**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

 

| **(Mark One)** |
|----------------|
|           |
| **x**          | ** ** | **ANNUAL REPORT PURSUANT  TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
| ** **     | ** ** | ** ** |
|           |   | **For the fiscal year ended  Dec. 31, 2007** |
|           |   |   |
|           |   | **OR** |
|           |   |   |
| **o**          | ** ** | **TRANSITION REPORT  PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF  1934** |
| ** **     | ** ** | ** ** |
|           |   | **For the transition period  from                 to** |
|           |   |   |
|           |   | **COMMISSION FILE NUMBER  000-31387** |

 

**NORTHERN STATES POWERCOMPANY**

(Exact name of registrant as specified in itscharter)

 

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

 

**414 Nicollet Mall****Minneapolis, Minnesota 55401**

(Address of principal executive offices)(Zip Code)

 

**(612) 330-5500**

(Registrant’s telephone number, including areacode)

 

Securities registered pursuant to Section 12(b) ofthe Act:**  None**

 

Securities registered pursuant to Section 12(g) ofthe Act:**  CommonStock**

 

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

 

Indicateby check mark if the registrant is not required to file reports pursuant to Section 13or Section 15(d) of the ExchangeAct.    Yes  o    No  x

 

Indicateby check mark whether the registrant (1) has filed all reports required tobe filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90days.    Yes  x    No  o

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the bestof registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or anyamendment to this Form 10-K.  x

 

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large acceleratedfiler,” “accelerated filer” and “smaller reporting company” in Rule 12b-2of the Act.  (Check one):

 

o  Largeaccelerated filer    o  Acceleratedfiler    x Non-acceleratedfiler    o  SmallerReporting Company

 

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theAct).  Yes  o  No  x

 

Asof Feb. 25, 2008, 1,000,000 shares of common stock, par value $0.01 pershare, were outstanding, all of which were held by Xcel Energy Inc., aMinnesota Corporation.

 

**DOCUMENTS INCORPORATED BYREFERENCE: Xcel Energy Inc.’s Definitive Proxy Statement for its 2008Annual Meeting of Shareholders is incorporated by reference into Part IIIof this Form 10-K**

 

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

 

 

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**INDEX**

 
| **PART I**                                                                                                                   | ** ** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------|------------|------------|
| Item 1 — Business                                                                                                            |       |       |
| DEFINITION OF ABBREVIATIONS  AND INDUSTRY TERMS                                                                                   |       |       |
| COMPANY OVERVIEW                                                                                                                  |       |       |
| ELECTRIC UTILITY OPERATIONS                                                                                                       |       |       |
| Overview                                                                                                                          |       |       |
| Summary of Recent Federal  Regulatory Developments                                                                                |       |       |
| Public Utility Regulation                                                                                                         |       |       |
| Capacity and Demand                                                                                                               |       |       |
| Energy Sources and Related  Initiatives                                                                                           |       |       |
| Fuel Supply and Costs                                                                                                             |       |       |
| Wholesale  Commodity Marketing Operations                                                                                         |       |       |
| Nuclear  Power Operations and Waste Disposal                                                                                      |       |       |
| Electric Operating  Statistics                                                                                                    |       |       |
| NATURAL GAS  UTILITY OPERATIONS                                                                                                   |       |       |
| Public Utility  Regulation                                                                                                        |       |       |
| Capability and Demand                                                                                                             |       |       |
| Natural Gas Supply  and Costs                                                                                                     |       |       |
| Natural Gas  Operating Statistics                                                                                                 |       |       |
| ENVIRONMENTAL MATTERS                                                                                                             |       |       |
| EMPLOYEES                                                                                                                         |       |       |
| Item 1A — Risk Factors                                                                                                       |       |       |
| Item 1B —  Unresolved SEC Staff Comments                                                                                     |       |       |
| 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(T) —  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**                                                                                                                    | ** ** | ** ** |

 

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

 

2

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**PART I**

 

**Item l — Business**

 

# **DEFINITIONOF ABBREVIATIONS AND INDUSTRY TERMS**

 
| ***Xcel Energy Subsidiaries and Affiliates***                  |   |                                                                                                                                                                                                                                                                                                                                                                                                                              |
|----------------------------------------------------------------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| NMC                                                            |   | Nuclear  Management Co., a wholly owned subsidiary of NSP Nuclear Corporation                                                                                                                                                                                                                                                                                                                                                     |
| NSP-Minnesota                                                  |   | Northern  States Power Co., a Minnesota corporation                                                                                                                                                                                                                                                                                                                                                                               |
| NSP-Wisconsin                                                  |   | Northern  States Power Co., a Wisconsin corporation                                                                                                                                                                                                                                                                                                                                                                               |
| PSCo                                                           |   | Public  Service Company of Colorado, a Colorado corporation                                                                                                                                                                                                                                                                                                                                                                       |
| SPS                                                            |   | Southwestern  Public Service Co., a New Mexico corporation                                                                                                                                                                                                                                                                                                                                                                        |
| utility subsidiaries                                           |   | NSP-Minnesota,  NSP-Wisconsin, PSCo, SPS                                                                                                                                                                                                                                                                                                                                                                                          |
| Xcel Energy                                                    |   | Xcel Energy  Inc., a Minnesota corporation                                                                                                                                                                                                                                                                                                                                                                                        |
|                                                           |   |                                                                                                                                                                                                                                                                                                                                                                                                                              |
| ***Federal and State Regulatory Agencies***                    |   |                                                                                                                                                                                                                                                                                                                                                                                                                              |
| DOE                                                            |   | United  States Department of Energy                                                                                                                                                                                                                                                                                                                                                                                               |
| 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.                                                                                                                                                   |
| NERC                                                           |   | North American Electric  Reliability Council                                                                                                                                                                                                                                                                                                                                                                                      |
| 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.                                                                                                                                                                                                                                                                                                                         |
| PSCW                                                           |   | Public  Service Commission of Wisconsin. The state agency that regulates the retail  rates, services, securities issuances and other aspects of NSP-Wisconsin’s  operations in Wisconsin.                                                                                                                                                                                                                                    |
| 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                                                                                                                                                                                                                                                                                                                                                                                               |
|                                                           |   |                                                                                                                                                                                                                                                                                                                                                                                                                              |
| ***Electric, Purchased Gas and Resource  Adjustment Clauses*** |   |                                                                                                                                                                                                                                                                                                                                                                                                                              |
| DSM                                                            |   | Demand-side management.  Energy conservation, weatherization and other programs to conserve or manage  energy use by customers.                                                                                                                                                                                                                                                                                                   |
| 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.                                                         |
| TCR                                                            |   | Transmission  cost recovery adjustment. Allows NSP-Minnesota to                                                                                                                                                                                                                                                                                                                                                                   |

 

3

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|                                |   | recover the cost of  transmission facilities not included in the determination of NSP-Minnesota’s  base electric rates in retail electric rates in Minnesota. The TCR was  approved by the MPUC in 2006 to be effective in 2007 and will be revised  annually as new transmission investments and costs are incurred.                                                                                                                                                                                                                                                                                                                                                                                                              |
|-------------------------------------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| ***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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| BART                                |   | Best Available Retrofit  Technology                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| CO2                                 |   | Carbon dioxide                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| CAIR                                |   | Clean Air Interstate Rule                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| CAMR                                |   | Clean Air Mercury Rule                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| COLI                                |   | Corporate-owned life  insurance                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| GHG                                 |   | Greenhouse  Gas                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| JOA                                 |   | Joint  operating agreement among the Utility Subsidiaries                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| Moody’s                        |   | Moody’s  Investor Services Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |

 

4

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| MPCA                             |         | Minnesota  Pollution Control Agency                                                                                                                                                                                                                                                                                                              |
|----------------------------------|--------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 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.                                                                                                                     |
| NOx                              |         | Nitrogen  oxide                                                                                                                                                                                                                                                                                                                                  |
| 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.                                                                                                                                                                       |
| PUHCA                            |         | Public  Utility Holding Company Act of 2005. Successor to the Public Utility Holding  Company Act of 1935, enacted to regulate the corporate structure and  financial operations of utility holding companies. Eliminates most federal  regulation of utility holding companies. Transfers other regulatory authority  from the SEC to the 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                                                                                                                                                                                                                                                                                                                                  |
| SPP                              |         | Southwest  Power Pool, Inc.                                                                                                                                                                                                                                                                                                                 |
| Standard &  Poor’s |         | Standard &  Poor’s Ratings Services                                                                                                                                                                                                                                                                                                |
| 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.                                                                                                                                                                           |
|                             |         |                                                                                                                                                                                                                                                                                                                                             |
| ***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                                                                                                                                                                                                                                                                                                                                |

 

5

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| MW   |   | Megawatts  (one MW equals one thousand KW)                                                                                                                                   |
|------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 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. |

 

6

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# **COMPANYOVERVIEW**

#  

NSP-Minnesota was 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 approximately10 percent of the total sales in 2007. 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 natural gasutility service to approximately 0.5 million customers.  Approximately 90 percent of NSP-Minnesota’sretail electric operating revenues were derived from operations in Minnesotaduring 2007.  Generally, NSP-Minnesota’searnings comprise approximately 35 percent to 45 percent of Xcel Energy’sconsolidated net income.

 

The electric production and transmission system of NSP-Minnesota ismanaged as an integrated system with that of NSP-Wisconsin, jointly referred toas the NSP System.  The electricproduction and transmission costs of the entire NSP System are shared byNSP-Minnesota and NSP-Wisconsin.  AFERC-approved agreement between the two companies, called the InterchangeAgreement, provides for the sharing of all costs of generation and transmissionfacilities of the NSP System, including capital costs.

 

NSP-Minnesota owns the following direct subsidiaries: United Power andLand Co., which holds real estate; and NSP Nuclear Corp., which owns NMC.

 

NSP-Minnesota conducts its utility business in the following reportablesegments: Regulated Electric Utility, Regulated Natural Gas Utility and AllOther.  Comparative segment revenues andrelated financial information for fiscal 2007, 2006 and 2005 are set forth in Note15 to the accompanying consolidated financial statements.

 

NSP-Minnesota focuses on growing through investments in electric andnatural gas rate base to meet growing customer demands, environmental andrenewable energy initiatives and to maintain or increase reliability andquality of service to customers. NSP-Minnesota files periodic rate cases with state and federalregulators to earn a return on its investments and recover costs of operations.

 

# **ELECTRICUTILITY OPERATIONS**

#  

**Overview**

 

***Climate Changeand Clean Energy –******Like most other utilities,NSP-Minnesota is subject to a significant array of environmental regulationsfocused on many different aspects of its operations.  There are significant future environmentalregulations under consideration to encourage the use of clean energytechnologies and regulate emissions of GHGs to address c*****limate change.  NSP-Minnesota’s** electricgenerating facilities are likely to be subject to regulation under climatechange policies introduced at either the state or federal level within the nextfew years.  Several of the states inwhich we operate have proposed or implemented clean energy policies, such asrenewable energy portfolio standards or DSM programs, in part designed to reducethe emissions of GHGs.  Congress andfederal policy makers are considering climate change legislation and a varietyof national climate change policies. NSP-Minnesota is advocating with state and federal policy makers forclimate change and clean energy policies that will result in significantlong-term reduction in GHG emissions, develop low-emitting technologies andsecure, cost-effective energy supplies for our customers and our nation.

 

While NSP-Minnesota is not currently subject to state or federal limitson its GHG emissions, NSP-Minnesota has undertaken a number of initiatives toprepare for climate change regulation and reduce our GHG emissions. Theseinitiatives include emission reduction programs, energy efficiency andconservation programs, renewable energy development and technology explorationprojects.  Although the impact of climatechange policy on NSP-Minnesota will depend on the specifics of state andfederal policies and legislation, NSP-Minnesota believes that, based on priorstate commission practice, NSP-Minnesota would be granted the authority torecover the cost of these initiatives through rates.

 

***UtilityRestructuring and Retail Competition***—The FERC hascontinued with its efforts to promote more competitive wholesale marketsthrough open-access transmission and other means.  As a consequence, NSP-Minnesota can purchasefrom competing wholesale suppliers and use the transmission systems of theutility subsidiaries on a comparable basis to the utility subsidiaries’ toserve their native load.  NSP-Minnesotasupports the continued development of wholesale competition andnon-discriminatory wholesale open-access transmission services.

 

7

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The retail electric business faces 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,it believes its rates are competitive with currently available alternatives.

 

**Summary of Recent FederalRegulatory Developments**

** **

The FERC has jurisdiction over rates for electric transmission servicein interstate commerce and electricity sold at wholesale, hydro facilitylicensing, natural gas transportation, accounting practices and certain otheractivities of NSP-Minnesota. State and local agencies have jurisdiction overmany of NSP-Minnesota’s activities, including regulation of retail rates andenvironmental matters. In addition to the matters discussed below, seeNote 11 to the consolidated financial statements for a discussion of otherregulatory matters.

