs. In addition, NSP-Minnesota’songoing evaluation of compliance with future requirements to installemission-control equipment, and merger, acquisition and divestitureopportunities to support corporate strategies may impact actual capitalrequirements.

 

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

 

Future commitments underoperating 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 asignificant portion of its current coal, nuclear fuel and natural gasrequirements. These contracts expire in various years between 2006 and 2027. Inaddition, NSP-Minnesota is required to pay additional amounts depending onactual quantities shipped under these agreements. The potential risk of loss,in the form of increased costs from market price changes in fuel, is mitigatedthrough the cost-rate adjustment mechanisms, which provides for pass through ofmost fuel, storage and transportation costs.

 

The estimated minimumpurchase for NSP-Minnesota under these contracts as of Dec. 31, 2005, is asfollows:

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

 

***Purchased Power Agreements****—*NSP-Minnesota has entered into agreementswith utilities and other energy suppliers for purchased power to meet systemload and energy requirements, replace generation from company-owned units undermaintenance and during outages, and meet operating reserve obligations.NSP-Minnesota has various pay-for-performance contracts with expiration datesthrough the year 2033. In general, these contracts provide for capacitypayments, subject to meeting certain contract obligations, and energy paymentsbased on actual power taken under the contracts. Certain contractual paymentobligations are adjusted based on indexes. However, the effect of these price adjustments are mitigated throughcost-of-energy rate adjustment mechanisms.

 

At Dec. 31, 2005, theestimated future payments for capacity that NSP-Minnesota is obligated topurchase, 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 |   |

 

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* Includes amounts allocatedto NSP-Wisconsin through intercompany charges.

 

# **EnvironmentalContingencies**

 

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

 

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

 

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

 

•              the site of a former federal uraniumenrichment 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 potentiallyresponsible party (PRP) that sent hazardous materials and wastes.

 

NSP-Minnesota records a liability when enough information is obtainedto develop an estimate of the cost of environmental remediation and revises theestimate as information is received. The estimated remediation cost may varymaterially.

 

Toestimate the cost to remediate these sites, assumptions are made when facts arenot fully known. For instance, assumptions may be made about the nature andextent of site contamination, the extent of required cleanup efforts, costs ofalternative cleanup methods and pollution control technologies, the period overwhich remediation will be performed and paid for, changes in environmentalremediation and pollution control requirements, the potential effect oftechnological improvements, the number and financial strength of other PRPs andthe identification of new environmental cleanup sites.

 

Estimatesare revised as facts become known.  AtDec. 31, 2005, the liability for the cost of remediating sites was estimated tobe $6.1 million, of which $5.3 million was considered to be a currentliability.  Some of the cost ofremediation may be recovered from:

 

•              insurance coverage;

 

•              other parties that have contributed to thecontamination; and

 

•              customers.

 

Neitherthe total remediation cost nor the final method of cost allocation among allPRPs of the unremediated sites has been determined.  Estimates have been recorded forNSP-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 DOEassessment for decommissioning a federal uranium enrichment facility. Thisenvironmental liability does not include accruals recorded and collected fromcustomers in rates for future nuclear fuel disposal costs or decommissioningcosts related to NSP-Minnesota’s nuclear generating plants. See Note 12 toConsolidated Financial Statements for further discussion of nuclearobligations.

 

***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 siteof the former Levee Station MGP site. The Levee Station was a coke-oven gaspurification, storage and distribution facility.  The Levee Station supplied manufactured gasto 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 andpartially remediated at a cost of approximately $2.9 million.  In 2006, NSP-Minnesota plans to commenceconstruction of the High Bridge Combined Cycle Generating Plant, as part of theMERP, on the site of the Levee Station. The construction of the new plantrequires the removal of buried structures and soil and groundwater remediation.Remediation activities began in 2005. The cost of the additional remediation isestimated to be $0.2 million, which will be accounted for as a capitalexpenditure of the MERP project.

 

***Third Party and Other Environmental SiteRemediation***

 

***Asbestos Removal****—*Some of our facilities contain asbestos. Mostasbestos will remain undisturbed until the facilities that contain it aredemolished or removed.  NSP-Minnesota hasrecorded an estimate for final removal of the asbestos as an asset retirementobligation.  See additional discussion ofasset retirement obligations elsewhere in Note 11.  It may be necessary to remove some asbestosto perform maintenance or make improvements to other equipment. The cost ofremoving asbestos as part of other work is immaterial and is recorded asincurred as operating expenses for maintenance projects, capital expendituresfor construction projects or removal costs for demolition projects.

