**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**FORM 10-K**

**(MarkOne)**

**x**              ANNUAL REPORTPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

**For the fiscal year ended December 31, 2006**

 

**OR**

               

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

 

**For the transition periodfrom                 to**

 

**COMMISSION FILE NUMBER 000-31387**

**NORTHERN STATES POWER COMPANY**

(Exact name of registrant as specified in its charter)
| **Minnesota**                                                    | ** ** | **41-1967505**                        |
|------------------------------------------------------------------|------------|---------------------------------------|
| (State or other  jurisdiction of  incorporation or organization) |       | (I.R.S. Employer  Identification No.) |

** **

**414 Nicollet Mall****Minneapolis, Minnesota 55401**(Address of principal executive offices)(Zip Code)

**(612) 330-5500**(Registrant’s telephone number, including area code)

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

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

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined by Rule 405 of theSecurities Act.    Yes  o    No  x

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

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

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, and willnot be contained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer or a non-accelerated filer (asdefined in Rule 12b-2 of the Act).

o  Largeaccelerated filer    o  Acceleratedfiler    x Non-acceleratedfiler

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

As of Feb. 20, 2007, 1,000,000 shares of common stock,par value $0.01 per share, were outstanding, all of which were held by XcelEnergy Inc., a Minnesota Corporation.

**DOCUMENTS INCORPORATED BY REFERENCE: XcelEnergy Inc.’s 2007 Proxy Statement, to be filed subsequently**

**NorthernStates Power Company meets the conditions set forth in General InstructionI(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduceddisclosure 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,  Related Stockholder Matters and Issuer Purchases of Equity Securities |       |       |       |
| 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, Executive Officers, and Corporate  Governance                                                          |       |       |       |
| Item  11 — Executive Compensation                                                                                           |       |       |       |
| Item 12 — Security Ownership of Certain Beneficial  Owners and Management and Related Stockholder Matters                   |       |       |       |
| Item 13 — Certain Relationships, Related Transactions,  and Director Independence                                           |       |       |       |
| Item 14 — Principal Accounting Fees and Services                                                                            |       |       |       |
|                                                                                                                             |       |       |       |
| **PART IV**                                                                                                                      |       |       |       |
| Item 15 — Exhibits, Financial Statement Schedules                                                                           |       |       |       |
|                                                                                                                             |       |       |       |
| **SIGNATURES**                                                                                                                   | ** ** | ** ** | ** ** |

 

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

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**PART I**

**Item l —Business**

# **DEFINITIONOF ABBREVIATIONS AND INDUSTRY TERMS**

 
| ***Xcel Energy  Subsidiaries and Affiliates***             |   |                                                                                                                                                                                                                                                                                                                                                                                                                             |   |
|------------------------------------------------------------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
| NMC                                                        |   | Nuclear Management Co., a company formed by  NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service  Corporation and Alliant Energy Corp.                                                                                                                                                                                                                                                                         |
| 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                                                                                                                                                                                                                                                                                                                                                                                               |   |
| 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.                                                                                                                                                     |   |
| 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 actual cost of electric fuel and  purchased energy compared to a prior forecast. 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 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.                                                                                                                                                   |   |

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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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |

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| 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.                                                                                                                     |   |
| PUHCA 2005               |         | Public Utility Holding Company Act of 2005.  Successor to the Public Utility Holding Company Act of 1935.  Eliminates most federal regulation of  utility holding companies.  Transfers  other regulatory authority from the SEC to FERC.                  |
| 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                                                                                                                                                                                                                          |
| 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                                                                                                                                                                                                                                                   |
| 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.                                                                                          |
|                          |              |                                                                                                                                                                                                                                                                      |  |  |  |

 

 

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# **COMPANYOVERVIEW**

NSP-Minnesotawas incorporated in 2000 under the laws of Minnesota.  NSP-Minnesota is an operating utility engagedin the generation, purchase, transmission, distribution and sale of electricityin Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately13 percent of the total sales in 2006. NSP-Minnesota also purchases, transports, distributes and sells naturalgas to retail customers and transports customer-owned natural gas in Minnesotaand North Dakota.  NSP-Minnesota provideselectric utility service to approximately 1.4 million customers and gas utilityservice to approximately 0.5 million customers. Approximately 90 percent of NSP-Minnesota’s retail electric operatingrevenues was derived from operations in Minnesota during 2006.

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

NSP-Minnesotaowns the following direct subsidiaries: United Power and Land Co., which holdsreal estate; and NSP Nuclear Corp., which holds NSP-Minnesota’s interest in theNMC.

# **ELECTRICUTILITY OPERATIONS**

**Overview**

***Utility IndustryGrowth***— NSP-Minnesota intends to focus on growingthrough investments in electric and natural gas rate base to meet growingcustomer demands and to maintain or increase reliability and quality of serviceto customers.  NSP-Minnesota plans tocontinue to file rate cases with state and federal regulators to earn a returnon its investment and recover costs of operations.

***UtilityRestructuring and Retail Competition***— The structure ofthe 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. The FERC has implemented wholesale electric utility competition, and thewholesale customers of Xcel Energy’s utility subsidiaries can purchase fromcompeting wholesale suppliers and use the transmission systems of the utilitysubsidiaries on a comparable basis to the utility subsidiaries’ use to servetheir native load.  Beginning in the late1990s, many states began studying or implementing some form of retail electricutility competition.

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

# **Summary of Recent FederalRegulatory Developments**

TheFERC has jurisdiction over rates for electric transmission service ininterstate commerce and electric energy sold at wholesale, hydro facilitylicensing, natural gas transportation, accounting practices and certain otheractivities of NSP-Minnesota.  State andlocal agencies have jurisdiction over many of NSP-Minnesota’s activities, includingregulation of retail rates and environmental matters. In addition to thematters discussed below, see Note 10 to the Consolidated Financial Statementsfor a discussion of other regulatory matters.

***FERC Rules Implementing Energy PolicyAct of 2005 (Energy Act)***— The Energy Act repealed PUHCAeffective Feb. 8, 2006.  Inaddition, the Energy Act required the FERC to conduct several rulemakings toadopt new regulations to implement various aspects of the Energy Act.  Since Aug. 2005, the FERC has completedor initiated the proceedings to modify its regulations on a number of subjects,including:

·                  Adopting newregulations by establishing rules for accounting procedures for holdingcompany systems, including cost allocation rules for transactions betweencompanies within a holding company system;

·                  Adopting newregulations to implement changes to the FERC’s merger and asset transferauthority;

·                  Adopting new “marketmanipulation regulations” prohibiting any “manipulative or deceptive device orcontrivance” in wholesale natural gas and electricity commodity andtransportation or transmission markets and interpreting this standard in amanner consistent with Rule 10b-5 of the SEC; violations are subject topotential civil penalties of up to $1 million per day;

·                  Adoptingregulations to establish a national Electric Reliability Organization (ERO) toreplace the voluntary North American Electric Reliability Council (NERC)structure, and requiring the ERO to establish mandatory reliability

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standards and impositionof financial or other penalties for violations of adopted standards.  The FERC has issued proposed rules to make 83ERO reliability standards mandatory and subject to potential financialpenalties for non-compliance to be effective June 1, 2007;

·                  Adoptingrules to implement changes to the Public Utility Regulatory Policy Act toallow utility ownership of QFs and strengthening the thermal energyrequirements for entities seeking to be QFs;

·                  Proposingrules that would allow a utility to seek to eliminate its mandatory QFpower purchase obligation for utilities in organized wholesale energy marketssuch as MISO; and

·                 Adoptingrules to establish incentives for investment in new electric transmissioninfrastructure.

NSP-Minnesotagenerally supports the regulations adopted or proposed by the FERC to date, butcannot predict the ultimate impact the new regulations will have on itsoperations or financial results.

***ElectricTransmission Rate Regulation***— The FERC also regulatesthe rates charged and terms and conditions for electric transmissionservices.  FERC policy encouragesutilities to turn over the functional control over their electric transmissionassets and the related responsibility for the sale of electric transmissionservices to an RTO.  NSP-Minnesota is amember of the MISO.  Each RTO separatelyfiles regional transmission tariff rates for approval by the FERC.  All members within that RTO are thensubjected to those rates.

***CentralizedRegional Wholesale Markets*** — The FERC rules require RTO’sto operate centralized regional wholesale energy markets.  The FERC required the MISO to begin operationof a “Day 2” wholesale energy market on April 1, 2005.  MISO uses security constrained regionaleconomic dispatch and congestion management using locational marginal pricing(LMP) and FTR’s.  The Day 2 market isintended to provide more efficient generation dispatch over the 15 state MISOregion.

**RatemakingPrinciples**

***Summary of Regulatory Agencies and Areas of Jurisdiction***—Retail rates, services and other aspects of NSP-Minnesota’s operations areregulated by the MPUC, the NDPSC and the SDPUC within their respective states.The MPUC has regulatory authority over aspects of NSP-Minnesota’s financialactivities, including security issuances, property transfers, mergers andtransactions between NSP-Minnesota and its affiliates. In addition, the MPUCreviews and approves NSP-Minnesota’s electric resource plans for meetingcustomers’ future energy needs. The MPUC also certifies the need for generatingplants greater than 50 MW and transmission lines greater than 100 KV.

The MPUC is alsoempowered to select and designate sites for new power plants with a capacity of50 MW or more and wind energy conversion plants with a capacity of five MW ormore. It also designates routes for electric transmission lines with a capacityof 100 KV or more. No large power plant or transmission line may be constructedin Minnesota except on a site or route designated by the MPUC. The NDPSC andSDPUC have regulatory authority over the need for certain generating andtransmission facilities, and the siting and routing of certain new generationand transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subjectto the jurisdiction of the FERC with respect to its wholesale electricoperations, accounting practices, wholesale sales for resale and thetransmission of electricity in interstate commerce. NSP-Minnesota has receivedauthorization from the FERC to make wholesale electric sales at market-based prices(see market-based rate authority discussion) and is a transmission-owner memberof the MISO.

***Fuel, Purchased Energy and Conservation Cost RecoveryMechanisms*** — 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’s participationin the MISO Day 2 market, questions were raised regarding the inclusion ofcertain MISO charges in the FCA. However, in December 2006, the MPUC authorized FCA recovery of all MISODay 2 charges, except certain administrative charges, which NSP-Minnesota ispartially recovering in base rates and partially deferring for futurerecovery.  In general, capacity costs arenot recovered through the FCA. NSP-Minnesota’s electric wholesale customers also have a FCA provisionin their contracts.

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

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***MERP RiderRegulation***— In 2003, the MPUC approved NSP-Minnesota’sMERP proposal to convert two coal-fueled electric generating plants to naturalgas, and to install advanced pollution control equipment at a third coal-firedplant.  All three plants are located inthe Minneapolis - St. Paul metropolitan area. These improvements are expectedto significantly reduce air emissions from these facilities, while increasingthe capacity at system peak by 300 MW. The projects are expected to come online between 2007 and 2009, at a cumulative investment of approximately $1billion.  The MPUC also approved a raterider to recover prudent costs of the projects from Minnesota customersbeginning Jan. 1, 2006, including a rate of return on the construction work inprogress.  The MPUC approval has asliding ROE scale based on actual construction cost compared with a targetlevel of construction costs (based on an equity ratio of 48.5 percent and adebt ratio of 51.5 percent) to incentivize NSP-Minnesota to controlconstruction costs. At Dec. 31, 2006, the estimated ROE was 10.74 percent,based on construction progress to date.

| 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    | %          |

 

For a further discussion of rate and regulatorymatters see Note 10 to the Consolidated Financial Statements.

**Capacityand Demand**

Uninterrupted system peakdemand for the NSP System’s electric utility for each of the last three yearsand the forecast for 2007, assuming normal weather, are listed below.

|            | ** ** | **System Peak Demand (in MW)** | ** ** |
|------------|------------|----------------------------------------------------|------------|
| ** ** | ** ** | **2004**                                           | ** ** | **2005** | ** ** | **2006** | ** ** | **2007 Forecast** | ** ** |
| ** ** | ** ** | ** **                                         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| NSP System |       | 8,665                                              |       | 9,212 |   | 9,787 |   | 9,623 |   |

 

The peak demand for theNSP System typically occurs in the summer. The 2006 uninterrupted system peak demand for the NSP System occurred onJuly 31, 2006.

**EnergySources and Related Initiatives**

NSP-Minnesota expects touse existing electric generating stations, purchases from other utilities,independent power producers and power marketers, demand-side managementoptions, new generation facilities and phased expansion of existing generationat select power plants to meet its net dependable system capacity requirements.

***Purchased Power***— NSP-Minnesota hascontractual arrangements to purchase power from other utilities andnonregulated energy suppliers. Capacity is the measure of the rate at which aparticular generating source produces electricity.  Energy is a measure of the amount ofelectricity produced from a particular generating source over a period oftime.  Long-term purchase power contractstypically require a periodic payment to secure the capacity from a particulargenerating source and a charge for the associated energy actually purchased fromsuch generating source.

NSP-Minnesota also makesshort-term purchases to replace generation from company-owned units that areunavailable due to maintenance and unplanned outages, to comply with minimumavailability requirements, 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.

***Excelsior Energy Inc.(Excelsior)***—*** ***In December 2005, Excelsior, an independent energy developer, filed apower purchase agreement with the MPUC seeking a declaration by the MPUC thatNSP-Minnesota be compelled to enter into a power purchase agreement andpurchase the output from each of two integrated gas combined cycle (IGCC)plants to be located in northern Minnesota. Excelsior filed this petition making claims pursuant to Minnesotastatutes, relating to Innovative Energy Projects and Clean Energy Technology.

TheMPUC referred this matter to a contested case hearing to develop the facts andissues that must be resolved to act on Excelsior’s petition, includingdevelopment of price information.  Thecontested case proceeding considered a 603 MW unit in phase I and a second 603 MWunit in phase II of Excelsior project.

8

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In2006, NSP-Minnesota and other parties filed testimony in phase I of thisproceeding.  The parties filed briefs inJanuary 2007.  The ALJ is expected tomake a recommendation to the MPUC on phase I later in the first quarter of 2007and make a recommendation on phase II in August 2007.

NSP-Minnesota’sposition in the proceeding is that the proposal (i) is inconsistent with ourresource need, (ii) is not likely to be least-cost and is not in the publicinterest, (iii) shifts substantial risks to NSP-Minnesota and our ratepayers,(iv) presents a power purchase agreement that is inconsistent with industrystandards in its allocation of risks and costs, (v) the proposal fails tosatisfy the elements of the statutes under which it is proposed, and (vi) theproposal could result in significant adverse financial consequences.  NSP-Minnesota intends to request that allcosts associated with the proposed power purchase agreement, if approved, willbe recoverable in customer rates.

***NSP System Resource Plan***—On Nov. 1, 2004, NSP-Minnesota filed its proposed resource plan for the period2005 through 2019.  The proposed planidentified needed resources and proposed processes for acquiring resources tomeet those needs.  On July 28, 2006, theMPUC issued an order that, among other things:

·                  ApprovedNSP-Minnesota’s proposal to proceed with a request for proposal for 136 MW ofpeaking resources with an intended in service date of 2011;

·                  Identified abase load resource need of 375 MW beginning in 2015 and requires NSP-Minnesotato file a certificate of need application for a proposed base load resource tobegin the acquisition process by Nov. 1, 2006;

·                  Approvedacquisition of 1,680 MW of wind generation resource over the planning period;

·                  Accepted theproposed increases in demand-side management and energy-savings goals; and

·                  Accepted thesubmittal of NSP-Minnesota’s plan for uprating the Monticello and PrairieIsland nuclear plants along with a comprehensive environmental and upgrade planfor the Sherco plant.

OnOct. 18, 2006, the MPUC issued an order after reconsideration clarifying theNov. 1, 2006, filing requirements and extending the filing requirement for thenuclear upgrades until Sept. 1, 2007, to accommodate scheduling and legislativereview of the MPUC’s decision in the Monticello certificate of need proceeding.

NSP-Minnesotaexpects to file its next resource plan with the MPUC on July 1, 2007.

***Base Load Acquisition Proceeding****—*On Nov. 1, 2006, NSP-Minnesota filed aproposal with the MPUC for a purchase of 375 MW of capacity and energy from Manitoba Hydro for the period2015-2025 and the purchase of 380 MW of wind energy to fulfill the base loadneed identified in the 2004 resource plan. The proposal included a signed term sheet with Manitoba Hydro for and aprocess to acquire the wind energy through competitive bidding.  Alternative suppliers were entitled to submitcompeting proposals to the MPUC by Dec. 18, 2006.  An alternate supplier proposed a 375 MW shareof a mine mouth lignite circulating fluidized bed plant located in North Dakotaand 380 MW of wind energy generation, with an option for Xcel Energy ownershipin both components.  The MPUC found bothNSP-Minnesota’s proposal and the alternate proposal to be substantiallycomplete and referred the matter to a contested case proceeding.

***Transmission Certificates of Need***—******In December 2001,NSP-Minnesota proposed construction of various transmission system upgrades toprovide transmission outlet capacity for up to 825 MW of renewable energygeneration (wind and biomass) being constructed in southwest and westernMinnesota.  In March 2003, the MPUCgranted four certificates of need to NSP-Minnesota, thereby approvingconstruction, subject to certain conditions. The initial projected cost of the transmission upgrades wasapproximately $160 million.  The MPUCgranted 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 RCRautomatic adjustment mechanism that allows NSP-Minnesota to recover the revenuerequirements associated with certain transmission investments for delivery ofrenewable energy resources.

In late 2006, NSP-Minnesota filed two applications forcertficates of need with the MPUC for four additional transmission lines insouthwestern Minnesota and Chisago County.  NSP-Minnesota along with ten othertransmission providers, have announced plans to file certificate of needapplications by mid 2007 for three transmission lines serving Minnesota andparts of surrounding states.

***Purchased Transmission Services***—******NSP-Minnesota andNSP-Wisconsin have contractual arrangements with MISO to deliver power andenergy to the NSP System for native load customers.

***Nuclear Power Operations and Waste Disposal***—******NSP-Minnesota ownstwo nuclear generating plants: the Monticello plant and the Prairie Islandplant.  See additional discussionregarding the nuclear generating plants at Note 12 to the ConsolidatedFinancial Statements.

9

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

*Low-LevelRadioactive Waste Disposal  **—***Federal lawplaces responsibility on each state for disposal of its low-level radioactivewaste generated within its borders. Low-level radioactive waste from NSP-Minnesota’s Monticello and PrairieIsland nuclear plants is currently disposed at the Barnwell facility located inSouth Carolina (all classes of low-level waste) and at the Clive facilitylocated in Utah (class A low-level substance only).  NSP-Minnesota has an annual contract withBarnwell, but is also able to utilize the Clive facility through variouslow-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 current licensed lives, if off-site low-leveldisposal facilities were not available to NSP-Minnesota.

*High-LevelRadioactive Waste Disposal**—***Thefederal government has the responsibility to dispose of, or permanently store,domestic spent nuclear fuel and other high-level radioactive wastes.  The Nuclear Waste Policy Act requires the DOEto implement a program for nuclear high level waste management.  This includes the siting, licensing,construction and operation of a repository for domestically produced spentnuclear fuel from civilian nuclear power reactors and other high-levelradioactive wastes at a permanent Federal storage or disposal facility.  To date, the DOE has not accepted any ofNSP-Minnesota’s spent nuclear fuel.  SeeItem 3 — Legal Proceedings and Note 12 to the Consolidated Financial Statementsfor further discussion of this matter.

NSP-Minnesota has on-sitestorage for spent nuclear fuel at its Monticello and Prairie Island nuclearplants.  In 1993, the Prairie Islandplant was licensed by the federal NRC to store up to 48 casks of spent fuel atthe plant.  In 1994, the MinnesotaLegislature adopted a limit on dry cask storage of 17 casks for the entire state.  In 2003, the Minnesota Legislature enactedrevised legislation that will allow NSP-Minnesota to continue to operate thefacility and store spent fuel there until its current licenses with the NRCexpire in 2013 and 2014.  The legislationtransfers the primary authority concerning future spent-fuel storage issuesfrom the state Legislature to the MPUC. It also allows for additional storage without the requirement of anaffirmative vote from the state Legislature, if the NRC extends the licenses ofthe Prairie Island and Monticello plants and the MPUC grants a certificate ofneed for such additional storage.  It isestimated that operation through the end of the current license will require 12additional storage casks to be stored at Prairie Island, for a total of 29casks.  In October 2006, the MPUCauthorized an on-site storage facility and 30 casks at Monticello which willallow the plant to operate to 2030.  Theirdecision becomes effective June 1, 2007, unless the legislature takesaction.  As of Dec. 31, 2006, there were22 casks loaded and stored at the Prairie Island plant.

*PFS  **—***NSP-Minnesotais part of a consortium of private parties working to establish a privatefacility for interim storage of spent nuclear fuel.  In 1997, PFS filed a license application withthe NRC for a temporary storage site for spent nuclear fuel on the Skull ValleyIndian Reservation in Utah.  On Feb. 28,2006, the NRC commissioners issued the license for PFS, ending the 8-yeareffort to gain a license for the site. The license is contingent on the condition that PFS must demonstratethat it has adequate funding before construction may begin.  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-Minnesota indicated that it would hold inabeyance future investments in the construction of PFS as long as there is apparentand continuing progress in federally sponsored initiatives for storage, reuse,and/or disposal for the nation’s spent nuclear fuel. In September 2006, theDepartment of the Interior issued two findings: (1) that it would not grant theleases for rail or intermodal sites and (2) that  it was revoking its previous ConditionalApproval of the site lease between PFS and the Skull Valley Indian tribe eventhough the conditions had been met.  Thestated reasons were principally lack of progress at Yucca Mountain and lack ofBureau of Indian Affairs staff to monitor this activity.  Both findings are expected to be appealed.

*PrairieIsland Steam Generator Replacement  **—*** Prairie IslandUnit 2 steam generators received required inspections during a scheduled 2005outage.  Based on current rates ofdegradation and available repair processes, NSP-Minnesota plans to replacethese steam generators in the 2013 regular refueling outage.  Due to the potential shortages in the worldmarkets for materials and shop capabilities, NSP-Minnesota received Xcel Energyboard approval in August 2006 to begin the process for long-lead timematerials.

*NuclearPlant Re-licensing*****— Monticello’scurrent 40-year license expires in 2010, and Prairie Island’s licenses for itstwo units expire in 2013 and 2014. Montcello’s license renewal was approved by the NRC in November 2006,and the MPUC issued its approval in October 2006 allowing additional spent fuelstorage.  Minnesota statutes provide thatthe MPUC decision becomes effective June 1, 2007, which allows the legislaturethe opportunity to review the MPUC action if considered appropriate.  Prairie Island has initiated the necessaryplant assessments and aging analysis to support submittal of similarapplications to the NRC and the MPUC, currently planned for submittal in early2008.

10

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*NuclearPlant Power Uprates*— * *At the direction of the MPUC,NSP-Minnesota is pursuing capacity increases of all three units that will totalapproximately 250 MW, to be implemented, if approved, between 2009 and 2015.The life extension and a capacity increase for Prairie Island Unit 2 iscontingent on replacement of Unit 2’s original steam generators, currentlyplanned for replacement during the refueling outage in 2013. Total capitalinvestment for these activities is estimated to be approximately $1 billionbetween 2006 and 2015. NSP-Minnestoa plans to seek approval for an alternativerecovery mechanism from customers of its nuclear costs.  NSP-Minnesota plans to submit the certificateof need for the Monticello uprate in the second quarter of 2007 and thecertificate of need for the Prairie Island uprate in the third quarter of 2007.

*NMC*****— As of Dec.31, 2006, all members of the NMC, other than NSP-Minnesota, have chosen to selltheir units and exit the NMC.  Regardingthe remaining members of the NMC, the sales transaction of the CMS Energy Corp.Palisades Nuclear Power Plant is targeted to close in the first quarter of2007.  In December 2006, WisconsinElectric Power Co., announced its intent to sell its Point Beach Nuclear Plant to FPL Energy, with the saleexpected to close in the third or fourth quarter of 2007.

Following consummation of thesesale transacions, NSP-Minnesota will be the sole remaining member of theNMC.  NSP-Minnesota is evaluating thesituation and is considering various alternatives, including transitioning  the NMC to a wholly owned subsidiary of XcelEnergy.  To facilitate implementation ofthis option, Xcel Energy plans are progressing to restructure the NMC to supporta two-site organization, as well as reabsorb the adminstrative functions withinXcel Energy by the end of 2007.

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

**FuelSupply and 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.
| **NSP System   Generating Plants** | ** ** | **Coal***  | ** ** | **Nuclear** | ** ** | **Natural Gas** | ** ** | **Average Fuel** | ** ** |
|---------------------------------------------------|------------|------------|------------|-------------|------------|----------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **Cost**   | ** ** | **Percent** | ** ** | **Cost**             | ** ** | **Percent**           | ** ** | **Cost** | ** ** | **Percent** | ** ** | **Cost** | ** ** |
| ** **                                        | ** ** | ** ** | ** ** | ** **  | ** ** | ** **           | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| 2006                                              |       | $          | 1.12       |        | 59         | %                    | $          | 0.46                  |       | 38 | % | $ | 7.28 |   | 3 | % | $ | 1.08 |   |
| 2005                                              |       | $          | 1.04       |        | 60         | %                    | $          | 0.46                  |       | 36 | % | $ | 8.32 |   | 3 | % | $ | 1.11 |   |
| 2004                                              |       | $          | 0.99       |        | 61         | %                    | $          | 0.44                  |       | 37 | % | $ | 6.48 |   | 2 | % | $ | 0.92 |   |

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*Includes refuse-derivedfuel and wood

See additional discussionof fuel supply and costs under Risks associated with Our Business under Item1A.

***Fuel Sources***— Coal inventory levelsmay vary widely among plants.  However,the NSP System normally maintains approximately 30 days of coal inventory ateach plant site.  Coal supply inventoriesat Dec. 31, 2006, were approximately 30 days usage, based on the maximum burnrate for all of NSP-Minnesota’s coal-fired plants.  Estimated coal requirements at NSP-Minnesotaand NSP-Wisconsin’s major coal-fired generating plants are approximately 12.4million tons per year.

NSP-Minnesota andNSP-Wisconsin have a number of coal transportation contracts that provide fordelivery of approximately 99 percent of 2007 coal requirements, 99 percent of2008 coal requirements and 99 percent of 2009 coal requirements.  Coal delivery may be subject to short-terminterruptions or reductions due to transportation problems, weather, andavailability of equipment.

To operateNSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts foruranium concentrates, uranium conversion, uranium enrichment and fuelfabrication.  The contract strategyinvolves a portfolio of spot purchases and medium- and long-term contracts foruranium, conversion and enrichment with multiple producers and countries toalleviate the current supply/demand imbalance. Due to less availability in the world market for uranium, conversion andenrichment, NSP-Minnesota is working toward maintaining a strategic inventorylevel to decrease its exposure to supply limitations.

·                  Current nuclearfuel supply contracts cover 100 percent of uranium concentrates requirementsthrough 2008, approximately 90 percent of the requirements for 2009, andapproximately 32 percent of the requirements for 2010 through 2012 with nocoverage of requirements for 2013 and beyond. Contracts with additional uranium concentrate suppliers are currently invarious stages of negotiations that are expected to provide a portion of therequirements through 2016.

·                  Currentcontracts for conversion services cover 100 percent of the requirements through2009 and approximately 67 percent of the requirements from 2010 through 2012,with no coverage for 2013 and beyond.

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·                  Currentenrichment services contracts cover 100 percent of 2007 and 2008 andapproximately 96 percent of the 2009 requirements.  Approximately 50 percent of the 2010 through2013 enrichment services requirements are currently covered with no coverage ofrequirements for 2014 and beyond.  Thesecurrent contracts expire at varying times between 2009 and 2013.  Contracts with additional enrichment servicessuppliers are being investigated for coverage from 2010 and beyond.

·                  Fuel fabricationfor Monticello is covered through 2010. Under a new contract executed in 2006 for fuel fabrication services,Prairie Island’s fuel fabrication is 100 percent committed for six reloads withan option to extend for three additional reloads.  The six reloads provide for fabricationservices through at least 2013, while adding the optional reloads would providefor fabrication services to at least 2015.

NSP-Minnesota expectssufficient uranium, conversion and enrichment to be available for the totalfuel requirements of its nuclear generating plants.  Contracts for additional uranium arecurrently being negotiated that would provide additional supply requirementsthrough 2016.  Some exposure to pricevolatility will remain, due to index-based pricing structures of the contracts.