 

***FERC Rules ImplementingEnergy Policy Act of 2005 (Energy Act) —*** The Energy Act repealed PUHCA effective Feb. 8,2006. In addition, the Energy Act required the FERC to conduct severalrulemakings to adopt new regulations to implement various aspects of the EnergyAct. Since August 2005, the FERC has completed several rulemakingproceedings to modify its regulations on a number of subjects, including:

 

·                  Adopting regulations to establish anational Electric Reliability Organization (ERO) to replace the voluntary NERCstructure and requiring the ERO to establish mandatory electric reliabilitystandards and imposition of financial or other penalties for violations ofadopted standards;

·                  Certifyingthe NERC as the ERO and adopting rules making 83 NERC reliabilitystandards mandatory and subject to potential financial penalties up to $1million per day per violation for non-compliance effective June 18, 2007;and approving delegation agreements between NERC and various regional entities,including the Midwest Reliability Organization (MRO), SPP and WesternElectricity Coordinating Council (WECC), whereby the regional entities will beresponsible for regional enforcement of approved NERC standards.  On Dec. 21, 2007, the FERC approvedseven additional NERC mandatory standards to be effective in first quarter2008;

·                  Adopting rules allowingutilities in organized wholesale energy markets such as MISO and SPP to seek toeliminate their mandatory Public Utility Regulatory Policies Act (PURPA) QFpower purchase obligations; and

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

 

During 2007, both state and federal legislativeinitiatives were introduced, with the Xcel Energy subsidiaries taking an activerole in their development.

 

WhileNSP-Minnesota cannot predict the ultimate impact the new regulations will haveon its operations or financial results, NSP-Minnesota is taking actions thatare intended to comply with and implement these new rules and regulationsas they become effective.

 

***Electric Transmission RateRegulation —***The FERC regulates the rates charged and terms and conditions for electrictransmission services.  FERC policyencourages utilities to turn over the functional control over their electrictransmission assets and the related responsibility for the sale of electrictransmission services to an RTO. NSP-Minnesota and NSP-Wisconsin are members ofthe MISO RTO. Each RTO separately files regional transmission tariff rates forapproval by the FERC. All members within that RTO are then subjected to thoserates.

 

OnFeb. 15, 2007, the FERC issued final rules (Order No. 890)adopting revisions to its open access transmission service rules. Xcel Energysubmitted the required compliance revisions to its Open Access TransmissionTariff (OATT) on July 13, 2007, Sept. 11, 2007 and Dec. 7, 2007, asrequired. The compliance filings are pending FERC action.  On Dec. 28, 2007, the FERC issued anorder on rehearing making certain modifications to Order No. 890.  The revised rules will be effective in March 2008.  Xcel Energy is now reviewing the amendedfinal rules.

 

Inaddition, in January 2007, the FERC issued interim and proposed rules tomodify the current FERC standards of conduct rules governing the functionalseparation of the Xcel Energy electric transmission function from the wholesalesales and marketing function. The proposed rules are pending final FERCaction.

 

WhileNSP-Minnesota cannot predict the ultimate impact the new regulations will have onits operations or financial results, NSP-Minnesota is taking actions that areintended to comply with and implement these new rules and regulations asthey become effective.

 

***Centralized Regional WholesaleMarkets —***FERC rules allow RTOs to operate centralized regional wholesale energy

 

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markets.  In April 2005, MISO began operation of a“Day 2” regional day-ahead and real time wholesale energy market. MISO usessecurity constrained regional economic dispatch and congestion management usingLocational Marginal Pricing (LMP) and FTRs. The Day 2 market is intended toprovide more efficient generation dispatch over the 15 state MISO region,including the NSP System

 

In September 2007,MISO filed for FERC approval to establish a centralized regional wholesaleancillary services market (ASM) in the second quarter of 2008.  The ASM is intended to provide furtherefficiencies in generation dispatch by allowing for regional regulationresponse and contingency reserve services through a bid-based market mechanismco-optimized with the Day 2 energy market. In addition, MISO would consolidatethe operation of approximately 20 existing NERC approved balancing authorities(the entity responsible for maintaining reliable operations for a definedgeographic region) into a single regional balancing authority.  Xcel Energy generally supports implementationof the ASM, because it is expected to allow native NSP System generation to beused more efficiently, as certain generation will not always need to be held inreserve and to facilitate the operation of intermittent wind generation on theNSP System required to achieve state-mandated renewable energy supplystandards. Comments on the ASM proposal were filed on Oct. 15, 2007 andthe FERC held a technical conference on certain market power issues in November 2007.  The proposal is pending FERC action.  If the FERC approves the ASM tariff in February 2008without material conditions, and if MISO can demonstrate system and operationreadiness, MISO would implement the ASM on June 1, 2008.  If approved by the FERC, NSP-Minnesota andNSP-Wisconsin expect to file for state regulatory approvals, as necessary, torecover ASM costs via their fuel and purchased energy cost recovery mechanismsin first quarter 2008.

 

In another developmentaffecting regional wholesale markets, in December 2007, MISO and some MISOtransmission owners, including NSP-Minnesota and NSP-Wisconsin, filed proposedchanges to the MISO TEMT affecting the revenue distribution of transmissionrevenues.  Without the proposed tariffchange, certain MISO transmission owners would experience an increase inprospective transmission revenues, while the revenues to other MISO transmissionowners would correspondingly decrease. The proposed change did not affect 2007 results, but would essentiallypreserve the historic allocation of transmission service revenues in 2008 andfuture years.  In December 2007,Ameren - Union Electric (Ameren UE) protested the proposed change.  In February 2008, the FERC issued anorder accepting the MISO tariff change effective February 2008 andrejecting the Ameren-UE protest.

 

***Market Based Rate Rules ******—***In June 2007, the FERCissued a final order governing its market-based rate authorizations to electricutilities. The FERC reemphasized its commitment to market-based pricing, but isrevising the tests it uses to assess whether a utility has market power and hasemphasized that it intends to exercise greater oversight where it hasmarket-based rate authorizations. NSP-Minnesota has been granted market-basedrate authority and will be subject to the new rule.

 

**Public Utility Regulation**

** **

***Summary ofRegulatory Agencies and Areas of Jurisdiction —***Retailrates, services and other aspects of NSP-Minnesota’s operations are regulatedby the MPUC, the NDPSC and the SDPUC within their respective states. The MPUChas regulatory authority over aspects of NSP-Minnesota’s financial activities,including security issuances, property transfers, mergers and transactionsbetween NSP-Minnesota and its affiliates. In addition, the MPUC reviews andapproves NSP-Minnesota’s electric resource plans for meeting customers’ futureenergy needs. The MPUC also certifies the need for generating plants greaterthan 50 MW and transmission lines greater than 100 KV.

 

No large power plant or transmission line may be constructed inMinnesota except on a site or route designated by the MPUC. The NDPSC and SDPUChave regulatory authority over the need for certain generating and transmissionfacilities and the siting and routing of certain new generation andtransmission facilities in North Dakota and South Dakota, respectively.

 

NSP-Minnesota is subject to the jurisdiction of the FERC with respectto its wholesale electric operations, hydroelectric licensing, accountingpractices, wholesale sales for resale and the transmission of electricity ininterstate commerce. NSP-Minnesota has received authorization from the FERC tomake wholesale electric sales at market-based prices (see market-based rateauthority discussion) and is a transmission-owner member of the MISO RTO.

 

***Fuel, Purchased Energy and Conservation Cost RecoveryMechanisms —***NSP-Minnesota’s retail electricrate schedules 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-Minnesotais permitted to recover these costs through FCA mechanisms individuallyapproved by the regulators in each jurisdiction.

 

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The FCA mechanisms allow NSP-Minnesota to billcustomers for the cost of fuel and fuel related costs used to generateelectricity at its plants and energy purchased from other suppliers. In December 2006,the MPUC authorized FCA recovery of all MISO Day 2 charges, except certainadministrative charges, which NSP-Minnesota is partially recovering in baserates and partially deferring for future recovery. In general, capacity costsare not recovered through the FCA. NSP-Minnesota’s electric wholesale customersalso have a FCA provision in their contracts.

 

NSP-Minnesota is required by Minnesota law to spend aminimum of 2 percent of Minnesota electric revenue on conservation improvementprograms. These costs are recovered through an annual cost recovery mechanismfor electric conservation and energy management program expenditures.NSP-Minnesota is required to request a new cost recovery level annually.  While this law will change to a savings-basedrequirement beginning in 2010, the costs of providing qualified conservationimprovement programs will continue to be recoverable through a rate adjustmentmechanism.

 

***MERP RiderRegulation —***In December 2003, the MPUCapproved NSP-Minnesota’s MERP proposal to convert two coal-fueled electricgenerating plants to natural gas and to install advanced pollution controlequipment 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. The first MERP project at the A. S. Kingplant went into service in July 2007 with the remaining two projects (HighBridge and Riverside) expected to begin operations in 2008 and 2009, respectively,at a cumulative investment of approximately $1 billion. The MPUC approved arate rider to recover prudent costs of the projects from Minnesota customersbeginning Jan. 1, 2006, including a rate of return on the constructionwork in progress. The MPUC approval has a sliding ROE scale based on actualconstruction cost compared with a target level of construction costs (based onan equity ratio of 48.5 percent and a debt ratio of 51.5 percent) toincentivize NSP-Minnesota to control construction costs. At Dec. 31, 2007,the estimated ROE was 10.7 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    |       |

 

**Capacity and Demand**

 

Uninterrupted system peak demand for the NSP System’s electric utilityfor each of the last three years and the forecast for 2008, assuming normalweather, are listed below.

 
| ** ** | ** ** | **System Peak Demand (in MW)** | ** ** |
|------------|------------|----------------------------------------------------|------------|
| ** ** | ** ** | **2005**                                           | ** ** | **2006** | ** ** | **2007** | ** ** | **2008 Forecast** | ** ** |
| NSP System |       | 9,104                                              |       | 9,859 |   | 9,427 |   | 9,737 |   |

 

The peak demand for the NSP System typically occurs in the summer.  The 2007 system peak demand for the NSPSystem occurred on July 26, 2007.

 

**Energy Sources and Related Transmission Initiatives**

** **

NSP-Minnesota expects to use existing electricgenerating stations, power purchases, DSM options, new generation facilitiesand phased expansion of existing generation at select power plants to meet itssystem capacity requirements.

 

***PurchasedPower —***NSP-Minnesota has contractualarrangements to purchase power from other utilities and independent powerproducers.  Capacity is the measure ofthe rate at which a particular generating source produces electricity.  Energy is a measure of the amount of electricityproduced from a particular generating source over a period of time.  Long-term purchase power contracts typicallyrequire a periodic payment to secure the capacity from a particular generatingsource and a charge for the associated energy actually purchased from suchgenerating source.

 

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NSP-Minnesota also makes short-term purchases toreplace generation from company-owned units that are unavailable due tomaintenance and unplanned outages, to comply with minimum availabilityrequirements, to obtain energy at a lower cost and for various other operatingrequirements.

 

***PurchasedTransmission Services —***In addition to usingtheir integrated transmission system, NSP-Minnesota and NSP-Wisconsin havecontractual arrangements with MISO and regional transmission service providersto deliver power and energy to the NSP System for native load customers, whichare retail and wholesale load obligations with terms of more than one year.

 

***Excelsior Energy Inc. (Excelsior) —****** ***In December 2005, Excelsior, anindependent energy developer, filed a power purchase agreement with the MPUCseekinga declaration that NSP-Minnesota be compelled to enter into an agreement topurchase the output from two integrated gas combined cycle (IGCC) plants to belocated in northern Minnesota as part of the Mesaba Energy Project. Excelsiorfiled this petition making claims pursuant to Minnesota statutes relating to anInnovative Energy Project and Clean Energy Technology. NSP-Minnesotaopposed the petition.

 

The MPUC referred this matter toa contested case hearing before an ALJ to act on Excelsior’s petition.  The contested case proceeding considered a600 MW unit in phase I and a second 600 MW unit in phase II of the MesabaEnergy Project.

 

The MPUCissued its order for phase 1 of the hearing on Aug. 30, 2007.  In it, the MPUC found that:

 

·                  TheMesaba Energy Project is an innovative energy project under the applicablestatute,

·                  Theterms and conditions of the proposed purchased power agreement are inconsistentwith the public interest and are denied,

·                  Excelsiorand NSP-Minnesota should resume negotiations towards an acceptable purchasedpower agreement, with assistance from the Minnesota Department of Commerce(MDOC) and the guidance provided by the order, and

·                  TheMPUC will explore a statewide market for the output of this project.

 

The MPUCdenied rehearing, except for certain clarifications and requiring statusreports on negotiations.  Excelsiorappealed the MPUC’s decision in December 2007.  The Minnesota Court of Appeals dismissed theappeal as premature because the MPUC’s order on phase I is not final agencyaction on the entire case.

 

Meanwhile, theALJ issued a decision in Phase 2 of this proceeding, recommending denial ofExcelsior’s proposed purchased power agreement for a second IGCC project.Exceptions and replies have been filed. The MPUC is expected to take up thismatter in 2008.