 

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***Other EnvironmentalRequirements***

 

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

 

The objective of CAIR is to cap emissions of SO2 and NOx inthe eastern United States, including Minnesota. When fully implemented, CAIR will reduce SO2 emissions in 28eastern states and the District of Columbia by over 70 percent and NOxemissions by over 60 percent from 2003 levels. It is designed to address thetransportation of fine particulates, ozone and emission precursors tonon-attainment downwind states.  CAIR hasa 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 beallocated an emissions budget for SO2 and NOX that willresult in significant emission reductions.  It will be based on stringent emissioncontrols and forms the basis for a cap-and-trade program.   State emission budgets or caps decline overtime.  States can choose to implement anemissions reduction program based on the EPA’s proposed model program, or theycan propose another method, which the EPA would need to approve.

 

Minnesota and Wisconsin will be included in CAIR, and Xcel Energy hasgenerating facilities in these states that will be impacted.  Preliminary estimates of capital expendituresassociated with compliance with CAIR for the NSP System range from $30 millionto $40 million, which would be a cost sharable through the InterchangeAgreement.  Xcel Energy is notchallenging CAIR in these states.

 

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

 

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

 

The EPA’s CAMR also uses a national cap-and-trade system and isdesigned to achieve a 70 percent reduction in mercury emissions.  It affects all coal- and oil-fired generatingunits across the country that are greater than 25 megawatts.  Compliance with this rule also occurs intwo phases, with the first phase beginning in 2010 and the second phase in2018.  States will be allocated mercuryallowances based on coal type and their baseline heat input relative to otherstates.  Each electric generating unitwill be allocated mercury allowances based on its percentage of total coal heatinput for the state.  Similar to CAIR,states can choose to implement an emissions reduction program based on the EPA’sproposed model program, or they can propose another method, which the EPA wouldneed to approve.

 

Under CAMR, NSP-Minnesota can comply through capital investments inemission controls or purchase of emission “allowances” from other utilitiesmaking reductions on their systems. Estimating the cost of compliance with CAMRis difficult because technologies specifically designed for control of mercuryare in the early stages of development and there is no established market onwhich to base the cost of mercury allowances. NSP-Minnesota’s preliminary analysis for Phase I compliance suggestscapital costs of approximately $7.1 million and increased operating andmaintenance expenses of approximately $6.1 million, beginning in 2010.  Further testing is planned during 2006 toconfirm 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 the2006 session that could require up to a 90 percent reduction in mercuryemissions from coal-fueled power plants provided the MPUC determines that it istechnically feasible and economically reasonable to do so.  The cost impact of this potential legislationis unknown.  The legislation is expectedto allow for cost recovery by the utility

 

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

 

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

 

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

 

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the EPApublished phase II of the rule that applies to existing cooling water intakesat steam-electric power plants. The rule will require NSP-Minnesota to performadditional environmental studies at several power plants in Minnesota todetermine the impact the facilities may be having on aquatic organismsvulnerable to injury.  If the studiesdetermine the plants are not meeting the new performance standards establishedby the phase II rule, physical and/or operational changes may be required atthese plants.  It is not possible toprovide an accurate estimate of the overall cost of this rulemaking at thistime due to the many uncertainties involved, including unresolved third partylegal challenges to the Federal rule.  Based on the limited information available, total capital and operatingand maintenance costs to the NSP System are estimated at approximately $29.5million.  After costs are shared throughthe Interchange Agreement, NSP-Minnesota’s estimated cost is $28.0 million overthe next five to 10 years.  Actual costsmay be higher or lower depending on the final resolution of legal challenges tothe rule, as well as pending state and federal decisions regardinginterpretation of specific rule requirements.