TheNSP System uses both firm and interruptible natural gas and standby oil incombustion turbines and certain boilers. Natural gas supplies for power plants are procured under short-,intermediate- and long-term contracts at liquid trading hubs that expire invarious years from 2006 through 2027 in order to provide an adequate supply offuel.  Certain natural gas supply andtransportation agreements include obligations for the purchase and/or deliveryof specified volumes of natural gas or to make payments in lieu ofdelivery.  At Dec. 31, 2006,NSP-Minnesota’s commitments related to these contracts were approximately $128million.  The NSP System has limitedon-site fuel oil storage facilities and relies on the spot market forincremental supplies, if needed.

**CommodityMarketing Operations**

NSP-Minnesota conductsvarious wholesale marketing operations, including the purchase and sale ofelectric capacity, energy and energy related products.  NSP-Minnesota uses physical and financialinstruments to minimize commodity price and credit risk and hedge supplies andpurchases.  See additional discussionunder Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

 

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**NSP-Minnesota Electric Operating Statistics**

 
|                                               | ** ** | **Year Ended Dec. 31,** | ** ** |
|-----------------------------------------------|------------|----------------------------------------|------------|
| ** **                                    | ** ** | **2006**                               | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Electric Sales (Millions of  Kwh)**         |       |                                   |       |   |   |   |   |
| Residential                                   |       | 10,223                                 |       | 10,177 |   | 9,558 |   |
| Commercial and  Industrial                    |       | 25,420                                 |       | 25,207 |   | 24,323 |   |
| Public Authorities  and Other                 |       | 280                                    |       | 272 |   | 284 |   |
| Total Retail                                  |       | 35,923                                 |       | 35,656 |   | 34,165 |   |
| Sales for Resale                              |       | 5,435                                  |       | 3,300 |   | 4,635 |   |
| Total Energy  Sold                            |       | 41,358                                 |       | 38,956 |   | 38,800 |   |
|                                          |       |                                   |       |   |   |   |   |
| **Number of customers at end of  period**     |       |                                   |       |   |   |   |   |
| Residential                                   |       | 1,206,278                              |       | 1,184,620 |   | 1,201,560 |   |
| Commercial and  Industrial                    |       | 144,315                                |       | 141,384 |   | 144,631 |   |
| Public  Authorities and Other                 |       | 5,998                                  |       | 5,904 |   | 5,984 |   |
| Total Retail                                  |       | 1,356,591                              |       | 1,331,908 |   | 1,352,175 |   |
| Wholesale                                     |       | 35                                     |       | 56 |   | 69 |   |
| Total Customers                               |       | 1,356,626                              |       | 1,331,964 |   | 1,352,244 |   |
|                                          |       |                                   |       |   |   |   |   |
| **Electric revenues (Thousands of  Dollars)** |       |                                   |       |   |   |   |   |
| Residential                                   |       | $                                      | 929,276    |   | $ | 865,738 |   | $ | 747,288 |   |
| Commercial and  Industrial                    |       | 1,665,004                              |       | 1,527,149 |   | 1,306,486 |   |
| Public  Authorities and Other                 |       | 30,898                                 |       | 27,369 |   | 31,524 |   |
| Total Retail                                  |       | 2,625,178                              |       | 2,420,256 |   | 2,085,298 |   |
| Wholesale                                     |       | 227,000                                |       | 212,152 |   | 165,993 |   |
| Interchange  Revenue from NSP-Wisconsin       |       | 322,733                                |       | 305,202 |   | 217,127 |   |
| Other Electric  Revenues                      |       | 90,460                                 |       | 73,347 |   | 81,246 |   |
| Total Electric  Revenues                      |       | $                                      | 3,265,371  |   | $ | 3,010,957 |   | $ | 2,549,664 |   |
|                                          |       |                                   |       |   |   |   |   |
| Kwh Sales per Retail  Customer                |       | 26,480                                 |       | 26,771 |   | 25,267 |   |
| Revenue per Retail  Customer                  |       | $                                      | 1,935.13   |   | $ | 1,817.13 |   | $ | 1,542.18 |   |
| Residential Revenue per  Kwh                  |       | 9.09                                   | ¢     | 8.51 | ¢ | 7.82 | ¢ |
| Commercial and  Industrial Revenue per Kwh    |       | 6.55                                   | ¢     | 6.06 | ¢ | 5.37 | ¢ |
| Wholesale Revenue per Kwh                     |       | 4.18                                   | ¢     | 6.43 | ¢ | 3.58 | ¢ |

 

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**NATURAL GAS UTILITY OPERATIONS**

# **Summary of Recent RegulatoryDevelopments**

The most significant recent developments in thenatural gas operations of NSP-Minnesota have been the continued volatility inwholesale natural gas market prices and the continued trend toward declininguse per customer by residential customers as a result of improved buildingconstruction technologies and higher appliance efficiencies.  From 1996 to 2006, average annual sales tothe typical residential customer declined from 114 MMBtu per year to 90 MMBtuper year on a weather-normalized basis. Although recent wholesale price increases do not directly affectearnings because of natural gas cost recovery mechanisms, the high prices areexpected to encourage further efficiency efforts by customers.

# **Ratemaking Principles**

***Summary of Regulatory Agencies and Areas of Jurisdiction***—Retail rates, services and other aspects of NSP-Minnesota’s operations areregulated by the MPUC and the NDPSC within their respective states. The MPUChas regulatory authority over aspects of NSP-Minnesota’s financial activities,including security issuances, certain property transfers, mergers with otherutilities and transactions between NSP-Minnesota and its affiliates. Inaddition, the MPUC reviews and approves NSP-Minnesota’s natural gas supplyplans for meeting customers’ future energy needs.

***Purchased Gas and Conservation Cost Recovery Mechanisms***—****NSP-Minnesota’s retailnatural gas rates for Minnesota and North Dakota include a PGA clause thatprovides for prospective monthly rate adjustments to reflect the forecastedcost of purchased natural gas. The annual difference between the natural gascosts collected through PGA rates and the actual natural gas costs arecollected or refunded over the subsequent 12-month period. The MPUC and NDPSChave the authority to disallow recovery of certain costs if they find theutility was not prudent in its procurement activities.

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

For a furtherdiscussion of rate and regulatory matters see Note 10 to the ConsolidatedFinancial Statements.

**Capabilityand Demand**

Natural gas supplyrequirements are categorized as firm or interruptible (customers with analternate energy supply).  The maximumdaily send-out (firm and interruptible) for NSP-Minnesota was 601,336 MMBtu for2006, which occurred on Feb. 17, 2006.

NSP-Minnesota purchasesnatural gas from independent suppliers. These purchases are generally priced based on market indices thatreflect current prices.  The natural gasis delivered under natural gas transportation agreements with interstatepipelines.  These agreements provide forfirm deliverable pipeline capacity of 526,013 MMBtu/day.  In addition, NSP-Minnesota has contractedwith providers of underground natural gas storage services.  These storage agreements provide storage forapproximately 30 percent of winter natural gas requirements and 37 percent ofpeak day, firm requirements of NSP-Minnesota.

NSP-Minnesota also ownsand operates one LNG plant with a storage capacity of 2.13 Bcf equivalent andthree propane-air plants with a storage capacity of 1.4 Bcf equivalent to helpmeet its peak requirements.  Thesepeak-shaving facilities have production capacity equivalent to 250,300 MMBtu ofnatural gas per day, or approximately 34 percent of peak day firmrequirements.  LNG and propane-air plantsprovide a cost-effective alternative to annual fixed pipeline transportationcharges to meet the peaks caused by firm space heating demand on extremely coldwinter days.

NSP-Minnesota is requiredto file for a change in natural gas supply contract levels to meet peak demand,to redistribute demand costs among classes, or to exchange one form of demandfor another.  The 2006-2007 entitlementlevels are pending MPUC action.

**NaturalGas Supply and Costs**

NSP-Minnesota activelyseeks natural gas supply, transportation and storage alternatives to yield adiversified portfolio that provides increased flexibility, decreasedinterruption and financial risk, and economical rates.  In addition, NSP-Minnesota conducts naturalgas price hedging activity that has been approved by the MPUC.  This diversification involves numerousdomestic and Canadian supply sources with varied contract lengths.

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The following tablesummarizes the average delivered cost per MMBtu of natural gas purchased forresale by NSP-Minnesota’s regulated retail natural gas distribution business:

 

| 2006 |   | $ | 8.32 |   |
|------|--------|---|------|--------|
| 2005 |   | $ | 8.90 |   |
| 2004 |   | $ | 6.88 |   |

 

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 2007 through 2027.

NSP-Minnesota has certainnatural gas supply, transportation and storage agreements that includeobligations for the purchase and/or delivery of specified volumes of naturalgas or to make payments in lieu of delivery. At Dec. 31, 2006, NSP-Minnesota was committed to approximately $722million in such obligations under these contracts.

NSP-Minnesota purchasesfirm natural gas supply utilizing long-term and short-term agreements fromapproximately 25 domestic and Canadian suppliers.  This diversity of suppliers and contractlengths allows NSP-Minnesota to maintain competition from suppliers andminimize supply costs.

See additional discussionof natural gas costs under Factors Affecting Results of Continuing Operationsin Management’s Discussion and Analysis under Item 7.

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**NSP-Minnesota Natural GasOperating Statistics**
|                                                  | ** ** | **Year Ended Dec. 31,** | ** ** |
|--------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                       | ** ** | **2006**                               | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Natural gas deliveries  (Thousands of MMBtu)** |       |                                   |       |   |   |   |   |
| Residential                                      |       | 33,896                                 |       | 38,224 |   | 39,168 |   |
| Commercial and  Industrial                       |       | 35,231                                 |       | 37,215 |   | 39,186 |   |
| Other                                            |       | 1,370                                  |       | 2,195 |   | 1,334 |   |
| Total Retail                                     |       | 70,497                                 |       | 77,634 |   | 79,688 |   |
| Transportation  and Other                        |       | 8,727                                  |       | 8,203 |   | 7,727 |   |
| Total Deliveries                                 |       | 79,224                                 |       | 85,837 |   | 87,415 |   |
|                                             |       |                                   |       |   |   |   |   |
| **Number of customers at end of  period**        |       |                                   |       |   |   |   |   |
| Residential                                      |       | 426,479                                |       | 418,827 |   | 414,782 |   |
| Commercial and  Industrial                       |       | 39,056                                 |       | 38,275 |   | 39,190 |   |
| Total Retail                                     |       | 465,535                                |       | 457,102 |   | 453,972 |   |
| Transportation  and Other                        |       | 14                                     |       | 14 |   | 10 |   |
| Total Customers                                  |       | 465,549                                |       | 457,116 |   | 453,982 |   |
|                                             |       |                                   |       |   |   |   |   |
| **Natural gas revenues (Thousands  of Dollars)** |       |                                   |       |   |   |   |   |
| Residential                                      |       | $                                      | 394,204    |   | $ | 449,724 |   | $ | 372,455 |   |
| Commercial and  Industrial                       |       | 335,392                                |       | 359,634 |   | 304,282 |   |
| Total Retail                                     |       | 729,596                                |       | 809,358 |   | 676,737 |   |
| Transportation  and Other                        |       | 15,039                                 |       | 12,564 |   | 30,321 |   |
| Total Gas  Revenues                              |       | $                                      | 744,635    |   | $ | 821,922 |   | $ | 707,058 |   |
|                                             |       |                                   |       |   |   |   |   |
| MMBtu Sales per Retail  Customer                 |       | 151.43                                 |       | 169.84 |   | 175.54 |   |
| Revenue per Retail  Customer                     |       | $                                      | 1,567.22   |   | $ | 1,770.63 |   | $ | 1,490.70 |   |
| Residential Revenue per  MMBtu                   |       | $                                      | 11.63      |   | $ | 11.77 |   | $ | 9.51 |   |
| Commercial and  Industrial Revenue per MMBtu     |       | $                                      | 9.52       |   | $ | 9.66 |   | $ | 7.77 |   |
| Transportation and Other Revenue per MMBtu       |       | $                                      | 1.72       |   | $ | 1.53 |   | $ | 3.92 |   |

 

**ENVIRONMENTALMATTERS**

Certain of NSP-Minnesota’s facilities are regulated byfederal and state environmental agencies. These agencies have jurisdiction overair emissions, water quality, wastewater discharges, solid wastes and hazardoussubstances. Various company activities require registrations, permits,licenses, inspections and approvals from these agencies.  NSP-Minnesota has received all necessaryauthorizations for the construction and continued operation of its generation,transmission and distribution systems. Company facilities have been designedand constructed to operate in compliance with applicable environmentalstandards.

NSP-Minnesota strives to comply with all environmentalregulations applicable to its operations. However, it is not possible todetermine when or to what extent additional facilities or modifications ofexisting or planned facilities will be required as a result of changes toenvironmental regulations, interpretations or enforcement policies or, whateffect future laws or regulations may have upon NSP-Minnesota’s operations. Formore information on environmental contingencies, see Notes 11 and 12 to theConsolidated Financial Statements and the matters discussed below.

# **EMPLOYEES**

The number of full-time NSP-Minnesota employees onDec. 31, 2006 was 2,595.  Of thesefull-time employees, 2,094, or 81 percent, are covered under collectivebargaining agreements.  NSP-Minnesotafull-time employees include 420 employees loaned to the NMC.  In addition, the NMC has 651 full-timeemployees of its own.  See Note 6 to theConsolidated Financial Statements for further discussion.  Employees of Xcel Energy Services Inc., asubsidiary of Xcel Energy, also provide services to NSP-Minnesota.

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# **Item 1A —Risk Factors**

** **

**Risks Associated with Our Business**

** **

***Our profitability depends in parton our ability to recover costs from our customers and there may be changes incircumstances or in the regulatory environment that impair our ability torecover costs from our customers.***

*** ***

We are subject to comprehensive regulation by severalfederal and state utility regulatory agencies. The state utility commissionsregulate many aspects of our utility operations, including siting andconstruction of facilities, customer service and the rates that we can chargecustomers.  The FERC has jurisdiction,among other things, over wholesale rates for electric transmission service andthe sale of electric energy in interstate commerce.

 

Our profitability is dependent on our ability torecover costs related to providing energy and utility services to ourcustomers.  We currently provide serviceat rates approved by one or more regulatory commissions.  These rates are generally regulated based onan analysis of our 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 the applicable regulatorycommission will judge all of our costs to have been prudently incurred or thatthe regulatory process in which rates are determined will always result inrates that will produce full recovery of our costs.   Rising fuel costs could increase the riskthat we will not be able to fully recover our under-recovered fuel costs fromour customers.  Furthermore, there couldbe changes in the regulatory environment that would impair our ability torecover costs historically collected from our customers.  If all of our costs are not recovered throughcustomer rates, we could incur financial operating losses, which, over the longterm, could jeopardize our ability to meet our financial obligations.

 

We are unable to predict the impact on our operatingresults from the future regulatory activities of any of these agencies. Changesin regulations or the imposition of additional regulations could have anadverse impact on our results of operations and hence could materially andadversely affect our ability to meet our financial obligations, includingpaying debt payments.

 

***Any reductions inour credit ratings could increase our financing costs and the cost of maintainingcertain contractual relationships.***

*** ***

We cannot be assured that any of our current ratingswill remain 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. In addition, our credit ratings may change as a result of the differingmethodologies or change in the methodologies used by the various ratingagencies.  For example, Standard andPoor’s calculates an imputed debt associated with capacity payments frompurchased power contracts.   An increasein the overall level of capacity payments would increase the amount of imputeddebt, based on Standard and Poor’s methodology. Therefore, our credit ratings could be adversely affected based on thelevel of capacity payments associated with purchased power contracts or changesin how imputed debt is determined.  Anydowngrade could lead to higher borrowing costs.

 

***We are subject to commodity risksand other risks associated with energy markets.***

*** ***

We engage in wholesale sales and purchases of electriccapacity, energy and energy-related products and are subject to market supplyand commodity price risk.  Commodityprice changes can affect the value of our commodity trading derivatives.  We mark certain derivatives to estimated fairmarket value on a daily basis (mark-to-market accounting), which may causeearnings variability. We utilize quoted market prices to the maximum extentpossible in determining the value of these derivative commodity instruments.  For positions for which market prices are notavailable, we utilize models based on forward price curves. These modelsincorporate estimates and assumptions as to a variety of factors such aspricing relationships between various energy commodities and geographiclocations. Actual experience can vary significantly from these estimates andassumptions and significant changes from our assumptions could causesignificant earnings variability.

17

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If we encounter market supply shortages, we may beunable to fulfill contractual obligations to our retail, wholesale and othercustomers at previously authorized or anticipated costs.  Any such supply shortages could cause us toseek alternative supply services at potentially higher costs or sufferincreased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costsrelative to corresponding sales commitments would have a negative impact on ourcash flows and could potentially result in economic losses.

 

***We are subject to interest rate risk.***

 

If interest rates increase, we may incurincreased interest expense on variable interest debt or short-term borrowings, which could have an adverse impact on our operating results.

 

***We are subject to credit risks.***

 

Credit riskincludes the risk that counterparties that owe us money or product will breachtheir obligations. Should the counterparties to these arrangements fail toperform, we may be forced to enter into alternative arrangements. In thatevent, our financial results could be adversely affected and we could incurlosses.

 

***We are subject to environmentallaws and regulations, compliance with which could be difficult and costly.***

*** ***

We are subject to a number of environmental laws andregulations that affect many aspects of our past, present and futureoperations, including air emissions, water quality, wastewater discharges andthe management of wastes and hazardous substances.  These laws and regulations generally requireus to obtain and comply with a wide variety of environmental registrations,licenses, permits, inspections and other approvals.  Environmental laws and regulations can alsorequire us to restrict or limit the output of certain facilities or the use ofcertain fuels, to install pollution control equipment at our facilities, cleanup spills and correct environmental hazards and other contamination.  Both public officials and private individualsmay seek to enforce the applicable environmental laws and regulations againstus.  We must pay all or a portion of thecost to remediate (i.e. clean-up) sites where our past activities, or theactivities of certain other parties, caused environmental contamination.  At Dec. 31, 2006, these sites included:

 

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

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

 

In addition, existing environmental laws orregulations may be revised, new laws or regulations seeking to protect theenvironment may be adopted or become applicable to us and we may incuradditional unanticipated obligations or liabilities under existingenvironmental laws and regulations. Revised or additional laws or regulations which result in increasedcompliance costs or additional operating restrictions, or currentlyunanticipated 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.

 

For furtherdiscussion see Note 11 to the Consolidated Financial Statements.

*** ***

***Economic conditions couldnegatively impact our business.***

*** ***

Our operations are affected by local and nationaleconomic conditions.  The consequences ofa prolonged recession may include a lower level of economic activity anduncertainty regarding energy prices and the capital and commodity markets.  A lower level of economic activity mightresult in a decline in energy consumption, which may adversely affect ourrevenues and future growth.  Instabilityin the financial markets, as a result of recession or otherwise, also mayaffect the cost of capital and our ability to raise 

18

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capital.

 

***We are subject to the risks ofnuclear generation.***

 

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

 

•                the risksassociated with storage, handling and disposal of radioactive materials and thecurrent lack 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 has authority to impose licensing andsafety-related requirements for the operation of nuclear generation facilities.In the event of non-compliance, the NRC has the authority to impose fines orshut down a unit, or both, depending upon its assessment of the severity of thesituation, until compliance is achieved. Revised safety requirementspromulgated by the NRC could necessitate substantial capital expenditures atNSP-Minnesota’s nuclear plants. 

 

If an incident did occur, it could have a materialadverse effect on our results of operations or financial condition.Furthermore, the non-compliance of other nuclear facilities operators withapplicable regulations or the occurrence of a serious nuclear incident at otherfacilities could result in increased regulation of the industry as a whole,which could then increase NSP-Minnesota’s compliance costs and impact theresults of operations of its facilities.

*** ***

***Our operationscould be impacted by war, acts of terrorism or threats of terrorism.***

 

The conflict in Iraq and any other military strikes orsustained military campaign may affect our operations in unpredictable ways andmay cause disruptions of fuel supplies and markets, particularly with respectto natural gas and purchased energy.  Warand the possibility of further war may have an adverse impact on the economy ingeneral. 

 

Our generation plants, fuel storage facilities,transmission and distribution facilities and information systems may be targetsof terrorist activities that could disrupt our ability to produce or distributesome portion of our energy products. Any such disruption could result in asignificant decrease in revenues and significant additional costs to repair andinsure our assets, which could have a material adverse impact on our financialcondition and results of operations.  Thepotential for terrorism has subjected our operations to increased risks andcould have a material adverse effect on our business.  While we have already incurred increasedcosts for security and capital expenditures in response to these risks, we mayexperience additional capital and operating costs to implement security for ourplants, such as additional physical plant security and additional securitypersonnel. 

 

The insurance industry has also been affected by theseevents and the availability of insurance covering risks we and our competitorstypically insure against may decrease. In addition, the insurance we are able to obtain may have higherdeductibles, higher premiums and more restrictive policy terms.

 

***A disruption or black-out of the regional electrictransmission grid could negatively impact our business.***

*** ***

Because our generation and transmission systems arepart of an interconnected regional grid, we face the risk of possible loss ofbusiness due to a disruption or black-out caused by an event (severe storm,generator or transmission facility outage) on a neighboring system or theactions of a neighboring utility, similar to the Aug. 14, 2003 black-outin portions of the eastern U.S. and Canada. Any such disruption could result in a significant decrease in revenuesand significant additional costs to repair assets, which 

19

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could have a material adverse impact on our financialcondition and results of operations.

*** ***

***Reduced coal availability could negatively impact ourbusiness.***

*** ***

Our coal generationportfolio is heavily dependent on coal supplies located in the Powder RiverBasin of Wyoming.  Approximately 50percent of NSP’s annual coal requirement comes from this area. Coal generationcomprises approximately 60 percent our annual generation.  We have recently experienced disruptions inthe delivery of Powder River Basin coal to our facilities and such disruptionscould occur again in the future.  Coaldelivery may be subject to short-term interruptions or reductions due tovarious factors, including transportation problems, weather and availability ofequipment.  Failure or delay by oursuppliers of coal deliveries could disrupt our ability to deliver electricityand require us to incur additional expenses to meet the needs of ourcustomers.  In addition, as agreementsexpire with our suppliers, we may not be able to enter into new agreements forcoal delivery on equivalent terms.

 

***Rising energy prices couldnegatively impact our business.***

*** ***

Higher fuel costs couldsignificantly impact our 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 our results of operations.  Delays in the timing of the collection offuel cost recoveries as compared with expenditures for fuel purchases couldhave an impact on our cash flows.  We areunable to predict the future prices or the ultimate impact of such prices onour results of operations or cash flows.

 

***Our operating results mayfluctuate on a seasonal and quarterly basis and can be adversely affected bymilder weather.***

*** ***

Our electric utility and natural gas businesses are seasonaland weather patterns can have a material impact on our operating performance.Demand for electricity is often greater in the summer and winter months associatedwith cooling and heating.  Becausenatural gas is heavily used for residential and commercial heating, the demand forthis product depends heavily upon weather patterns throughout our serviceterritory, and a significant amount of natural gas revenues are recognized inthe first and fourth quarters related to the heating season.  Accordingly, our operations have historicallygenerated less revenues and income when weather conditions are milder in thewinter and cooler in the summer. Unusually mild winters and summers could havean adverse effect on our financial condition and results of operations.

 

***Our natural gas distributionactivities involve numerous risks that may result in accidents and otheroperating risks and costs.***

 

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

 

***Increased risks of regulatorypenalties could negatively impact our business***

 

TheEnergy Act increased FERC’s civil penalty authority for violation of FERC statutes,rules and orders.  FERC can now imposepenalties of $1 million per violation per day. Effective June 1, 2007, approximately 80 electric reliability standardsthat were historically subject to voluntary compliance will become mandatoryand subject to potential civil penalties for violations.  If a serious reliability incident did occur,it could have a material adverse effect on our operations or financial results.

*** ***

***Increasing costs associated withour defined benefit retirement plans and other employee-related benefits mayadversely affect our results of operations, financial position, or liquidity.***

*** ***

We have defined benefit and postretirement plans thatcover substantially all of our employees. Assumptions related to future costs, return on investments, interestrates and other actuarial assumptions have a significant impact on our fundingrequirements related to these plans. These estimates and assumptions may change based on actual stock marketperformance, changes in interest rates and any changes in governmentalregulations.  In addition, the PensionProtection Act of 2006 changed the minimum funding requirements for definedbenefit pension plans beginning in 2008. Therefore, our funding requirements may change and our contributionscould be required in the future.

 

***Increasing costs associated with health care plans may adversely affectour results of operations, financial position or liquidity.***

 

The costs of providing health care benefits to ouremployees and retirees have increased substantially in recent years.  We believe that our employee benefit costs,including costs related to health care plans for our employees and formeremployees, will continue to rise.  Theincreasing costs and funding requirements associated with our health care plansmay adversely affect our results of operations, financial position, orliquidity.  

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**As we are a subsidiary of Xcel Energy, if XcelEnergy’s credit ratings and access to capital were restricted, this could limitXcel Energy’s ability to contribute equity or make loans to us, or may causeXcel Energy to seek additional or accelerated funding from us in the form ofdividends.  If such event were to occur,we may need to seek alternate 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.  If either Standard & Poor’s or Moody’swere to downgrade Xcel Energy’s debt securities below investment grade, itwould increase Xcel Energy’s cost of capital and restrict its access to thecapital 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 event were to occur,we may need to seek alternative sources of funds to meet our cash needs.

*** ***

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

 

As of Dec. 31, 2006, XcelEnergy had approximately $6.4 billion of long-term debt and $1.0 billion ofshort-term debt or current maturities. Xcel Energy provides various guarantees and bond indemnities supportingsome of its subsidiaries by guaranteeing the payment or performance by thesesubsidiaries of specified agreements or transactions.  Xcel Energy also has other contingentliabilities resulting from various tax disputes and other matters.  Xcel Energy’s exposure under the guaranteesis based upon the net liability of the relevant subsidiary under the specifiedagreements or transactions.  The majorityof Xcel Energy’s guarantees limit its exposure to a maximum amount that isstated in the guarantees.  As of Dec. 31,2006, Xcel Energy had guarantees outstanding with a maximum stated amount ofapproximately $76.2 million and $17.5 million of exposure.  Xcel Energy has also provided indemnities tosureties in respect of bonds for the benefit of its subsidiaries.  The total amount of bonds with theseindemnities outstanding as of Dec. 31, 2006, was approximately $118.6million.  Xcel Energy’s total exposureunder these indemnities cannot be determined at this time.  If Xcel Energy were to become obligated tomake payments under these guarantees and bond indemnities or become obligatedto fund the other contingent liabilities, it could limit Xcel Energy’s abilityto contribute equity or make loans to us, or may cause Xcel Energy to seekadditional or accelerated funding from 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.

**We are awholly owned subsidiary of Xcel Energy. Xcel Energy can exercise substantial control over our dividend policyand business and operations and may exercise that control in a manner that maybe perceived to be adverse to our interests.**

 

Our board of directors, as well as many of our executive officers, areofficers of Xcel Energy.  Our board makesdeterminations with respect to a number of significant corporate events,including the payment of our dividends.

 

We have historically paid quarterly dividends to Xcel Energy.  In 2006, 2005 and 2004 we paid $219.6million, $215.3 million and $213.0 million of dividends to Xcel Energy,respectively.  If Xcel Energy’s cashrequirements increase, our board of directors could decide to increase thedividends we pay to Xcel Energy to help support Xcel Energy’s cash needs.  This could adversely affect ourliquidity.  The amount of dividends thatwe can pay is also limited to some extent by our indenture for our firstmortgage bonds.

 

**Item 1B — Unresolved SEC StaffComments**

None.

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**Item 2 —Properties**

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

Electric utility generating stations:

| Station, City and Unit | ** ** | **Fuel**          | ** ** | **Installed** | ** ** | **Summer 2006 Net  Dependable  Capability (MW)** | ** ** |
|---------------------------------------|------------|-------------------|------------|---------------|------------|-----------------------------------------------------------------|------------|
| ***Steam:***                          |       |              |       |          |       |                                                            |       |
| Sherburne-Becker, MN                  |       |              |       |          |       |                                                            |       |
| Unit 1                                |       | Coal              |       | 1976          |       | 697                                                             |       |
| Unit 2                                |       | Coal              |       | 1977          |       | 682                                                             |       |
| Unit 3                                |       | Coal              |       | 1987          |       | 504                                                             | (a)        |
| Prairie Island-Welch,  MN             |       |              |       |          |       |                                                            |       |
| Unit 1                                |       | Nuclear           |       | 1973          |       | 551                                                             |       |
| Unit 2                                |       | Nuclear           |       | 1974          |       | 545                                                             |       |
| 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  Falls, 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       |       | 169                                                             |       |
|                                  |       |              |       | Total         |       | 6,704                                                           |       |

----

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

Electric utility overhead and underground transmissionand distribution lines (measured in conductor miles) at Dec. 31, 2006:

| Conductor Miles | ** ** |
|----------------------|------------|
| 500 KV               |       | 2,917 |   |
| 345 KV               |       | 5,648 |   |
| 230 KV               |       | 1,827 |   |
| 161 KV               |       | 295 |   |
| 115 KV               |       | 6,484 |   |
| Less than 115 KV     |       | 81,274 |   |

 

NSP-Minnesota had 364 electric utility transmissionand distribution substations at Dec. 31, 2006.