 

***Greenhouse GasEmissions******—******The 2007Minnesota legislature adopted***the goal to reducestatewide GHG emissions across all sectors producing those emissions to a levelat least 15 percent below 2005 levels by 2015, to a level at least 30 percentbelow 2005 levels by 2025 and to a level at least 80 percent below 2005 levelsby 2050.

 

The legislation prohibits theconstruction within Minnesota of a new large energy facility, the import or commitmentto import from outside Minnesota power from a new large energy facility, orentering into a new long-term power purchase agreement that would increasestatewide power sector CO2 emissions.  The statute does not impose limitations on CO2or other GHG emissions on NSP-Minnesota and provided certain exemptions.On Feb. 1, 2008, the MDOC submitted to the legislature a climate changeaction plan that proposes certain changes to meet the requirements of thissection.

 

***Renewable Energy Standard (RES)******—****** ***The 2007 Minnesota legislatureadopted a RES statute requiring NSP-Minnesota to acquire 30 percent of itsenergy requirements by 2020 from qualifying renewable sources, of which 25percent must be wind energy. The legislation allows all NSP-Minnesota renewableresources to count toward meeting the standard. Costs associated with complyingwith the standard are recoverable through automatic recovery mechanisms.

 

NSP-Minnesotahas filed with the MPUC an renewable energy plan detailing its plans for addingwind resources.  This plan seeks toachieve balance in the wind portfolio, with roughly half of new resources beingowned by NSP-Minnesota and achieving roughly proportionate shares betweencommunity-based energy developments, other power purchase agreements andutility projects.

 

***Conservation and DSM Legislation —***The2007 Minnesota legislature adopted a statute establishing a statewide goal

 

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to reduceenergy demand by 1.5 percent per year and fossil fuel use by 15 percent. Thebill requires utilities to propose conservation and DSM programs that achieveat least 1.0 percent per year reduction in energy demand, subject tolimitations regarding excessive costs for customers, reliability or othernegative consequences.  The statute alsoallows utilities to fund internal infrastructure changes that will contributeto lower energy use and provides for cost recovery outside a rate case for suchprojects.

 

***NSP SystemResource Plan —*******OnDec. 14, 2007, NSP-Minnesota filed its 2007 resource plan with theMPUC.  The plan**incorporatesthe actions needed to comply with expansive new legislation regarding GHGemissions control, renewable energy procurement and DSM adopted by the 2007Minnesota legislature.  Due to the expansionof wind generation procurement and DSM obligations, the plan indicates that thetype of incremental resources has changed from prior plans.  Key highlights of the plan include:

 

·                  Additional wind generation resourcesof 2,600 MW, allowing NSP-Minnesota to comply with our RES of 30 percentrenewable energy by 2020.

·                  Increases in DSMof approximately 30 percent energy savings and 50 percent demand savings.

·                  Seek license renewals for Prairie Island’stwo units through 2033 and 2034, respectively, and expand capacity at PrairieIsland by 160 MW and Monticello by 71 MW.

·                  Request approval to make environmentalupgrades at Sherburne County (Sherco), while expanding capacity by 80 MW. Theenvironmental upgrades would result in a significant reduction in overall SO2,NOx and mercury emissions from the facility.

·                  Negotiate and seek approval of purchases fromManitoba Hydro Electric Board (Manitoba Hydro) for 375 MW of intermediate and350 MW of peaking resources beginning in 2015.

·                  Incrementalpeaking and intermediate generation needs of 2,300 MWs.

·                  Carbon emissionreductions of 22 percent below 2005 levels by 2020, a six million tonreduction.

 

The MPUC will set a schedulefor consideration of the plan early in 2008.

 

***NSP-Minnesota Base Load AcquisitionProceeding —***On Nov. 1, 2006,NSP-Minnesota filed a proposal with the MPUC for a purchase of 375 MW ofcapacity and energy from Manitoba Hydro for 2015-2025 and the purchase of380 MW of wind energy to fulfill the base load need identified in the 2004resource plan.  An alternate supplierproposed a 375 MW share of a lignite coal generation plant to be located inNorth Dakota and 380 MW of wind energy generation, with an option for Xcel Energyownership in both components.  The MPUCreferred the matter to a contested case proceeding.

 

On July 20,2007, NSP-Minnesota filed a petition asking to suspend the proceeding untilNSP-Minnesota can complete its analysis of the impact of the RES and conservationgoals on its need for additional resources, as outlined in the July 20,2007 Notice of Changed Circumstance in the resource plan.

 

In September 2007,the MPUC approved NSP-Minnesota’s Notice of Changed Circumstance and requiredNSP-Minnesota to file a new resource plan by Dec. 14, 2007. NSP-Minnesotafiled the 2007 resource plan, along with a proposal for closing this proceedingas the new plan does not indicate a base load resource need.  The MPUC is expected to take up matter ofschedule for the base load proceeding in early 2008.

 

***Additional Base Load Capacity Projects forSherco, Monticello and Prairie Island******—***The MPUC order in the 2004NSP-Minnesota resource plan indicated that additional capacity from the Sherco,Monticello and Prairie Island plants would be cost-effective and should bepursued.  On July 20, 2007,NSP-Minnesota filed a Notice of Changed Circumstance with the MPUC seeking todelay these proceedings until NSP-Minnesota can complete its analysis of theimpact of the RES and conservation goals on its need for additionalresources.  In September 2007, MPUCapproved the Notice of Changed Circumstance and directed NSP-Minnesota to filea new resource plan by Dec. 14, 2007. NSP-Minnesota filed the 2007 resource plan, which confirms thecost-effectiveness of these projects and proposed to initiate filings forapproval to pursue these projects in the first half of 2008.

 

***NSP-Minnesota Transmission Certificates of Need —***In March 2003, the MPUC granted fourcertificates of need to NSP-Minnesota for the construction of varioustransmission system upgrades for up to 825 MW of renewable energy generation(wind and biomass) in southwest and western Minnesota.

 

The MPUC granted routingpermits in 2004-2005 for the major transmission facilities. NSP-Minnesotaexpects to complete the transmission construction in 2008 at a cost ofapproximately $230 million.  As of Dec. 20,2007, MISO has determined the new transmission facilities already installedprovide transmission outlet capacity for up to 900 MW of renewable generation.

 

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In late 2006,NSP-Minnesota filed applications for certificates of need with the MPUC forthree additional transmission lines in southwestern Minnesota and one inChisago County, Minn.  In  2007, the MPUC issued a certificate of needauthorizing NSP-Minnesota to construct three new 115 KV transmission lines(totaling 35 to 50 miles) in southwestern Minnesota to provide approximately350 MW of incremental transmission delivery capacity for wind generation. Thethree projects, including associated substations, are expected to cost $72.5million. The MPUC order required NSP-Minnesota to file required route permitapplications by January 2008 and complete construction by Spring 2009. Theroute permit applications were filed with the MPUC and SDPUC as required, andare pending MPUC and SDPUC action.

 

In January 2008,the MPUC voted to grant NSP-Minnesota a certificate of need for the ChisagoCounty, Minnesota project, which would replace an existing 69 KV line with 115and 161 KV facilities and add a new substation at an estimated cost of $64million and a route permit for the majority of the proposed line.  The MPUC set the issue of the disputed routefor a half-mile segment of the line for further discussions between theparties.  The project would be placed inservice in 2010.  The PSCW has alreadyapproved construction by NSP-Wisconsin and Dairyland Power Cooperative ofrelated 161 KV facilities in Wisconsin.

 

As part ofCAPX 2020, NSP-Minnesota and Great River Energy (on behalf of nine otherregional transmission providers) filed a certificate of need application in August 2007,for three 345 KV transmission lines serving Minnesota and parts of surroundingstates. The current schedule targets an MPUC order by the end of 2008 or early2009.  The three lines would includeconstruction of approximately 700 miles of new facilities at a cost of $1.4 to$1.7 billion, with construction to be completed in phases between 2011 and2015. The application put forth a potential ownership percentage of 36 to 72percent for each of the three 345 KV projects for NSP-Minnesota andNSP-Wisconsin (combined). Updated NSP-Minnesota and NSP-Wisconsin costestimates are expected following the negotiation of project agreementsoutlining the terms and conditions related to construction management,ownership, operations and maintenance of these facilities.

 

***FCA Investigation******—*********In 2003, the MPUCopened an investigation to consider the continuing usefulness of the FCAs forelectric utilities in Minnesota. There was no further activity until the MPUCissued a notice for comments on April 5, 2007, as to whether to continuethe statewide investigation.

 

Pursuant to the notice, utilities in Minnesota, the MDOC and theMinnesota Office of Attorney General (MOAG) filed initial and reply comments onApril 30, 2007 and June 1, 2007, respectively. The utilitiesgenerally argued the 2003 investigation could be closed, with remaining issuesaddressed in the separate investigation initiated by the Dec. 20, 2006,order in the MISO Day 2 cost recovery docket. The MDOC filed comments seekingto continue the investigations. In response, the utilities filed additionalcomments on Sept. 28, 2007 that indicated a willingness to continue with theinvestigation and provide more information to both regulators and customersregarding fuel and purchased power costs, plant outages and other factorsaffecting fuel clause levels. Continued discussions among utilities, the MDOC,MOAG and business customers regarding appropriate FCA reporting detail andprovision of additional information to customers is on-going.

 

***Grand Meadow Wind Farm******—*** In June 2007, NSP-Minnesota filed an application for acertificate of need for the Grand Meadows wind farm, a 100-MW development to belocated in southeast Minnesota. The Grand Meadows project would be implementedunder a build-own-transfer agreement between NSP-Minnesota and enXco, a windproject developer. Total project costs are estimated to be approximately $213million. The MPUC approved the certificate of need and issued a sitepermit.  Construction is expected tostart in early 2008.

 

***Capital Structure Petition******—*** In December 2007, theMPUC approved NSP-Minnesota’s regular annual capital structure petition forongoing security issuance and increased capitalization.

 

***Mercury Reductionand Emissions Reduction Filings - ***Pursuantto Minnesota law, in December 2007, NSP-Minnesota filed a plan with theMPCA and MPUC for reducing mercury emissions by up to 90 percent at the Shercounit 3 and King plants.  Estimatedproject costs amount to approximately $9.1 million.  At the same time, NSP-Minnesota submitted arevised filing to the MPUC for a major emissions reduction project at ShercoUnits 1and 2 to reduce emissions and expand capacity.  The revised filing has estimated projectcosts of approximately $1.1 billion.  Thefiling also contains alternatives for the MPUC to consider additional capacityand to achieve lower emissions.  Ifselected, these alternatives could range from $90.8 million to $330.8 millionin addition to the $1.1 billion proposal. NSP-Minnesota’s investments aresubject to the MPUC approval of a cost recovery mechanism.

 

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***Nuclear PowerOperations and Waste Disposal***—******NSP-Minnesota owns two nuclear generating plants: theMonticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants atNote 12 to the consolidated financial statements.

 

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

 

*Low-Level Radioactive Waste Disposal  **—***Federallaw places responsibility on each state for disposal of its low-levelradioactive waste (LLW) generated within its borders.  LLW from NSP-Minnesota’s Monticello andPrairie Island nuclear plants is currently disposed at the Barnwell facilitylocated in South Carolina (all classes of LLW) and at the Clive facilitylocated in Utah (class A LLW only). NSP-Minnesota has an annual contract with Barnwell that is scheduled toexpire on June 30, 2008, but is also able to utilize the Clive facilitythrough various LLW processors. NSP-Minnesota has storage capacity available on-site at Prairie Islandand Monticello that would allow both plants to continue to operate until theend of their current licensed lives, if off-site LLW disposal facilities werenot available to NSP-Minnesota.

 

*High-Level Radioactive Waste Disposal**—***The federalgovernment has the responsibility to dispose of, or permanently store, domesticspent 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-site storage for spent nuclearfuel at its Monticello and Prairie Island nuclear plants.

 

·                  In 1993, the Prairie Island plant waslicensed by the federal NRC to store up to 48 casks of spent fuel at the plant.

·                  In 1994, the Minnesota legislatureadopted a limit on dry cask storage of 17 casks.

·                  In 2003, the Minnesota legislatureenacted revised legislation that will allow NSP-Minnesota to continue tooperate the facility and store spent fuel there until its current licenses withthe NRC expire in 2013 and 2014.  Thelegislation transfers the primary authority concerning future spent-fuel storageissues from 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 MPUC authorizedan on-site storage facility and 30 casks at Monticello, which will allow theplant to operate to 2030.  The MPUCdecision became effective June 1, 2007.

·                  As of Dec. 31, 2007, there were24 casks loaded and stored at the Prairie Island plant.

 

See Note 13 in the consolidated financial statementsfor further discussion of the matter.