 

# **AssetRetirement Obligations**

 

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

 

In March 2005, the Financial Accounting Standards Board (FASB) issuedFASB Interpretation No. 47 – “Accounting for Conditional Asset RetirementObligations” (FIN No. 47) to clarify the scope and timing of liabilityrecognition for conditional asset retirement obligations pursuant to SFAS No.143.  The interpretation requires that aliability be recorded for the fair value of an asset retirement obligation, ifthe fair value is estimable, even when the obligation is dependent on a futureevent.  FIN No. 47 further clarified thatuncertainty surrounding the timing and method of settlement of the obligationshould be factored into the measurement of the conditional asset retirementobligation rather than affect whether a liability should be recognized.  NSP-Minnesota implemented FIN No. 47 as ofDec. 31, 2005.  Included in thesefinancial statements are the recognition of a cumulative change in accountingand disclosure of the liability on a pro forma basis.

 

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

 

NSP-Minnesotarecognized an ARO for the retirement costs of natural gas mains and for theremoval of electric transmission and distribution equipment.  The electric transmission and distributionARO consists of many small potential obligations associated withpolychlorinated biphenyls (PCBs), mineral oil, storage tanks, treated poles,lithium batteries, mercury and street lighting lamps.  These electric and natural gas assets havemany in-service dates for which it is difficult to assign the obligation to aparticular year.  Therefore, theobligation was measured at Dec. 31, 2005. The asset retirement cost was set to this recognized obligation and nocumulative effect adjustment was shown.

 

A liabilityhas also been recorded in previous years for nuclear decommissioning of anNSP-Minnesota steam production plant. This plant began operating as a nuclear production facility in 1964before being converted to a steam peaking facility in 1969. For the nuclearassets, the asset retirement obligation associated with the decommissioning oftwo 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 operationin 1973 and 1974, respectively.  See Note12 to the Consolidated Financial Statements for further discussion of nuclearobligations.

 

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A reconciliation of thebeginning and ending aggregate carrying amount of NSP-Minnesota’s assetretirement 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 ofNSP-Minnesota assets legally restricted for purposes of settling the nuclearasset retirement obligations is $1.1 billion as of Dec. 31, 2005, includingexternal nuclear decommissioning investment funds and internally fundedamounts.

 

***Cumulative Effect of FIN No. 47 —***In March 2005, the FASB issued FIN No.47.  The interpretation clarified theterm “conditional asset retirement obligation” as used in SFAS No. 143.  The recording of the obligation for regulatedoperations has no income statement impact due to the deferral of the adjustmentsthrough the establishment of a regulatory asset pursuant to SFAS No. 71.  If NSP-Minnesota had implemented FIN No. 47at Jan. 1, 2004, the liability for asset retirement obligations would haveincreased by $37.4 million.  The sameliability at Dec. 31, 2004 would have increased by $39.4 million.  A summary of the accounting for the initialadoption 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 forplant removal costs for other generation, transmission and distributionfacilities.  Generally, the accrual offuture non-ARO removal obligations is not required.  However, long-standing ratemaking practicesapproved by applicable state and federal regulatory commissions have allowedprovisions for such costs in historical depreciation rates. These removal costshave accumulated over a number of years based on varying rates as authorized bythe appropriate regulatory entities. Given the long periods over which theamounts were accrued and the changing of rates through time, NSP-Minnesota hasestimated the amount of removal costs accumulated through historic depreciationexpense based on current factors used in the existing depreciation rates.  Accordingly, the recorded amounts ofestimated future removal costs are considered Regulatory Liabilities under SFASNo. 71. Removal costs as of Dec. 31, 2005 and 2004 are $334 million and $323million, respectively.

 

***Nuclear Insurance —***NSP-Minnesota’s public liability for claims resulting from any nuclearincident is limited to $10.8 billion under the 1988 Price-Anderson amendment tothe Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million ofcoverage for its public liability exposure with a pool of insurance companies.The remaining $10.5 billion of exposure is funded by the Secondary FinancialProtection Program, available from assessments by the federal government incase 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 forpublic liability arising from a nuclear incident at any licensed nuclearfacility in the United States. The maximum funding requirement is $15 millionper reactor during any one year.

 

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NSP-Minnesota purchasesinsurance for property damage and site decontamination cleanup costs fromNuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.1 billionfor each of NSP-Minnesota’s two nuclear plant sites. NEIL also providesbusiness interruption insurance coverage, including the cost of replacementpower obtained during certain prolonged accidental outages of nucleargenerating units. Premiums are expensed over the policy term. All companiesinsured with NEIL are subject to retroactive premium adjustments if lossesexceed accumulated reserve funds. Capital has been accumulated in the reservefunds of NEIL to the extent that NSP-Minnesota would have no exposure forretroactive premium assessments in case of a single incident under the businessinterruption and the property damage insurance coverage. However, in eachcalendar year, NSP-Minnesota could be subject to maximum assessments ofapproximately $14.8 million for business interruption insurance and $26.5million for property damage insurance if losses exceed accumulated reservefunds.