Natural gas utility mains at Dec. 31, 2006:

|              | ** ** | **Miles** | ** ** |
|--------------|------------|-----------|------------|
| Transmission |       | 120       |       |
| Distribution |       | 9,321     |       |

 

**Item 3 —Legal Proceedings**

In the normal course of business, various lawsuits andclaims have arisen against NSP-Minnesota. Management, after consultation withlegal counsel, has recorded an estimate of the probable cost of settlement orother disposition for such matters.

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***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 nuclear fuel from civilian nuclearpower reactors and other high-level radioactive substances.   The Act and contracts between the DOE anddomestic utilities obligated the DOE to begin to dispose of these materials byJan. 31, 1998.  The federalgovernment has designated the site as Yucca Mountain in Nevada. The nuclearwaste disposal program has resulted in extensive litigation.

On June 8, 1998,NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against theUnited States requesting breach of contract damages, past and as projected intothe future, in excess of $1 billion for the DOE’s failure to meet the 1998deadline.  NSP-Minnesota has demandeddamages consisting of the added costs of storage of spent nuclear fuel at thePrairie Island and Monticello nuclear generating plants, costs related to thePrivate Fuel Storage, LLC and certain costs relating to the 1994 and 2003 statelegislation relating to the storage of spent nuclear fuel at PrairieIsland.  On July 31, 2001, the Courtgranted NSP-Minnesota’s motion for partial summary judgment on liability.  A subsequent court decision determined thatthe utilities were precluded from making a claim for future damages, a utilitycould claim damages up to some point prior to the trial, and separate claimswould have to be made in the future as damages accumulated.  In response to this decision, NSP-Minnesotafiled an amended complaint seeking damages through Dec. 31, 2004.

NSP-Minnesota currently claims total damages in excessof $100 million through Dec. 31, 2004 (damages after 2004 will be claimedin subsequent proceedings). A trial on the damages issue commenced onOct. 24, 2006, and concluded on Dec. 11, 2006.  NSP-Minnesota’s initial post-trial brief wasfiled pursuant to the court’s scheduling order on Feb. 9, 2007 and additionalbriefs and reply briefs are scheduled to be filed by April 30, 2007. Closingarguments are set for May 31, 2007.

On July 9, 2004, theU.S. Court of Appeals for the District of Columbia Circuit issued a decision inconsolidated cases challenging regulations and decisions on the federal nuclearwaste program. The Court of Appeals rejected challenges by the state of Nevadaand other intervenors with respect to most of the NRC’s challenged repositorylicensing regulations, the congressional resolution approving Yucca Mountain asthe site of the permanent repository, and the DOE and presidential actionsleading to the approval of the Yucca Mountain site. The Court of Appealsvacated the 10,000 year compliance period adopted by EPA regulations governingspent nuclear fuel disposal at Yucca Mountain and incorporated in the NRCregulations. Xcel Energy has not ascertained the impact of the decision on itsnuclear operations and storage of spent nuclear fuel; however, the decision mayresult in additional delay and uncertainty around disposal of spent nuclearfuel. In July 2006 the Office of Civilian Radioactive Waste Managementindicated that under the “best achievable repository construction schedule”,Yucca Mountain would be able to begin accepting spent nuclear fuel in March2017.

***NewMech vs. Northern States Power Company***—On May 16, 2006, NewMech served and filed a complaint against NSP-Minnesota,Southern Minnesota Municipal Power Agency (SMMPA), and Benson Engineering inthe Minnesota State District Court, Sherburne County, alleging entitlement topayment in the amount of approximately $4.2 million for unpaid costs allegedlyassociated with construction work done by NewMech at NSP-Minnesota and SMMPA’sjointly owned Sherco 3 generating plant in 2005.  NewMech had previously served a mechanic’slien, and sought, through this action, foreclosure of the lien and sale of theproperty.  NewMech additionally soughtclaimed damages as a result of an alleged breach of contract byNSP-Minnesota.  NSP-Minnesota, SMMPA andBenson filed answers denying NewMech’s allegations.  Additionally, NSP-Minnesota and SMMPAcounterclaimed for damages in excess of $7 million for breach of contract,delay in contract performance, misrepresentation and fraudulent inducement toenter into the contract and slander of title. A confidential settlement of the dispute was reached on Sept. 29, 2006,and it did not have a material financial impact on NSP-Minnesota.

***Other Matters***

For more discussion of legal claims and environmentalproceedings, see Note 11 to the Consolidated Financial Statements under Item 8,incorporated by reference. For a discussion of proceedings involving utilityrates, see Pending and Recently Concluded Regulatory Proceedings under Item 1and Note 10 to the Consolidated Financial Statements under Item 8, incorporatedby reference.

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

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

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**PART II**

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

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

NSP-Minnesota’s first mortgage indenture placescertain restrictions on the amount of cash dividends it can pay to Xcel Energy,the holder of its common stock. Even with these restrictions, NSP-Minnesotacould have paid more than $905 million in additional cash dividends on commonstock at Dec. 31, 2006. In addition, NSP-Minnesota  had dividend restrictions imposed by itscredit agreement, FERC rules and state regulatory commissions.

·                  Dividendsare subject to the FERC’s jurisdiction under the Federal Power Act, whichprohibits the payment of dividends out of capital accounts; payment ofdividends is allowed out of retained earnings only.

·                  Covenantrestrictions under NSP-Minnesota’s credit agreement include a required debt tototal capital ratio.

·                  Stateregulatory commissions indirectly limit the amount of dividendsNSP-Minnesota  can pay to Xcel Energythrough requiring a minimum equity ratio of 45.99%.

The dividends declared during 2006 and 2005 were asfollows:

| **(****Thousands of Dollars)  Quarter Ended** |
|--------------------------------------------------------------|
| **March 31, 2006**                                 |   | **June 30, 2006** |   | **Sept. 30, 2006** |   | **Dec. 31, 2006** |
| $54,616                                                      |   | $55,344 |   | $55,025 |   | $56,105 |

 

| **March 31, 2005** |   | **June 30,  2005** |   | **Sept.  30, 2005** |   | **Dec. 31,  2005** |
|-------------------------|--------|-------------------------|--------|---------------------|--------|--------------------|
| $54,672                 |   | $52,969                 |   | $54,668             |   | $54,613            |

 

**Item 6 —Selected Financial Data**

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

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

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

**Forward Looking Information**

The following discussion and analysis by managementfocuses on those factors that had a material effect on the financial conditionand results of operations of NSP-Minnesota during the periods presented, or areexpected to have a material impact in the future. It should be read inconjunction with the respective accompanying Consolidated Financial Statementsand Notes to the Consolidated Financial Statements.

Except for the historicalstatements contained in this report, the matters discussed in the followingdiscussion and analysis are forward-looking statements that are subject tocertain risks, uncertainties and assumptions. Such forward-looking statementsare intended to be identified in this document by the words “anticipate,” “believe,”“estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,”“possible,” “potential,” “should,” and similar expressions. Actual results mayvary materially. Factors that could cause actual results to differ materiallyinclude, but are not limited to: general economic conditions, including the availability ofcredit and its impact on capital expenditures and the ability of NSP-Minnesotato obtain financing on favorable terms; businessconditions in the energy industry; actions of credit rating agencies;competitive factors, including the extent and timing of the entry of additionalcompetition in the markets served by NSP-Minnesota; unusual weather; effects ofgeopolitical events, including war and acts of terrorism; state, federal andforeign legislative and regulatory initiatives that affect cost and investmentrecovery, have an impact on rates or have an impact on asset operation orownership, structures that affect the speed and degree to which competitionenters the electric and natural gas markets; costs and other effects of legaland administrative proceedings, settlements, investigations and claims; actionsof accounting regulatory bodies; the items described under “Risk Factors” inItem 1A and Exhibit 99.01 of NSP-Minnesota’s Form 10-K for the year endedDec. 31, 2006.

24

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**Management’sDiscussion and Analysis of Financial Condition and Results of Operations**

**Results of Operations**

NSP-Minnesota’s net income was approximately $272.3million for 2006, compared with approximately $237.7 million for 2005.

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

Electric fuel and purchased power expenses tend tovary with changing retail and wholesale sales requirements and unit costchanges in fuel and purchased power. Due to fuel and purchased energycost-recovery mechanisms for customers, most fluctuations in energy costs donot materially affect electric utility margin.

NSP-Minnesota has two distinct forms of wholesalesales: short-term wholesale and commodity trading. Short-term wholesale refersto energy-related purchase and sales activity, and the use of certain financialinstruments associated with the fuel required for, and energy produced from,NSP-Minnesota’s generation assets and energy and capacity purchased to servenative load. Commodity trading is not associated with NSP-Minnesota’sgeneration assets or the energy or capacity purchased to serve native load. Short-termwholesale and commodity trading activities are considered part of the electricutility segment.

Margins from commodity trading activity conducted atNSP-Minnesota are partially redistributed among PSCo and SPS, both wholly ownedsubsidiaries of Xcel Energy, pursuant to the JOA approved by the FERC. Marginsreceived pursuant to the JOA are reflected as part of Base Electric UtilityRevenues. Commodity trading revenues, as discussed in Note 1 to theConsolidated Financial Statements, are reported net of related costs (i.e., ona margin basis) in the Consolidated Statements of Income. Commodity trading costsinclude purchased power, transmission, broker fees and other related costs. Short-termwholesale and commodity trading margins reflect the estimated impact ofregulatory sharing of margins, if applicable.

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

 

|                                                          | ** ** | **Base  Electric  Utility**         | ** ** | **Short-Term  Wholesale** | ** ** | **Commodity  Trading** | ** ** | **Consolidated  Totals** | ** ** |
|----------------------------------------------------------|------------|-------------------------------------|------------|---------------------------|------------|------------------------|------------|--------------------------|------------|
| ** **                                               | ** ** | **(Millions of Dollars)** | ** ** |
| **2006**                                                 |       |                                |       |                      |       |                   |       |                     |       |
| Electric utility  revenue (excluding  commodity trading) |       | $                                   | 3,084      |                      | $          | 178                    |       | $                        | —     |   | $ | 3,262 |   |
| Fuel and purchased  power                                |       | (1,287                              | )          | (159                      | )          | —                 |       | (1,446                   | )          |
| Commodity trading  revenue                               |       | —                              |       | —                    |       | 131                    |       | 131                      |       |
| Commodity trading costs                                  |       | —                              |       | —                    |       | (128                   | )          | (128                     | )          |
| Gross margin  before operating expenses                  |       | $                                   | 1,797      |                      | $          | 19                     |       | $                        | 3          |   | $ | 1,819 |   |
| Margin as a percentage  of revenue                       |       | 58.3                                | %          | 10.7                      | %          | 2.3                    | %          | 53.6                     | %          |
|                                                     |       |                                |       |                      |       |                   |       |                     |       |
| **2005**                                                 |       |                                |       |                      |       |                   |       |                     |       |
| Electric utility  revenue (excluding  commodity trading) |       | $                                   | 2,828      |                      | $          | 177                    |       | $                        | —     |   | $ | 3,005 |   |
| 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                     | %          |

 

25

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

***Base ElectricRevenue***
| **(Millions of dollars)**               | ** ** | **2006 vs. 2005** | ** ** |
|---------------------------------------------------|------------|-----------------------------|------------|
| ** **                                        | ** ** | ** **                  | ** ** |
| NSP-Minnesota electric  base rate changes         |       | $                           | 129        |   |
| MERP rider                                        |       | 38                          |       |
| Sales growth (excluding  weather impact)          |       | 18                          |       |
| Interchange agreement  billing with NSP-Wisconsin |       | 18                          |       |
| Firm wholesale                                    |       | 16                          |       |
| Conservation and  non-fuel rider revenues         |       | 13                          |       |
| Transmission revenue                              |       | 10                          |       |
| Joint operating  agreement revenue                |       | 8                           |       |
| Estimated impact of  weather                      |       | (7                          | )          |
| Other                                             |       | 13                          |       |
| Total base electric  revenue increase             |       | $                           | 256        |   |

 

###### ***Base Electric Margin***

| **(Millions of dollars)**               | ** ** | **2006 vs. 2005** | ** ** |
|---------------------------------------------------|------------|-----------------------------|------------|
| ** **                                        | ** ** | ** **                  | ** ** |
| NSP-Minnesota electric  base rate changes         |       | $                           | 129        |   |
| MERP rider                                        |       | 38                          |       |
| Interchange agreement  billing with NSP-Wisconsin |       | 14                          |       |
| Sales growth (excluding  weather impact)          |       | 14                          |       |
| Conservation and  non-fuel rider revenues         |       | 13                          |       |
| Firm wholesale                                    |       | 9                           |       |
| Joint operating  agreement revenue                |       | 8                           |       |
| Transmission fee  classification change           |       | (22                         | )          |
| Purchased capacity  costs                         |       | (8                          | )          |
| Estimated impact of  weather                      |       | (6                          | )          |
| Other                                             |       | 7                           |       |
| Total base electric  margin increase              |       | $                           | 196        |   |

 

Certain transmission expenses related to purchasepower are reported as a component of base electric margin in 2006, comparedwith the 2005 presentation as a component of operating and maintenance expense,which served to lower electric margin by $22 million for the year, with noimpact on operating or net income.

Short-term wholesale andcommodity trading margins decreased $58 million in 2006, compared with 2005. Asexpected, short-term margins declined due to retail sales growth, which reducedsurplus generation available for sale in the wholesale market, and decreasedopportunities to sell due to the MISO centralized dispatch market.

In addition, NSP-Minnesota entered into a wholesaleelectric sales margin settlement agreement in the second quarter of 2006 aspart of the Minnesota rate case proceeding. The agreement was approved by theMPUC in its order in the electric rate case. The approved settlement agreementprovides for a sharing of certain short-term wholesale and commodity tradingmargins with retail electric customers beginning Jan. 1, 2006. The financial impact of this agreement isreflected in the financial statements as of and for the period ended Dec. 31,2006.

***Natural Gas UtilityMargins*****—The following table details the change in natural gas revenue and margin. Thecost of natural gas tends to vary with changing sales requirements and unitcost of natural gas purchases. However, due to purchased natural gas costrecovery mechanisms for retail customers, fluctuations in the cost of naturalgas have little effect on natural gas margin.
| **(Millions of dollars)**            | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|
| Natural gas utility  revenue                   |       | $        | 745        |     | $          | 822 |   |
| Cost of natural gas  purchased and transported |       | (590     | )          | (665     | )          |
| Natural gas utility  margin                    |       | $        | 155        |     | $          | 157 |   |

 

26

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

***Natural Gas Revenue***

| (Millions of dollars)           | ** ** | **2006 vs. 2005** | ** ** |
|-------------------------------------------|------------|-----------------------------|------------|
| ** **                                | ** ** | ** **                  | ** ** |
| Purchased gas  adjustment clause recovery |       | $                           | (50        | ) |
| Estimated impact of  weather              |       | (32                         | )          |
| Sales decline  (excluding weather impact) |       | (9                          | )          |
| Base rate changes                         |       | 9                           |       |
| Transportation and  other                 |       | 5                           |       |
| Total natural gas  revenue decrease       |       | $                           | (77        | ) |

 

Naturalgas revenue decreased primarily due to lower natural gas costs in 2006, whichare recovered from customers.  Retailnatural gas weather-normalized sales declined when compared to 2005, largelydue to declining use per customer.

***Natural Gas Margin***

| (Millions of dollars)           | ** ** | **2006 vs. 2005** | ** ** |
|-------------------------------------------|------------|-----------------------------|------------|
| ** **                                | ** ** | ** **                  | ** ** |
| Sales decline  (excluding weather impact) |       | $                           | (8         | ) |
| Estimated impact of  weather              |       | (4                          | )          |
| Base rate changes                         |       | 9                           |       |
| Transportation and  other                 |       | 1                           |       |
| Total natural gas  margin decrease        |       | $                           | (2         | ) |

 

***Non-Fuel Operating Expense and Other Costs*****— Other operating and maintenanceexpenses for 2006 increased $20 million, or 2.2 percent, compared to 2005.  The following summarizes the components ofthe changes for the year ended Dec. 31:

 
| **(Millions of dollars)**                             | ** ** | **2006 vs. 2005** | ** ** |
|-----------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                      | ** ** | ** **                  | ** ** |
| Higher nuclear plant  operating costs                           |       | $                           | 22         |   |
| Higher consulting costs                                         |       | 12                          |       |
| Higher combustion/hydro  plant costs                            |       | 12                          |       |
| Higher employee benefit  costs, primarily performance-based     |       | 8                           |       |
| Higher uncollectible  receivable costs                          |       | 7                           |       |
| Higher conservation  incentive program costs                    |       | 3                           |       |
| Higher fleet  transportation costs                              |       | 1                           |       |
| Transmission fees  classification change                        |       | (26                         | )          |
| Private Fuel Storage  regulatory asset                          |       | (17                         | )          |
| Lower nuclear plant  outage costs                               |       | (4                          | )          |
| Other, including fleet  transportation and facilities cost      |       | 2                           |       |
| Total other utility  operating and maintenance expense increase |       | $                           | 20         |   |

 

Depreciation andamortization expense increased by approximately $52.6 million, or 14.1 percent,for 2006 compared with 2005.  The decommissioning internal fund transfer,ending in 2005, resulted in an increase within decommissioning accruals of $20million in 2006.  In addition, regulatoryamortizations were higher than 2005, due to increased renewable developmentfund amortization, resulting from higher eligible program funding.

Interest charges increased by approximately $15.1million, or 10.1 percent, for 2006, compared with 2005. The increase was due tothe issuance of new long-term debt in July of 2005 and May of 2006, partiallyoffset by November 2005 and July 2006 bond retirements.

AFDC is an amount capitalized as a part ofconstruction costs representing the cost of financing the construction.  Generally, these costs are recovered fromcustomers as the related property is depreciated.  NSP-Minnesota’s MERP project consists ofconverting two coal-fueled electric generating plants located in theMinneapolis - St. Paul metropolitan area to natural gas, and installingadvanced pollution control equipment at a third coal-fired plant.  The projects are expected to begin operationsbetween 2007 and 2009.  AFDC, resultingin part from these projects, increased by approximately $4.8 million, or 15.8percent for 2006, compared with 2005.

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Income tax expense increasedby approximately $15.8 million in 2006, compared with 2005.  The increase in tax expense wasprimarily due to an increase in pretax income, which was partially offset bythe reversal of a $9.8 million regulatory reserve in 2006 and by recognition ofresearch and experimentation credits and net operating loss carry back claimsof $6.7 million in 2005. The effective tax rate was 31.9 percent for 2006, compared with 32.0 percent for 2005.  Withoutthe additional tax benefits, the effective tax rate would have been 34.4percent for 2006 and 33.9 percent in 2005.

**Item 7A —Quantitative and Qualitative Disclosures About Market Risk**

**Derivatives, Risk Management andMarket Risk**

In the normalcourse of business, NSP-Minnesota is exposed to a variety of market risks.  Market risk is the potential loss that mayoccur as a result of changes in the market or fair value of a particularinstrument or commodity.  All financialand commodity-related instruments, including derivatives, are subject to marketrisk.  These risks, as applicable toNSP-Minnesota, are discussed in further detail below.

***Commodity PriceRisk —*** NSP-Minnesota is exposed to commodity price riskin its electric and natural gas operations. Commodity price risk is managed by entering into both long- andshort-term physical purchase and sales contracts for electric capacity, energy,and energy-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-TermWholesale and Commodity Trading Risk —***NSP Minnesotaconducts various short-term wholesale and commodity trading activities,including the purchase and sale of capacity, energy and energy-relatedinstruments. These marketing activities generally have terms of less than oneyear in length. NSP Minnesota’s risk-management policy allows management toconduct these activities within guidelines and limitations as approved by theCompany’s risk management committee, which is made up of management personnelnot directly involved in the activities governed by the policy.

Certain contracts within the scope of these activitiesqualify for hedge accounting treatment under SFAS No. 133 — “Accounting forDerivative Instruments and Hedging Activities,” (SFAS No. 133).

See Note 8 to the Consolidated Financial Statementsfor a discussion of the various trading and hedging contracts of NSP-Minnesota.

NSP-Minnesota’s short-term wholesale and commoditytrading operations measure the outstanding risk exposure to price changes ontransactions, contracts and obligations that have been entered into, but notclosed, using an industry standard methodology known as VaR. VaR expresses the potentialchange in fair value on the outstanding transactions, contracts and obligationsover a particular period of time, with a given confidence interval under normalmarket conditions. NSP-Minnesota utilizes the variance/covariance approach incalculating VaR. The VaR model employs a 95-percent confidence interval levelbased on historical price movement, lognormal price distribution assumption,delta half-gamma approach for non-linear instruments and a three-day holdingperiod for both electricity and natural gas.

VaR is calculated on a consolidated basis.  The VaRs for the commodity trading operationswere:

 
| ** **                          | ** ** | **Year ended Dec.** | ** ** | **During 2006** | ** ** |
|-------------------------------------|------------|-------------------------------|------------|----------------------|------------|
| **(Millions of Dollars)** | ** ** | **31, 2006**             | ** ** | **Average**          | ** ** | **High** | ** ** | **Low** | ** ** |
| ** **                          | ** ** | ** **                    | ** ** | ** **           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Commodity trading (a)               |       | $                             | 0.49       |                 | $          | 1.32 |   | $ | 2.60 |   | $ | 0.39 |   |
|                                     |            |                               |            |                      |            |  |  |  |  |  |  |  |  |

 

 
| ** **                          | ** ** | **Year ended Dec.** | ** ** | **During 2005** | ** ** |
|-------------------------------------|------------|-------------------------------|------------|----------------------|------------|
| **(Millions of Dollars)** | ** ** | **31, 2005**             | ** ** | **Average**          | ** ** | **High** | ** ** | **Low** | ** ** |
| ** **                          | ** ** | ** **                    | ** ** | ** **           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Commodity trading (a)               |       | $                             | 2.06       |                 | $          | 1.44 |   | $ | 4.43 |   | $ | 0.26 |   |
|                                     |            |                               |            |                      |            |  |  |  |  |  |  |  |  |

 

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

***Interest Rate Risk —***NSP-Minnesota issubject to the risk of fluctuating interest rates in the normal course ofbusiness.  NSP-Minnesota’s riskmanagement policy allows interest rate risk to be managed through the use offixed rate debt, floating rate debt and interest rate derivatives such asswaps, caps, collars and put or call options, subject to regulatory approvalwhen required.

28

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NSP-Minnesota mayengage 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 debt instruments.  Changes in thederivative fair values that are designated as fair value hedges are recognizedin earnings as offsets to the changes in fair values of debt instruments.  To test the effectiveness of such swaps, ahypothetical swap is used to mirror all the critical terms of the underlyingdebt and regression analysis is utilized to assess the effectiveness of theactual swap at inception and on an ongoing basis.  The fair value of interest rate swaps isdetermined through counterparty valuations, internal valuations and brokerquotes.  There have been no materialchanges in the techniques or models used in the valuation of interest rateswaps during the periods presented.

At Dec. 31, 2006and 2005, a 100-basis-point change in the benchmark rate on NSP-Minnesota’svariable rate debt would impact pretax interest expense by approximately $0.3million and $1.5 million, respectively.

NSP-Minnesota alsomaintains trust funds, as required by the NRC, to fund certain costs of nucleardecommissioning, which are subject to interest rate risk and equity pricerisk.  As of Dec. 31, 2006 and 2005, thesefunds were invested primarily in domestic and international equity securitiesand fixed-rate fixed-income securities. Per NRC mandates, these funds may be used only for activities related tonuclear decommissioning.  The accountingfor nuclear decommissioning recognizes that costs are recovered through rates;therefore fluctuations in equity prices, or interest rates do not have animpact on earnings.

***Credit Risk —***Inaddition to the risks discussed previously, NSP-Minnesota is also exposed tocredit 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 conducts standard credit reviews for allcounterparties. NSP-Minnesota employs additional credit risk controlmechanisms, such as letters of credit, parental guarantees, standardized masternetting agreements and termination provisions that allow for offsetting ofpositive and negative exposures. The credit exposure is monitored and, whennecessary, the activity with a specific counterparty is limited until creditenhancement is provided.

29

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

# **REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

Board of Directors and StockholderNorthern States Power Company—Minnesota

We have audited the accompanying consolidatedbalance sheets and statements of capitalization of Northern States PowerCompany—Minnesota and subsidiaries (the “Company”) as of December 31, 2006 and2005, and the related consolidated statements of income, common stockholder’sequity and comprehensive income and cash flows for each of the three years inthe period ended December 31, 2006.  Our audits also included thefinancial statement schedule listed in the Index at Item 15. Thesefinancial statements and financial statement schedule are the responsibility ofthe Company’s management.  Our responsibility is to express an opinion onthe financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance withthe standards of the Public Company Accounting Oversight Board (UnitedStates).  Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement.  The Company is not required to have, nor were weengaged to perform, an audit of its internal control over financialreporting.  Our audits included consideration of internal control overfinancial reporting as a basis for designing audit procedures that areappropriate in the circumstances, but not for the purpose of expressing anopinion on the effectiveness of the Company’s internal control over financialreporting.  Accordingly, we express no such opinion.  An audit alsoincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements, assessing the accounting principlesused and significant estimates made by management, as well as evaluating theoverall financial statement presentation.  We believe that our auditsprovide a reasonable basis for our opinion.

In our opinion, such consolidated financialstatements present fairly, in all material respects, the financial position ofNorthern States Power Company—Minnesota and subsidiaries as of December 31,2006 and 2005, and the results of their operations and their cash flows foreach of the three years in the period ended December 31, 2006, in conformitywith accounting principles generally accepted in the United States ofAmerica.  Also, in our opinion, such financial statement schedule, whenconsidered in relation to the basic consolidated financial statements taken asa whole, presents fairly in all material respects the information set forththerein.