 

*PFS  **—***NSP-Minnesota is part of aconsortium of private parties working to establish a private facility forinterim storage of spent nuclear fuel. In 1997, PFS filed a license application with the NRC for a temporarystorage site for spent nuclear fuel on the Skull Valley Indian Reservation inUtah.  On Feb. 28, 2006, the NRCcommissioners issued the license for PFS. 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 holdin abeyance future investments in the construction of PFS as long as there isapparent and continuing progress in federally sponsored initiatives forstorage, reuse, and/or disposal for the nation’s spent nuclear fuel. In September 2006,the Department of the Interior issued two findings: (1) that it would notgrant the leases for rail or intermodal sites and (2) that it was revokingits previous conditional approval of the site lease between PFS and the SkullValley Indian tribe even though the conditions had been met.  The stated reasons were principally lack ofprogress at Yucca Mountain and lack of Bureau of Indian Affairs staff to monitorthis activity.  Both findings areexpected to be appealed.

 

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*Prairie Island Steam Generator Replacement  **—***Prairie Island Unit 2 steam generators received required inspections during ascheduled 2005 outage.  Based on currentrates of degradation and available repair processes, NSP-Minnesota plans toreplace these steam generators in the 2013 regular refueling outage.

 

*Nuclear Plant Re-licensing*****— Monticello’s renewed license expires in 2030 and PrairieIsland’s licenses for its two units expire in 2013 and 2014.  NRC approved Monticello’s renewed license in November 2006and the MPUC order approving additional spent fuel storage to support twentyadditional years of operation went into effect in June 2007.  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.

 

*Nuclear Plant Power Uprates*—* *NSP-Minnesotais seeking approval to increase the capacity of all three nuclear units by atotal of approximately 235 MW, to be implemented, between 2009 and 2015.  The life extension and a capacity increasefor Prairie Island Unit 2 is contingent on replacement of Unit 2’s originalsteam generators, currently planned for replacement during the refueling outagein 2013.  Capital investments for lifecycle management and power uprate activities through 2007 have totaledapproximately $40 million.  For the years2008 through 2015, spending is estimated at $1.1 billion.  NSP-Minnesota plans to seek approval for analternative recovery mechanism from customers of its nuclear costs.  NSP-Minnesota plans to submit thecertificates of need for the Monticello uprate and the Prairie Island uprate inthe first quarter of 2008.

 

*NMC* — On Sept. 28, 2007, NSP-Minnesotaobtained 100 percent ownership in NMC as a result of WEC exiting thepartnership due to the sale of its Point Beach Nuclear Plant to FPLEnergy.  Accordingly, the results of operationsof NMC and the estimated fair value of assets and liabilities were consolidatedin NSP-Minnesota’s consolidated financial statements from the Sept. 28, 2007transaction date.  WEC was required topay an exit fee and surrender all of its equity interest in NMC uponexiting.  The effect of this transactionwas not material to the financial position or the results of operations toNSP-Minnesota.  NSP-Minnesota is in theprocess of reintegrating its nuclear operations into its generation operationsand apply to the NRC to transfer the nuclear operating licenses from NMC toNSP-Minnesota.  The transfer of licensesis expected to be completed in 2008.

 

For further discussion of nuclear obligations, seeNote 13 to the consolidated financial statements.

 

**Fuel Supply and Costs**

 

The following table shows the delivered cost per MMBtu of eachsignificant category of fuel consumed for electric generation, the percentageof total fuel requirements represented by each category of fuel and the totalweighted average cost of all fuels.

 
| **NSP System**        | ** ** | **Coal***  | ** ** | **Nuclear** | ** ** | **Natural Gas** | ** ** | **Average Fuel** | ** ** |
|----------------------------|------------|------------|------------|-------------|------------|----------------------|------------|-----------------------|------------|
| **Generating Plants** | ** ** | **Cost**   | ** ** | **Percent** | ** ** | **Cost**             | ** ** | **Percent**           | ** ** | **Cost** | ** ** | **Percent** | ** ** | **Cost** | ** ** |
| ** **                 | ** ** | ** ** | ** ** | ** **  | ** ** | ** **           | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| 2007                       |       | $          | 1.56       |        | 57         | %                    | $          | 0.51                  |       | 38 | % | $ | 7.60 |   | 4 | % | $ | 1.47 |   |
| 2006                       |       | 1.12       |       | 59          |       | 0.46                 |       | 38                    |       | 7.28 |   | 3 |   | 1.08 |   |
| 2005                       |       | 1.04       |       | 60          |       | 0.46                 |       | 36                    |       | 8.32 |   | 3 |   | 1.11 |   |
|                            |            |            |            |             |            |                      |            |                       |            |  |  |  |  |  |  |  |  |  |  |

 

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*Includes refuse-derived fuel and wood

 

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

 

***Fuel Sources***—The NSP System normally maintains approximately 30 days of coal inventory ateach plant site.  Coal inventory levels,however, may vary widely among plants. Coal supply inventories at Dec. 31, 2007, were approximately 47days usage, based on the maximum burn rate for all of NSP-Minnesota’scoal-fired plants.  NSP-Minnesota’sgeneration stations use low-sulfur western coal purchased primarily underlong-term contracts with suppliers operating in Wyoming and Montana.  Estimated coal requirements at NSP-Minnesotaand NSP-Wisconsin’s major coal-fired generating plants are approximately 12.4million tons per year.

 

NSP-Minnesota and NSP-Wisconsin have contracted forcoal supplies to provide approximately 100 percent of its coal requirements in2008, 63 percent of its coal requirements in 2009 and 39 percent of its coalrequirements in 2010.  Any

 

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remaining requirements will be filled through arequest for proposal (RFP) process according to the fuel supply operationsprocurement strategy.

 

NSP-Minnesota and NSP-Wisconsin have a number of coal transportationcontracts that provide for delivery of approximately 100 percent of 2008, 2009and 2010 coal requirements.  Coaldelivery may be subject to short-term interruptions or reductions due totransportation problems, weather and availability of equipment.

 

To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesotasecures contracts for uranium concentrates, uranium conversion, uraniumenrichment and fuel fabrication.  Thecontract strategy involves a portfolio of spot purchases and medium- andlong-term contracts for uranium, conversion and enrichment with multipleproducers and with a focus on diversification to minimize potential impactscaused by supply interruptions that may be exacerbated by the supply/demandimbalance.

 

·                  Current nuclear fuel supply contractscover 100 percent of uranium concentrates requirements through 2008,approximately 63 percent of the requirements for 2009, 72 percent of therequirements for 2010 through 2012, 69 percent of the requirements for 2013through 2015, 28 percent of the requirements for 2016 and 2017, with nocoverage of requirements for 2018 and beyond. Contracts with additional uranium concentrate suppliers are currently invarious stages of negotiations that are expected to provide a portion of therequirements through 2019.

 

·                  Current contracts for conversionservices cover 100 percent of the requirements through 2011 and approximately52 percent of the requirements from 2012 through 2015, with no coverage for2016 and beyond.

 

·                  Current enrichment services contractscover 100 percent of 2008 and approximately 94 percent of 2009requirements.  Approximately 29 percentof the 2010 through 2013 enrichment services requirements are currently coveredwith no coverage of requirements for 2014 and beyond.  These current contracts expire at varyingtimes between 2009 and 2013.  A contractfor additional enrichment services is being negotiated to provide 100 percentcoverage from 2009 through 2013.

 

·                  The fuel fabrication contract forMonticello was extended during 2007 to cover one additional reload in2011.  Prairie Island’s fuel fabricationis 100 percent committed for six reloads with an option to extend for threeadditional reloads.  The six reloadsprovide for fabrication services through at least 2013, while adding theoptional reloads would provide for fabrication services to at least 2015.  Request for proposals from the fuelfabrication vendors for additional supply for Monticello is planned for 2008with contract negotiations to follow.

 

NSP-Minnesota expects sufficient uranium, conversion and enrichment tobe available for the total fuel requirements of its nuclear generatingplants.  Contracts for additional uraniumare currently being negotiated that would provide additional supplyrequirements through 2019.  Some exposureto price volatility will remain, due to index-based pricing structures of thecontracts.

 

TheNSP System uses both firm and interruptible natural gas and standby oil in combustionturbines and certain boilers.  Naturalgas supplies and associated transportation and storage services for powerplants are procured under contracts with various terms to provide an adequatesupply of fuel.  The NSP System presentlyhas no long-term supply commitments.  Thetransportation and storage contracts expire in various years from 2010 to2028.  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, 2007,NSP-Minnesota’s commitments related to these transportation and storagecontracts were approximately $575 million. The NSP System has limited on-site fuel oil storage facilities andrelies on the spot market for incremental supplies, if needed.

 

**Wholesale Commodity Marketing Operations**

 

NSP-Minnesota conducts various wholesale marketing operations,including the purchase and sale of electric capacity, energy and energy relatedproducts.  NSP-Minnesota uses physicaland financial instruments to minimize commodity price and credit risk and hedgesupplies and purchases.  See additionaldiscussion under Item 7A — Quantitative and Qualitative Disclosures About MarketRisk.

 

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**ElectricOperating Statistics**

 
| ** **                                   | ** ** | **Year Ended Dec. 31,** | ** ** |
|----------------------------------------------|------------|----------------------------------------|------------|
| ** **                                   | ** ** | **2007**                               | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Electric Sales (Millions of Kwh)**         |       |                                   |       |   |   |   |   |
| Residential                                  |       | 10,534                                 |       | 10,223 |   | 10,177 |   |
| Commercial and Industrial                    |       | 25,844                                 |       | 25,420 |   | 25,207 |   |
| Public Authorities and Other                 |       | 275                                    |       | 280 |   | 272 |   |
| **Total Retail**                             |       | 36,653                                 |       | 35,923 |   | 35,656 |   |
| Sales for Resale                             |       | 4,073                                  |       | 5,435 |   | 3,300 |   |
| **Total Energy Sold**                        |       | 40,726                                 |       | 41,358 |   | 38,956 |   |
|                                         |       |                                   |       |   |   |   |   |
| **Number of customers at end of period**     |       |                                   |       |   |   |   |   |
| Residential                                  |       | 1,218,340                              |       | 1,206,278 |   | 1,184,620 |   |
| Commercial and Industrial                    |       | 146,487                                |       | 144,315 |   | 141,384 |   |
| Public Authorities and Other                 |       | 6,072                                  |       | 5,998 |   | 5,904 |   |
| **Total Retail**                             |       | 1,370,899                              |       | 1,356,591 |   | 1,331,908 |   |
| Wholesale                                    |       | 31                                     |       | 35 |   | 56 |   |
| **Total Customers**                          |       | 1,370,930                              |       | 1,356,626 |   | 1,331,964 |   |
|                                         |       |                                   |       |   |   |   |   |
| **Electric revenues (Thousands of Dollars)** |       |                                   |       |   |   |   |   |
| Residential                                  |       | $                                      | 1,015,315  |   | $ | 929,276 |   | $ | 865,738 |   |
| Commercial and Industrial                    |       | 1,774,027                              |       | 1,665,004 |   | 1,527,149 |   |
| Public Authorities and Other                 |       | 31,446                                 |       | 30,898 |   | 27,369 |   |
| **Total Retail**                             |       | 2,820,788                              |       | 2,625,178 |   | 2,420,256 |   |
| Wholesale                                    |       | 198,248                                |       | 227,000 |   | 212,152 |   |
| Interchange Revenues from NSP-Wisconsin      |       | 372,215                                |       | 322,733 |   | 305,202 |   |
| Other Electric Revenues                      |       | 85,423                                 |       | 90,460 |   | 73,347 |   |
| **Total Electric Revenues**                  |       | $                                      | 3,476,674  |   | $ | 3,265,371 |   | $ | 3,010,957 |   |
|                                         |       |                                   |       |   |   |   |   |
| Kwh Sales per Retail Customer                |       | 26,737                                 |       | 26,480 |   | 26,771 |   |
| Revenue per Retail Customer                  |       | $                                      | 2,057.62   |   | $ | 1,935.13 |   | $ | 1,817.13 |   |
| Residential Revenue per Kwh                  |       | 9.64¢                             |       | 9.09¢ |   | 8.51¢ |   |
| Commercial and Industrial Revenue per Kwh    |       | 6.86                                   |       | 6.55 |   | 6.06 |   |
| Wholesale Revenue per Kwh                    |       | 4.87                                   |       | 4.18 |   | 6.43 |   |

 

**NATURAL GAS UTILITYOPERATIONS**

 

The mostsignificant recent developments in the natural gas operations of NSP-Minnesotaare continued volatility in wholesale natural gas market prices and thecontinued trend toward declining use per customer by residential customers as aresult of improved building construction technologies and higher applianceefficiencies.  From 1997 to 2007, averageannual sales to the typical residential customer declined from 112 MMBtu peryear to 90 MMBtu per year on a weather-normalized basis.  Although recent wholesale price increases donot directly affect earnings because of natural gas cost recovery mechanisms,the high prices are expected to encourage further efficiency efforts bycustomers.