 

**LegalContingencies**

 

In the normal course ofbusiness, NSP-Minnesota is party to routine claims and litigation arising fromprior and current operations. NSP-Minnesota is actively defending these mattersand has recorded a liability related to the probable cost of settlement orother disposition when it can be reasonably estimated.

 

***Metropolitan Airports Commission vs. Northern States Power Company****—* On Dec. 30, 2004, the Metropolitan AirportsCommission (MAC) filed a complaint in Minnesota state district court assertingthat NSP-Minnesota is required to relocate facilities on MAC property at theexpense of NSP-Minnesota.  MAC claimsthat approximately $7.1 million charged by NSP-Minnesota over the past fiveyears for relocation costs should be repaid. Both parties have asserted cross motions for partial summary judgmentconcerning legal obligations associated with rent payments allegedly due andowing by NSP-Minnesota to MAC for the use of its property for a substation thatserves the MAC.  This hearing was held inJanuary 2006; the judge has not yet issued his decision.  Both sides have scheduled depositions of keywitnesses 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 anaction against NSP-Minnesota alleging negligence in the handling, supplying,distributing, and selling of electrical power systems, negligence in theconstruction and maintenance of distribution systems, and failure to warn oradequately test such systems.  Plaintiffsallege decreased milk production, injury and damage to a dairy herd as a resultof stray voltage resulting from NSP-Minneosta’s distribution system.  Plaintiff’s expert report on the economic damageto their dairy farm  that the totalpresent value of plaintiffs’ loss is $6.8 million.  Trial is scheduled to commence in March2007.  NSP-Minnesota denies theseallegations 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 asseveral environmental groups, filed lawsuits in U.S. District Court for theSouthern District of New York against five utilities, including Xcel Energy, toforce reductions in carbon dioxide (CO2) emissions.  Although NSP-Minnesota is not named as aparty to this litigation, the requested relief that Xcel Energy cap and reduceits CO2 emissions could have a material adverse effect on NSP-Minnesota.  The other utilities include American ElectricPower Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  CO2 is emitted whenever fossilfuel is combusted, such as in automobiles, industrial operations and coal- orgas-fired power plants.  The lawsuitsallege that CO2 emitted by each company is a public nuisance asdefined under state and federal common law because it has contributed to globalwarming.  The lawsuits do not demandmonetary damages.  Instead, the lawsuitsask the court to order each utility to cap and reduce its CO2emissions.  In October 2004, Xcel Energyand four other utility companies filed a motion to dismiss the lawsuit,contending, among other reasons, that the lawsuit should be dismissed becauseit is an attempt to usurp the policy-setting role of the U.S. Congress and thepresident.  On Sept. 19, 2005, the judgegranted the defendants’ motion to dismiss on constitutional grounds.  Plaintiffs have filed a notice of appeal.

 

The issue of global climate change is receiving increasedattention.  Debate continues in thescientific community concerning the extent to which the earth’s climate iswarming, the causes of climate variations that have been observed, and theultimate impacts that might result from a changing climate.  There also is considerable debate regardingpublic policy for the approach that the United States should follow to addressthe issue.  The United Nations-sponsoredKyoto Protocol, which establishes greenhouse gas reduction targets for developednations, entered into force on Feb. 16, 2005. President Bush has declared that the United States will not ratify theprotocol and is opposed to legislative mandates, preferring a program based onvoluntary efforts and research on new technologies.  NSP-Minnesota is closely monitoring the issuefrom both scientific and policy perspectives. While it is not possible to know the eventual outcome, NSP-Minnesotabelieves the issue merits close attention and is taking actions it believes areprudent to be best positioned for a variety of possible future outcomes.  Xcel Energy, including NSP-Minnesota, isparticipating in a voluntary carbon management program and has establishedgoals to reduce its volume of carbon dioxide emissions by 12 million tons by2009 and to reduce carbon intensity by 7 percent by 2012.  NSP-Minnesota’s evaluation process for futuregenerating resources incorporates the risk of future carbon limits through theuse of externality costs.  NSP-Minnesotaalso is involved in other projects to improve available methods for managingcarbon.