As discussed in Note 6 to the consolidated financialstatements, the Company adopted Statement of Financial Accounting StandardsNo. 158, “Employers’ Accounting for Defined Benefit Pension and OtherPostretirement Plans,” as of December 31, 2006.

 
| /S/ DELOITTE & TOUCHE  LLP |   |
|--------------------------------|--------|
| Minneapolis,  Minnesota        |   |
| February 22,  2007             |   |

 

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**NSP-MINNESOTA****CONSOLIDATED STATEMENTS OFINCOME (Thousands of Dollars)**
| ** **                                                                                    | ** ** | **Year Ended Dec. 31** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                    | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Operating revenues**                                                                        |       |                                  |       |   |   |   |   |
| Electric utility                                                                              |       | $                                     | 3,265,371  |   | $ | 3,010,957 |   | $ | 2,549,664 |   |
| Natural gas  utility                                                                          |       | 744,635                               |       | 821,922 |   | 707,058 |   |
| Other                                                                                         |       | 17,609                                |       | 20,705 |   | 19,135 |   |
| Total operating  revenues                                                                     |       | 4,027,615                             |       | 3,853,584 |   | 3,275,857 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Operating expenses**                                                                        |       |                                  |       |   |   |   |   |
| Electric fuel  and purchased power                                                            |       | 1,445,590                             |       | 1,329,553 |   | 976,639 |   |
| Cost of natural  gas sold and transported                                                     |       | 590,094                               |       | 664,551 |   | 556,662 |   |
| Cost of sales —  nonregulated and other                                                  |       | 7,769                                 |       | 7,762 |   | 6,743 |   |
| Operating and  maintenance expenses                                                           |       | 902,237                               |       | 882,552 |   | 838,466 |   |
| Depreciation and  amortization                                                                |       | 425,511                               |       | 372,956 |   | 336,744 |   |
| Taxes (other  than income taxes)                                                              |       | 135,903                               |       | 129,928 |   | 128,970 |   |
| Total operating  expenses                                                                     |       | 3,507,104                             |       | 3,387,302 |   | 2,844,224 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Operating income**                                                                          |       | 520,511                               |       | 466,282 |   | 431,633 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| Interest and  other income — net (see Note 7)                                            |       | 9,431                                 |       | 2,964 |   | 1,089 |   |
| Allowance for  funds used during construction — equity                                   |       | 20,896                                |       | 16,416 |   | 20,747 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Interest charges and financing  costs**                                                     |       |                                  |       |   |   |   |   |
| Interest charges  — including financing costs of $6,480, $7,292 and $8,258, respectively |       | 165,381                               |       | 150,261 |   | 142,147 |   |
| Allowance for  funds used during construction — debt                                     |       | (14,459                               | )          | (14,126 | ) | (13,565 | ) |
| Total interest  charges and financing costs                                                   |       | 150,922                               |       | 136,135 |   | 128,582 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| Income before income  taxes                                                                   |       | 399,916                               |       | 349,527 |   | 324,887 |   |
| Income taxes                                                                                  |       | 127,606                               |       | 111,783 |   | 94,613 |   |
| Net income                                                                                    |       | $                                     | 272,310    |   | $ | 237,744 |   | $ | 230,274 |   |

 

See Notes toConsolidated Financial Statements

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**NSP-MINNESOTA****CONSOLIDATED STATEMENTS OF CASH FLOWS(Thousands of Dollars)**
|                                                                                | ** ** | **Year Ended Dec. 31** | ** ** |
|--------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                     | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Operating  activities**                                                      |       |                                  |       |   |   |   |   |
| Net income                                                                     |       | $                                     | 272,310    |   | $ | 237,744 |   | $ | 230,274 |   |
| Adjustments to  reconcile net income to cash provided by operating activities: | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Depreciation and amortization                                                  |       | 433,883                               |       | 378,884 |   | 351,887 |   |
| Nuclear fuel amortization                                                      |       | 47,531                                |       | 45,158 |   | 43,296 |   |
| Deferred income taxes                                                          |       | (83,361                               | )          | 28,846 |   | 20,545 |   |
| Amortization of investment tax credits                                         |       | (4,846                                | )          | (6,611 | ) | (7,150 | ) |
| Allowance for equity funds used during construction                            |       | (20,896                               | )          | (16,416 | ) | (20,747 | ) |
| Impairment of assets                                                           |       | —                                |       | 2,887 |   | — |   |
| Settlement of interest rate swap                                               |       | 16,359                                |       | — |   | — |   |
| Unrealized (gain) loss on derivative instruments                               |       | (6,104                                | )          | (934 | ) | 2,560 |   |
| Change in accounts receivable                                                  |       | 28,043                                |       | (102,347 | ) | (18,185 | ) |
| Change in accounts receivable from affiliates                                  |       | 20,479                                |       | (45,064 | ) | 40,466 |   |
| Change in inventories                                                          |       | (6,475                                | )          | (27,855 | ) | (12,622 | ) |
| Change in other current assets                                                 |       | 37,212                                |       | (89,350 | ) | (73,706 | ) |
| Change in accounts payable                                                     |       | 49,650                                |       | 121,975 |   | 27,032 |   |
| Change in other current liabilities                                            |       | 3,639                                 |       | (22,933 | ) | (24,204 | ) |
| Change in other noncurrent assets                                              |       | 11,945                                |       | (31,419 | ) | 11,554 |   |
| Change in other noncurrent liabilities                                         |       | (45,825                               | )          | 16,153 |   | 64,806 |   |
| Net cash provided by operating activities                                      |       | 753,544                               |       | 488,718 |   | 635,806 |   |
|                                                                           |       |                                  |       |   |   |   |   |
| **Investing activities**                                                       |       |                                  |       |   |   |   |   |
| Utility capital/construction expenditures                                      |       | (905,352                              | )          | (693,028 | ) | (641,476 | ) |
| Allowance for equity funds used during construction                            |       | 20,896                                |       | 16,416 |   | 20,747 |   |
| Purchase of investments in external decommissioning  fund                      |       | (1,288,104                            | )          | (576,001 | ) | (305,328 | ) |
| Proceeds from sale of investments in external  decommissioning fund            |       | 1,240,034                             |       | 494,529 |   | 228,676 |   |
| Investments in utility money pool                                              |       | (1,359,000                            | )          | — |   | — |   |
| Repayments from utility money pool                                             |       | 1,359,000                             |       | — |   | — |   |
| Proceeds from sale of assets                                                   |       | —                                |       | 11,228 |   | — |   |
| Investments in and advances to affiliates                                      |       | 33,700                                |       | (32,500 | ) | (7,790 | ) |
| Other investments                                                              |       | 6,439                                 |       | (13,929 | ) | (1,293 | ) |
| Net cash used in investing activities                                          |       | (892,387                              | )          | (793,285 | ) | (706,464 | ) |
|                                                                           |       |                                  |       |   |   |   |   |
| **Financing  activities**                                                      |       |                                  |       |   |   |   |   |
| Short-term borrowings — net                                               |       | 89,000                                |       | (90,000 | ) | 32,000 |   |
| Proceeds from issuance of long-term debt                                       |       | 393,724                               |       | 250,000 |   | 10 |   |
| Repayment of long-term debt, including reacquisition  premiums                 |       | (210,662                              | )          | (82,031 | ) | (4,508 | ) |
| Borrowings under 5-year unsecured credit facility                              |       | 194,000                               |       | 1,000,000 |   | — |   |
| Repayments under 5-year unsecured credit facility                              |       | (444,000                              | )          | (750,000 | ) | — |   |
| Capital contributions from parent                                              |       | 313,856                               |       | 224,247 |   | 180,408 |   |
| Dividends and cash distributions paid to parent                                |       | (219,598                              | )          | (215,341 | ) | (213,033 | ) |
| Net cash provided by (used in) financing activities                            |       | 116,320                               |       | 336,875 |   | (5,123 | ) |
|                                                                           |       |                                  |       |   |   |   |   |
| Net increase  (decrease) in cash and cash equivalents                          |       | (22,523                               | )          | 32,308 |   | (75,781 | ) |
| Cash and cash  equivalents at beginning of year                                |       | 38,542                                |       | 6,234 |   | 82,015 |   |
| Cash and cash  equivalents at end of year                                      |       | $                                     | 16,019     |   | $ | 38,542 |   | $ | 6,234 |   |
|                                                                           |       |                                  |       |   |   |   |   |
| Supplemental  disclosure of cash flow information                              |       |                                  |       |   |   |   |   |
| Cash paid for interest (net of amounts capitalized)                            |       | $                                     | 145,585    |   | $ | 124,516 |   | $ | 123,705 |   |
| Cash paid for income taxes (net of refunds received)                           |       | $                                     | 227,285    |   | $ | 122,456 |   | $ | 32,796 |   |
|                                                                           |       |                                  |       |   |   |   |   |
| Supplemental  disclosure of non-cash flow information                          |       |                                  |       |   |   |   |   |
| Property, plant  and equipment additions in accounts payable                   |       | $                                     | 36,613     |   | $ | 20,535 |   | $ | 20,683 |   |

 

See Notes toConsolidated Financial Statements

32

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**NSP-MINNESOTACONSOLIDATED BALANCE SHEETS****(Thousandsof Dollars)**
|                                                                                                   | ** ** | **Dec. 31, 2006** | ** ** | **Dec. 31, 2005** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| **ASSETS**                                                                                        | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Current assets:                                                                                   |       |                        |       |                        |       |
| Cash and cash equivalents                                                                         |       | $                           | 16,019     |                        | $          | 38,542 |   |
| Notes receivable from affiliates                                                                  |       | 30,300                      |       | 64,000                      |       |
| Accounts receivable — net of allowance for bad  debts: $13,408 and $10,128, respectively     |       | 370,635                     |       | 398,678                     |       |
| Accounts receivable from affiliates                                                               |       | 32,936                      |       | 53,414                      |       |
| Accrued unbilled revenues                                                                         |       | 220,034                     |       | 258,028                     |       |
| Materials and supplies inventories — at average cost                                         |       | 93,183                      |       | 94,395                      |       |
| Fuel inventory — at average cost                                                             |       | 40,257                      |       | 33,609                      |       |
| Natural gas inventory — at average cost                                                      |       | 85,016                      |       | 83,977                      |       |
| Derivative instruments valuation                                                                  |       | 62,211                      |       | 107,786                     |       |
| Prepayments and other                                                                             |       | 50,381                      |       | 34,602                      |       |
| Total current assets                                                                              |       | 1,000,972                   |       | 1,167,031                   |       |
| Property, plant  and equipment, at cost:                                                          |       |                        |       |                        |       |
| Electric utility plant                                                                            |       | 8,245,632                   |       | 8,018,167                   |       |
| Natural gas utility plant                                                                         |       | 859,533                     |       | 829,522                     |       |
| Construction work in progress                                                                     |       | 917,275                     |       | 496,884                     |       |
| Common utility and other property                                                                 |       | 416,635                     |       | 467,215                     |       |
| Total property, plant and equipment                                                               |       | 10,439,075                  |       | 9,811,788                   |       |
| Less accumulated depreciation                                                                     |       | (4,590,719                  | )          | (4,454,408                  | )          |
| Nuclear fuel — net of accumulated amortization:  $1,237,917 and $1,190,386, respectively     |       | 140,152                     |       | 102,409                     |       |
| Net property, plant and equipment                                                                 |       | 5,988,508                   |       | 5,459,789                   |       |
| Other assets:                                                                                     |       |                        |       |                        |       |
| Nuclear decommissioning fund investments                                                          |       | 1,200,688                   |       | 1,047,592                   |       |
| Regulatory assets                                                                                 |       | 372,349                     |       | 450,200                     |       |
| Prepaid pension asset                                                                             |       | 276,571                     |       | 379,808                     |       |
| Derivative instruments valuation                                                                  |       | 181,616                     |       | 198,044                     |       |
| Other investments                                                                                 |       | 30,892                      |       | 37,331                      |       |
| Other                                                                                             |       | 27,452                      |       | 51,589                      |       |
| Total other assets                                                                                |       | 2,089,568                   |       | 2,164,564                   |       |
| Total assets                                                                                      |       | $                           | 9,079,048  |                        | $          | 8,791,384 |   |
| **LIABILITIES  AND EQUITY**                                                                       | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Current  liabilities:                                                                             |       |                        |       |                        |       |
| Current portion of long-term debt                                                                 |       | $                           | 40         |                        | $          | 204,833 |   |
| Short-term debt                                                                                   |       | 89,000                      |       | 3⁄4                      |       |
| Accounts payable                                                                                  |       | 468,727                     |       | 379,950                     |       |
| Accounts payable to affiliates                                                                    |       | 39,139                      |       | 60,419                      |       |
| Taxes accrued                                                                                     |       | 126,104                     |       | 123,384                     |       |
| Accrued interest                                                                                  |       | 48,308                      |       | 49,122                      |       |
| Dividends payable to parent                                                                       |       | 56,105                      |       | 54,613                      |       |
| Derivative instruments valuation                                                                  |       | 36,167                      |       | 93,544                      |       |
| Other                                                                                             |       | 38,572                      |       | 57,852                      |       |
| Total current liabilities                                                                         |       | 902,162                     |       | 1,023,717                   |       |
| Deferred credits  and other liabilities:                                                          |       |                        |       |                        |       |
| Deferred income taxes                                                                             |       | 708,772                     |       | 821,417                     |       |
| Deferred investment tax credits                                                                   |       | 47,654                      |       | 52,500                      |       |
| Asset retirement obligations                                                                      |       | 1,311,271                   |       | 1,242,919                   |       |
| Regulatory liabilities                                                                            |       | 658,571                     |       | 846,195                     |       |
| Derivative instruments valuation                                                                  |       | 248,981                     |       | 246,951                     |       |
| Pension and employee benefit obligations                                                          |       | 209,548                     |       | 93,827                      |       |
| Other liabilities                                                                                 |       | 69,229                      |       | 55,922                      |       |
| Total deferred credits and other liabilities                                                      |       | 3,254,026                   |       | 3,359,731                   |       |
| Commitments and  contingent liabilities (see Note 11)                                             |       |                        |       |                        |       |
| Capitalization  (see Statements of Capitalization):                                               |       |                        |       |                        |       |
| Long-term debt                                                                                    |       | 2,299,188                   |       | 2,155,540                   |       |
| Common stock — authorized 5,000,000 shares of $0.01  par value; outstanding 1,000,000 shares |       | 10                          |       | 10                          |       |
| Additional paid in capital                                                                        |       | 1,561,480                   |       | 1,247,624                   |       |
| Retained earnings                                                                                 |       | 1,055,983                   |       | 1,004,762                   |       |
| Accumulated other comprehensive income                                                            |       | 6,199                       |       | 3⁄4                      |       |
| Total common stockholder’s equity                                                            |       | 2,623,672                   |       | 2,252,396                   |       |
| Total  liabilities and equity                                                                     |       | $                           | 9,079,048  |                        | $          | 8,791,384 |   |

 

See Notes toConsolidated Financial Statements

33

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**NSP-MINNESOTA****CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’SEQUITY****AND COMPREHENSIVE INCOME****(Dollars in Thousands)**
|                                                                                       | ** ** | **Common Stock** | ** ** | **Additional Paid** | ** ** | **Retained**        | ** ** | **Accumulated  Other  Comprehensive** | ** ** | **Total  Stockholder’s** | ** ** |
|---------------------------------------------------------------------------------------|------------|-----------------------|------------|--------------------------|------------|---------------------|------------|---------------------------------------|------------|-------------------------------|------------|
| ** **                                                                            | ** ** | **Shares**            | ** ** | **Amount**               | ** ** | **in Capital** | ** ** | **Earnings**                          | ** ** | **Income (Loss)**        | ** ** | **Equity** | ** ** |
| ** **                                                                            | ** ** | ** **            | ** ** | ** **               | ** ** | ** **          | ** ** | ** **                            | ** ** | ** **                    | ** ** | ** ** | ** ** |
| **Balance  at Dec. 31, 2003**                                                         |       | 1,000,000             |       | $                        | 10         |                | $          | 842,969                               |       | $                             | 965,880    |   | $ | (4 | ) | $ | 1,808,855 |   |
| Net income                                                                            |       |                  |       |                     |       |                |       | 230,274                               |       |                          |       | 230,274 |   |
| Net derivative  instrument fair value changes during the period, 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 |   |
| Net derivative  instrument fair value changes during the period                       |       |                  |       |                     |       |                |       |                                  |       | —                        |       | — |   |
| 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 |   |
|                                                                                  |       |                  |       |                     |       |                |       |                                  |       |                          |       |   |   |
| Net income                                                                            |       |                  |       |                     |       |                |       | 272,310                               |       |                          |       | 272,310 |   |
| Net derivative  instrument fair value changes during the period, net of tax of $6,513 |       |                  |       |                     |       |                |       |                                  |       | 9,433                         |       | 9,433 |   |
| Comprehensive  income for 2006                                                        |       |                  |       |                     |       |                |       |                                  |       |                          |       | 281,743 |   |
| SFAS No. 158  adoption, net of tax of $(2,233) (see Note 6)                           |       |                  |       |                     |       |                |       |                                  |       | (3,234                        | )          | (3,234 | ) |
| Common dividends  declared to parent                                                  |       |                  |       |                     |       |                |       | (221,089                              | )          |                          |       | (221,089 | ) |
| Contribution of  capital by parent                                                    |       |                  |       |                     |       | 313,856             |       |                                  |       |                          |       | 313,856 |   |
| **Balance at Dec. 31, 2006**                                                          |       | 1,000,000             |       | $                        | 10         |                | $          | 1,561,480                             |       | $                             | 1,055,983  |   | $ | 6,199 |   | $ | 2,623,672 |   |

 

See Notes toConsolidated Financial Statements

34

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**NSP-MINNESOTA****CONSOLIDATED STATEMENTS OFCAPITALIZATION (Thousands of Dollars)**
| ** **                                                                                                          | ** ** | **Dec. 31** | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                                                          | ** ** | **2006**         | ** ** | **2005** | ** ** |
| **Long-Term Debt**                                                                                                  |       |             |       |   |   |
| First Mortgage Bonds,  Series due:                                                                                  |       |             |       |   |   |
| Dec. 1, 2006,  4.1% (a)                                                                                             |       | $                | —     |   | $ | 2,420 |   |
| Dec. 1,  2007-2008, 4.5%-4.6% (a)                                                                                   |       | —           |       | 7,490 |   |
| Aug. 1, 2006,  2.875%                                                                                               |       | —           |       | 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          |       | 250,000 |   |
| June 1, 2036,  6.25%                                                                                                |       | 400,000          |       | — |   |
| 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                                                                                                               |       | 89               |       | 841 |   |
| Unamortized discount                                                                                                |       | (7,761           | )          | (7,278 | ) |
| Total                                                                                                               |       | 2,299,228        |       | 2,360,373 |   |
| Less current maturities                                                                                             |       | 40               |       | 204,833 |   |
| Total long-term  debt                                                                                               |       | $                | 2,299,188  |   | $ | 2,155,540 |   |
|                                                                                                                |       |             |       |   |   |
| **Common Stockholder’s Equity**                                                                                |       |             |       |   |   |
| Common stock —  authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares  in 2006 and 2005 |       | $                | 10         |   | $ | 10 |   |
| Additional paid  in capital                                                                                         |       | 1,561,480        |       | 1,247,624 |   |
| Retained  earnings                                                                                                  |       | 1,055,983        |       | 1,004,762 |   |
| Accumulated  other comprehensive income                                                                             |       | 6,199            |       | — |   |
| Total common  stockholder’s equity                                                                             |       | $                | 2,623,672  |   | $ | 2,252,396 |   |

----

(a)             Resource recoveryfinancing

(b)            Pollutioncontrol financing

See Notes toConsolidated Financial Statements

35

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**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

**1. Summary of Significant AccountingPolicies**

***Business and Systemof Accounts*****—NSP-Minnesota is principally engaged in the generation, purchase, transmission,distribution and sale of electricity and in the purchase, transportation,distribution and sale of natural gas. NSP-Minnesota is 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.

***Principles ofConsolidation*****—NSP-Minnesota has subsidiaries, which have been consolidated and for which allsignificant intercompany transactions and balances have been eliminated.

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

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

·                     NSP-Minnesota’srates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recoverymechanism allowing dollar-for-dollar recovery of the respective costs, whichare trued-up on a two-month and annual basis, respectively.  The electriccost-of-fuel-and-purchased-energy mechanism also provides a sharing amongshareholders and customers of certain margins on short-term wholesale sales andcommodity trading.

·                     NSP-Minnesotaoperates under various service quality standards which could require customerrefunds if certain criteria are not met. NSP-Minnesota’s rates also includemonthly adjustments for the recovery of conservation and energy-managementprogram costs, which are reviewed annually. NSP-Minnesota is allowed to recover certain costs associated with newtransmission facilities to deliver renewable energy resources through a raterider.

·                     NSP-Minnesotasells firm power and energy in wholesale markets, which are regulated by theFERC. Certain of these rates include monthly wholesale fuel cost-recoverymechanisms.

***Commodity TradingOperations*****—All applicable gains and losses related to commodity trading activities,whether or not settled physically, are shown on a net basis in the ConsolidatedStatements of Income.

Pursuant to the JOA approved by the FERC, some of thecommodity trading margins from NSP-Minnesota are apportioned to PSCo and SPS.Commodity trading activities are not associated with energy produced fromNSP-Minnesota’s generation assets or energy and capacity purchased to servenative load. Commodity trading contracts are recorded at fair market value inaccordance with SFAS 133.  In addition,commodity trading results include the impact of all pertinent margin-sharingmechanisms.   For more information, seeNote 8 to the Consolidated Financial Statements.

***DerivativeFinancial Instruments****—*NSP-Minnesota utilizes a variety of derivatives, includingcommodity forwards, futures and options, index or fixed price swaps and basisswaps to mitigate market risks and to enhance its operations.  For further discussion of NSP-Minnesota’srisk management and derivative activities, see Note 8 to the ConsolidatedFinancial Statements.

***Property, Plant,and Equipment and Depreciation*****— Property, plant and equipment is stated at original cost.The cost of plant includes direct labor and materials, contracted work,overhead costs and applicable interest expense. The cost of plant retired ischarged to accumulated depreciation and amortization. Removal costs associatedwith regulatory obligations are recorded as regulatory liabilities. Significantadditions or improvements extending asset lives are capitalized, while repairand maintenance costs are charged to expense as incurred. Maintenance andreplacement of items determined to be less than units of property are chargedto operating expenses as incurred. Planned major maintenance activities arecharged to operating expense unless the cost represents the acquisition of anadditional unit of property or the replacement of an existing unit ofproperty.  Property, plant and equipmentalso includes costs associated with property held for future use.

36

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NSP-Minnesota records depreciation expense related toits plant by using the straight-line method over the plant’s useful life.Actuarial and semi-actuarial life studies are performed on a period basis andsubmitted to the state and federal commissions for review.  Upon acceptance by the various commissions,the resulting lives and net salvage rates are used to calculatedepreciation.  Depreciation expense,expressed as a percentage of average depreciable property, for the years endedDec. 31, 2006, 2005 and 2004 was 3.9 percent, 3.9 percent and 3.8 percent,respectively.

***AFDC*****— AFDC represents the cost of capitalused to finance utility construction activity. AFDC is computed by applying acomposite pretax rate to qualified construction work in progress. The amount ofAFDC capitalized as a utility construction cost is credited to other income anddeductions (for equity capital) and interest charges (for debt capital). AFDCamounts capitalized are included in NSP-Minnesota’s rate base for establishingutility service rates. In addition to construction-related amounts, AFDC alsois recorded to reflect returns on capital used to finance conservation programsin Minnesota.

GenerallyAFDC costs are recovered from customers as the related property is depreciated.In December 2003, the MPUC voted to approve NSP-Minnesota’s MERP proposalto convert two coal-fueled electric generating plants to natural gas, and toinstall advanced pollution control equipment at a third coal-fired plant. Allthree plants are located in the Minneapolis - St. Paul metropolitan area. Theseimprovements are expected to significantly reduce air emissions from thesefacilities, while increasing the capacity at system peak by 300 MW. Theprojects are expected to come on line between 2007 and 2009, at a cumulativeinvestment of approximately $1 billion. The MPUC has approved a more currentrecovery of the financing costs related to the MERP. The in-service plantcosts, including the financing costs during construction, are recovered fromcustomers through a MERP rider resulting in a lower recognition of AFDC.

***Decommissioning*****— NSP-Minnesota accounts for the futurecost of decommissioning, or retirement, of its nuclear generating plantsthrough annual depreciation accruals using an annuity approach designed toprovide for full rate recovery of the future decommissioning costs. The decommissioningcalculation covers all expenses, including decontamination and removal ofradioactive material, and extends over the estimated lives of the plants. Thecalculation assumes that NSP-Minnesota will recover those costs through rates.The fair value of external nuclear decommissioning fund investments areestimated based on quoted market prices for those or similar investments.Unrealized gains or losses on the fund’s assets are included with RegulatoryAssets on the Consolidated Balance Sheets.

***Nuclear FuelExpense*****—Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generatingplants use fuel, includes the cost of fuel used in the current period(including AFDC), as well as future disposal costs of spent nuclear fuel, costsassociated with the end-of-life fuel segments, and fees assessed by the DOE forNSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuelenrichment facility.

***Environmental Costs*****— Environmental costs are recorded on anundiscounted basis when it is probable NSP-Minnesota is liable for the costsand the liability can be reasonably estimated. Costs may be deferred as aregulatory asset if it is probable that the costs will be recovered fromcustomers in future rates. Otherwise, the costs are expensed. If anenvironmental 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 inflationaryincreases, are recorded. The estimates are based on experience, an assessmentof the current situation and the technology currently available for use in theremediation. The recorded costs are regularly adjusted as estimates are revisedand remediation proceeds. If several designated responsible parties exist,costs are estimated and recorded only for NSP-Minnesota’s expected share of thecost. Any future costs of restoring sites where operation may extendindefinitely are treated as a capitalized cost of plant retirement. Thedepreciation expense levels recoverable in rates include a provision forremoval expenses, which may include final remediation costs. Removal costsrecovered in rates are classified as a regulatory liability.

***Legal Costs***— Legal costs are not accrued, but expensed as incurred.

***Income Taxes*****— Xcel Energy and its utilitysubsidiaries, including NSP-Minnesota, file consolidated federal and combinedand separate state income tax returns. Income taxes for consolidated orcombined subsidiaries are allocated to the subsidiaries based on separatecompany computations of taxable income or loss. The holding company also allocates its own net income tax benefits toits direct subsidiaries based on the positive tax liability of each company inthe consolidated federal or combined state returns. NSP-Minnesota defers incometaxes for all temporary differences between the book and tax bases of assetsand liabilities. The tax rates used are those that are scheduled to be ineffect when the temporary differences are expected to turn around, or reverse.

Investment tax credits are deferred and their benefitsamortized over the estimated lives of the related property. Utility rateregulation also has created certain regulatory assets and liabilities relatedto income taxes, which are summarized in Note 13 to the Consolidated FinancialStatements. For more information on income taxes, see Note 5 to theConsolidated Financial Statements.

37

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***Use of Estimates*****— In recording transactions and balancesresulting from business operations, NSP-Minnesota uses estimates based on thebest information available. Estimates are used for such items as plantdepreciable lives, asset retirement obligations, decommissioning, taxprovisions, uncollectible amounts, environmental costs, unbilled revenues,jurisdictional fuel and energy cost allocations and actuarially determinedbenefit costs. The recorded estimates are revised when better information isobtained or actual amounts are determinable. Those revisions can affectoperating results. Each year the depreciable lives of certain plant assets arereviewed and revised, if appropriate.

***Cash and CashEquivalents*****—NSP-Minnesota considers investments in certain instruments, includingcommercial paper and money market funds, with a remaining maturity of threemonths or less at the time of purchase to be cash equivalents.

***Inventory*****— All inventory for NSP-Minnesota isrecorded at average cost.

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

·              certain costs, whichwould otherwise be charged to expense, are deferred as regulatory assets basedon the expected ability to recover them in future rates; and

·              certain credits,which would otherwise be reflected as income, are deferred as regulatoryliabilities based on the expectation they will be returned to customers infuture rates.

Estimates of recovering deferred costs and returningdeferred credits are based on specific ratemaking decisions or precedent foreach item. Regulatory assets and liabilities are amortized consistent with theperiod of expected regulatory treatment.

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

***Deferred FinancingCosts*****—Other assets include deferred financing costs, which are amortized over theremaining maturity periods of the related debt. NSP-Minnesota’s deferredfinancing costs, net of amortization at Dec. 31, 2006 and 2005 were $20.4million and $17.2 million, respectively.

***Accounts Receivableand Allowance for Uncollectibles*—**Accounts receivableare stated at the actual billed amount net of the allowance foruncollectibles.  NSP-Minnesotaestablishes an allowance for uncollectibles based on a reserve policy thatreflects its expected exposure to the credit risk of customers.

***Emission Allowances*—**Emissionallowances are recorded at cost, including the annual SO2 and NOx emissionallowance entitlement received at no cost from the Federal EPA.  We follow the inventory model for allallowances.  The sales of allowances arereported in the Operating Activities section of the Consolidated Statements ofCash Flows.  The net margin on sales ofemission allowances is included in Operationing Revenue as it is integral tothe production process of energy and our revenue optimization strategy for ourutility operations.

***Reclassifications*—**The balance sheetand the statements of cash flows have been reclassified from prior-periodpresentation to conform to the 2006 presentation. These reclassifications hadno effect on net income or earnings per share. The reclassifications wererelated to the presentation of regulatory assets and liabilities for ARO anddecommissioning activities on a net basis. These reclassifications did not affect total operating, investing orfinancing within the statements of cash flows.

***FASB Interpretation No. 48 (FIN 48)***— In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty inIncome Taxes — an interpretation of FASB Statement No. 109.” FIN 48prescribes how a company should recognize, measure, present and discloseuncertain tax positions that the company has taken or expects to take in itsincome tax returns. FIN 48 requires that only income tax benefits that meet the“more likely than not” recognition threshold be recognized or continue to berecognized on its effective date. Initial derecognition amounts would bereported as a cumulative effect of a change in accounting principle. Followingimplementation, the ongoing recognition of changes in the measurement ofuncertain tax positions could be reflected as a component of income taxexpense.

FIN 48is effective for fiscal years beginning after Dec. 15, 2006. NSP-Minnesota hassubtantially completed its analysis and does not expect the cumulative effectof the adoption to be material.