 

# **PublicUtility Regulation**

# ** **

***Summary ofRegulatory Agencies and Areas of Jurisdiction****** —***Retail rates, services and other aspects ofNSP-Minnesota’s operations are regulated by the MPUC and the NDPSC within theirrespective states. The MPUC has regulatory authority over aspects ofNSP-Minnesota’s financial activities, including security issuances, certainproperty transfers, mergers with other utilities and transactions betweenNSP-Minnesota and its affiliates. In addition, the MPUC reviews and approvesNSP-Minnesota’s natural gas supply plans for meeting customers’ future energyneeds.

 

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

 

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NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5percent of Minnesota natural gas revenue on conservation improvement programs.These costs are recovered through an annual cost recovery mechanism for naturalgas conservation and energy management program expenditures. NSP-Minnesota isrequired to request a new cost recovery level annually.  While this law will change to a savings-basedrequirement beginning in 2010 pursuant to 2007 legislation, the costs ofproviding qualified conservation improvement programs will continue to be recoverablethrough a rate adjustment mechanism.

 

For a further discussion of rate and regulatory matters see Note 11 tothe consolidated financial statements.

 

**Capability and Demand**

 

Natural gas supply requirements are categorized asfirm or interruptible (customers with an alternate energy supply).  The maximum daily send-out (firm andinterruptible) for NSP-Minnesota was 643,320 MMBtu for 2007, which occurred on Feb. 7,2007.

 

NSP-Minnesota purchases natural gas from independentsuppliers.  These purchases are generallypriced based on market indices that reflect current prices.  The natural gas is delivered under naturalgas transportation agreements with interstate pipelines.  These agreements provide for firm deliverablepipeline capacity of 562,298 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of undergroundnatural gas storage services.  Thesestorage agreements provide storage for approximately 30 percent of winternatural gas requirements and 36 percent of peak day, firm requirements ofNSP-Minnesota.

 

NSP-Minnesota also owns and operates one LNG plantwith a storage capacity of 2.13 Bcf equivalent and three propane-air plantswith a storage capacity of 1.4 Bcf equivalent to help meet its peakrequirements.  These peak-shaving facilitieshave production capacity equivalent to 250,300 MMBtu of natural gas per day, orapproximately 33 percent of peak day firm requirements.  LNG and propane-air plants provide acost-effective alternative to annual fixed pipeline transportation charges tomeet the peaks caused by firm space heating demand on extremely cold winterdays.

 

NSP-Minnesota is required to file for a change innatural gas supply contract levels to meet peak demand, to redistribute demandcosts among classes, or to exchange one form of demand for another.  The 2006-2007 and 2007-2008 entitlementlevels are pending MPUC action.

 

**Natural Gas Supply and Costs**

 

NSP-Minnesota actively seeks natural gas supply, transportation andstorage alternatives to yield a diversified portfolio that provides increasedflexibility, decreased interruption and financial risk and economicalrates.  In addition, NSP-Minnesotaconducts natural gas price hedging activity that has been approved by the MPUC.  This diversification involves numerousdomestic and Canadian supply sources with varied contract lengths.

 

The following table summarizes the average delivered cost per MMBtu ofnatural gas purchased for resale by NSP-Minnesota’s regulated retail naturalgas distribution business:

 
| 2007 |   | $    |  7.67 |   |
|------|--------|------|------------|--------|
| 2006 |   | 8.32 |       |
| 2005 |   | 8.90 |       |

 

The cost of natural gas supply, transportation service and storageservice is recovered through the PGA cost recovery mechanism.

 

NSP-Minnesota has firm natural gas transportation contracts withseveral pipelines, which expire in various years from 2008 through 2027.

 

NSP-Minnesota has certain natural gas supply,transportation and storage agreements that include obligations for the purchaseand/or delivery of specified volumes of natural gas or to make payments in lieuof delivery.  At Dec. 31, 2007,NSP-Minnesota was committed to approximately $813 million in such obligationsunder these contracts.

 

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NSP-Minnesota purchases firm natural gas supplyutilizing long-term and short-term agreements from approximately25 domestic and Canadian suppliers. This diversity of suppliers andcontract lengths allows NSP-Minnesota to maintain competition from suppliersand minimize supply costs.

 

**Natural Gas Operating Statistics**

 
| ** **                                      | ** ** | **Year Ended Dec. 31,** | ** ** |
|-------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                      | ** ** | **2007**                               | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Natural gas deliveries (Thousands of MMBtu)** |       |                                   |       |   |   |   |   |
| Residential                                     |       | 38,024                                 |       | 33,896 |   | 38,224 |   |
| Commercial and Industrial                       |       | 40,184                                 |       | 35,231 |   | 37,215 |   |
| Other                                           |       | 2,276                                  |       | 1,370 |   | 2,195 |   |
| **Total Retail**                                |       | 80,484                                 |       | 70,497 |   | 77,634 |   |
| Transportation and Other                        |       | 8,528                                  |       | 8,727 |   | 8,203 |   |
| **Total Deliveries**                            |       | 89,012                                 |       | 79,224 |   | 85,837 |   |
|                                            |       |                                   |       |   |   |   |   |
| **Number of customers at end of period**        |       |                                   |       |   |   |   |   |
| Residential                                     |       | 430,048                                |       | 426,479 |   | 418,827 |   |
| Commercial and Industrial                       |       | 39,570                                 |       | 39,056 |   | 38,275 |   |
| **Total Retail**                                |       | 469,618                                |       | 465,535 |   | 457,102 |   |
| Transportation and Other                        |       | 14                                     |       | 14 |   | 14 |   |
| **Total Customers**                             |       | 469,632                                |       | 465,549 |   | 457,116 |   |
|                                            |       |                                   |       |   |   |   |   |
| **Natural gas revenues (Thousands of Dollars)** |       |                                   |       |   |   |   |   |
| Residential                                     |       | $                                      | 413,790    |   | $ | 394,204 |   | $ | 449,724 |   |
| Commercial and Industrial                       |       | 350,640                                |       | 335,392 |   | 359,634 |   |
| **Total Retail**                                |       | 764,430                                |       | 729,596 |   | 809,358 |   |
| Transportation and Other                        |       | 12,541                                 |       | 15,039 |   | 12,564 |   |
| **Total Natural Gas Revenues**                  |       | $                                      | 776,971    |   | $ | 744,635 |   | $ | 821,922 |   |
|                                            |       |                                   |       |   |   |   |   |
| MMBtu Sales per Retail Customer                 |       | 171.38                                 |       | 151.43 |   | 169.84 |   |
| Revenue per Retail Customer                     |       | $                                      | 1,627.77   |   | $ | 1,567.22 |   | $ | 1,770.63 |   |
| Residential Revenue per MMBtu                   |       | 10.88                                  |       | 11.63 |   | 11.77 |   |
| Commercial and Industrial Revenue per MMBtu     |       | 8.73                                   |       | 9.52 |   | 9.66 |   |
| Transportation and Other Revenue per MMBtu      |       | 1.47                                   |       | 1.72 |   | 1.53 |   |

 

**ENVIRONMENTAL MATTERS**

 

Certain ofNSP-Minnesota’s facilities are regulated by federal and state environmentalagencies. These agencies have jurisdiction over air emissions, water quality,wastewater discharges, solid wastes and hazardous substances. Variousactivities require registrations, permits, licenses, inspections and approvalsfrom these agencies.  NSP-Minnesota hasreceived all necessary authorizations for the construction and continuedoperation of its generation, transmission and distribution systems.NSP-Minnesota facilities have been designed and constructed to operate incompliance with applicable environmental standards.

 

NSP-Minnesotastrives to comply with all environmental regulations applicable to its operations.However, it is not possible to determine when or to what extent additionalfacilities or modifications of existing or planned facilities will be requiredas a result of changes to environmental regulations, interpretations orenforcement policies or, what effect future laws or regulations may have uponNSP-Minnesota’s operations. For more information on environmentalcontingencies, see Notes 12 and 13 to the consolidated financial statements.

 

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**EMPLOYEES**

 

The number of full-time NSP-Minnesota employees on Dec. 31, 2007was 3,561.  Of these full-time employees,2,287, or 64 percent, are covered under collective bargaining agreements.  See Note 7 in the consolidated financialstatements for further discussion of the bargaining agreements.  Employees of Xcel Energy Services Inc., asubsidiary of Xcel Energy, also provide services to NSP-Minnesota and are notconsidered in the above amounts.

 

# **Item 1A — Risk Factors**

#  

**RisksAssociated with Our Business**

 

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

 

We are subjectto comprehensive regulation by federal and state utility regulatory agencies.The state utility commissions regulate many aspects of our utility operations,including siting and construction of facilities, customer service and the ratesthat we can charge customers.  The FERChas jurisdiction, among other things, over wholesale rates for electrictransmission service and the sale of electric energy in interstate commerce.

 

Ourprofitability is dependent on our ability to recover the costs of providingenergy and utility services to our customers. We currently provide service at rates approved by one or more regulatorycommissions.  These rates are generallyregulated based on an analysis of our expenses incurred in a test year.  Thus, the rates we are allowed to charge may ormay not match our expenses at any given time. While rate regulation is premised on providing a reasonable opportunityto earn a reasonable rate of return on invested capital, there can be noassurance that the applicable regulatory commission will judge all of our coststo have been prudently incurred or that the regulatory process in which ratesare determined will always result in rates that will produce full recovery ofour costs.  Rising fuel costs could increasethe risk that we will not be able to fully recover our fuel costs from ourcustomers.  Furthermore, there could bechanges in the regulatory environment that would impair our ability to recovercosts 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.

 

Managementcurrently believes these prudently incurred costs are recoverable given theexisting regulatory mechanisms in place. However, changes in regulations or the imposition of additionalregulations, including additional environmental regulation or regulationrelated to climate change, could have an adverse impact on our results ofoperations and hence could materially and adversely affect our ability to meetour financial obligations, including debt payments.

 

***Any reductions in our credit ratings couldincrease our financing costs and the cost of maintaining certain contractualrelationships.***

 

We cannot beassured that any of our current ratings will remain in effect for any givenperiod of time or that a rating will not be lowered or withdrawn entirely by arating agency if, in its judgment, circumstances in the future so warrant.  In addition, our credit ratings may change asa result of the differing methodologies or change in the methodologies used bythe various rating agencies.  Forexample, Standard and Poor’s calculates an imputed debt associated withcapacity payments from purchase power contracts.  An increase in the overall level of capacitypayments would increase the amount of imputed debt, based on Standard and Poor’smethodology.  Therefore, our creditratings could be adversely affected based on the level of capacity paymentsassociated with purchase power contracts or changes in how imputed debt isdetermined.  Any downgrade could lead tohigher borrowing costs.

 

***Weare subject to interest rate risk.***

 

If interestrates increase, we may incur increased interest expense on variable interestdebt or short-term borrowings, which could have an adverse impact on ouroperating results.

 

***We are subject to capital market risk.***

*** ***

NSP-Minnesota’s operations require significant capitalinvestment in plant, property and equipment; consequently, NSP-Minnesota is anactive participant in debt and equity markets. Any disruption in capital markets could have a material impact on ourability to fund our operations.  Capitalmarkets are global in nature and are impacted by

 

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numerous events throughout the world economy.  Capital market disruption events, asevidenced by the collapse in the U.S. sub-prime mortgage market, could preventNSP-Minnesota from issuing new securities or cause us to issue securities withless than ideal terms and conditions.

 

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

 

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

 

***We are subject to commodity risks and other risks associated withenergy markets.***

 

We engage in wholesale sales and purchases of electriccapacity, energy and energy-related products and are subject to market supplyand commodity price risk. Commodity price changes can affect the value of ourcommodity trading derivatives. We mark certain derivatives to estimated fairmarket value on a monthly basis (mark-to-market accounting), which may causeearnings volatility. We utilize quoted observable market prices to the maximumextent possible in determining the value of these derivative commodityinstruments. For positions for which observable market prices are notavailable, we utilize observable quoted market prices of similar assets orliabilities or indirectly observable prices based on forward price curves ofsimilar markets.  For positions for whichwe have unobservable market prices, we incorporate estimates and assumptions asto a variety of factors such as pricing relationships between various energycommodities and geographic locations. Actual experience can vary significantlyfrom these estimates and assumptions and significant changes from ourassumptions could cause significant earnings variability.

 

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 supplyshortages could cause us to seek alternative supply services at potentiallyhigher costs or suffer increased liability for unfulfilled contractualobligations. Any significantly higher energy or fuel costs relative to correspondingsales commitments would have a negative impact on our cash flows and couldpotentially result in economic losses. Potential market supply shortages may not be fully resolved throughalternative supply sources and such interruptions may cause short-termdisruptions in our ability to provide electric and/or natural gas services toour customers.