 

**12. NuclearObligations**

 

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

 

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responsible for permanentlystoring spent-fuel from NSP-Minnesota’s nuclear plants as well as from otherU.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’spermanent disposal program since 1981. The fuel disposal fees are based on acharge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation.Fuel expense includes DOE fuel disposal assessments of approximately $12million 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’sassessments to all utilities will be sufficient to fully fund the DOE’spermanent storage or disposal facility.

 

The Nuclear Waste PolicyAct 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 ananticipated delay in accepting spent-nuclear fuel by the required date andconceded that a permanent storage or disposal facility will not be availableuntil at least 2010. NSP-Minnesota and other utilities have commenced lawsuitsagainst the DOE to recover damages caused by the DOE’s failure to meet itsstatutory and contractual obligations.

 

NSP-Minnesota has its owntemporary, on-site storage facilities for spent-fuel at its Monticello andPrairie Island nuclear plants, which consists of storage pools and a dry caskfacility. With the dry cask storage facility licensed by the NRC, approved in1994 and again in 2003, management believes it has adequate storage capacity tocontinue operation of its Prairie Island nuclear plant until at least the endof its license terms in 2013 and 2014. The Monticello nuclear plant has storagecapacity in the pool to continue operations until 2010. Storage availability topermit operation beyond these dates is not known at this time. All of thealternatives for spent-fuel storage are being investigated until a DOE facilityis available, including pursuing the establishment of a private facility forinterim storage of spent-nuclear fuel as part of a consortium of electricutilities.

 

Nuclear fuel expenseincludes payments to the DOE for the decommissioning and decontamination of theDOE’s uranium enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’sinitial assessment of $46 million, which is payable in annual installments from1993 to 2008. NSP-Minnesota is amortizing each installment to expense on amonthly 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 thecost-of-energy adjustment clause as the assessments are amortized. Accordingly,the unamortized assessment of $8.3 million at Dec. 31, 2005, is deferred as aregulatory asset.

 

***Regulatory Plant Decommissioning Recovery*****— Decommissioning of NSP-Minnesota’s nuclearfacilities, as last approved by the MPUC, is planned for the period fromcessation of operations through 2040, assuming the prompt dismantlementmethod.  NSP-Minnesota is currentlyaccruing the costs for decommissioning over the MPUC approved cost-recoveryperiod and including the accruals in Accumulated Depreciation.  Upon implementation of SFAS No. 143, thedecommissioning costs in Accumulated Depreciation and ongoing accruals arereclassified to a regulatory liability account. The total decommissioning costobligation is recorded as an asset retirement obligation in accordance withSFAS No. 143.

 

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

 

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

 

The MPUC last approvedNSP-Minnesota’s nuclear decommissioning study request in December 2003, using2002 cost data. In October 2005, NSP-Minnesota filed with the MPUC anuclear decommissioning study using 2005 cost data.  Xcel Energy’s recommendation is to reduce the2006 funding if approved by the MPUC. Xcel Energy expects the MPUC to approve a new funding amount in 2006.

 

Internalfunding for all retail jurisdictions has been transferred to the external fundsby the end of 2005.  Based on thelast MPUC approval requiring the acceleration of the internal fund transfer,there is a step change in the level of the overall decommissioning expense atthe expiration of the transfer beginning Jan. 1, 2006. Expecting to operatePrairie Island through the end of each unit’s licensed life, the approvedcapital recovery will allow for the plant to be fully depreciated, includingthe accrual and recovery of decommissioning costs, in 2014. Xcel Energybelieves future decommissioning cost accruals will continue to be recovered in 

 

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customer rates.

 

The total obligation fordecommissioning currently is expected to be funded 100 percent by externalfunds, as approved by the MPUC. Contributions to the external fund started in1990 and are expected to continue until plant decommissioning begins. Theassets held in trusts as of Dec. 31, 2005, primarily consisted of investmentsin fixed income securities, such as tax-exempt municipal bonds and U.S.government securities that mature in one to 20 years, and common stock ofpublic companies. NSP-Minnesota plans to reinvest matured securities until decommissioningbegins.