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***FairValue Measurements (SFAS No. 157) —*** In September 2006, the FASB issued SFASNo. 157, which provides a single definition of fair value, together with aframework for measuring it, and requires additional disclosure about the use offair value to measure assets and liabilities. SFAS No. 157 also emphasizesthat fair value is a market-based measurement, and sets out a fair valuehierarchy with the highest priority being quoted prices in active markets.  Fair value measurements are disclosed bylevel within that hierarchy. SFAS No. 157 is effective for financialstatements issued for fiscal years beginning after Nov. 15, 2007.NSP-Minnesota is evaluating the impact of SFAS No. 157 on its financialcondition and results of operations and does not expect the impact ofimplementation to be material.

**2.****     Short-Term Borrowings**

***Commercial Paper *—**During 2006, NSP-Minnesota resumed short-term borrowings in the commercialpaper market.  At Dec. 31, 2006,NSP-Minnesota had commercial paper outstanding of approximately $89.0 millionwith a weighted average interest rate of 5.45 percent.

***Money Pool***-Xcel Energy has established a utility money pool arrangement with the utilitysubsidiaries and received required state regulatory approvals.  Approval was also granted by the FERC in aJuly 18, 2006 order.  The utilitymoney pool allows for short-term loans between the utility subsidiaries andfrom the holding company to the utility subsidiaries at market-based interestrates. The utility money pool arrangement does not allow loans from the utilitysubsidiaries to the holding company. NSP-Minnesota has approval to borrow up to $250 million under thearrangement.  NSP-Minnesota had noborrowings or loans outstanding under the arrangement at Dec. 31, 2006.

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

***Credit Facilities***—At Dec. 31, 2006, NSP-Minnesota had the following committed credit facility ineffect, in millions of dollars:
|                      |   | **Credit  Facility** |   | ** **     |   | ** ** |   | ** **         |   |
|----------------------|--------|----------------------|--------|----------------|--------|------------|--------|--------------------|--------|
| **Credit  Facility** |   | **Borrowings**       |   | **Available*** |   | **Term**   |   | **Maturity**       |   |
| $500                 |   | $—              |   | $376.5         |   | Five year  |   | December 2011 |   |

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* Net of creditfacility borrowings, issued and outstanding letters of credit and commercialpaper borrowings.

The line of creditprovides short-term financing in the form of notes payable to banks, letters ofcredit and back-up support for commercial paper borrowings.  NSP-Minnesota has the right to request anextension 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 was in compliance at Dec. 31, 2006.  The interest rate is based on either theagent bank’s prime rate or the applicable LIBOR, plus a borrowing margin asdetermined by NSP-Minnesota’s senior unsecured credit ratings from Moody,Standard & Poor and Fitch.

As of Dec. 31, 2006, NSP-Minnesota had no directborrowings on this line of credit; however, this credit facility was used toprovide back-up support for NSP-Minnesota commercial paper and letters ofcredit   Also, $35.3 million of lettersof credit were outstanding at Dec. 31, 2006, as discussed in Note 9 to theConsolidated Financial Statements, of which $34.5 million were outstandingunder the above credit facility.

All property ofNSP-Minnesota is subject to the lien of its first mortgage indenture.  NSP-Minnesota’s first mortgage indentureplaces certain restrictions on the amount of cash dividends it can pay XcelEnergy, the holder of its common stock. Even with these restrictions,NSP-Minnesota could have paid more than $905 million in additional cashdividends on common stock at Dec. 31, 2006.

Maturities of long-term debt are:
| (Millions of Dollars) | ** ** | ** ** | ** ** |
|---------------------------------|------------|------------|------------|
| 2007                            |       | $          | —     |   |
| 2008                            |       | $          | —     |   |
| 2009                            |       | $          | 250.0      |   |
| 2010                            |       | $          | 175.0      |   |
| 2011                            |       | $          | —     |   |

 

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**4. Joint Plant Ownership**

Following are the investments by NSP-Minnesota injointly owned plants and the related ownership percentages as of Dec. 31, 2006:
| **(Thousands of Dollars)**            | ** ** | **Plant in  Service** | ** ** | **Accumulated  Depreciation** | ** ** | **Construction  Work in  Progress** | ** ** | **Ownership%** | ** ** |
|-------------------------------------------------|------------|----------------------------|------------|-------------------------------|------------|------------------------------------------|------------|----------------|------------|
| Sherco Unit 3                                   |       | $                          | 496,188    |                          | $          | 293,906                                  |       | $              | 2,130      |   | 59.0 |   |
| Sherco Common  Facilities Units 1, 2 & 3    |       | 106,939                    |       | 57,800                        |       | 2,292                                    |       | 75.0           |       |
| Transmission  facilities, including substations |       | 4,832                      |       | 2,004                         |       | —                                   |       | 59.0           |       |
| Total                                           |       | $                          | 607,959    |                          | $          | 353,710                                  |       | $              | 4,422      |   |   |   |

 

NSP-Minnesota is part owner of Sherco 3, an 860-MW,coal-fueled electric generating unit. NSP-Minnesota is the operating agentunder the joint ownership agreement. NSP-Minnesota’s share of operatingexpenses and construction expenditures are included in the applicable utilityaccounts.  Each of the respective ownersis responsible for funding its portion of the construction costs.  For Sherco Common Facilities Units 1, 2 and3, the ownership percentage for Xcel Energy increased from 65.6 percent to 75percent in January 2006 on new capital investments.

**5.   IncomeTaxes**

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:

|                                                        | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal  statutory rate                                |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases  (decreases) in tax from:                    |       |     |       |     |       |     |       |
| State income taxes, net of federal income tax  benefit |       | 3.6      |       | 4.6      |       | 4.2      |       |
| Resolution of income tax audits                        |       | (2.5     | )          | (1.2     | )          | (3.8     | )          |
| Tax credits recognized                                 |       | (2.1     | )          | (2.8     | )          | (2.9     | )          |
| Regulatory differences — utility plant items      |       | (1.5     | )          | (1.4     | )          | (2.2     | )          |
| Life insurance policies                                |       | (0.2     | )          | (0.2     | )          | (0.3     | )          |
| Other — net                                       |       | (0.4     | )          | (2.0     | )          | (0.9     | )          |
| Effective income tax  rate                             |       | 31.9     | %          | 32.0     | %          | 29.1     | %          |

 

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

| (Thousands of Dollars) | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current federal  tax expense     |       | $        | 178,668    |     | $          | 81,518   |       | $ | 53,166 |   |
| Current state  tax expense       |       | 37,145   |       | 8,065    |       | 29,826   |       |
| Current tax  credits             |       | —   |       | (35      | )          | (1,774   | )          |
| Deferred federal  tax expense    |       | (66,676  | )          | 21,456   |       | 26,266   |       |
| Deferred state  tax expense      |       | (13,944  | )          | 10,629   |       | (5,194   | )          |
| Deferred tax  credits            |       | (2,741   | )          | (3,239   | )          | (527     | )          |
| Deferred  investment tax credits |       | (4,846   | )          | (6,611   | )          | (7,150   | )          |
| Total income tax  expense        |       | $        | 127,606    |     | $          | 111,783  |       | $ | 94,613 |   |

 

The components ofdeferred income tax at Dec. 31 were:

| (Thousands of Dollars)                                                                        | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax expense  excluding items below                                                             |       | $        | (144,209   | )        | $          | 46,863 |   |
| Amortization and  adjustments to deferred income taxes on income tax regulatory assets and  liabilities |       | 65,142   |       | (21,600  | )          |
| Tax expense  allocated to other comprehensive income and other                                          |       | (4,294   | )          | 3,583    |       |
| Deferred tax expense  (benefit)                                                                         |       | $        | (83,361    | )        | $          | 28,846 |   |

 

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The components of netdeferred tax liability (current and noncurrent portions) at Dec. 31 were:
| **(Thousands of Dollars)**               | ** ** | **2006** | ** ** | **2005** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax  liabilities:                         |       |     |       |     |       |
| Differences between book and tax bases of property |       | $        | 734,815    |     | $          | 771,495 |   |
| Regulatory assets                                  |       | 95,211   |       | 172,594  |       |
| Other                                              |       | 21,022   |       | 27,232   |       |
| Total deferred tax liabilities                     |       | $        | 851,048    |     | $          | 971,321 |   |
|                                               |       |     |       |     |       |
| Deferred tax  assets:                              |       |     |       |     |       |
| Employee benefits                                  |       | $        | 57,738     |     | $          | 54,861 |   |
| Regulatory liabilities                             |       | 20,590   |       | 21,282   |       |
| Deferred investment tax credits                    |       | 19,463   |       | 21,353   |       |
| Tax credit carryforward                            |       | 14,817   |       | 12,184   |       |
| Other                                              |       | 42,195   |       | 21,186   |       |
| Total deferred tax assets                          |       | $        | 154,803    |     | $          | 130,866 |   |
| Net deferred tax  liability                        |       | $        | 696,245    |     | $          | 840,455 |   |

 

**6.   Benefit Plans and OtherPostretirement Benefits**

Pension and other postretirement benefit disclosuresbelow generally represent Xcel Energy consolidated information unlessspecifically identified as being attributable to NSP-Minnesota.

Xcel Energy offers various benefit plans to itsbenefit 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, 2006, NSP-Minnesota had 2,094bargaining employees covered under a collective-bargaining agreement, whichexpires at the end of 2007.

**Employers’ Accounting for DefinedBenefit Pension and Other Postretirement Plans—an amendment of FASB StatementsNo. 87, 88, 106, and 132(R) (SFAS No. 158)** — In September2006, the FASB issued SFAS No. 158, which requires companies to fully recognizethe funded status of each pension and other postretirement benefit plan as aliability or asset on their balance sheets with all unrecognized amounts to be recordedin other comprehensive income.  Thefollowing table shows the impact of the implementation on the consolidatedstatement of financial position. NSP-Minnesota applied regulatory accounting treatment, which allowedrecognition of this item as a regulatory liability reduction rather than as acharge to accumulated other comprehensive income.  The table reflects the deferral of theseamounts as reductions to regulatory liabilities.  The table also includesnoncontributory, defined benefit supplemental retirement income plans.

 
| **Balance Sheet Line**                | ** ** | **Pre-SFAS No.  158** | ** ** | **SFAS No.  158 Adjustment** | ** ** | **SFAS No. 71  Adjustment** | ** ** | **After SFAS  No. 158** | ** ** |
|-------------------------------------------------|------------|----------------------------|------------|----------------------------------------|------------|---------------------------------------|------------|-----------------------------------|------------|
|                                            |       |                       |       |                                   |       |                                  |       |                              |       |
| Prepaid pension asset                           |       | $                          | 391,181    |                                   | $          | (114,610                              | )          | $                                 | —     |   | $ | 276,571 |   |
| Prepayments and other  (current deferred taxes) |       | 49,186                     |       | 1,195                                  |       | —                                |       | 50,381                            |       |
| Total Assets                                    |       | $                          | 440,367    |                                   | $          | (113,415                              | )          | $                                 | —     |   | $ | 326,952 |   |
|                                            |       |                       |       |                                   |       |                                  |       |                              |       |
| Other (current  liabilities)                    |       | $                          | 35,645     |                                   | $          | 2,927                                 |       | $                                 | —     |   | $ | 38,572 |   |
| Pension and employee  benefit obligations       |       | 97,146                     |       | 112,402                                |       | —                                |       | 209,548                           |       |
| Deferred income taxes                           |       | 709,810                    |       | (92,721                                | )          | 91,683                                |       | 708,772                           |       |
| Regulatory liabilities                          |       | 883,043                    |       | —                                 |       | (224,472                              | )          | 658,571                           |       |
| Total Liabilities                               |       | $                          | 1,725,644  |                                   | $          | 22,608                                |       | $                                 | (132,789   | ) | $ | 1,615,463 |   |
|                                            |       |                       |       |                                   |       |                                  |       |                              |       |
| AOCI-net of tax                                 |       | $                          | 9,433      |                                   | $          | (136,023                              | )          | $                                 | 132,789    |   | $ | 6,199 |   |
| Total Equity                                    |       | $                          | 9,433      |                                   | $          | (136,023                              | )          | $                                 | 132,789    |   | $ | 6,199 |   |

 

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**PensionBenefits**

Xcel Energy has severalnoncontributory, defined benefit pension plans that cover almost all employees.Benefits are based on a combination of years of service, the employee’s averagepay and Social Security benefits.

Xcel Energy’s policy isto fully 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 assetsprincipally consist of the common stock of public companies, corporate bondsand U.S. government securities. The target range for our pension assetallocation is 60 percent in equity investments, 20 percent in fixed incomeinvestments and 20 percent in nontraditional investments, such as real estate,private equity and a diversified commodities index.

Theactual composition of pension plan assets at Dec. 31 was:

|                             | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|-----------------------------|------------|------------|------------|------------|------------|
| ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Equity  securities          |       | 63         | %          | 65         | %          |
| Debt securities             |       | 22         |       | 20         |       |
| Real estate                 |       | 4          |       | 4          |       |
| Cash                        |       | 2          |       | 1          |       |
| Nontraditional  investments |       | 9          |       | 10         |       |
|                        |       | 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 11.3 percent, which is greater than the current assumptionlevel. The pension cost determination assumes 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. A higher weighting in equity investments can increase the volatility inthe return levels achieved by pension assets in any year. Investment returns in2006, 2005 and 2004 exceeded the assumed level of 8.75, 8.75 and 9.0 percent,respectively.  Xcel Energy continuallyreviews its pension assumptions.  In2007, Xcel Energy will continue to use an investment-return assumption of 8.75percent.

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***Benefit Obligations***— A comparison ofthe actuarially computed pension benefit obligation and plan assets, on acombined basis, is presented in the following table:
| **(Thousands of Dollars)**                                                                 | ** ** | **2006**        | ** ** | **2005**        | ** ** |
|-------------------------------------------------------------------------------------------------|------------|-----------------|------------|-----------------|------------|
| **Accumulated  Benefit Obligation at Dec. 31**                                                  |       | $               | 2,486,370  |            | $          | 2,642,177 |   |
|                                                                                            |       |            |       |            |       |
| **Change  in Projected Benefit Obligation**                                                     |       |            |       |            |       |
| Obligation at  Jan. 1                                                                           |       | $               | 2,796,780  |            | $          | 2,732,263 |   |
| Service cost                                                                                    |       | 61,627          |       | 60,461          |       |
| Interest cost                                                                                   |       | 155,413         |       | 160,985         |       |
| Plan amendments                                                                                 |       | (16,569         | )          | 300             |       |
| Actuarial (gain)  loss                                                                          |       | (82,339         | )          | 85,558          |       |
| Benefit payments                                                                                |       | (248,357        | )          | (242,787        | )          |
| Obligation at  Dec. 31                                                                          |       | $               | 2,666,555  |            | $          | 2,796,780 |   |
| ** **                                                                                      | ** ** | ** **      | ** ** | ** **      | ** ** |
| **Change  in Fair Value of Plan Assets**                                                        |       |            |       |            |       |
| Fair value of  plan assets at Jan. 1                                                            |       | $               | 3,093,536  |            | $          | 3,062,016 |   |
| Actual return on  plan assets                                                                   |       | 306,196         |       | 254,307         |       |
| Employer  contributions                                                                         |       | 32,000          |       | 20,000          |       |
| Benefit payments                                                                                |       | (248,357        | )          | (242,787        | )          |
| Fair value of  plan assets at Dec. 31                                                           |       | $               | 3,183,375  |            | $          | 3,093,536 |   |
|                                                                                            |       |            |       |            |       |
| **Funded  Status of Plans at Dec. 31**                                                     |       |            |       |            |       |
| Funded Status                                                                                   |       | $               | 516,820    |            | $          | 296,756 |   |
| Noncurrent  assets                                                                              |       | 586,713         |       | 685,028         |       |
| Noncurrent  liabilities                                                                         |       | (69,893         | )          | (90,595         | )          |
| Net pension  amounts recognized on Consolidated Balance Sheets                                  |       | $               | 516,820    |            | $          | 594,433 |   |
|                                                                                            |       |            |       |            |       |
| NSP-Minnesota  prepaid pension asset recorded                                                   |       | $               | 276,571    |            | $          | 379,808 |   |
| ** **                                                                                      |       |            |       |            |       |
| **NSP-Minnesota  Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:**       |       |            |       |            |       |
| Net loss                                                                                        |       | $               | 37,217     |            | 62,694     |   |
| Prior service  cost                                                                             |       | 77,393          |       | 108,256         |       |
| Total                                                                                           |       | $               | 114,610    |            | 170,950    |   |
|                                                                                            |       |            |       |            |       |
| **SFAS  No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in  Rates:** |       |            |       |            |       |
| Regulatory  liabilities                                                                         |       | $               | 114,610    |            | N/A        |   |
| Total                                                                                           |       | $               | 114,610    |            | N/A        |   |
|                                                                                            |       |            |       |            |       |
| **Measurement  Date**                                                                           |       | Dec.  31,  2006 |       | Dec.  31,  2005 |       |
|                                                                                            |       |            |       |            |       |
| **Significant  Assumptions Used to Measure Benefit Obligations**                                |       |            |       |            |       |
| Discount rate  for year-end valuation                                                           |       | 6.00            | %          | 5.75            | %          |
| Expected average  long-term increase in compensation level                                      |       | 4.00            | %          | 3.50            | %          |

 

***Cash Flows***—Cash funding requirements can be impacted by changes to actuarial assumptions,actual asset levels and other calculations prescribed by the fundingrequirements of income tax and other pension-related regulations. Theseregulations did not require cash funding in the years 2004 through 2006 forXcel Energy’s pension plans, and are not expected to require cash funding in2007.

***Plan Changes*—** The Pension ProtectionAct of 2006 (PPA) was reflected effective December 31, 2006.  PPA requires a change in the conversion basisfor lump-sum payments, three-year vesting for plans with account balance orpension equity benefits, as well as the repeal of the Economic Growth and Tax Relief Reconciliation Act of 2001 sunsetprovisions.  These changes are reflectedas a plan amendment for purposes of SFAS No. 87.

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***Benefit Costs***—******The components ofnet periodic pension cost (credit) are:

| (Thousands of Dollars)                              | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service cost                                                  |       | $        | 61,627     |     | $          | 60,461   |       | $ | 58,150 |   |
| Interest cost                                                 |       | 155,413  |       | 160,985  |       | 165,361  |       |
| Expected return  on plan assets                               |       | (268,065 | )          | (280,064 | )          | (302,958 | )          |
| Settlement gain                                               |       | —   |       | —   |       | (926     | )          |
| Amortization of  transition asset                             |       | —   |       | —   |       | (7       | )          |
| Amortization of  prior service cost                           |       | 29,696   |       | 30,035   |       | 30,009   |       |
| Amortization of  net (gain) loss                              |       | 17,353   |       | 6,819    |       | (15,207  | )          |
| Net periodic pension credit under SFAS No. 87                 |       | $        | (3,976     | )        | $          | (21,764  | )          | $ | (65,578 | ) |
|                                                          |       |     |       |     |       |     |       |
| **NSP-Minnesota**                                             |       |     |       |     |       |     |       |
| Net periodic  pension credit                                  |       | $        | (11,373    | )        | $          | (18,362  | )          | $ | (38,555 | ) |
| Credits not  recognized due to effects of regulation          |       | 12,637   |       | 19,368   |       | 38,967   |       |
| Net benefit cost (credit) recognized for financial  reporting |       | $        | 1,264      |     | $          | 1,006    |       | $ | 412 |   |
|                                                          |       |     |       |     |       |     |       |
| **Significant  Assumptions Used to Measure Costs**            |       |     |       |     |       |     |       |
| Discount rate                                                 |       | 5.75     | %          | 6.00     | %          | 6.25     | %          |
| Expected average  long-term increase in compensation level    |       | 3.50     | %          | 3.50     | %          | 3.50     | %          |
| Expected average  long-term rate of return on assets          |       | 8.75     | %          | 8.75     | %          | 9.00     | %          |

 

Pension costs include an expected return impact forthe current year that may differ from actual investment performance in theplan. The return assumption used for 2007 pension cost calculations will be8.75 percent. The cost calculation uses a market-related valuation of pensionassets, which reduces year-to-year volatility by recognizing the differencesbetween assumed and actual investment returns over a five-year period.

Xcel Energy and its operating utilities also maintainnoncontributory, defined benefit supplemental retirement income plans forcertain qualifying executive personnel. Benefits for these unfunded plans arepaid out of their operating cash flows.

**Defined Contribution Plans**

Xcel Energy maintains 401(k) and other definedcontribution plans that cover substantially all employees. The contributionsfor NSP-Minnesota were approximately $3.9 million in 2006, $3.8 million in 2005and  $3.8 million in 2004.

**Postretirement Health Care Benefits**

Xcel Energy has a contributory health and welfarebenefit plan that provides health care and death benefits to most Xcel Energyretirees. The former NSP discontinued contributing toward health care benefitsfor nonbargaining employees retiring after 1998 and for bargaining employees ofNSP-Minnesota and NSP-Wisconsin who retired after 1999. Employees of the formerNSP who retired after 1998 are eligible to participate in the Xcel Energyhealth care program with no employer subsidy.

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

Regulatory agencies for nearly all of Xcel Energy’sretail and wholesale utility customers have allowed rate recovery of accruedbenefit costs under SFAS No. 106. NSP-Minnesota transitioned to full accrualaccounting for SFAS No. 106 costs, with regulatory differences fully amortizedprior 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 theinvestment mix to equity funds. Also, a portion of the assets contributed onbehalf of non-bargaining retirees has been funded into a sub-account of theXcel Energy pension plans. These assets are invested in a manner consistentwith the investment strategy for the pension plan.

44

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

|                                           | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|
| Equity and  equity mutual fund securities |       | 67       | %          | 61       | %          |
| Fixed  income/debt securities             |       | 21       |       | 17       |       |
| Cash equivalents                          |       | 11       |       | 21       |       |
| Nontraditional  investments               |       | 1        |       | 1        |       |
|                                      |       | 100      | %          | 100      | %          |

 

Xcel Energy bases its investment-return assumption forthe postretirement health care fund assets on expected long-term performancefor each of the investment types included in its postretirement health careasset portfolio. Investment-return volatility is not considered to be amaterial factor in postretirement health care costs.

***Benefit Obligations***— A comparison of the actuarially computed benefitobligation and plan assets for Xcel Energy postretirement health care plansthat benefit employees of its utility subsidiaries is presented in thefollowing table:

| (Thousands of Dollars)                       | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|--------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Change  in Benefit Obligation**                      |       |       |       |       |       |
| Obligation at  Jan. 1                                  |       | $          | 938,172    |       | $          | 929,125 |   |
| Service cost                                           |       | 6,633      |       | 6,684      |       |
| Interest cost                                          |       | 52,939     |       | 55,060     |       |
| Medicare subsidy  reimbursements                       |       | 3,561      |       | —     |       |
| Plan amendments                                        |       | (945       | )          | —     |       |
| Plan  participants’ contributions                 |       | 11,870     |       | 12,008     |       |
| Actuarial gain                                         |       | (27,511    | )          | (3,175     | )          |
| Benefit payments                                       |       | (66,026    | )          | (61,530    | )          |
| Obligation at  Dec. 31                                 |       | $          | 918,693    |       | $          | 938,172 |   |
|                                                   |       |       |       |       |       |
| **Change in Fair Value of Plan  Assets**               |       |       |       |       |       |
| Fair value of  plan assets at Jan. 1                   |       | $          | 351,863    |       | $          | 318,667 |   |
| Actual return on  plan assets                          |       | 41,409     |       | 14,507     |       |
| Plan  participants’ contributions                 |       | 11,870     |       | 12,008     |       |
| Employer  contributions                                |       | 67,188     |       | 68,211     |       |
| Benefit payments                                       |       | (66,025    | )          | (61,530    | )          |
| Fair value of  plan assets at Dec. 31                  |       | $          | 406,305    |       | $          | 351,863 |   |
|                                                   |       |       |       |       |       |
| **Funded  Status at Dec. 31**                          |       |       |       |       |       |
| Funded status                                          |       | $          | (512,388   | )          | $          | (586,309 | ) |
| Current  liabilities                                   |       | (2,211     | )          | —     |       |
| Noncurrent  assets                                     |       | —     |       | 15,736     |       |
| Noncurrent  liabilities                                |       | (510,177   | )          | (150,014   | )          |
| Net amounts  recognized in Consolidated Balance Sheets |       | $          | (512,388   | )          | $          | (134,278 | ) |
|                                                   |       |       |       |       |       |

 

| **NSP-Minnesota Amounts Not Yet Recognized as Components of Net  Periodic Benefit Cost:**       |       |       |       |       |       |
|-------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| Net loss                                                                                        |       | $          | 105,868    |       | $          | 108,414 |   |
| Transition  obligation                                                                          |       | 8,111      |       | 9,457      |       |
| Total                                                                                           |       | $          | 113,979    |       | $          | 117,871 |   |
| ** **                                                                                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| **SFAS  No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in  Rates:** |       |       |       |       |       |
| Regulatory  liabilities                                                                         |       | $          | 108,513    |       | N/A        |   |
| Deferred income  taxes                                                                          |       | 2,233      |       | N/A        |       |
| Net-of-tax AOCI                                                                                 |       | 3,233      |       | N/A        |       |
| Total                                                                                           |       | $          | 113,979    |       | N/A        |   |
|                                                                                            |       |       |       |       |       |
| NSP-Minnesota  accrued benefit liability recorded                                               |       | $          | 184,868    |       | $          | 64,052 |   |

 

| Measurement Date                                            | ** ** | **Dec. 31,  2006** | ** ** | **Dec. 31,  2005** | ** ** |
|------------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|
| ** **                                                       |       |                    |       |                    | ** ** |
| **Significant Assumptions Used to  Measure Benefit Obligations** |       |                    |       |                    |       |
| Discount rate for year-end valuation                             |       | 6.00%                   |       | 5.75%                   |       |

 

45

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Effective Dec. 31, 2004, Xcel Energy raised itsinitial medical trend assumption from 6.5 percent to 9.0 percent and loweredthe ultimate trend assumption from 5.5 percent to 5.0 percent.  The period until the ultimate rate is reachedalso was increased from two years to six years. 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 the assumed health care costtrend rate would have the following effects on NSP-Minnesota:

| (Millions of Dollars)                                                 | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------|------------|------------|------------|
| 1-percent  increase in APBO components at Dec. 31, 2006                         |       | $          | 21.9       |   |
| 1-percent  decrease in APBO components at Dec. 31, 2006                         |       | (18.3      | )          |
| 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       | )          |
|                                                                                 |            |            |            |  |

 

***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 $61 million during 2007.

***Benefit Costs***—The components of net periodic postretirement benefit cost are:
| **(Thousands of Dollars)**                                          | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                                  |       | $          | 6,633      |       | $          | 6,684      |       | $ | 6,100 |   |
| Interest cost                                                                 |       | 52,939     |       | 55,060     |       | 52,604     |       |
| Expected return  on plan assets                                               |       | (26,757    | )          | (25,700    | )          | (23,066    | )          |
| Amortization of  transition obligation                                        |       | 14,444     |       | 14,578     |       | 14,578     |       |
| Amortization of  prior service credit                                         |       | (2,178     | )          | (2,178     | )          | (2,179     | )          |
| Amortization of  net loss                                                     |       | 24,797     |       | 26,246     |       | 21,651     |       |
| Net periodic postretirement benefit cost under SFAS  No. 106                  |       | $          | 69,878     |       | $          | 74,690     |       | $ | 69,688 |   |
|                                                                          |       |       |       |       |       |       |       |
| **NSP-Minnesota**                                                             |       |       |       |       |       |       |       |
| Net periodic  postretirement benefit cost recognized — SFAS No. 106 |       | $          | 17,154     |       | $          | 17,569     |       | $ | 15,936 |   |
|                                                                          |       |       |       |       |       |       |       |
| **Significant  assumptions used to measure costs (income)**                   |       |       |       |       |       |       |       |
| Discount rate                                                                 |       | 5.75       | %          | 6.00       | %          | 6.25       | %          |
| Expected average  long-term rate of return on assets (before tax)        |       | 7.5        | %          | 5.5%-8.5   | %          | 5.5%-8.5   | %          |

 

 

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# **Projected Benefit Payments**

The followingtable lists Xcel Energy’s projected benefit payments for the pension andpostretirement 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** | ** ** |
|--------------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------------------------------------------|------------|--------------------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|
| 2007                                 |       | $                                                 | 217,236    |                                                                                    | $          | 65,355                                                 |       | $                                                                                     | 5,358      |   | $ | 59,997 |   |
| 2008                                 |       | 215,815                                           |       | 67,110                                                                                  |       | 5,755                                                  |       | 61,355                                                                                |       |
| 2009                                 |       | 220,843                                           |       | 68,911                                                                                  |       | 6,115                                                  |       | 62,796                                                                                |       |
| 2010                                 |       | 227,528                                           |       | 70,457                                                                                  |       | 6,430                                                  |       | 64,027                                                                                |       |
| 2011                                 |       | 225,446                                           |       | 71,924                                                                                  |       | 6,665                                                  |       | 65,259                                                                                |       |
| 2012-2016                            |       | 1,195,629                                         |       | 368,206                                                                                 |       | 36,592                                                 |       | 331,614                                                                               |       |
|                                      |            |                                                   |            |                                                                                         |            |                                                        |            |                                                                                       |            |  |  |  |  |

 

**7.**   **Detail of Interest and Other Income — Net**

Interest and other income, net of nonoperatingexpenses, for the years ended Dec. 31 consists of the following:
| **(Thousands of Dollars)**                  | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest income                                       |       | $          | 13,294     |       | $          | 7,805      |       | $ | 8,681 |   |
| Equity income (expense)  in unconsolidated affiliates |       | 1,312      |       | 248        |       | (47        | )          |
| Other nonoperating  income                            |       | 945        |       | 1,171      |       | 604        |       |
| Employee-related  insurance policy expenses           |       | (6,120     | )          | (5,914     | )          | (6,261     | )          |
| Other nonoperating  expense                           |       | —     |       | (346       | )          | (1,888     | )          |
| Total interest and  other income — net           |       | $          | 9,431      |       | $          | 2,964      |       | $ | 1,089 |   |

 

**8.   Derivative Instruments**

In the normalcourse of business, NSP-Minnesota is exposed to a variety of market risks.  Market risk is the potential loss that mayoccur as a result of changes in the market or fair value of a particularinstrument or commodity.  NSP-Minnesotautilizes, in accordance with approved risk management policies, a variety ofderivative instruments to mitigate market risk and to enhance itsoperations.  The use of these derivativeinstruments is discussed in further detail below.