 

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

 

We are subjectto a number of environmental laws and regulations that affect many aspects ofour past, present and future operations, including air emissions, waterquality, wastewater discharges and the generation, transport and disposal ofsolid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a widevariety of environmental registrations, licenses, permits, inspections andother approvals.  Environmental laws andregulations can also require us to restrict or limit the output of certainfacilities or the use of certain fuels, to install pollution control equipmentat our facilities, clean up spills and correct environmental hazards and othercontamination.  Both public officials andprivate individuals may seek to enforce the applicable environmental laws andregulations against us.  We may berequired to pay all or a portion of the cost to remediate (i.e. clean-up) siteswhere our past activities, or the activities of certain other parties, causedenvironmental contamination.  At Dec. 31,2007, these sites included:

 

·                  thesites of former manufactured gas plants operated by us or our predecessors; and

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

 

We are alsosubject to mandates to provide customers with clean energy, renewable energyand energy conservation offerings.  Thesemandates are designed in part to mitigate the potential environmental impactsof utility operations.  Failure to meetthe requirements of these mandates may result in fines or penalties, whichcould have a material adverse effect on our results of operations.  If our regulators do not allow us to recoverall or a part of the cost of capital investment or the operating andmaintenance costs incurred to comply with the mandates, it could also have amaterial adverse effect on our results of operations.

 

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.

 

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***We are subject to physical and financial risks associatedwith climate change.***

 

**There is a growing consensus thatemissions of GHGs are linked to global climate change. Climate change createsphysical and financial risk. **Physicalrisks from climate change include an increase in sea level and changes inweather conditions, such as an increase in changes in precipitation and extremeweather events.  NSP-Minnesota does notserve any coastal communities so the possibility of sea level rises does notdirectly affect NSP-Minnesota or its customers. Our customers’ energy needsvary with weather conditions, primarily temperature and humidity.  For residential customers, heating andcooling represent their largest energy use. To the extent weather conditionsare affected by climate change, customers’ energy use could increase or decreasedepending on the duration and magnitude of the changes.  Increased energy use due to weather changesmay require us to invest in more generating assets, transmission and otherinfrastructure to serve increased load. Decreased energy use due to weather changes may affect our financialcondition, through decreased revenues. Extreme weather conditions in generalrequire more system backup, adding to costs, and can contribute to increasedsystem stresses, including service interruptions.  Weather conditions outside of the company’sservice territory could also have an impact on NSP-Minnesota’s revenues.  NSP-Minnesota buys and sells electricitydepending upon system needs and market opportunities.  Extreme weather conditions creating highenergy demand on our own and/or other systems may raise electricity prices aswe buy short-term energy to serve our own system, which would increase the costof energy we provide to our customers. Severe weather impacts NSP-Minnesota’sservice territories, primarily through thunderstorms, tornadoes and snow or icestorms. We include storm restoration in our budgeting process as a normalbusiness expense and we anticipate continuing to do so. To the extent thefrequency of extreme weather events increases, this could increase our cost ofproviding service.  Changes inprecipitation resulting in droughts or water shortages could adversely affectour operations, principally our fossil generating units.  A negative impact to water supplies due tolong-term drought conditions could adversely impact our ability to provideelectricity to customers, as well as increase the price they pay for energy. Wemay not recover all costs related to mitigating these physical and financialrisks.

 

Tothe extent climate change impacts a region’s economic health, it may alsoimpact NSP-Minnesota’s revenues. NSP-Minnesota’s financial performance is tied to the health of theregional economies we serve. The price of energy, as a factor in a region’scost of living as well as an important input into the cost of goods, has animpact on the economic health of our communities.  The cost of additional regulatoryrequirements, such as a tax on GHGs or additional environmental regulation,would normally be borne by consumers through higher prices for energy andpurchased goods.  To the extent financialmarkets view climate change and emissions of GHGs as a financial risk, thiscould negatively affect our ability to access capital markets or causeNSP-Minnesota to receive less than ideal terms and conditions.

 

***We may be subject to legislative andregulatory responses to climate change, with which compliance could bedifficult and costly.***

 

**Legislative and regulatory responsesrelated to climate change create financial risk.  Increased public awareness and concern mayresult in more regional and/or federal requirements to reduce or mitigate theeffects of GHG.  Numerous states haveannounced or adopted programs to stabilize and reduce GHG and federallegislation has been introduced in both houses of Congress. **NSP-Minnesota’s electricgenerating facilities are likely to be subject to regulation under climatechange policies introduced at either the state or federal level within the nextfew years.  **NSP-Minnesota is advocating with state and federalpolicy makers to design climate change regulation that is effective, flexible,low-cost and consistent with the our environmental leadership strategy.**

 

Many of the federal and state climate changelegislative proposals use a “cap and trade” policy structure, in which GHGemissions from a broad cross-section of the economy would be subject to anoverall cap.  Under the proposals, thecap becomes more stringent with the passage of time.  The proposals establish mechanisms for GHGsources, such as power plants, to obtain “allowances” or permits to emit GHGsduring the course of a year.  The sourcesmay use the allowances to cover their own emissions or sell them to othersources that do not hold enough emissions for their own operations.  Proponents of the cap and trade policybelieve it will result in the most cost effective, flexible emissionreductions. **The impact oflegislation and regulations, including a “cap and trade” structure, onNSP-Minnesota and its customers will depend on a number of factors, includingwhether GHG sources in multiple sectors of the economy are regulated, theoverall GHG emissions cap level, the degree to which GHG offsets are allowed,the allocation of emission allowances to specific sources and the indirectimpact of carbon regulation on natural gas and coal prices.  An important factor is NSP-Minnesota’sability to recover  the costs incurred tocomply with any regulatory requirements that are ultimately imposed. **We may not recover allcosts related to complying with regulatory requirements imposed onNSP-Minnesota.  If our regulators do notallow us to recover all or a part of the cost of capital investment or the

 

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operating and maintenance costs incurred to complywith the mandates, it could have a material adverse effect on our results ofoperations.

 

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

 

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

 

·                  therisks associated with storage, handling and disposal of radioactive materialsand the current lack of a long-term disposal solution for radioactivematerials;

·                  limitationson the amounts and types of insurance commercially available to cover losses thatmight arise in connection with nuclear operations; and

·                  uncertaintieswith respect to the technological and financial aspects of decommissioningnuclear plants at the end of their licensed lives.

 

The NRC hasauthority to impose licensing and safety-related requirements for the operationof nuclear generation facilities. In the event of non-compliance, the NRC hasthe authority to impose fines or shut down a unit, or both, depending upon itsassessment of the severity of the situation, until compliance is achieved.Revised safety requirements promulgated by the NRC could necessitatesubstantial capital expenditures at NSP-Minnesota’s nuclear plants.

 

If an incidentdid occur, it could have a material adverse effect on our results of operationsor financial condition. Furthermore, the non-compliance of other nuclearfacilities operators with applicable regulations or the occurrence of a seriousnuclear incident at other facilities could result in increased regulation ofthe industry as a whole, which could then increase NSP-Minnesota’s compliancecosts and impact the results of operations of its facilities.

 

***Economic conditions could negatively impact our business.***

 

Our operations are affected by local, national andworldwide economic conditions. The consequences of a prolonged recession mayinclude a lower level of economic activity and uncertainty regarding energyprices and the capital and commodity markets. A lower level of economicactivity might result in a decline in energy consumption, which may adverselyaffect our revenues and future growth. Instability in the financial markets, asa result of recession or otherwise, also may affect the cost of capital and ourability to raise capital.

 

Worldwide economic activity has an impact on thedemand for basic commodities needed for utility infrastructure, such as steel,copper, aluminum, etc., which may impact our ability to acquire sufficientsupplies.  Additionally, the cost ofthose commodities may be higher than expected.

 

***Our utility operations are subject to long termplanning risks.***

 

On a periodic basis, or as needed, our utilityoperations file long term resource plans. These plans are based on numerous assumptions over the relevant planninghorizon such as: sales growth, economic activity, costs, regulatory mechanisms,impact of technology on sales and production and customer response.  Given the uncertainty in these planningassumptions, there is a risk that the magnitude and timing of resourceadditions and demand may not coincide. This could lead to under recovery of costs or insufficient resources tomeet customer demand.

 

***Our operations could be impacted by war, acts of terrorism, threats ofterrorism or disruptions in normal operating conditions due to localized orregional events.***

 

Our generation plants, fuel storage facilities, transmission anddistribution facilities and information systems may be targets of terroristactivities that could disrupt our ability to produce or distribute some portionof our energy products.  Any suchdisruption could result in a significant decrease in revenues and significantadditional costs to repair and insure our assets, which could have a materialadverse impact on our financial condition and results of operations.  The potential for terrorism has subjected ouroperations to increased risks and could have a material adverse effect on ourbusiness.  While we have already incurredincreased costs for security and capital expenditures in response to theserisks, we may experience additional capital and operating costs to implementsecurity for our plants, including our nuclear power plants under the NRC’sdesign basis threat requirements, such as additional physical plant securityand additional security personnel.

 

23

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The insurance industry has also been affected by these events and theavailability of insurance covering risks our competitors and we typicallyinsure against may decrease.  Inaddition, the insurance we are able to obtain may have higher deductibles,higher premiums and more restrictive policy terms.

 

A disruption of the regional electric transmission grid, interstatenatural gas pipeline infrastructure or other fuel sources, could negativelyimpact our business.  Because ourgeneration, transmission systems and local natural gas distribution companiesare part of an interconnected system, we face the risk of possible loss ofbusiness due to a disruption caused by an event (severe storm, generator ortransmission facility outage, pipeline rupture, railroad disruption, sudden andsignificant increase or decrease in wind generation) within our operatingsystems or on a neighboring system or the actions of a neighboringutility.  Any such disruption couldresult in a significant decrease in revenues and significant additional coststo repair assets, which could have a material adverse impact on our financialcondition and results.

 

***We are subject to business continuity risks associated with our abilityto respond to unforeseen events.***

 

Our response to unforeseen events will, in part, determine thefinancial impact of the event on our financial condition and results.  It’s difficult to predict the magnitude ofsuch events and associated impacts.

 

***We are subject to information security risks.***

 

A security breach of our information systems could subject us tofinancial harm associated with theft or inappropriate release of certain typesof information, including, but not limited to, customer or system operatinginformation.  We are unable to quantifythe potential impact of such an event.

 

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

 

Higher fuel costs could significantly impact our results of operationsif requests for recovery are unsuccessful. In addition, the higher fuel costs could reduce customer demand orincrease bad debt expense, which could also have a material impact on ourresults of operations.  Delays in thetiming of the collection of fuel cost recoveries as compared with expendituresfor fuel purchases could have an impact on our cash flows.  We are unable to predict the future prices orthe ultimate impact of such prices on our results of operations or cash flows.

 

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

 

Our electricutility and natural gas businesses are seasonal and weather patterns can have amaterial impact on our operating performance. Demand for electricity is oftengreater in the summer and winter months associated with cooling and heating.  Because natural gas is heavily used forresidential and commercial heating, the demand for this product depends heavilyupon weather patterns throughout our service territory and a significant amountof natural gas revenues are recognized in the first and fourth quarters relatedto the heating season.  Accordingly, ouroperations have historically generated less revenues and income when weatherconditions are milder in the winter and cooler in the summer. Unusually mildwinters and summers could have an adverse effect on our financial condition andresults of operations.

 

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

 

There areinherent in our natural gas distribution activities a variety of hazards andoperating risks, such as leaks, explosions and mechanical problems, which couldcause substantial financial losses.  Inaddition, these risks could result in loss of human life, significant damage toproperty, environmental pollution, impairment of our operations and substantiallosses to us.  In accordance withcustomary industry practice, we maintain insurance against some, but not all,of these risks and losses.

 

The occurrenceof any of these events not fully covered by insurance could have a materialadverse effect on our financial position and results of operations.  For our distribution lines located nearpopulated areas, including residential areas, commercial business centers,industrial sites and other public gathering areas, the level of damagesresulting from these risks is greater.

 

***Increased risks of regulatory penalties could negatively impact ourbusiness.***

 

The Energy Act increased the FERC’s civilpenalty authority for violation of FERC statutes, rules and orders.  The

 

24

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FERC can now impose penalties of $1 millionper violation per day.  Effective June 2007,83 electric reliability standards that were historically subject to voluntarycompliance became mandatory and subject to potential civil penalties forviolations.  If a serious reliabilityincident did occur, it could have a material adverse effect on our operationsor financial results.

 

***Increasing costs associated with our defined benefit retirement plansand other employee-related benefits may adversely affect our results ofoperations, financial position, or liquidity.***

 

We havedefined benefit and postretirement plans that cover substantially all of ouremployees.  Assumptions related to futurecosts, return on investments, interest rates and other actuarial assumptionshave a significant impact on our funding requirements related to theseplans.  These estimates and assumptionsmay change based on actual stock market performance, changes in interest ratesand any changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimumfunding requirements for defined benefit pension plans beginning in 2008.  Therefore, our funding requirements andrelated contributions may change in the future.

 

***Increasing costs associated with health care plansmay adversely affect our results of operations, financial position orliquidity.***

 

The costs ofproviding health care benefits to our employees and retirees have increasedsubstantially in recent years.  Webelieve that our employee benefit costs, including costs related to health careplans for our employees and former employees, will continue to rise.  The increasing costs and funding requirementsassociated with our health care plans may adversely affect our results ofoperations, financial position, or liquidity.