 

At Dec. 31, 2005,NSP-Minnesota had recorded and recovered in rates cumulative decommissioningaccruals of $816 million. The following table summarizes the funded status ofNSP-Minnesota’s decommissioning obligation based on approved regulatoryrecovery parameters.  These amounts arenot those recorded in the financial statements for the asset retirementobligation 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 expensesrecognized 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 interestaccruals are included with Regulatory Liabilities on the Consolidated BalanceSheet. Interest costs and trust earnings associated with externally funded obligationsare reported in Other Nonoperating Income on the Consolidated Statements ofOperations.

 

Negative accruals forinternally funded portions in 2003, 2004 and 2005 reflect the impact of the2002 decommissioning study, which approved an assumption of 100-percentexternal funding of future costs.  The2005 nuclear decommissioning filing has not been used for the regulatorypresentation because it is effective for 2006. However, the filing and all the updated parameters were used for a newARO layer for SFAS No. 143 recognition.

 

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**13.Regulatory Assets and Liabilities**

 

NSP-Minnesota’s financialstatements are prepared in accordance with the provisions of SFAS No. 71, asdiscussed in Note 1 to the Consolidated Financial Statements. Under SFAS No.71, regulatory assets and liabilities can be created for amounts thatregulators may allow to be collected, or may require to be paid back tocustomers in future electric and natural gas rates. Any portion of the businessthat is not rate regulated cannot use SFAS No. 71 accounting.  If changes in the utility industry or thebusiness of NSP-Minnesota no longer allow for the application of SFAS No. 71under GAAP, NSP-Minnesota would be required to recognize the write-off ofregulatory assets and liabilities in its statement of operations.  The components of unamortized regulatoryassets 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 |   |

 

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

 

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

 

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

 

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

 

**14. Segmentand Related Information**

 

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

 

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

 

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

 

Revenues from operatingsegments not included above are below the necessary quantitative thresholds andare therefore included in the All Other category. Those primarily includeappliance repair services, nonutility real estate activities and revenuesassociated with processing solid waste into refuse-derived fuel.

 

To report net income forRegulated Electric and Regulated Natural Gas Utility segments, NSP-Minnesotamust assign or allocate all costs and certain other income. In general, costsare:

 

•       directly assigned whereverapplicable;

•       allocated based on costcausation allocators wherever applicable; or

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

 

The accounting policies ofthe segments are the same as those described in Note 1 to the ConsolidatedFinancial Statements.  Thesesegments are managed separately because the revenue streams are dependent uponregulated 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. RelatedParty Transactions**

 

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

 

Xcel Energy has establisheda utility money pool arrangement with the utility subsidiaries and receivedrequired state regulatory approvals.  SeeNote 2 for further discussion of this borrowing arrangement.

 

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

 

57

----

 

NMC is anoperating company that manages the operations, maintenance and physicalsecurity of several nuclear generating units on five sites, including threeunits/two sites owned by NSP-Minnesota. NSP-Minnesota continues to own the plants, controls all energy producedby the plants, and retains responsibility for nuclear property and liabilityinsurance and decommissioning costs.  TheWisconsin Public Service Corporation is no longer participating in NMC afterthe sale of its Kewaunee nuclear power plant in July 2005.  In January 2006, Florida Power & Lightpurchased the majority interest in the Duane Arnold plant from Alliant Energyand announced it will assume management of the plant.  As a result, NSP-Minnesota’s ownershipinterest 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 andcapital improvement costs incurred by NMC. NSP-Minnesota paid NMC $257.1 million in 2005, $314.7 million in 2004and $227.0 million in 2003.

 

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

 

The table below containssignificant affiliate transactions among the companies and related partiesincluding 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 andpayable 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 obtainsshort-term borrowings from NSP-Minnesota at NSP-Minnesota’s average dailyinterest rate, including the cost of NSP-Minnesota’s compensating balancerequirements. At Dec. 31, 2005 and 2004, NSP-Minnesota had notes receivableoutstanding from NSP-Wisconsin in the amount of $64.0 million and $31.5million, respectively.  Interest incomerelated to the NSP-Wisconsin borrowing on NSP-Minnesota’s statement of incomewas $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 

 

58

----

 

 

compared to amounts previously reported in the first quarter 200510-Q.  Revenue for the quarter ended Dec.31, 2004 has been reduced by $10.3 million as compared to the amount previouslyreported in the 2004 10-K.  Theseadjustments are a result of fees collected from customers on behalf ofgovernmental agencies that were reclassified to be presented net of the relatedpayments 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 sharedwith NSP-Wisconsin, pursuant to the Interchange Agreement.  In addition, an adjustment, which reducedexpenses charged to NSP-Wisconsin by NSP-Minnesota of $6.2 million was recordedfor 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 thesuccessful resolution of various IRS audit issues and other adjustments tocurrent and deferred taxes related to prior years.