***Utility Commodity Price Risk —***NSP-Minnesota is exposed to commodity price risk in their electric and naturalgas operations.  Commodity price risk ismanaged by entering into both long- and short-term physical purchase and salescontracts for electric capacity, energy and other energy-related products, andfor various fuels used in the generation of electricity 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.

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***Short-Term Wholesale and Commodity Trading Risk —***NSP-Minnesota conducts various short-term wholesale and commodity tradingactivities, including the purchase and sale of electric capacity and energy andother energy-related instruments. NSP-Minnesota’s risk-management policy allows management to conduct themarketing activity within guidelines and limitations as approved by our riskmanagement committee, which is made up of management personnel not directlyinvolved in the activities governed by this policy.

***Interest Rate Risk —***NSP-Minnesota issubject to the risk of fluctuating interest rates in the normal course ofbusiness.  NSP-Minnesota’srisk-management policy allows interest rate risk to be managed through the useof fixed rate debt, floating rate debt and interest rate derivatives such asswaps, caps, collars and put or call options, subject to regulatory approvalwhen required.

# **Types of and Accounting forDerivative Instruments**

NSP-Minnesota usesderivative instruments in connection with its utility commodity price, interestrate, short-term wholesale and commodity trading activities, including forwardcontracts, futures, swaps and options. All derivative instruments not qualifying for the normal purchases andnormal sales exception, as defined by SFAS No. 133, are recorded at fair value.The classification of the fair value for these derivative instruments isdependent on the designation of a qualifying hedging relationship.  The adjustment to fair value of derivativeinstruments not designated in a qualifying hedging relationship is reflected incurrent earnings or as a regulatory balance. This classification is dependent on the applicability of specificregulation.  This includes certaininstruments used to mitigate market risk for NSP-Minnesota and all instrumentsrelated to the commodity trading operations. The designation of a cash flowhedge permits the classification of fair value to be recorded within OtherComprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’sgains or losses to offset the related results of the hedged item in theConsolidated Statements of Income.

SFAS No. 133requires that the hedging relationship be highly effective and that a companyformally designate a hedging relationship to apply hedge accounting.  NSP-Minnesota formally documents hedgingrelationships, including, among other factors, the identification of thehedging instrument and the hedged transaction, as well as the risk-managementobjectives and strategies for undertaking the hedged transaction.  NSP-Minnesota also formally assesses, both atinception and on an ongoing basis, if required, whether the derivativeinstruments being used are highly effective in offsetting changes in either thefair value or cash flows of the hedged items.

Gains or losses onhedging transactions for the sales of energy or energy-related products areprimarily recorded as a component of revenue; hedging transactions for fuelused in energy generation are recorded as a component of fuel costs;  hedging transactions for natural gaspurchased for resale are recorded as a component of natural gas costs; andinterest rate hedging transactions are recorded as a component of interestexpense.  NSP-Minnesota is allowed torecover in natural gas rates the costs of certain financial instrumentsacquired to reduce commodity cost volatility.

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

# **Cash Flow Hedges**

The effectiveportion of the change in the fair value of a derivative instrument qualifyingas a cash flow hedge is recorded as a component of Other Comprehensive Incomeor deferred as a regulatory asset or liability, and reclassified into earningsin the same period or periods during which the hedged transaction affectsearnings.  The ineffective portion of aderivative instrument’s change in fair value is recognized in current earnings.

***Commodity Cash Flow Hedges******—***NSP-Minnesotaenters into derivative instruments to manage variability of future cash flowsfrom changes in commodity prices.  Thesederivative instruments are designated as cash flow hedges for accountingpurposes.  At Dec. 31, 2006,NSP-Minnesota had various commodity-related contracts classified as cash flowhedges extending through November 2007. The fair value of these cash flow hedges is recorded in either OtherComprehensive Income or deferred as a regulatory asset or liability.  This classification is based on theregulatory recovery mechanism in place. Amounts deferred in these accounts are recorded in earnings as thehedged purchase or sales transaction is settled.  This could include the purchase or sale ofenergy or energy-related products, the use of natural gas to generate electricenergy or natural gas purchased for resale.

48

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As of Dec. 31,2006, NSP-Minnesota had no amounts in Accumulated Other Comprehensive Incomethat is expected to be recognized in earnings during the next 12 months as thehedged transactions settle.

NSP-Minnesota hadimmaterial ineffectiveness related to commodity cash flow hedges during theyear ended Dec. 31, 2006 and no ineffectiveness during the year ended Dec. 31,2005.

### ***Interest Rate Cash Flow Hedges*** — NSP-Minnesota enters into various instruments that effectively fix theinterest payments on certain floating rate debt obligations or effectively fixthe yield or price on a specified benchmark interest rate for a specific period.  These derivative instruments are designatedas cash flow hedges for accounting purposes.

As ofDec. 31, 2006, NSP-Minnesota had net gains related to interest rate swapsof approximately $0.3 million in Accumulated Other Comprehensive Income that itexpects to recognize in earnings during the next 12 months.

***FinancialImpact of Qualifying Cash Flow Hedges*** — The impact ofqualifying cash flow hedges on NSP-Minnesota’s Accumulated Other ComprehensiveIncome, included in the Consolidated Statements of Stockholder’s Equity, isdetailed in the following table:

| (Millions of Dollars)                                                           | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------------------------|------------|------------|------------|
| 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 gains related to derivatives accounted for as hedges       |       | —     |       |
| After-tax net realized  gains on derivative transactions reclassified into earnings  |       | —     |       |
| Accumulated other  comprehensive income related to hedges at Dec. 31, 2005           |       | $          | —     |   |
|                                                                                 |       |       |       |
| After-tax net  unrealized gains related to derivatives accounted for as hedges       |       | 9.6        |       |
| After-tax net realized  gains on derivative transactions reclassified into earnings  |       | (0.2       | )          |
| Accumulated other comprehensive income related to hedges at Dec. 31,  2006           |       | $          | 9.4        |   |

 

**NormalPurchases or Normal Sales Contracts**

NSP-Minnesotaenters into contracts for the purchase and sale of commodities for use in itsbusiness operations.  SFAS No. 133requires a company to evaluate these contracts to determine whether thecontracts are derivatives.  Certaincontracts that meet the definition of a derivative may be exempted from SFASNo. 133 as normal purchases or normal sales.

NSP-Minnesotaevaluates all of its contracts when such contracts are entered to determine ifthey are derivatives 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.

In 2003, as a result of FASB Statement 133Implementation Issue No. C20, NSP-Minnesota began recording several long-termpower purchase agreements at fair value due to accounting requirements relatedto underlying price adjustments.  Asthese purchases are recovered through normal regulatory recovery mechanisms inthe respective jurisdictions, the changes in fair value for these contractswere offset by regulatory assets and liabilities.  During the first quarter of 2006,NSP-Minnesota qualified these contracts under the normal purchaseexception.  Based on this qualification,the contracts will no longer be adjusted to fair value and the previouscarrying value of these contracts will be amortized over the remaining contractlives along with the offsetting regulatory balances.

Normal purchasesand normal sales contracts are accounted for as executory contracts.

***Commodity Trading Instruments***- Thefair value of commodity trading contracts as of Dec. 31, 2006 and 2005 was$(1.3) million and $1.9 million, respectively.

***Hedging Contracts***- The fair value ofqualifying cash flow hedges at Dec. 31, 2006 and 2005 was $14.7 million and$2.3 million, respectively.

For a furtherdiscussion of other financial instruments at NSP-Minnesota, see Note 9 to theConsolidated Financial Statements.

49

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**9.   Financial Instruments**

The estimated Dec. 31 fair values of NSP-Minnesota’sfinancial instruments are as follows:
| ** **                                 | ** ** | **2006**                   | ** ** | **2005**            | ** ** |
|--------------------------------------------|------------|----------------------------|------------|---------------------|------------|
| **(Thousands of Dollars)**            | ** ** | **Carrying   Amount** | ** ** | **Fair Value** | ** ** | **Carrying   Amount** | ** ** | **Fair Value** | ** ** |
| Nuclear  decommissioning fund              |       | $                          | 1,200,688  |                | $          | 1,200,688 |   | $ | 1,047,592 |   | $ | 1,047,592 |   |
| Other  investments                         |       | $                          | 10,415     |                | $          | 10,415 |   | $ | 2,544 |   | $ | 2,544 |   |
| Long-term debt,  including current portion |       | $                          | 2,299,228  |                | $          | 2,466,465 |   | $ | 2,360,373 |   | $ | 2,549,257 |   |

 

The fair value ofcash and cash equivalents, notes and accounts receivable and notes and accountspayable are not materially different from their carrying amounts.  The fair value of NSP-Minnesota’s debtsecurities in an external nuclear decommissioning fund and other investmentsare estimated based on quoted market prices for those or similar investments.The fair value of NSP-Minnesota’s long-term debt is estimated based on thequoted market prices for the same or similar issues, or the current rates fordebt of the same remaining maturities and credit quality.

The fair value estimates presented are based oninformation available to management as of Dec. 31, 2006 and 2005. These fairvalue estimates have not been comprehensively revalued for purposes of theseConsolidated Financial Statements since that date, and current estimates offair values may differ significantly.

The following tables provide the externaldecommissioning fund’s approximate gains, losses and proceeds from the sale ofsecurities for the years ended Dec. 31:
| **(Thousands of Dollars)** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Realized gains                       |       | $        | 310,066    |     | $          | 8,967    |       | $ | 16,578 |   |
| Realized losses                      |       | $        | 32,412     |     | $          | 8,990    |       | $ | 20,180 |   |
| Proceeds from sale of  securities    |       | $        | 1,240,034  |     | $          | 489,697  |       | $ | 223,135 |   |

 
| **(Thousands of Dollars)** | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|
| Unrealized gains                     |       | $        | 41,355     |     | $          | 253,991 |   |
| Unrealized losses                    |       | $        | —     |     | $          | 10,558 |   |

#  

# **Letters of Credit**

NSP-Minnesota uses letters of credit, generally withterms of one year, to provide financial guarantees for certain operatingobligations.  At Dec. 31, 2006, there was$35.3 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fairvalue and are subject to fees determined in the marketplace.

**10. Rate Matters**

# **Pending and RecentlyConcluded Regulatory Proceedings - FERC**

***MISO Operations —***NSP-Minnesota is amember of the MISO. The MISO is a FERC-regulated RTO that provides regionaltransmission tariff administration services for electric transmission systems,including those of NSP-Minnesota.

MISOalso operates a regional wholesale energy market using locational marginalpricing and financial congestion relief which is also known as a Day 2 market.NSP-Minnesota recovers most MISO regional market charges through the FCA.  For further discussion, see Pending andRecently Concluded Regulatory Proceedings******— MPUC.

Within MISO, anindependent market monitor (IMM) reviews market bids and prices to identify anyunusual activity.  NSP-Minnesota andother market participants continue to work with MISO, the IMM and the FERC toresolve Day 2 market implementation issues such as dispatch methods andsettlement calculation details.

***MISO Long-Term Transmission Pricing —***InOctober 2005, MISO filed a proposed change to its TEMT to regionalize futurecost recovery of certain high voltage (345 KV) transmission projects to be constructedfor reliability improvements.  Theproposal, called the Regional Expansion Criteria Benefits phase 1 (RECB I)proposal, would recover 20 percent of eligible transmission costs from alltransmission service customers in the MISO 15 state region, with 80 percentrecovered on a sub-regional basis.  Theproposal would exclude certain projects that had been planned prior to theOctober 2005 filing, and would require new generators to fund 50 percent of thecost of network upgrades associated with their interconnection.  In Feb. 2006, the FERC generally approved theRECB I proposal, but set the 20 percent limitation on regionalization for

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additionalproceedings.  Various parties filedrequests for rehearing.  On Nov. 29,2006, the FERC issued an order on rehearing upholding the February 2006 orderand approving the 20 percent limitation.

Inaddition, in October 2006, MISO filed additional changes to its TEMT toregionalize future recovery of certain transmission projects (230 KV and above)constructed for “economic” reasons (e.g., to provide access to lower costgeneration supplies).  The filing, knownas RECB II, would provide regional recovery of 20 percent of the project costsand sub-regional recovery of 80 percent, based on a benefits analysis.  MISO proposed that the RECB II tariff beeffective April 1, 2007.  Initialcomments were filed at FERC on Dec. 22, 2006. The date the FERC will take initial action is not known.

Transmissionservice rates in the MISO region presently use a rate design, in which thetransmission cost depends on the location of the load being served.  Costs of existing transmission facilities arenot regionalized.  MISO is required tofile a replacement rate methodology in August 2007, to be effective Feb. 1,2008.  It is possible MISO will proposeto regionalize the recovery of the costs of existing transmissionfacilities.  Proposals to regionalizetransmission costs could shift the costs of NSP-Minnesota transmissioninvestments to other MISO transmission service customers, but would also shiftthe costs of transmission investments in other parts of MISO to NSP-Minnesota.

***MISO/PJM SECA —***On Nov. 18, 2004,the FERC issued an order approving portions of a plan providing for continueduse of location-based rates for the MISO/PJM region, but rejecting proposedtransition payments to compensate transmission owners for reductions intransmission revenues.  The FERC insteadordered the MISO and PJM to each file a Seams Elimination Charge Adjustment(SECA) transition mechanism.  The replacementcompliance filings were effective Dec. 1, 2004, subject to refund.

The competing SECAcompliance proposals were the subject of litigated hearings at the FERC.  Certain parties proposed a regional averageSECA charge, which could shift costs to NSP-Minnesota and NSP-Wisconsin.  On Aug. 10, 2006, the ALJ in the case issuedan initial decision recommending that all the SECA compliance filings berejected and recommending adoption of a regional SECA, which could shiftapproximately $13 million in charges to NSP-Minnesota and NSP-Wisconsin.  Xcel Energy, through the MISO transmissionowners, filed exceptions to the ALJ initial decision, arguing the decisiondirectly violates the 2004 FERC orders. In addition, the MISO transmission owners have executed settlements withseveral parties in the litigation.  Thesettlement resolves specific claims and would limit any regionalization tounresolved claims.  Final FERC action isexpected in the SECA litigation in 2007.

***Revenue Sufficiency Guarantee Charges —***OnApril 25, 2006, the FERC issued an order determining that MISO had incorrectlyapplied its TEMT regarding the application of the revenue sufficiency guarantee(RSG) charge to certain transactions. The FERC ordered MISO to resettle allaffected transactions retroactive to April 1, 2005. The RSG charges arecollected from certain MISO customers and paid to others. Based on the FERCorder, NSP-Minnesota could be required to make net payments to MISO. On Oct.26, 2006, the FERC issued an order granting rehearing in part and reversed theprior ruling requiring MISO to issue retroactive refunds and ordered MISO toimplement prospective changes.  In lateNovember 2006, however, certain parties filed further requests for rehearingchallenging the reversal regarding refunds. The date of a final FERC decision is unknown, and one appeal has beenfiled.  Xcel Energy reserved $6.1 millionin response to the April 25, 2006, FERC order.

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

***Electric Rate Case***—In November 2005, NSP-Minnesota requested an electric rate increase of$168 million or 8.05 percent. This increase was based on a requested 11 percentreturn on common equity, a projected common equity to total capitalizationratio of 51.7 percent and a projected electric rate base of $3.2 billion. OnDec. 15, 2005, the MPUC authorized an interim rate increase of $147million, subject to refund, which became effective on Jan. 1, 2006.

OnSept. 1, 2006, the MPUC issued a written order granting an electric revenueincrease of approximately $131 million for 2006 based on an authorized returnon equity of 10.54 percent. The scheduled rate increase will be reduced in 2007to $115 million to reflect the return of Flint Hills Resources, a largeindustrial customer, to the NSP-Minnesota system.  The MPUC approved the wholesale marginsettlement in which NSP-Minnesota returns most margins from unused generatingcapacity back to customers through the FCA mechanism.  NSP-Minnesota is allowed to earn an incentiveon sales related to ancillary service obligations.  The MPUC Order became effective in November2006, and final rates were implemented on February 1, 2007.  A citizen intervenor has appealed the MPUC’sdecision.

***Natural Gas Rate Case***-On Nov. 9, 2006, NSP-Minnesota filed a request with the MPUC to increaseMinnesota natural gas rates by $18.5 million annually, which represents anincrease of 2.4 percent.  The request wasbased on 11.0 percent ROE, a projected equity ratio of 51.98 percent and anatural gas rate base of $439 million. Interim rates, subject to refund, were set at a $15.9 million annualincrease and went into effect on Jan. 8, 2007. A final decision is expected in the third quarter of 2007.

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***North Dakota Gas Rate Case*** — On Dec.15, 2006, NSP-Minnesota filed a notice of rate change with the NDPSC requestingan increase of natural gas distribution rates of $2.8 million annually, or 3percent.  In February 2007, the NDPSCapproved interim rates of $2.2 million. Interim rates would remain in effect until the NDPSC makes its finaldetermination in the summer of 2007. Final natural gas rates will be put into place after the decision.

***Renewable Transmission Cost Recovery****—*Since December 2004, NSP-Minnesota hasrecovered certain transmission costs related to wind generation projectsthrough a RCR rider.  In November 2006,the MPUC approved the replacement of the RCR rider with a TCR rider pursuant to2005 legislation.  The TCR mechanismwould allow recovery of incremental transmission investments between ratecases.  On Oct. 27, 2006, NSP-Minnesotafiled for approval of recovery of $14.8 million in 2007 revenue requirementsunder the TCR tariff.  Final MPUC actionis expected later in the first quarter of 2007. The RCR rate factors will remain in effect until the TCR factors areimplemented.

***MISO Day 2 Market Cost Recovery***—On Dec. 18, 2004, NSP-Minnesota filed with the MPUC a petition to seekrecovery of the Minnesota jurisdictional portion of all net costs associatedwith the implementation of the MISO Day 2 market through its FCA.  A Dec. 21, 2006 MPUC order ruled that allMISO costs, except Schedule 16 and 17, can be recovered through the FCA.  Schedules 16 and 17 costs were recoveredthrough the FCA in 2005. However, the MPUC’s Dec. 21 order requires NSP-Minnesotato refund these costs to customers through the FCA in equal monthlyinstallments beginning March 2007.  Italso provided the opportunity to defer 100 percent of the 2005 costs for athree-year period before starting the amortization.  A refund liability was recorded for $4.4million with an offsetting regulatory asset.

InMarch 2005, NSP-Minnesota filed petitions similar to theDecember 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 throughthe FCA beginning April 1, 2005, but conditioned the relief as beingsubject to refund until the merits of the case are determined.  Since April 1, 2005, NSP-Minnesota hascollected approximately $28 million of MISO Day 2 charges through its NorthDakota FCA.

**11. Commitments and ContingentLiabilities**

***Capital Commitments —***The estimatedcost, as of Dec. 31, 2006, of the capital expenditure programs and othercapital requirements of NSP-Minnesota was approximately $995 million in 2007,$1.1 billion in 2008 and $1.0 billion in 2009. NSP-Minnesota’s capital forecast includes the following major projects.

*CAPX 2020  **—***InJune 2006, CapX 2020, an alliance of electric cooperatives, municipals andinvestor-owned utilities in the upper Midwest, including Xcel Energy, announcedthat it had identified three groups of transmission projects that proposed tobe complete by 2020**. **Group 1 project investments areexpected to total approximately $1.3 billion, with major construction targetedto begin in 2009 or 2010 and ending three or four years later. Xcel Energy’s investmentis expected to be approximately $700 million. Approximately 75 percent of thecapital expenditures and return on investment for transmission projects areexpected to be recovered under an NSP-Minnesota transmission cost recoverytariff rider mechanism authorized by Minnesota legislation and pending MPUCapproval. Similar transmission cost recovery mechanisms have been proposed inNorth Dakota and South Dakota.

*NuclearCapacity Increases and Life Extension**—***InAugust 2004, NSP-Minnesota announced plans to pursue 20-year licenserenewals for the Monticello and Prairie Island nuclear plants, whose licenseswill expire between 2010 and 2014. License renewal applications for Monticellowere submitted to the NRC and the MPUC in early 2005. License renewal wasapproved by the NRC in November 2006, and the MPUC issued its approval inOctober 2006 allowing additional spent fuel storage. The MPUC stayed theorder until June 2007, following the Minnesota legislative session.Similar applications will be submitted for Prairie Island in 2008, withapproval expected in 2010.

At the direction of theMPUC, NSP-Minnesota is pursuing capacity increases of all three units that willtotal approximately 250 MW, to be implemented, if approved, between 2009 and2015. The life extension and a capacity increase for Prairie Island Unit 2 iscontingent on replacement of Unit 2’s original steam generators, currentlyplanned for replacement during the refueling outage in 2013. Total capitalinvestment for these activities is estimated to be approximately $1 billionbetween 2006 and 2015. Xcel Energy plans to seek approval for an alternativerecovery mechanism from customers of its nuclear costs.  It is NSP-Minnesota’s plan to submit the certificateof need for Monticello in the second quarter of 2007 and the certificate ofneed for Prairie Island in the third quarter of 2007.

*MERP Project  **—***InDecember 2003, the MPUC approved NSP-Minnesota’s MERP proposal to converttwo coal-fueled electric generating plants to natural gas, and to installadvanced pollution control equipment at a third coal-fired plant.  These improvements are expected tosignificantly reduce air emissions from these facilities, while increasing thecapacity at system peak by 300 MW.  Majorconstruction for the MERP project began in 2005, and these projects areexpected to come on line between 2007 and 2009. The cumulative investment is approximately $1 billion.  The MPUC has approved a more current 

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recovery of the financing costs related to theMERP.  The in-service plant costs,including the financing costs during construction, are recovered from customersthrough a MERP rider, which was effective Jan. 1, 2006.

*ShercoProject  **—***NSP-Minnesota has proposed a $905million upgrade at the Sherburne County (Sherco) coal-fired power plant.  The project will increase capacity and reduceemissions.  The MPUC is expected to ruleon the project in 2008.  If approved,construction would start in late 2008 and be completed in 2012.

*Wind Generation**—***NSP-Minnesota plans to invest $205 million toacquire 100-MW of wind generation.  Theproject would be eligible for rider recovery in Minnesota.  The project requires approval by the MPUC.

The capital expenditure programs of NSP-Minnesota aresubject to continuing review and modification. Actual utility constructionexpenditures may vary from the estimates due to changes in electric and naturalgas projected load growth regulatory decisions, the desired reserve margin andthe availability of purchased power, as well as alternative plans for meetingNSP-Minnesota’s long-term energy needs. In addition, NSP-Minnesota’s ongoingevaluation of compliance with future requirements to install emission-controlequipment, and merger, acquisition and divestiture opportunities to supportcorporate strategies may impact actual capital requirements.

***Leases*****— NSP-Minnesota leases a variety ofequipment and facilities used in the normal course of business.  The leases are accounted for as operatingleases.  Rental expense under operatinglease obligations was approximately $35.7 million, $26.1 million and $27.3million for 2006, 2005 and 2004, respectively.

Future commitments under noncancellable operatingleases with terms in excess of one year are:
| **(Millions of Dollars)** | ** ** | ** ** | ** ** |
|-------------------------------------|------------|------------|------------|
| 2007                                |       | $          | 36.6       |   |
| 2008                                |       | $          | 35.0       |   |
| 2009                                |       | $          | 35.2       |   |
| 2010                                |       | $          | 33.9       |   |
| 2011                                |       | $          | 32.8       |   |
| Thereafter                          |       | $          | 480.1      |   |

 

***Fuel Contracts*****— NSP-Minnesota has contracts providingfor the purchase and delivery of a significant portion of its current coal,nuclear fuel and natural gas requirements. These contracts expire in variousyears between 2007 and 2027. In addition, NSP-Minnesota may be required to payadditional amounts depending on actual quantities shipped under theseagreements. The potential risk of loss, in the form of increased costs frommarket price changes in fuel, is mitigated through the cost-rate adjustmentmechanisms, which provide for pass through of most fuel, storage andtransportation costs.

The estimatedminimum purchases for NSP-Minnesota under these contracts as of Dec. 31, 2006,is as follows:

| **Coal**                            |   | **Nuclear Fuel** |   | **Natural Gas  Supply** |   | **Gas Storage &  Transportation** |
|-------------------------------------|--------|-----------------------|--------|------------------------------|--------|-------------------------------------------------|
| **(Millions of Dollars)** |
| $771                                |   | $387                  |   | $191                         |   | $659                                            |

 

***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 indices. However, the effects of these price adjustments are mitigated throughcost-of-energy rate adjustment mechanisms.

 

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At Dec. 31, 2006, the estimated future payments forcapacity that NSP-Minnesota is obligated to purchase, subject to availability,were as follows (Millions of Dollars):

| 2007                 |   | $       | 103.9   |   |
|----------------------|--------|---------|---------|--------|
| 2008                 |   | 120.0   |    |
| 2009                 |   | 129.7   |    |
| 2010                 |   | 131.8   |    |
| 2011                 |   | 130.9   |    |
| 2012 and  thereafter |   | 1,002.2 |    |
| Total*               |   | $       | 1,618.5 |   |

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* Includes amountsallocated to NSP-Wisconsin through intercompany charges.

**EnvironmentalContingencies**

NSP-Minnesota hasbeen, or is currently, involved with the cleanup of contamination from certainhazardous substances at several sites. In many situations, NSP-Minnesotabelieves it will recover some portion of these costs through insurance 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 theextent any costs are not recovered through the options listed above,NSP-Minnesota would be required to recognize an expense.

***Site Remediation****—*NSP-Minnesota must pay all or a portionof the 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:

·              thesite of a former MGP operated by NSP-Minnesota’s subsidiaries or predecessors;and

·              thirdparty sites, such as landfills, to which NSP-Minnesota is alleged to be apotentially responsible party (PRP) that sent hazardous materials and wastes.

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

To estimate thecost to remediate these sites, assumptions are made when facts are not fullyknown. For instance, assumptions may be made about the nature and extent ofsite 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.

Estimates arerevised as facts become known.  At Dec.31, 2006, the liability for the cost of these remediating sites was estimatedto be $1.1 million, of which $0.3 million was considered to be a currentliability.  Some of the cost ofremediation may be recovered from:

·              insurancecoverage;

·              otherparties that have contributed to the contamination; and

·              customers.

Neither the totalremediation cost nor the final method of cost allocation among all PRPs of theunremediated sites has been determined.  Estimateshave been recorded for NSP-Minnesota’s future costs for these sites.

***Third Party and Other Environmental Site Remediation***

***Asbestos Removal****—*Some of NSP-Minnesota’s facilitiescontain asbestos. Most asbestos will remain undisturbed until the facilitiesthat contain it are demolished or removed. NSP-Minnesota has recorded an estimate for final removal of the asbestosas an asset retirement obligation.  Seeadditional discussion of asset retirement obligations below.  It may be necessary to remove some asbestosto perform maintenance or make improvements to other equipment. The cost ofremoving

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asbestos as partof other work is immaterial and is recorded as incurred as operating expensesfor maintenance projects, capital expenditures for construction projects orremoval costs for demolition projects.