 

***As we are asubsidiary 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 Xcel Energy’scredit ratings and access to capital were restricted, this could limit XcelEnergy’s ability to contribute equity or make loans to us, or may cause Xcel Energyto 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.***

 

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 of Dec. 31, 2007, Xcel Energy had approximately $6.3 billion oflong-term debt and $1.7 billion of short-term debt or current maturities.  Xcel Energy provides various guarantees andbond indemnities supporting some of its subsidiaries by guaranteeing thepayment or performance by these subsidiaries of specified agreements ortransactions.

 

Xcel Energy also has other contingent liabilities resulting fromvarious tax disputes and other matters. Xcel Energy’s exposure under the guarantees is based upon the netliability of the relevant subsidiary under the specified agreements ortransactions.  The majority of XcelEnergy’s guarantees limit its exposure to a maximum amount that is stated inthe guarantees.  As of Dec. 31,2007, Xcel Energy had guarantees outstanding with a maximum stated amount ofapproximately $76.2 million and $0.1 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, 2007, was approximately $31.6million.  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 a whollyowned subsidiary of Xcel Energy.  XcelEnergy can exercise substantial control over our dividend policy and businessand operations and may exercise that control in a manner that may be perceivedto be adverse to our interests.***

 

25

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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 havehistorically paid quarterly dividends to Xcel Energy.  In 2007, 2006 and 2005 we paid $226.8million, $219.6 million and $215.3 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 Staff Comments**

 

None.

 

**Item 2 — Properties**

 

Virtually allof the utility plant of NSP-Minnesota is subject to the lien of its firstmortgage bond indenture.

 

Electricutility generating stations:

 
| **Station, City and Unit** | ** ** | **Fuel**         | ** ** | **Installed** | ** ** | **Summer 2007 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      |       | 1987-2002     |       | 298                                                             |       |
| High Bridge-St. Paul, MN                  |       |             |       |          |       |                                                            |       |
| 2 Units                                   |       | Coal             |       | 1956-1959     |       | 271                                                             | (b)        |
| 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                                                           |       |

 

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

 

(b)            HighBridge coal units were removed from service on August 31, 2007.

 

26

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Electricutility overhead and underground transmission and distribution lines (measuredin conductor miles) at Dec. 31, 2007:

 

**Conductor Miles**

 
| 500 KV           |   | 2,917  |   |
|------------------|--------|--------|--------|
| 345 KV           |   | 5,564  |   |
| 230 KV           |   | 1,801  |   |
| 161 KV           |   | 295    |   |
| 115 KV           |   | 6,577  |   |
| Less than 115 KV |   | 82,100 |   |

 

NSP-Minnesotahad 367 electric utility transmission and distribution substations at Dec. 31,2007.

 

Natural gas utility mains at Dec. 31, 2007:

 
| ** **   | ** ** | **Miles** | ** ** |
|--------------|------------|-----------|------------|
| Transmission |       | 135       |       |
| Distribution |       | 9,446     |       |

 

**Item 3 — Legal Proceedings**

 

In the normalcourse of business, various lawsuits and claims have arisen againstNSP-Minnesota. Management, after consultation with legal counsel, has recordedan estimate of the probable cost of settlement or other disposition for suchmatters.

 

***Other Matters***

 

For adiscussion of legal claims and environmental proceedings, see Note 12 to theconsolidated financial statements under Item 8, incorporated by reference. Fora discussion of proceedings involving utility rates, see Pending and RecentlyConcluded Regulatory Proceedings under Item 1 and Note 11 to the consolidatedfinancial statements under Item 8, incorporated by reference.

 

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

 

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

 

**PART II**

 

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

 

NSP-Minnesotais a wholly owned subsidiary and there is no market for its common equitysecurities.

 

NSP-Minnesota’sfirst mortgage indenture places certain restrictions on the amount of cashdividends it can pay to Xcel Energy, the holder of its common stock. Even withthese restrictions, NSP-Minnesota could have paid more than $946 million inadditional cash dividends on common stock at Dec. 31, 2007. In addition,NSP-Minnesota had dividend restrictions imposed by its credit agreement, FERC rules andstate regulatory commissions.

 

·                  Dividends are subject to the FERC’sjurisdiction under the Federal Power Act, which prohibits the payment ofdividends out of capital accounts; payment of dividends is allowed out ofretained earnings only.

·                  Covenant restrictions underNSP-Minnesota’s credit agreement include a required debt to total capitalratio.

·                  State regulatory commissionsindirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energyby requiring a minimum equity ratio of 45.99%.

 

27

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The dividendsdeclared during 2007 and 2006 were as follows:

 

**Quarter Ended**

**(Thousands of Dollars)**

 
| **March 31, 2007** | ** ** | **June 30, 2007** | ** ** | **Sept. 30, 2007** | ** ** | **Dec. 31, 2007** | ** ** |
|------------------------------|------------|-----------------------------|------------|------------------------------|------------|-----------------------------|------------|
| $                            | 57,124     |                        | $          | 57,312                       |       | $                           | 56,282     |   | $ | 56,094 |   |
|                              |            |                             |            |                              |            |                             |            |  |  |  |  |

 
| **March 31, 2006** | ** ** | **June 30, 2006** | ** ** | **Sept. 30, 2006** | ** ** | **Dec. 31, 2006** | ** ** |
|------------------------------|------------|-----------------------------|------------|------------------------------|------------|-----------------------------|------------|
| $                            | 54,616     |                        | $          | 55,344                       |       | $                           | 55,025     |   | $ | 56,104 |   |
|                              |            |                             |            |                              |            |                             |            |  |  |  |  |

 

**Item 6 — Selected Financial Data**

 

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

 

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

 

Discussion offinancial condition and liquidity for NSP-Minnesota is omitted per conditionsset forth in general instructions I (1)(a) and (b) of Form 10-Kfor wholly owned subsidiaries. It is replaced with management’s narrativeanalysis and the results of operations for the current year as set forth ingeneral instructions I(2)(a) of Form 10-K for wholly ownedsubsidiaries (reduced disclosure format).

 

**ForwardLooking Information**

 

The followingdiscussion and analysis by management focuses on those factors that had amaterial effect on the financial condition and results of operations ofNSP-Minnesota during the periods presented, or are expected to have a materialimpact in the future. It should be read in conjunction with the respectiveaccompanying consolidated financial statements and notes to the consolidatedfinancial statements.

 

Except for thehistorical statements contained in this report, the matters discussed in thefollowing discussion and analysis are forward-looking statements that aresubject to certain risks, uncertainties and assumptions. Such forward-lookingstatements are intended to be identified in this document by the words “anticipate,”“believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,”“project,” “possible,” “potential,” “should” and similar expressions. Actualresults may vary materially. Forward-looking statements speak only as of thedate they are made and we do not undertake any obligation to update them toreflect changes that occur after that date. Factors that could cause actualresults to differ materially include, but are not limited to: general economicconditions, including the availability of credit and its impact on capitalexpenditures and the ability of Xcel Energy and its subsidiaries to obtainfinancing on favorable terms; business conditions in the energy industry;actions of credit rating agencies; competitive factors, including the extentand timing of the entry of additional competition in the markets served byNSP-Minnesota; unusual weather; effects of geopolitical events, including warand acts of terrorism; state, federal and foreign legislative and regulatoryinitiatives that affect cost and investment recovery, have an impact on rates,have an impact on asset operation or ownership or impose environmentalcompliance conditions; structures that affect the speed and degree to whichcompetition enters the electric and natural gas markets; costs and othereffects of legal and administrative proceedings, settlements, investigationsand claims; actions of accounting regulatory bodies; the items described under “RiskFactors” in Item 1A and Exhibit 99.01 of NSP-Minnesota’s Form 10-Kfor the year ended Dec. 31, 2007.

 

**Results of Operations**

** **

NSP-Minnesota’s net income was approximately $267.3 million for 2007,compared with approximately $272.3 million for 2006.

 

***Electric Utility, Short-Term Wholesale andCommodity Trading Margins***

 

Electric fuel and purchased power expenses tend to vary with changingretail and wholesale sales requirements and unit cost changes in fuel andpurchased power. Due to fuel and purchased energy cost-recovery mechanisms forcustomers, most fluctuations in energy costs do not materially affect electricutility margin.

 

NSP-Minnesota has two distinct forms of wholesale sales: short-termwholesale and commodity trading. Short-term wholesale refers to energy-related purchase and salesactivity and the use of certain financial instruments associated

 

28

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with the fuel required for and energy produced from, NSP-Minnesota’sgeneration assets and energy and capacity purchased to serve native load.  Commodity trading is not associated withNSP-Minnesota’s generation assets or the energy or capacity purchased to servenative load.  Short-term wholesale andcommodity trading activities are considered part of the electric utilitysegment.

 

Margins from commodity trading activity conducted at NSP-Minnesota arepartially redistributed between PSCo and SPS, both wholly owned subsidiaries ofXcel Energy, pursuant to the JOA approved by the FERC.  Margins received pursuant to the JOA arereflected as part of base electric utility revenues.  Commodity trading revenues, as discussed inNote 1 to the consolidated financial statements, are reported net of relatedcosts (i.e., on a margin basis) in the consolidated statements of income.Commodity trading expenses include purchased power, transmission, broker feesand other related costs. Short-term wholesale and commodity trading marginsreflect the estimated impact of regulatory sharing of margins, if applicable.

 

The following table details the revenues and margin for base electricutility, short-term wholesale and commodity trading activities:

 
| **(Millions of Dollars)**                      | ** ** | **Base  Electric  Utility** | ** ** | **Short-Term  Wholesale** | ** ** | **Commodity  Trading** | ** ** | **Consolidated  Totals** | ** ** |
|----------------------------------------------------------|------------|-----------------------------|------------|---------------------------|------------|------------------------|------------|--------------------------|------------|
| **2007**                                                 |       |                        |       |                      |       |                   |       |                     |       |
| Electric utility revenues (excluding  commodity trading) |       | $                           | 3,329      |                      | $          | 145                    |       | $                        | —     |   | $ | 3,474 |   |
| Electric fuel and purchased power                        |       | (1,442                      | )          | (135                      | )          | —                 |       | (1,577                   | )          |
| Commodity trading revenues                               |       | —                      |       | —                    |       | 112                    |       | 112                      |       |
| Commodity trading expenses                               |       | —                      |       | —                    |       | (109                   | )          | (109                     | )          |
| Gross margin before operating expenses                   |       | $                           | 1,887      |                      | $          | 10                     |       | $                        | 3          |   | $ | 1,900 |   |
| Margin as a percentage of revenues                       |       | 56.7                        | %          | 6.9                       | %          | 2.7                    | %          | 53.0                     | %          |
|                                                     |       |                        |       |                      |       |                   |       |                     |       |
| **2006**                                                 |       |                        |       |                      |       |                   |       |                     |       |
| Electric utility revenues (excluding  commodity trading) |       | $                           | 3,084      |                      | $          | 178                    |       | $                        | —     |   | $ | 3,262 |   |
| Electric fuel and purchased power                        |       | (1,287                      | )          | (159                      | )          | —                 |       | (1,446                   | )          |
| Commodity trading revenues                               |       | —                      |       | —                    |       | 131                    |       | 131                      |       |
| Commodity trading expenses                               |       | —                      |       | —                    |       | (128                   | )          | (128                     | )          |
| Gross margin before operating expenses                   |       | $                           | 1,797      |                      | $          | 19                     |       | $                        | 3          |   | $ | 1,819 |   |
| Margin as a percentage of revenues                       |       | 58.3                        | %          | 10.7                      | %          | 2.3                    | %          | 53.6                     | %          |

 

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

 

***Base ElectricRevenues***

 
| **(Millions of dollars)**               | ** ** | **2007 vs. 2006** | ** ** |
|---------------------------------------------------|------------|-----------------------------|------------|
| Fuel and purchased power cost recovery            |       | $                           | 84         |   |
| Interchange agreement billing with  NSP-Wisconsin |       | 50                          |       |
| MERP rider                                        |       | 29                          |       |
| Retail sales growth (excluding weather  impact)   |       | 22                          |       |
| Service and facility fees                         |       | 18                          |       |
| Transmission revenues                             |       | 17                          |       |
| Estimated impact of weather                       |       | 11                          |       |
| Conservation and non-fuel riders                  |       | 6                           |       |
| Firm wholesale                                    |       | 5                           |       |
| Other                                             |       | 3                           |       |
| Total increase in base electric revenues          |       | $                           | 245        |   |

 

29

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

 
| **(Millions of dollars)**              | ** ** | **2007 vs. 2006** | ** ** |
|--------------------------------------------------|------------|-----------------------------|------------|
| MERP rider                                       |       | $                           | 29         |   |
| Retail sales growth (excluding weather  impact)  |       | 22                          |       |
| Service and facility fees                        |       | 18                          |       |
| Estimated impact of weather                      |       | 11                          |       |
| Conservation and non-fuel riders                 |       | 6                           |       |
| Purchased capacity costs                         |       | (12                         | )          |
| Other, including fuel recovery and  transmission |       | 16                          |       |
| Total increase in base electric margin           |       | $                           | 90         |   |

 

***Natural Gas Utility Margins****—* The following table details natural gasrevenues and margin. The cost of natural gas tends to vary with changing salesrequirements and unit cost of natural gas purchases. However, due to purchasednatural gas cost recovery mechanisms for retail customers, fluctuations in thecost of natural gas have little effect on natural gas margin.

 
| **(Millions of dollars)**            | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|
| Natural gas utility revenues                   |       | $        | 777        |     | $          | 745 |   |
| Cost of natural gas purchased and  transported |       | (603     | )          | (590     | )          |
| Natural gas utility margin                     |       | $        | 174        |     | $          | 155 |   |

 

The followingsummarizes the components of the changes in natural gas revenues and margin forthe year ended Dec. 31:

 

***Natural Gas Revenues***

 
| **(Millions of dollars)**                  | ** ** | **2007 vs. 2006** | ** ** |
|------------------------------------------------------|------------|-----------------------------|------------|
| Estimated impact of weather                          |       | $                           | 38         |   |
| Base rate changes – Minnesota and North  Dakota |       | 11                          |       |
| Sales growth (excluding weather impact)              |       | 3                           |       |
| Purchased natural gas cost recovery                  |       | (17                         | )          |
| Kansas property tax refund                           |       | (4                          | )          |
| Other                                                |       | 1                           |       |
| Total increase in natural gas revenues               |       | $                           | 32         |   |

 

Natural gasrevenues increased primarily due to more favorable weather in 2007 and theimpact of the Minnesota state rate increase. Partially offsetting the positive factors were lower purchased gascosts, which are recovered from customers and the impact of the Kansas SupremeCourt decision disallowing property taxes on stored gas inventories, which hadbeen recovered through the purchased gas adjustment.  This refund was offset by lower property taxexpense.