 

**Item 9 — Changes in and Disagreements With Accountantson Accounting and Financial Disclosure**

 

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

 

**Item 9A — Controls and Procedures**

 

**DisclosureControls and Procedures**

 

NSP-Minnesota maintains aset of disclosure controls and procedures designed to ensure that informationrequired to be disclosed in reports that it files or submits under theSecurities Exchange Act of 1934 is recorded, processed, summarized and reportedwithin the time periods specified in Securities and Exchange Commission rulesand forms. As of the end of the period covered by this report, based on anevaluation carried out under the supervision and with the participation of theNSP-Minnesota’s management, including the Chief Executive Officer (CEO) andChief Financial Officer (CFO), of the effectiveness of its disclosure controlsand procedures, the CEO and CFO have concluded that the Company’s disclosurecontrols and procedures are effective.

 

**Internal Control Over Financial Reporting**

 

No change in NSP-Minnesota’sinternal control over financial reporting has occurred during NSP-Minnesota’smost recent fiscal quarter that has materially affected, or is reasonablylikely to materially affect, NSP-Minnesota’s internal control over financialreporting.

 

**Item 9B**— **Other Information**

 

None

 

**PART III**

 

Items 10, 11, 12 and 13 ofPart III of Form 10-K have been omitted from this report for NSP-Minnesota inaccordance 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 theRegistrant**

 

**Item 11 — Executive Compensation**

 

**Item 12 — Security Ownership of Certain BeneficialOwners and Management**

 

**Item 13 — Certain Relationships and RelatedTransactions**

 

**Item 14 — Principal Accounting Fees and Services**

 

Information concerningfees paid to the principal accountant for each of the last two years iscontained in the Xcel Energy Proxy Statement for its 2006 Annual Meeting ofShareholders, which is incorporated by reference.

 

**PART IV**

 

**Item15 — 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.

 

59

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

Consolidated Statements of Cash Flows **—** For the three years ended Dec. 31, 2005, 2004 and2003.

Consolidated Balance Sheets **—**Asof Dec. 31, 2005 and 2004.

 

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

 

3.               Exhibits

 

----

*Indicates incorporation by reference

+Executive Compensation Arrangements and Benefit Plans CoveringExecutive 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                                                                                                                                                                                                                                                                         |

 

60

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|    |   | 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).                                                                                                                                                                                                                                                                                                                                                                     |

 

61

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| 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                                                                                                                                                                                                                                                          |
|         |        |                                                                                                                                                                                                                                                                                                                                                            |  |  |

 

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|   |   | 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.                                                                                                                                                                                             |

 

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# **SCHEDULEII**

 

**NSP-MINNESOTAVALUATION AND QUALIFYING ACCOUNTSYears Ended Dec. 31, 2005, 2004 and 2003**

**(Thousands ofDollars)**

 
| ** **                            | ** ** | ** **                           | ** ** | **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 |   |

 

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(1)          Recovery of amounts previously written off.

(2)          Principally uncollectible accounts written off or transferred.

 

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**SIGNATURES**

 

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

 
| ** **             | **NORTHERN  STATES POWER COMPANY**                                                                 |
|------------------------|----------------------------------------------------------------------------------------------------|
|                   |                                                                                               |
|                   | /s/ BENJAMIN G.S. FOWKE  III                                                                       |   |
|                   | Benjamin G.S. Fowke III  Vice President and Chief Financial Officer  (Principal Financial Officer) |
|                   |                                                                                               |
| **February  24, 2006** |                                                                                               |

 

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report has been signed below bythe following persons on behalf of the registrant and in the capacities and onthe date indicated.

 
| /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                        |                                                                                                         |
|                                                                         |                                                                                                              |                              |        |        |  |

 

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**SUPPLEMENTALINFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THEACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12OF THE ACT**

 

NSP-Minnesotahas not sent, and does not expect to send, an annual report or proxy statementto its security holder.

 

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