***Other Environmental Requirements***

***Clean Air Interstate Rule***— In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR)to further regulate SO2 andnitrogen oxide (NOx) emissions.  Theobjective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota.  CAIR addresses the transportation of fineparticulates, ozone and emission precursors to nonattainment downwindstates.  CAIR has a two-phase complianceschedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for bothemissions.  Under CAIR, each affectedstate will be allocated an emissions budget for SO2 and NOX that willresult in significant emission reductions. It will be based on stringent emission controls and forms the basis fora cap-and-trade program.   State emissionbudgets or caps decline over time. States can choose to implement an emissions reduction program based onthe EPA’s proposed model program, or they can propose another method, which theEPA would need to approve.

Minnesotaand Wisconsin will be included in CAIR, and NSP- Minnesota has generatingfacilities that will be impacted. Preliminary estimates of capital expenditures associated with compliancewith CAIR for the NSP System range from $30 million to $40 million.

On June 13, 2006,the MPCA issued a draft rule for implementing the CAIR in Minnesota, whichfurther regulates SO2 and NOx emissions. This proposal would requiremore stringent emission reductions than the federal CAIR program, resulting inadditional implementation costs. The MPCA has stated publicly that it isrevising its proposal such that the federal CAIR program will be implementedfor 2009 and that the MPCA is considering a rulemaking process to require morestringent emission reductions than the federal CAIR program for subsequentyears. Approval to commence this rulemaking is expected in 2007.

WhileNSP-Minnesota expects to comply with the new rules through a combinationof additional capital investments in emission controls at various facilitiesand purchases of emission allowances, it is continuing to review thealternatives.  Xcel Energy believes thecost of any required capital investment or allowance purchases will be recoverablefrom customers.

***Clean Air Mercury Rule***— In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), whichregulates mercury emissions from power plants for the first time.  The EPA’s CAMR  uses a nationalcap-and-trade system, where compliance may be achieved by either adding mercurycontrols or purchasing allowances or a combination of both and is designed toachieve a 70 percent reduction in mercury emissions.  It affects all coal- and oil-fired generatingunits across the country that are greater than 25 MW.  Compliance with this rule occurs in twophases, 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.

NSP-Minnesotacontinues to evaluate the strategy for complying with CAMR. NSP-Minnesota cancomply through capital investments in emission controls or purchase of emission“allowances” from other utilities making reductions on their systems.Estimating the cost of compliance with CAMR is difficult because technologiesspecifically designed for control of mercury are in the early stages ofdevelopment and there is no established market on which to base the cost ofmercury allowances.  NSP-Minnesota’spreliminary analysis for phase I compliance suggests capital costs ofapproximately $10.3 million for the mercury control equipment and continuousmonitoring equipment and increased operating and maintenance expenses ofapproximately $4.8 million, beginning in 2010. These costs are included in theestimated costs of compliance with the Minnesota Mercury Legislation describedbelow.  Additional costs will be incurredto meet phase II requirements in 2018.

***Minnesota Mercury Legislation***— On May 2, 2006, the Minnesota Legislature enacted the Mercury EmissionsReduction Act of 2006 (Act) providing a process for plans, implementation andcost recovery for utility efforts to curb mercury emissions at certain powerplants. For Xcel Energy, the Act covers units at the A. S. King and SherburneCounty (Sherco) generating facilities. Under the Act, Xcel Energy must install,maintain and operate continuous mercury emission monitoring systems or othermonitoring methods approved by the MPCA at these units by July 1, 2007. Theinformation obtained will be used to establish a baseline from which to measuremercury emission reductions.  Mercuryemission reduction plans must be filed by utilities by Dec. 31, 2007 (dryscrubbed units) and Dec. 31, 2009 (wet scrubbed units) that propose toimplement technologies most likely to reduce emissions by 90 percent.  Implementation would occur by Dec. 31, 2009for one of the dry scrubbed units, Dec. 31, 2010 for the remaining dry scrubbedunit and Dec. 31, 2014 for wet scrubbed units. The cost of controls will bedetermined as part of the engineering analysis portion of the mercury reductionplans and is  currently estimated at$10.3 million for the mercury control and continuous monitoring equipment andincreased operating and 

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maintenanceexpenses of approximately $11.3 million, beginning in 2010.  Utilities subject to the Act may also submitplans to address non-mercury pollutants subject to federal and state statutesand regulations, which became effective after Dec. 31, 2004. Cost recoveryprovisions of the Act also apply to these other environmental initiatives. OnSept. 15, 2006, NSP-Minnesota filed a request with the MPUC for deferredaccounting of up to $6.3 million of certain environmental improvement coststhat are expected to be recoverable under the Act.  On Jan. 11, 2007, the MPUC approved thisrequest for deferred accounting with a cap of $6.3 million.

***Regional Haze Rules ***— OnJune 15, 2005, the EPA finalized amendments to the July 1999 regionalhaze rules. These amendments apply to the provisions of the regional hazerule that require emission controls, known as best available retrofittechnology (BART), for industrial facilities emitting air pollutants thatreduce visibility by causing or contributing to regional haze.

The EPA requires statesto develop implementation plans to comply with BART by December 2007.  NSP-Minnesota submitted its BART alternativesanalysis for Sherco units 1 and 2 on Oct. 26, 2006. The expected cost associatedwith the range of alternatives for additional emission controls for SO2 and NOx is a capital investment of $7 millionto $617 million. NSP- Minnesota supports the alternative with the associatedcost estimate of $7 million; however, NSP-Minnesota has not yet received aresponse from the Minnesota Pollution Control Agency (MPCA) concerning itspreferred alternative. NSP-Minnesota expects that the costs of any requiredcapital investment will be recoverable from customers.  All BART issues are addressed by thevoluntary capacity upgrades noted below.

***Voluntary Capacity Upgrade and EmissionsReduction Filing*** — On Jan. 2, 2007, NSP-Minnesota made afiling to the MPUC for a major emissions reduction project at the Sherco Units1, 2 and 3 to reduce emissions and expand capacity by installing NOx controls(low NOx burners, overfire air and Selective Catalytic Reduction), installing mercury control systems,replacing the wet scrubbers on units 1 and 2 with semi-dry scrubbers,retrofitting different sections of the turbines on all three units, replacinggenerators and other associated equipment on all three units, and installingadditional cooling capacity. The projected cost of this project isapproximately $905 million and encompasses the BART capital investment of $7million to $617 million noted above. NSP-Minnesota’s investments are subject to MPUC approval of a costrecovery mechanism.

***Federal Clean Water Act***—The federalClean Water Act requires the EPA to regulate cooling water intakestructures  to assure that thesestructures reflect the “best technology available” for minimizing adverseenvironmental impacts. In July 2004, the EPA published phase II of therule, which applies to existing cooling water intakes at steam-electric powerplants. Several lawsuits were filed against the EPA in the United States Courtof Appeals for the Second Circuit challenging the phase II rulemaking.  On Jan. 25, 2007, the court issued itsdecision and remanded virtually every aspect of the rule to the EPA forreconsideration. It is unclear whether the EPA will stay the deadlines in therule until the remanded rulemaking is finished. As a result, the rule’s compliance requirements and associated deadlinesare currently unknown. It is not possible to provide an accurate estimate ofthe overall cost of this rulemaking at this time due to the many uncertaintiesinvolved.

# **AssetRetirement Obligations**

NSP-Minnesotarecords future plant removal obligations as a liability at fair value with acorresponding increase to the carrying values of the related long-lived assetsin accordance with SFAS No. 143 — “Accounting for Asset RetirementObligations” (SFAS No. 143). This liability will be increased over time byapplying the interest method of accretion to the liability, and the capitalizedcosts will be depreciated over the useful life of the related long-livedassets.  The recording of the obligationfor regulated operations has no income statement impact due to the deferral ofthe adjustments through the establishment of a regulatory asset pursuant toSFAS No. 71.

***Recorded ARO —***ARO’shave been recorded for plant related to nuclear production, steam production,electric transmission and distribution, gas distribution and officebuildings.  The steam productionobligation includes asbestos, ash containment facilities anddecommissioning.  The asbestosrecognition associated with the steam production includes certain plants atNSP-Minnesota.   NSP-Minnesota alsorecorded 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-Minnesota recognized an ARO for the retirementcosts of natural gas mains and for the removal of electric transmission anddistribution equipment.  The electrictransmission and distribution ARO consists of many small potential obligationsassociated with polychlorinated 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 using an average service life.

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For the nuclear assets, the ARO associated with thedecommissioning of two NSP-Minnesota nuclear generating plants, Monticello andPrairie 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.

If NSP-Minnesota hadimplemented FIN No. 47 at Jan. 1, 2005, the liability for asset retirementobligations would have increased by $39.4 million.

A reconciliation of the beginning and ending aggregatecarrying amounts of NSP-Minnesota’s asset retirement obligations is shown inthe table below for the 12 months ended Dec. 31, 2006 and Dec. 31, 2005,respectively:
| **(Thousands of Dollars)**    | ** ** | **Beginning  Balance  Jan. 1, 2006** | ** ** | **Liabilities  Recognized** | ** ** | **Liabilities  Settled** | ** ** | **Accretion** | ** ** | **Revisions  To Prior  Estimates** | ** ** | **Ending  Balance  Dec. 31, 2006** | ** ** |
|-----------------------------------------|------------|------------------------------------------------|------------|-----------------------------|------------|--------------------------|------------|---------------|------------|-----------------------------------------|------------|----------------------------------------------|------------|
| ** **                              | ** ** | ** **                                     | ** ** | ** **                  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                              | ** ** | ** **                                   | ** ** |
| **Electric Utility Plant:**             | ** ** | ** **                                     | ** ** | ** **                  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                              | ** ** | ** **                                   | ** ** |
| Steam production  asbestos              |       | $                                              | 21,719     |                        | $          | —                   |       | $             | —     |                                    | $          | 1,229                                        |       | $ | (779 | ) | $ | 22,169 |   |
| Steam production ash  containment       |       | 16,887                                         |       | —                      |       | —                   |       | 933           |       | (657                                    | )          | 17,163                                       |       |
| Steam production  retirement            |       | 3,152                                          |       | —                      |       | (3,309                   | )          | 157           |       | —                                  |       | —                                       |       |
| Nuclear production  decommissioning     |       | 1,184,968                                      |       | —                      |       | —                   |       | 71,795        |       | —                                  |       | 1,256,763                                    |       |
| Electric transmission  and distribution |       | 1,100                                          |       | —                      |       | —                   |       | 29            |       | (189                                    | )          | 940                                          |       |
| **Gas Utility Plant:**                  |       |                                           |       |                        |       |                     |       |          |       |                                    |       |                                         |       |
| Gas transmission and  distribution      |       | 12,059                                         |       | —                      |       | —                   |       | 299           |       | 20                                      |       | 12,378                                       |       |
| **Common Utility and Other  Property:** |       |                                           |       |                        |       |                     |       |          |       |                                    |       |                                         |       |
| Common general plant  asbestos          |       | 3,034                                          |       | —                      |       |                     |       | 162           |       | (1,338                                  | )          | 1,858                                        |       |
| Total liability                         |       | $                                              | 1,242,919  |                        | $          | —                   |       | $             | (3,309     | )                                       | $          | 74,604                                       |       | $ | (2,943 | ) | $ | 1,311,271 |   |

 
| **(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 |   |

 

The fair value of NSP-Minnesota assets legallyrestricted for purposes of settling the nuclear asset retirement obligations is$1.2 billion as of Dec. 31, 2006, including external nuclear decommissioninginvestment funds and internally funded amounts.

***Removal Costs*****— NSP-Minnesota accrues an obligation forplant removal costs for 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 of

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estimated future removal costs are consideredRegulatory Liabilities under SFAS No. 71. Removal costs as of Dec. 31, 2006 andDec. 31, 2005 were $355 million and $334 million, respectively.

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

NSP-Minnesotapurchases insurance for property damage and site decontamination cleanup costsfrom Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.1billion for 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 $16.1 million for business interruption insurance and $26.1million for property damage insurance if losses exceed accumulated reservefunds.

**Legal Contingencies**

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

***Metropolitan Airports Commission vs. Northern States PowerCompany****—*On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed acomplaint in Minnesota state district court in Hennepin County asserting thatNSP-Minnesota is required to relocate facilities on MAC property at the expenseof NSP-Minnesota.  MAC claims thatapproximately $7.1 million charged by NSP-Minnesota over the past five yearsfor relocation costs should be repaid. Both parties asserted cross motions forpartial summary judgment on a separate and less significant claim concerninglegal obligations associated with rent payments allegedly due and owing byNSP-Minnesota to MAC for the use of its property for a substation that servesMAC. A hearing regarding these cross motions was held in January 2006. InFebruary 2006, the court granted MAC’s motion on this issue, finding that therewas a valid lease and that the past course of action between the partiesrequired NSP-Minnesota to continue making rent payments. NSP-Minnesota had maderent payments for 45 years. Depositions of key witnesses took place inFebruary, March and April of 2006. The parties entered into meaningfulsettlement negotiations in May 2006, and in August 2006 reached an oralsettlement of the dispute.  The partiesare negotiating over the final form of the settlement documents and it isexpected that the action will be formally dismissed in the near future.

***Siewert  vs. XcelEnergy***— Plaintiffs, the owners and operators of aMinnesota dairy farm, brought an action against NSP-Minnesota allegingnegligence in the handling, supplying, distributing, and selling of electricalpower systems, negligence in the construction and maintenance of distributionsystems, and failure to warn or adequately test such systems.  Plaintiffs allege decreased milk production,injury and damage to a dairy herd as a result of stray voltage resulting fromNSP-Minnesota’s distribution system. Plaintiffs’ expert report on the economic damage to their dairy farmstates that the total present value of plaintiffs’ loss is $6.8 million.  Trial is scheduled to commence in January2008.  NSP-Minnesota denies theseallegations and will vigorously defend itself in this matter.

***Carbon Dioxide Emissions Lawsuit***— OnJuly 21, 2004, the attorneys general of eight states and New York City, aswell as several environmental groups, filed lawsuits in U.S. District Court forthe Southern District of New York against five utilities, including XcelEnergy, to force 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 fossil fuel iscombusted, such as in automobiles, industrial operations and coal- or naturalgas-fired power plants.  The lawsuitsallege that CO2 emitted by each company is a public nuisance as defined understate and federal common law because it has contributed to global warming.  The lawsuits do not demand monetarydamages.  Instead, the lawsuits ask thecourt to order each utility to cap and reduce its CO2 emissions.  In October 2004, Xcel Energy and fourother utility companies filed a motion to dismiss the lawsuit, contending,among other reasons, that the lawsuit is an attempt to usurp the policy-settingrole of the U.S. Congress and the president. On Sept. 19,

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2005, the judgegranted the defendants’ motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the SecondCircuit Court of Appeals.  Oral argumentswere presented on June 7, 2006 and a decision on the appeal is pending.

**Hoffman vs. Northern States Power Company** — On March 15,2006, a purported class action complaint was filed in Minnesota State DistrictCourt in Hennepin County, on behalf of NSP-Minnesota’s residential customers inMinnesota, North Dakota and South Dakota for alleged breach of a contractualobligation to maintain and inspect the points of connection betweenNSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffsclaim NSP-Minnesota’s alleged breach results in an increased risk of fire andis in violation of tariffs on file with the MPUC. Plaintiffs seek injunctiverelief and damages in an amount equal to the value of inspections plaintiffsclaim NSP-Minnesota was required to perform over the past six years.NSP-Minnesota filed a motion for dismissal on the pleadings, which was heard onAug. 16, 2006.  In November 2006, thecourt issued an order denying NSP-Minnesota’s motion.  On Nov. 28, 2006, pursuant to a motion byNSP-Minnesota, the court certified the issues raised in NSP-Minnesota’soriginal motion as important and doubtful. This certification permits NSP-Minnesota to file an appeal, and it hasdone so.

***Comer vs. Xcel Energy Inc. et al.***— OnApril 25, 2006, Xcel Energy received notice of a purported class action lawsuitfiled in U.S. District Court for the Southern District of Mississippi.  Although NSP-Minnesota is not named as aparty to this litigation, if the litigation ultimately results in anunfavorable outcome for Xcel Energy, it could have a material adverse effect onNSP-Minnesota.  The lawsuit names morethan 45 oil, chemical and utility companies, including Xcel Energy, asdefendants and alleges that defendants’ CO2 “were a proximate and direct causeof the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim,several legal theories, including negligence, and public and private nuisanceand seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is withoutmerit and intends to vigorously defend itself against these claims.  On July 19, 2006, Xcel Energy filed a motionto dismiss the lawsuit in its entirety.

***AmeriPride Services vs. NSP***— InAugust 2006, a complaint was served on NSP-Minnesota and suit was filed in theHennepin County District Court in Minnesota, alleging that on or about Sept. 2,2004, fires occurred on the premises of AmeriPride, a linen and apparel servicefacility in Minneapolis, and that the cause of the fire was NSP-Minnesota’sfailure to properly repair a primary underground cable after two prior failuresin the same cable.  AmeriPride claimsdamages slightly in excess of $2 million, and asserts claims of negligence,gross negligence, negligent inspection and maintenance, negligent design, negligentfailure to install equipment to discontinue power, negligent continuation ofpower, and negligent misrepresentation. NSP-Minnesota denies these allegations and will vigorously defendagainst them.

***Schiltgen vs. Northern States Power Co. et al****.*****—In November 2006, a suit was filed against NSP-Minnesota and others in theMinnesota State District Court in Washington County, alleging that negligenceon the part of NSP-Minnesota and others led to severe injuries when theplaintiff contacted an electrical distribution line while working with a portablegrain auger. NSP-Minnesota denies all allegations asserted against it and willvigorously defend itself against them.

**12. Nuclear Obligations**

***Fuel Disposal —***NSP-Minnesota isresponsible for temporarily storing used or spent nuclear fuel from its nuclearplants. The DOE is responsible for permanently storing spent fuel fromNSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants.NSP-Minnesota has funded its portion of the DOE’s permanent disposal programsince 1981. The fuel disposal fees are based on a charge of 0.1 cent perkilowatt-hour sold to customers from nuclear generation. Fuel expense includesthe DOE fuel disposal assessments of approximately $13 million in 2006, $12million in 2005 and $13 million in 2004. In total, NSP-Minnesota had paidapproximately $360 million to the DOE through Dec. 31, 2006. However, itis not determinable whether the amount and method of the DOE’s assessments toall utilities will be sufficient to fully fund the DOE’s permanent storage ordisposal facility.

The Nuclear Waste PolicyAct of 1982 required the DOE to begin accepting spent nuclear fuel no laterthan Jan. 31, 1998. In 1996, the DOE notified commercial spent-fuel ownersof an anticipated delay in accepting spent nuclear fuel by the required dateand conceded that a permanent storage or disposal facility will not beavailable until at least 2010. NSP-Minnesota and other utilities have commencedlawsuits against the DOE to recover damages caused by the DOE’s failure to meetits statutory and contractual obligations.

NSP-Minnesota has its owntemporary on-site storage facilities for spent fuel at its Monticello andPrairie Island nuclear plants, which consist of storage pools at both sites anda dry cask facility at Prairie Island. With the dry cask storage facilitylicensed by the NRC, approved in 1994 and again in 2003, management believes ithas adequate storage capacity to continue operation of its Prairie Islandnuclear plant until at least the end of its current license terms in 2013 and 2014.The Monticello nuclear plant has storage capacity in the storage pool tocontinue operations until 2010. In 2005, NSP-Minnesota filed a certificate ofneed to allow interim storage of spent fuel at the Monticello nuclear plant tosupport license renewal and operation for an additional 20 years, and inOctober 2006, the MPUC issued its approval allowing additional interim spentfuel storage.  Minnesota Statutes providethat the MPUC decision becomes effective June 1, 2007, which allows thelegislature the opportunity to review the MPUC action if desired.  All of the alternatives for spent fuelstorage are being investigated until a DOE facility is available, includingpursuing the establishment of a private facility for interim storage of spentnuclear fuel as part of a consortium of electric utilities.

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 for15 years to 2007. NSP-Minnesota is amortizing each installment to expense on amonthly basis. The most recent installment paid in 2006 was $4.9 million;future installments are subject to inflation adjustments under the 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 $3.7 million at Dec. 31, 2006, is deferredas a regulatory asset.

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***Regulatory Plant Decommissioning Recovery —***Decommissioningof NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is plannedfor the period from cessation of operations through 2050, assuming the promptdismantlement method. NSP-Minnesota is currently accruing the regulatory costsfor decommissioning over the MPUC-approved cost-recovery period and includingthe accruals in a regulatory liability account. The total decommissioning costobligation is recorded as an asset retirement obligation in accordance withSFAS No. 143.

Monticello began operation in 1971 with an originallicense to operate until 2010. Prairie Island units 1 and 2 began operation in1973 and 1974, respectively, and are currently licensed to operate until 2013and 2014, respectively. In 2003, the Minnesota Legislature changed a law thathad limited expansion of on-site storage. On Sept. 28, 2006, the MPUC approved Xcel Energy’s request for acertificate of need to authorize construction and operation of a dry spent fuelstorage facility at Monticello. Minnesota statutes provide that the order is not effective until June 1,2007.  The purpose of the stay is to givethe state legislature the opportunity to review the MPUC action if lawmakerswish.  On Nov. 8, 2006, the NRC renewedthe operating license of the Monticello nuclear plant for an additional 20years to 2030.   Plant assessments andother work for the Prairie Island applications started in 2006.  The Prairie Island operating license extensionfor an additional 20 years of operation will be filed in 2008 with the NRC.

The total obligation fordecommissioning currently is expected to be funded 100 percent by externalfunds, as approved by the MPUC. The MPUC last approved NSP-Minnesota’s nucleardecommissioning study request in March 2006, using 2005 cost data.  The MPUC approval decreasing 2006decommissioning funding for Minnesota retail customers resulted from anextension of remaining life for the Monticello unit by 10 years (from 2010 to2020).  Contributions to the externalfund started in 1990 and are expected to continue until plant decommissioningbegins. The assets held in trusts as of Dec. 31, 2006, primarily consistedof investments in fixed income securities, such as tax-exempt municipal bondsand U.S. government securities that mature in one to 20 years, and common stockof public companies. NSP-Minnesota plans to reinvest matured securities untildecommissioning begins.

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. Current authorized funding presumes that costs willescalate in the future at a rate of 3.61 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 5.4 percent, net of tax, for externalfunding. The net unrealized gain on nuclear decommissioning investments isdeferred as a regulatory liability based on the assumed offsetting againstdecommissioning costs in current ratemaking treatment.

In 2006, the Nuclear Decommissioning Trust (NDT) fundalso recorded the sale of certain investments in the non-qualified fund and thereinvestment of the proceeds into the qualified fund.  The sale and reinvestment, along with thetransfer of securities was part of a transaction intended to consolidate trustfund accounts into an income tax advantaged fund, resulting from the EnergyAct.  The transfer of funds was completedin the fourth quarter of 2006.

At Dec. 31, 2006, NSP-Minnesota had recorded andrecovered in rates cumulative decommissioning accruals of $1.1 billion. Thefollowing table summarizes the funded status of NSP-Minnesota’s decommissioningobligation based on approved regulatory recovery parameters.  Xcel Energy believes future decommissioningcost accruals will continue to be recovered in customer rates.  These amounts are not those recorded in thefinancial statements for the asset retirement obligation in accordance withSFAS No. 143.

 
| **(Thousands of Dollars)**                                                                                | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| Estimated  decommissioning cost obligation from most recently approved study (2005 and  2002 dollars, respectively) |       | $          | 1,683,750  |       | $          | 1,716,618 |   |
| Effect of escalating  costs to 2006 and 2005 dollars (at 3.61 and 4.19 percent per year,  respectively)             |       | 60,783     |       | 224,946    |       |
| Estimated  decommissioning cost obligation in current dollars                                                       |       | 1,744,533  |       | 1,941,564  |       |
| Effect of escalating  costs to payment date (at 3.61and 4.19 percent per year, respectively)                        |       | 1,382,293  |       | 1,851,801  |       |
| Estimated future  decommissioning costs (undiscounted)                                                              |       | 3,126,826  |       | 3,793,365  |       |
| Effect of discounting  obligation (using risk-free interest rate)                                                   |       | (1,675,114 | )          | (2,026,003 | )          |
| Discounted  decommissioning cost obligation                                                                         |       | 1,451,712  |       | 1,767,362  |       |
| Assets held in external  decommissioning trust                                                                      |       | 1,200,688  |       | 1,047,592  |       |
| Discounted decommissioning obligation in excess of assets currently  held in external trust                         |       | $          | 251,024    |       | $          | 719,770 |   |

 

 

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Decommissioning expensesrecognized include the following components:
| (Thousands of Dollars)                                        | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Annual decommissioning  cost accrual reported as  depreciation expense: |       |     |       |     |       |     |       |
| Externally  funded                                                      |       | $        | 48,069     |     | $          | 80,582   |       | $ | 80,582 |   |
| Internally  funded (including interest costs)                           |       | (5,046   | )          | (57,561  | )          | (53,307  | )          |
| Net decommissioning accruals recorded                                   |       | $        | 43,023     |     | $          | 23,021   |       | $ | 27,275 |   |

 

Negative accruals forinternally funded portions in 2004 and 2005 reflect the impact of the 2002 decommissioningstudy approved in 2003, which approved an assumption of 100-percent externalfunding of future costs.  The 2005nuclear decommissioning filing approved in 2006 has been used for theregulatory presentation  and all theupdated parameters were used for the 2005 ARO layer for SFAS No. 143recognition.

**13. Regulatory Assets and Liabilities**

NSP-Minnesota’s financial statements are prepared inaccordance with the provisions of SFAS No. 71, as discussed in Note 1 to theConsolidated Financial Statements. Under SFAS No. 71, regulatory assets andliabilities can be created for amounts that regulators may allow to becollected, or may require to be paid back to customers in future electric andnatural gas rates. Any portion of the business that is not rate regulatedcannot use SFAS No. 71 accounting.  Ifchanges in the utility industry or the business of NSP-Minnesota no longerallow for the application of SFAS No. 71 under GAAP, NSP-Minnesota would berequired to recognize the write-off of regulatory assets and liabilities in itsstatement of income.  The components ofunamortized regulatory assets and liabilities on the balance sheets ofNSP-Minnesota are:
|                                                       | ** ** | ** **           | ** ** | **Remaining Amortization**               | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------------------|------------|----------------------|------------|-----------------------------------------------|------------|------------|------------|------------|------------|
| **(Thousands of Dollars)**                  | ** ** | **See Note(s)** | ** ** | **Period**                                    | ** ** | **2006**   | ** ** | **2005**   | ** ** |
| ** **                                            | ** ** | ** **           | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Regulatory Assets:                                    |       |                 |       |                                          |       |       |       |       |       |
| AFDC recorded in  plant (a)                           |       |                 |       | Plant  lives                                  |       | $          | 106,088    |       | $          | 96,296 |   |
| Contract  valuation adjustments (d)                   |       | 8                    |       | Term  of contract                             |       | 68,188     |       | 53,425     |       |
| Renewable  resource costs                             |       |                 |       | Two  to Three years                           |       | 49,902     |       | 46,889     |       |
| Net asset  retirement obligations (e)                 |       | 11                   |       | Plant  lives                                  |       | 36,945     |       | 155,814    |       |
| Conservation  programs (a)                            |       |                 |       | Generally  one year                           |       | 31,448     |       | 29,670     |       |
| Losses on  reacquired debt                            |       | 1                    |       | Term  of related debt                         |       | 25,944     |       | 29,081     |       |
| Unrecovered  natural gas costs (b)                    |       | 1                    |       | One  to two years                             |       | 17,943     |       | 12,874     |       |
| Private fuel  storage                                 |       |                 |       | Five  years                                   |       | 14,473     |       | —     |       |
| Minnesota  renewable cost recovery                    |       |                 |       |                                          |       | —     |       | 3,564      |       |
| State commission  accounting adjustments (a)     |       |                 |       | Plant  lives                                  |       | 4,187      |       | 4,240      |       |
| Nuclear  decommissioning costs (c)                    |       |                 |       | One  year                                     |       | 3,700      |       | 8,317      |       |
| Unrecovered  electric production and MISO day 2 costs |       |                 |       | To  be determined in  future rate proceedings |       | 2,960      |       | —     |       |
| Rate case costs                                       |       | 1                    |       | Various                                       |       | 2,043      |       | 2,538      |       |
| Environmental  costs                                  |       | 11, 12               |       | Various                                       |       | 2,237      |       | 3,001      |       |
| Other                                                 |       |                 |       | Various                                       |       | 6,291      |       | 4,491      |       |
| Total regulatory  assets                              |       |                 |       |                                          |       | $          | 372,349    |       | $          | 450,200 |   |
|                                                  |       |                 |       |                                          |       |       |       |       |       |
| Regulatory Liabilities:                               |       |                 |       |                                          |       |       |       |       |       |
| Plant removal  costs                                  |       | 11                   |       |                                          |       | $          | 355,390    |       | $          | 334,353 |   |
| Pension and  employee benefit obligations             |       | 6                    |       |                                          |       | 185,425    |       | 397,261    |       |
| Deferred income  tax adjustments                      |       |                 |       |                                          |       | 48,644     |       | 57,430     |       |
| Investment tax  credit deferrals                      |       |                 |       |                                          |       | 32,902     |       | 35,993     |       |
| Contract  valuation adjustments (d)                   |       |                 |       |                                          |       | 16,420     |       | 6,631      |       |
| Fuel costs,  refunds and other                        |       |                 |       |                                          |       | 11,340     |       | 8,546      |       |
| Interest on  income tax refunds                       |       |                 |       |                                          |       | 5,208      |       | 5,981      |       |
| MERP rider recoveries                                 |       |                 |       |                                          |       | 3,242      |       | —     |       |
| Total regulatory  liabilities                         |       |                 |       |                                          |       | $          | 658,571    |       | $          | 846,195 |   |

 

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(a)             Earnsa return on investment in the ratemaking process. These amounts are amortizedconsistent with recovery in rates.

(b)            Excludescurrent portion expected to be returned to customers within 12 months of $17.7million for 2006, and expected to be returned to customers within 12 months of$16.3 million for 2005.

(c)             Thesecosts do not relate to NSP-Minnesota’s nuclear plants. They relate to the DOEassessments to pay for the decommissioning of a federal uranium enrichmentfacility.  See Note 12 to theConsolidated Financial Statements.

(d)            Includesthe fair value of certain long-term contracts used to meet native energyrequirements.

(e)             Includesamounts recorded for future ecovery of asset retirement obligations, lessamounts recovered through nuclear decommissioning accruals and gains fromdecommissioning investments.

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**14. Segments and Related Information**

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

·       NSP-Minnesota’s RegulatedElectric Utility generates, transmits and distributes electricity in Minnesota,North Dakota and South Dakota. In addition, this segment includes sales forresale and provides wholesale transmission service to various entities in theUnited States.  Regulated ElectricUtility also includes NSP-Minnesota’s commodity trading operations.

·       NSP-Minnesota’s RegulatedNatural Gas Utility transports, stores and distributes natural gas in portionsof Minnesota and North Dakota.

Revenues from operating segments not included aboveare below the necessary quantitative thresholds and are therefore included inthe All Other category. Those primarily include appliance repair services,nonutility real estate activities and revenues associated with processing solidwaste into refuse-derived fuel.

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

·       directly assigned wherever applicable;

·       allocated based on cost causation allocatorswherever applicable; or

·       allocatedbased on a general allocator for all other costs not assigned by the above twomethods.

The accounting policies of the segments are the sameas those described in Note 1 to the Consolidated Financial Statements.  These segments are managed separately becausethe revenue streams are dependent upon regulated rate recovery which areseparately determined for each segment.
| **(Thousands of Dollars)**        | ** ** | **Regulated  Electric Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|---------------------------------------------|------------|--------------------------------------|------------|------------------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| **2006**                                    |       |                                 |       |                                     |       |           |       |                          |       |                    |       |
| Operating revenues from  external customers |       | $                                    | 3,265,371  |                                     | $          | 744,635        |       | $                             | 17,609     |                    | $          | — |   | $ | 4,027,615 |   |
| Intersegment revenues                       |       | 496                                  |       | 8,929                                    |       | —         |       | (9,425                        | )          | —                  |       |
| Total revenues                              |       | $                                    | 3,265,867  |                                     | $          | 753,564        |       | $                             | 17,609     |                    | $          | (9,425 | ) | $ | 4,027,615 |   |
| Depreciation and  amortization              |       | $                                    | 393,560    |                                     | $          | 31,566         |       | $                             | 385        |                    | $          | — |   | $ | 425,511 |   |
| Financing costs, mainly  interest expense   |       | 134,347                              |       | 15,539                                   |       | 1,040          |       | (4                            | )          | 150,922                 |       |
| Income tax expense  (benefit)               |       | 138,077                              |       | 5,448                                    |       | (15,919        | )          | —                        |       | 127,606                 |       |
| Segment net income                          |       | $                                    | 242,815    |                                     | $          | 9,674          |       | $                             | 19,821     |                    | $          | — |   | $ | 272,310 |   |
|                                        | ** ** | ** **                           | ** ** | ** **                               | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| **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 |   |

** **

63

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**15. Related Party Transactions**

Xcel Energy Services Inc. provides management,administrative and other services for the subsidiaries of Xcel Energy,including NSP-Minnesota.  The servicesare provided and billed to each subsidiary in accordance with ServiceAgreements  executed by each subsidiary.Costs are charged directly to the subsidiary which uses the service wheneverpossible, and are allocated if they cannot be directly assigned.

Xcel Energy has established a utility money poolarrangement with the utility subsidiaries and received required FERC and stateregulatory approvals.  See Note 2 forfurther discussion of this borrowing arrangement.

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

***Nuclear Plant Operation***— The NMC is an operating company that manages the operations, maintenance andphysical security of several nuclear generating units, including three units/twosites owned by NSP-Minnesota. NSP-Minnesota continues to own the plants, controls all energy producedby the plants and retains responsibility for nuclear property, liabilityinsurance, spent fuel and decommissioning costs.  As ofDec. 31, 2006, all members of the NMC, other than Xcel Energy, have chosen tosell their units and exit the NMC. Regarding the remaining members of the NMC, the sales transaction of CMSEnergy Corp Palisades Nuclear Power Plant is targeted to close in the firstquarter of 2007.  In December 2006,Wisconsin Electric Power Co., announced its intent to sell its Point Beach Nuclear Plant to FPLEnergy with the sale expected to close in the third or fourth quarter of2007.

Followingconsummation of the sale transactions, NSP-Minnesota will be the sole remainingmember of the NMC.  NSP-Minnesota isevaluating the situation.  One optionunder consideration is to transition the NMC to a wholly owned subsidiary ofXcel Energy.  To facilitateimplementation of this option, Xcel Energy plans are progressing to restructurethe NMC to support a two-site organization, as well as reabsorb theadministrative functions within Xcel Energy by the end of 2007

In accordance with theNuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays itsproportionate share of the operating expenses and capital improvement costsincurred by NMC.  NSP-Minnesota paid theNMC $292.5 million in 2006, $257.1 million in 2005 and $314.7 million in 2004.

The electricproduction and transmission costs of the entire NSP system are shared byNSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for thesharing of all costs of generation and transmission facilities of the system,including capital costs.

The table belowcontains significant affiliate transactions among the companies and relatedparties including billings under the Interchange Agreement for the years endedDec. 31:
| (Thousands of Dollars)                           | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Operating revenues:                                        |       |     |       |     |       |     |       |
| Electric utility                                           |       | $        | 322,733    |     | $          | 305,202  |       | $ | 220,165 |   |
| Natural gas  utility                                       |       | 350      |       | 386      |       | 303      |       |
| Operating expenses:                                        |       |     |       |     |       |     |       |
| Purchased power                                            |       | 61,342   |       | 60,801   |       | 55,222   |       |
| Transmission  expense                                      |       | 38,061   |       | 37,803   |       | 40,794   |       |
| Other operations  — paid to Xcel Energy Services Inc. |       | 284,108  |       | 284,906  |       | 274,074  |       |
| Interest expense                                           |       | 1,083    |       | 494      |       | 224      |       |
| Interest income                                            |       | 4,497    |       | 1,326    |       | 335      |       |
|                                                            |            |          |            |          |            |          |            |  |  |  |

 

64

----

Accounts receivable and payable with affiliates atDec. 31, was:
|                                         | ** ** | **2006**                 | ** ** | **2005**              | ** ** |
|-----------------------------------------|------------|--------------------------|------------|-----------------------|------------|
| **(Thousands of Dollars)**    | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** |
| ** **                              | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** |
| NSP-Wisconsin                           |       | $                        | 9,905      |                  | $          | — |   | $ | 11,756 |   | $ | — |   |
| PSCo                                    |       | —                   |       | 6,598                 |       | 162 |   | 22,356 |   |
| SPS                                     |       | —                   |       | 4,015                 |       | — |   | 10,282 |   |
| Other subsidiaries of  Xcel Energy Inc. |       | 23,031                   |       | 28,526                |       | 41,496 |   | 27,781 |   |
|                                    |       | $                        | 32,936     |                  | $          | 39,139 |   | $ | 53,414 |   | $ | 60,419 |   |

 

NSP-Wisconsin obtains short-term borrowings fromNSP-Minnesota at NSP-Minnesota’s average daily interest rate, including thecost of NSP-Minnesota’s compensating balance requirements. At Dec. 31, 2006 and2005, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in theamount of $30.3 million and $64.0 million, respectively.

**16. Summarized Quarterly FinancialData (Unaudited)**

 
|                                      | ** ** | **Quarter Ended**       | ** ** |
|--------------------------------------|------------|------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **March 31, 2006** | ** ** | **June 30, 2006** | ** ** | **Sept. 30, 2006** | ** ** | **Dec. 31, 2006** | ** ** |
|                                 |       |                         |       |   |   |   |   |   |   |
| Revenue                              |       | $                            | 1,087,713  |   | $ | 829,345 |   | $ | 1,080,203 |   | $ | 1,030,354 |   |
| Operating income                     |       | 123,028                      |       | 75,020 |   | 221,925 |   | 100,538 |   |
| Net income                           |       | 58,942                       |       | 30,120 |   | 130,705 |   | 52,543 |   |
|                                      |            |                              |            |  |  |  |  |  |  |  |  |  |  |

 
|                                      | ** ** | **Quarter Ended**       | ** ** |
|--------------------------------------|------------|------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **March 31, 2005** | ** ** | **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 |   |
|                                      |            |                              |            |  |  |  |  |  |  |  |  |  |  |

 

**Item9 — Changes in and Disagreements With Accountants on Accounting and FinancialDisclosure**

During 2005 and 2006, and through the date of thisreport, there were no disagreements with the independent public accountants forNSP-Minnesota on accounting principles or practices, financial statementdisclosures or auditing scope or procedures.

**Item 9A— Controls and Procedures**

**Disclosure Controls and Procedures**

NSP-Minnesota maintains a set of disclosure controlsand procedures designed to ensure that information required to be disclosed inreports that it files or submits under the Securities Exchange Act of 1934 isrecorded, processed, summarized and reported within the time periods specifiedin Securities and Exchange Commission rules and forms. As of the end of theperiod covered by this report, based on an evaluation carried out under thesupervision and with the participation of the NSP-Minnesota’s management,including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO),of the effectiveness of its disclosure controls and procedures, the CEO and CFOhave concluded that the Company’s disclosure controls and procedures areeffective.

**InternalControl Over Financial Reporting**

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

65

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**Item 9B**—**Other Information**

None.

**PART III**

Items 10, 11, 12 and 13 of Part III of Form 10-K havebeen omitted from this report for NSP-Minnesota in accordance with conditionsset forth in general instructions I (1) (a) and (b) of Form 10-K forwholly-owned subsidiaries.

**Item 10— Directors, Executive Officers, and Corporate Governance**

**Item 11— Executive Compensation**

**Item 12— Security Ownership of Certain Beneficial Owners and Management and RelatedStockholder Matters**

**Item 13— Certain Relationships, Related Transactions, and Director Independence**

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

Informationconcerning fees paid to the principal accountant for each of the last two yearsis contained in the Xcel Energy Proxy Statement for its 2007 Annual Meeting ofShareholders, which is incorporated by reference.

**PART IV**

**Item 15 —Exhibits, Financial Statement Schedules**

1.               Consolidated Financial Statements:

Reports of Independent Registered Public AccountingFirm **—**For the years ended Dec.31, 2006, 2005 and 2004.

Consolidated Statements of Income **—**For the threeyears ended Dec. 31, 2006, 2005 and 2004.

Consolidated Statementsof Cash Flows **—** For the threeyears ended Dec. 31, 2006, 2005 and 2004.

Consolidated Balance Sheets **—**As of Dec. 31, 2006 and 2005.

2.               Schedule II **—**Valuation and Qualifying Accounts andReserves for the years ended Dec. 31, 2006, 2005 and 2004.

3.               Exhibits

----

*Indicates incorporationby reference

+Executive Compensation Arrangements and Benefit PlansCovering Executive Officers and Directors

 
| 2.01* |   | Agreement and Plan of Merger, dated as of March 24,  1999, by and between Northern States Power Co. (a Minnesota corporation) and  New Century Energies, Inc. (Exhibit 2.1 to New Century Energies, Inc. Form  8-K (file no. 001-12907) dated March 24, 1999).                                                                                                                |
|-------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.01* |   | Articles of Incorporation and Amendments of Northern  Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on  Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5,  2000).                                                                                                                                                      |
| 3.02* |   | By-Laws of Northern States Power Co. (a Minnesota  corporation) (Exhibit 3.02 to Form 10-12G (file no. 000-31709) dated Oct. 5,  2000).                                                                                                                                                                                                                                       |
| 4.01* |   | Supplemental and Restated Trust Indenture, dated May  1, 1988, from Northern States Power Co. (a Minnesota corporation) to Harris  Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K of  NSP-Minnesota for the year 1988, file no. 001-03034). Supplemental Indentures  between NSP-Minnesota and said Trustee, supplemental to Exhibit 4.14, dated  as follows: |
| 4.02* |   | July 1, 1989 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated July 7, 1989).                                                                                                                                                                                                                                                                                             |
| 4.03* |   | June 1, 1990 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated June 1, 1990).                                                                                                                                                                                                                                                                                             |
| 4.04* |   | Oct. 1, 1992 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated Oct. 13, 1992).                                                                                                                                                                                                                                                                                            |
| 4.05* |   | April 1, 1993 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated March 30, 1993).                                                                                                                                                                                                                                                                                          |
| 4.06* |   | Dec. 1, 1993 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated Dec. 7, 1993).                                                                                                                                                                                                                                                                                             |
| 4.07* |   | Feb. 1, 1994 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated Feb. 10, 1994).                                                                                                                                                                                                                                                                                            |
| 4.08* |   | Oct. 1, 1994 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated Oct. 5, 1994).                                                                                                                                                                                                                                                                                             |

66

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| 4.09*   |   | June 1, 1995 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated June 28, 1995).                                                                                                                                                                                                                                                                                            |
|---------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.10*   |   | April 1, 1997 (Exhibit 4.47 to Form 10-K (file no.  001-03034) for the year 1997).                                                                                                                                                                                                                                                                                            |
| 4.11*   |   | March 1, 1998 (Exhibit 4.01 to Form 8-K (file no.  001-03034) dated March 11, 1998).                                                                                                                                                                                                                                                                                          |
| 4.12*   |   | May 1, 1999 (Exhibit 4.49 to NSP-Minnesota Form  10-12G (file no. 000-31709) dated Oct. 5, 2000).                                                                                                                                                                                                                                                                             |
| 4.13*   |   | June 1, 2000 (Exhibit 4.50 to NSP-Minnesota Form  10-12G (file no. 000-31709) dated Oct. 5, 2000).                                                                                                                                                                                                                                                                            |
| 4.14*   |   | Aug. 1, 2000 (Assignment and Assumption of Trust  Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709)  dated Oct. 5, 2000).                                                                                                                                                                                                                            |
| 4.15*   |   | June 1, 2002 (Exhibit 4.05 to Form 10-Q (file no.  000-31709) dated Sept. 30, 2002).                                                                                                                                                                                                                                                                                          |
| 4.16*   |   | June 1, 2002 (Exhibit 4.06 to Form 10-Q (file no.  000-31709) dated Sept. 30, 2002).                                                                                                                                                                                                                                                                                          |
| 4.17*   |   | Aug. 1, 2002 (Exhibit 4.01 to Form 8-K (file no.  001-31387) dated Aug. 22, 2002).                                                                                                                                                                                                                                                                                            |
| 4.18*   |   | Aug. 1, 2003 (Exhibit 4.01 to Form 8-K (file no.  001-31387) dated Aug. 6, 2003).                                                                                                                                                                                                                                                                                             |
| 4.19*   |   | May 1, 2003 (Exhibit 4.73 to Form 10-K (file no.  000-03034) for the year ended Dec. 31, 2003).                                                                                                                                                                                                                                                                               |
| 4.20*   |   | July 1, 2005 (Exhibit 4.01 to NSP-Minnesota Current  Report on Form 8-K (file no. 001-31387) dated July 14, 2005).                                                                                                                                                                                                                                                            |
| 4.21*   |   | Trust Indenture, dated July 1, 1999, between  Northern States Power Co. (a Minnesota corporation) and Norwest Bank  Minnesota, National Association, as Trustee. (Exhibit 4.01 to NSP-Minnesota  Form 8-K (file no. 001-03034) dated July 21, 1999).                                                                                                                          |
| 4.22*   |   | Supplemental Trust Indenture, dated July 15, 1999,  between Northern States Power Co. (a Minnesota corporation) and Norwest Bank  Minnesota, National Association, as Trustee. (Exhibit 4.02 to NSP-Minnesota  Form 8-K (file no. 001-03034) dated July 21, 1999).                                                                                                            |
| 4.23*   |   | Supplemental Trust Indenture, dated Aug. 18, 2000,  supplemental to the Indenture dated July 1, 1999, among Xcel Energy, Northern  States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota,  National Association, as Trustee. (Exhibit 4.63 to NSP-Minnesota Form 10-12G  (file no. 000-31709) dated Oct. 5, 2000).                                        |
| 4.24*   |   | Supplemental Trust Indenture dated June 1, 2002,  supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between  Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust  Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file no. 000-31709)  dated Sept. 30, 2002).                                                                    |
| 4.25*   |   | Supplemental Trust Indenture dated July 1, 2002,  supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between  Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust  Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file no. 000-31709)  dated Sept. 30, 2002).                                                                    |
| 4.26*   |   | Supplemental Trust Indenture dated July 1, 2002,  supplemental to the Indenture dated July 1, 1999, between Northern States  Power Co. (a Minnesota Corporation) and Wells Fargo Bank Minnesota, National  Association, as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated  July 8, 2002).                                                                       |
| 4.27*   |   | Supplemental Trust Indenture dated Aug. 1, 2002,  supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between  Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust  Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387)  dated Aug. 22, 2002).                                                                      |
| 4.28*   |   | Supplemental Trust Indenture dated Aug. 1, 2003  between Northern States Power Co. (a Minnesota corporation) and BNY Midwest  Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988  (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).                                                                                                     |
| 4.29*   |   | Supplemental Trust Indenture dated May 1, 2003  between Northern States Power Co. (a Minnesota corporation) and BNY Midwest  Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988.                                                                                                                                                                          |
| 4.30*   |   | Underwriting Agreement dated July 14, 2005 between  NSP-Minnesota, Barclays Capital Inc. and J.P. Morgan Securities Inc., as  representatives of the Underwriters named therein, relating to $250,000,000  principal amount of 5.25 percent First Mortgage Bonds, Series due July 15,  2035 (Exhibit 1.01 to NSP-Minnesota Current Report on Form 8-K, dated July  14, 2005). |
| 4.31*   |   | 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).                                                               |
| 4.32*   |   | Supplemental Indenture dated May 1, 2006  between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee,  creating $400,000,000 principal amount of 6.25 percent First Mortgage Bonds,  Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current  Report on Form 8-K, dated May 18, 2006).                                    |
| 4.33*   |   | $500,000,000 Credit Agreement dated Dec. 14, 2006  between NSP-Minnesota and various lenders (Exhibit 99.01 to Form 8-K (file  no. 000-31387) dated Dec. 14, 2006).                                                                                                                                                                                                           |
| 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).                                                                                                                 |

67

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| 10.04*+ |   | Amended and Restated Executive Long-Term Incentive  Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no.  001-03034) for the quarter ended March 31, 1998).                                                                                                                      |
|---------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.05*+ |   | Stock Equivalent Plan for Non-Employee Directors of  Xcel Energy As Amended and Restated Effective Oct. 1, 1997. (Exhibit 10.15 to  NSP-Minnesota Form 10-K (file no. 001-03034) for the year 1997).                                                                                              |
| 10.06*+ |   | Senior Executive Severance Policy, effective March  24, 1999, between New Century Energies, Inc. and Senior Executives (Exhibit  10(a)(2) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated  March 31, 1999).                                                                   |
| 10.07*+ |   | New Century Energies Omnibus Incentive Plan,  (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927)  filed March 26, 1998.                                                                                                                                                   |
| 10.08*+ |   | Directors’ Voluntary Deferral Plan (Exhibit 10(d)  (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec  31, 1998).                                                                                                                                                    |
| 10.09*+ |   | Supplemental Executive Retirement Plan (Exhibit  10(e) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated  Dec. 31, 1998).                                                                                                                                                    |
| 10.10*+ |   | Salary Deferral and Supplemental Savings Plan for  Executive Officers (Exhibit 10(f) (1) to New Century Energies, Inc. Form 10-K  (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                      |
| 10.11*+ |   | Salary Deferral and Supplemental Savings Plan for  Key Managers (Exhibit 10(g) (1) to New Century Energies, Inc. Form 10-K (file  no. 001-12927) dated Dec. 31, 1998).                                                                                                                            |
| 10.12*+ |   | Supplemental Executive Retirement Plan for Key  Management Employees, as amended and restated March 26, 1991 (Exhibit  10(e)(2) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1991).                                                                                                       |
| 10.13*+ |   | Form of Key Executive Severance Agreement, as  amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(e)(4) to PSCo Form 10-K  (file no. 001-3280) dated Dec. 31, 1995).                                                                                                                              |
| 10.14*+ |   | Supplemental Retirement Income Plan as amended July  23, 1991 (Exhibit 10(d) to SPS Form 10-K, (file no. 001-03789) dated Aug. 31,  1996).                                                                                                                                                        |
| 10.15*+ |   | Xcel Energy Senior Executive Severance and  Change-in-Control Policy dated Oct. 22, 2003 (Exhibit 10.10 to SPS Form S-4,  (file no. 333-112032) dated Jan. 21, 2004).                                                                                                                             |
| 10.16*+ |   | Stock Equivalent Plan for Non-Employee Directors of  Xcel Energy as amended and restated Jan. 1, 2004 (Exhibit B to Form DEF-14A  (file no. 001-03034) dated Apr. 9, 2004).                                                                                                                       |
| 10.17*+ |   | Xcel Energy Nonqualified Deferred Compensation Plan  (2002 restatement) (Exhibit 10.23 to Xcel Energy Form 10-K (file no.  001-03034) dated March 15, 2004).                                                                                                                                      |
| 10.18*+ |   | Xcel Energy Non-employee Directors’ Deferred  Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (file no.  001-03034) dated March 15, 2004).                                                                                                                                         |
| 10.19*+ |   | Xcel Energy 401(k) Savings Plan, amended and  restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4 (file no.  333-112032) dated Jan. 21, 2004).                                                                                                                                             |
| 10.20*+ |   | New Century Energies, Inc. Employee Investment Plan  for Bargaining Unit Employees and Former Non-bargaining Unit Employees, as  amended and restated effective Jan. 1, 2004 but with certain retroactive  amendments (Exhibit 10.20 to SPS Form S-4 (file no. 333-112032) dated Jan.  21, 2004). |
| 10.21*  |   | Form of Services Agreement between Xcel Energy  Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no.  001-03034) dated Nov. 16, 2000).                                                                                                                                          |
| 10.22*  |   | Securities Litigation Settlement Agreement as of  Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.01 to Form 8-K (file no.  001-03034) dated Jan. 14, 2005).                                                                                                                                 |
| 10.23*  |   | ERISA Actions Settlement Agreement as of Dec. 31,  2004 and approved Jan. 14, 2005 (Exhibit 10.02 to Form 8-K (file no.  001-03034) dated Jan. 14, 2005).                                                                                                                                         |
| 10.24*  |   | Shareholder Derivative Action Settlement Agreement  as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.03 to Form 8-K  (file no. 001-03034) dated Jan. 14, 2005).                                                                                                                         |
| 10.25*+ |   | Employment Agreement, effective Dec. 15, 1997,  between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel  Energy Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).                                                                                              |
| 10.26*+ |   | Compensation and reimbursement practices for Xcel  Energy non-employee directors (Exhibit 10.01 to Xcel Energy Form 10-Q (file  no. 001-03034) dated Sept. 30, 2005.                                                                                                                              |
| 10.27*+ |   | Xcel Energy executive officer salaries, annual bonus  targets and long-term compensation awards for 2005 (Exhibit 10.27 to Form  10-K (file no. 001-03034) for the year ended Dec. 31, 2004).                                                                                                     |
| 10.28*+ |   | Amended Schedule of Participants for Xcel Energy  Senior Executive Severance and Change-in-Control Policy (Exhibit 10.28 to  Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).                                                                                                    |
| 10.29*+ |   | Xcel Energy Executive Annual Incentive Award Plan  Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy Form 10-Q  (file no. 001-03034) dated June 30, 2005).                                                                                                                         |
| 10.30*+ |   | Xcel Energy Omnibus Incentive Plan Form of  Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file  no. 001-03034) dated June 30, 2005).                                                                                                                                   |
| 10.31*+ |   | Xcel Energy Omnibus Incentive Plan Form of  Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no.  001-03034) dated June 30, 2005).                                                                                                                                       |
| 10.32*+ |   | Xcel Energy Omnibus Incentive Plan Form of  Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file  no. 001-03034) dated June 30, 2005).                                                                                                                                   |
| 10.33*  |   | Xcel Energy Omnibus 2005 Incentive Plan (Exhibit  10.01 to Form 8-K (file no. 001-03034) dated May 25, 2005).                                                                                                                                                                                     |

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| 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                                                                                                                                                                                                                                                         |
|   |   | 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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# **SCHEDULE II**

**NSP-MINNESOTAVALUATION AND QUALIFYING ACCOUNTSYears Ended Dec. 31, 2006, 2005 and 2004(Thousands of Dollars)**

 
|                                        | ** ** | ** **                                     | ** ** | **Additions**                                   | ** ** | ** **                                    | ** ** | ** **                        | ** ** |
|----------------------------------------|------------|------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|-----------------------------------|------------|
| ** **                             | ** ** | **Balance at  beginning  of period** | ** ** | **Charged  to costs &  expenses** | ** ** | **Charged  to other  accounts (1)** | ** ** | **Deductions  from  reserves(2)** | ** ** | **Balance  at end  of period** | ** ** |
| Reserve deducted from  related assets: |       |                                           |       |                                            |       |                                          |       |                              |       |   |   |
| Provision for  uncollectible accounts: |       |                                           |       |                                            |       |                                          |       |                              |       |   |   |
| 2006                                   |       | $                                              | 10,128     |                                            | $          | 19,972                                        |       | $                                 | 6,102      |   | $ | 22,794 |   | $ | 13,408 |   |
| 2005                                   |       | $                                              | 7,845      |                                            | $          | 13,997                                        |       | $                                 | 4,089      |   | $ | 15,803 |   | $ | 10,128 |   |
| 2004                                   |       | $                                              | 7,581      |                                            | $          | 15,688                                        |       | $                                 | 4,077      |   | $ | 19,501 |   | $ | 7,845 |   |

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(1)             Recovery of amountspreviously written off.

(2)             Principallyuncollectible 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  26, 2007** |                                                                                                 |

 

Pursuant to the requirements of the SecuritiesExchange Act of 1934, this report has been signed below by the followingpersons on behalf of the registrant and in the capacities and on the dateindicated.

 
| /s/ RICHARD C. KELLY                                                      |   | /s/ DAVID M. SPARBY                                                                                                                   |   |
|---------------------------------------------------------------------------|--------|---------------------------------------------------------------------------------------------------------------------------------------|--------|
| Richard C. Kelly    Chairman and Director   (Principal Executive Officer) |   | David M. Sparby   Executive Vice President, Acting President and     ChiefExecutive Officer   (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                        |   |                                                                                                                                  |   |

 

**SUPPLEMENTAL INFORMATION TO BEFURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BYREGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THEACT**

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

 

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