 

***Natural Gas Margin***

 
| **(Millions of dollars)**                  | ** ** | **2007 vs. 2006** | ** ** |
|------------------------------------------------------|------------|-----------------------------|------------|
| Base rate changes – Minnesota and North  Dakota |       | $                           | 11         |   |
| Estimated impact of weather                          |       | 7                           |       |
| Sales growth (excluding weather impact)              |       | 3                           |       |
| Kansas property tax refund                           |       | (4                          | )          |
| Transportation and other                             |       | 2                           |       |
| Total increase in natural gas margin                 |       | $                           | 19         |   |

 

***Operating and Maintenance Expenses****—* Operating and maintenance expenses for2007 increased $55.2 million, or 6.1 percent, compared to 2006.  The following summarizes the components ofthe changes for the year ended Dec. 31:

 

30

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| **(Millions of dollars)**                         | ** ** | **2007 vs. 2006** | ** ** |
|-------------------------------------------------------------|------------|-----------------------------|------------|
| Higher nuclear plant operation costs                        |       | $                           | 19         |   |
| Recording of private fuel storage  regulatory asset in 2006 |       | 17                          |       |
| Higher combustion/hydro plant costs                         |       | 13                          |       |
| Higher conservation incentive program costs                 |       | 13                          |       |
| Higher labor costs                                          |       | 4                           |       |
| Higher uncollectible receivable costs                       |       | 3                           |       |
| Lower nuclear plant outage costs                            |       | (10                         | )          |
| Lower employee benefit costs                                |       | (7                          | )          |
| Lower fleet costs                                           |       | (4                          | )          |
| Other                                                       |       | 7                           |       |
| Total increase in operating and maintenance  expenses       |       | $                           | 55         |   |

 

***Depreciation and Amortization –***Depreciation and amortization expense decreased by approximately $19.9 million,or 4.7 percent, for 2007 compared with 2006. Depreciation and amortization expense typically increases 3-5percent year over year because of increased property, plant and equipmentadditions. This decrease for 2007 was primarily due to the MPUC approval ofNSP-Minnesota’s remaining lives depreciation filing lengthening the life of theMonticello nuclear plant by 20 years, effective as of Jan. 1, 2007, aswell as certain other smaller life adjustments. The adjustments from this orderresulted in an approximate $41 million reduction of depreciation expense. Thecompletion of the upgrade to the A.S. King plant, which came on line July 15,2007, increased depreciation expense by $7.0 million. These two events whencombined with the normal increase in depreciation expense from increasedproperty, plant and equipment expenditures for planned system expansionresulted in the $19.9 million decrease for the year.

 

***Interest Charges –***Interest charges increased by approximately $20.9 million, or 12.6 percent, for2007, compared with 2006. The increase was due to higher average debt balances.

 

***AFDC –*** AFDC is anon-cash amount capitalized as a part of construction costs representing thecost of financing the construction. Generally, these costs are recovered fromcustomers, in future rates, as the related property is depreciated.NSP-Minnesota’s MERP project consists of converting two coal-fueled electricgenerating plants located in the Minneapolis - St. Paul metropolitan area tonatural gas and installing advanced pollution control equipment at a thirdcoal-fired plant. The first of these projects began operating in July 2007with the remaining two expected to begin operations in 2008 and 2009. AFDC,resulting in part from these projects, increased by approximately $3.8 million,or 10.8 percent for 2007 compared with the same period in 2006. The increase was partially offset by thecurrent recovery from customers of the financing costs related to MERP througha rate rider, resulting in a lower recognition of AFDC.

 

***Income taxes –***Income tax expense increased by approximately $54.4 million for 2007 comparedwith 2006. The increase in tax expense in 2007 was primarily due to an increasein pretax income and higher state tax expense in 2007, and the reversal of a$9.8 million regulatory reserve in 2006. The effective tax rate was 40.5percent for 2007, compared with 31.9 percent for 2006. Without these chargesand benefits, the effective tax rate for 2007 and 2006 would have been 37.8percent and 36.4 percent, respectively.

 

**Item 7A — Quantitative andQualitative Disclosures About Market Risk**

** **

**DERIVATIVES, RISK MANAGEMENTAND MARKET RISK**

** **

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

 

***Commodity Price Risk—*** NSP-Minnesota is exposed to commodity 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, energyand 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.

 

31

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***Short-Term Wholesaleand 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 activitiesgenerally have terms of less than one year in length.  NSP Minnesota’s risk-management policy allowsmanagement to conduct these activities within guidelines and limitations asapproved by its risk management committee, which is made up of managementpersonnel not directly involved in the activities governed by the policy.

 

The fair value of the commodity trading contracts at Dec. 31,2007, were as follows:

 
| ** **                                                            | ** ** | **(Millions of Dollars)** | ** ** |
|-----------------------------------------------------------------------|------------|-------------------------------------|------------|
| Fair value of trading contracts outstanding  at Jan. 1, 2007     |       | $                                   | (1.3       | ) |
| Contracts realized or settled during the  year                        |       | (12.1                               | )          |
| Fair value of trading contract additions  and changes during the year |       | 15.5                                |       |
| Fair value of trading contracts outstanding  at Dec. 31, 2007    |       | $                                   | 2.1        |   |

 

At Dec. 31, 2007, the fair values by source for the commoditytrading net asset or liability balances were as follows:

 
| ** **                           | ** ** | **Futures/Forwards**                | ** ** |
|--------------------------------------|------------|-------------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **Source of  Fair Value** | ** ** | **Maturity  Less Than  1 Year** | ** ** | **Maturity  1 to 3 Years** | ** ** | **Maturity  4 to 5  Years** | ** ** | **Maturity  Greater  Than 5 Years** | ** ** | **Total Futures/  Forwards Fair  Fair Value** | ** ** |
| Futures/Forwards Fair Value          |       | 1                                   |       | $ | (2,499 | ) | $ | — |   | $ | — |   | $ | — |   | $ | (2,499 | ) |
|                                 |       | 2                                   |       | 3,769 |   | 980 |   | — |   | — |   | 4,749 |   |
|                                 |       |                                |       | $ | 1,270 |   | $ | 980 |   | $ | — |   | $ | — |   | $ | 2,250 |   |

 
| ** **                           | ** ** | **Options**                         | ** ** |
|--------------------------------------|------------|-------------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **Source of  Fair Value** | ** ** | **Maturity  Less Than  1 Year** | ** ** | **Maturity  1 to 3Years** | ** ** | **Maturity  4 to 5  Years** | ** ** | **Maturity  Greater  Than 5 Years** | ** ** | **Total Options   Fair Value** | ** ** |
| Options Fair Value                   |       | 2                                   |       | $ | (139 | ) | $ | — |   | $ | — |   | $ | — |   | $ | (139 | ) |
|                                 |       |                                |       | $ | (139 | ) | $ | — |   | $ | — |   | $ | — |   | $ | (139 | ) |

 

----

| (1)    | — | Prices actively quoted or based on actively quoted  prices.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| (2)    | — | Prices based on models and other valuation  methods.  These represent the fair  value of positions calculated using internal models when directly and  indirectly quoted external prices or prices derived from external sources are  not available.  Internal models  incorporate the use of options pricing and estimates of the present value of  cash flows based upon underlying contractual terms.   The models reflect management’s estimates,  taking into account observable market prices, estimated market prices in the  absence of quoted market prices, the risk-free market discount rate,  volatility factors, estimated correlations of commodity prices and  contractual volumes.  Market price  uncertainty and other risks also are factored into the model. |

 

Normal purchasesand sales transactions, as defined by SFAS No. 133, hedge transactions andcertain other long-term power purchase contracts are not included in the fairvalues by source tables as they are not recorded at fair value as part ofcommodity trading operations.

 

NSP-Minnesota’s short-term wholesale and commodity trading operationsmeasure the outstanding risk exposure to price changes on transactions,contracts and obligations that have been entered into, but not closed, using anindustry standard methodology known as VaR. VaR expresses the potential changein fair value on the outstanding transactions, contracts and obligations over aparticular period of time, with a given confidence interval under normal marketconditions. NSP-Minnesota utilizes the variance/covariance approach in calculatingVaR. The VaR model employs a 95-percent confidence interval level based onhistorical price movement, lognormal price distribution assumption, deltahalf-gamma approach for non-linear instruments and a three-day holding periodfor both electricity and natural gas.

 

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

 
| ** **                          | ** ** | **Year ended**         | ** ** | **During 2007** | ** ** |
|-------------------------------------|------------|-----------------------------|------------|----------------------|------------|
| **(Millions of Dollars)** | ** ** | **Dec. 31, 2007** | ** ** | **Average**          | ** ** | **High** | ** ** | **Low** | ** ** |
| Commodity trading (a)               |       | $                           | 0.26       |                 | $          | 0.47 |   | $ | 1.45 |   | $ | 0.09 |   |
|                                     |            |                             |            |                      |            |  |  |  |  |  |  |  |  |

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

----

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

 

32

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

 

At Dec. 31, 2007, a 100-basis-point change in the benchmark rateon NSP-Minnesota’s variable rate debt would impact pretax interest expense byapproximately $4.2 million.

 

NSP-Minnesota also maintains trust funds, as required by the NRC, tofund certain costs of nuclear decommissioning. At Dec. 31, 2007, these funds were invested primarily in domesticand international equity securities and fixed-rate fixed-incomesecurities.  These funds may be used onlyfor activities related to nuclear decommissioning.  The accounting for nuclear decommissioningrecognizes that costs are recovered through rates; therefore fluctuations inequity prices, or interest rates do not have an impact on earnings.

 

***Credit Risk –***NSP-Minnesotais also exposed to credit risk.  Creditrisk relates to the risk of loss resulting from the nonperformance by acounterparty of its contractual obligations. NSP-Minnesota maintains credit policies intended to minimize overallcredit risk and actively monitors these policies to reflect changes and scopeof operations.

 

NSP-Minnesota conducts standard credit reviews for allcounterparties.  NSP-Minnesota employsadditional credit risk control mechanisms, such as letters of credit, parentalguarantees, standardized master netting agreements and termination provisionsthat allow for offsetting of positive and negative exposures.  The credit exposure is monitored and, whennecessary, the activity with a specific counterparty is limited until creditenhancement is provided.

 

At Dec. 31, 2007, a 10-percent increase in prices would haveresulted in a net mark-to-market increase in credit risk exposure of $3.6million, while a decrease of 10 percent would have resulted in a decrease of$2.6 million.

 

33

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** **

**Item 8 — Financial Statements andSupplementary Data**

 

**Management Report on Internal Controls OverFinancial Reporting**

** **

The management of NSP-Minnesota is responsible forestablishing and maintaining adequate internal control over financialreporting.  NSP-Minnesota’s internalcontrol system was designed to provide reasonable assurance to the company’smanagement and board of directors regarding the preparation and fairpresentation of published financial statements.

 

All internal control systems, no matter how welldesigned, have inherent limitations. Therefore, even those systems determined to be effective can provide onlyreasonable assurance with respect to financial statement preparation andpresentation.

 

NSP-Minnesota management assessed the effectiveness ofthe company’s internal control over financial reporting as of Dec. 31,2007.  In making this assessment, it usedthe criteria set forth by the Committee of Sponsoring Organizations of theTreadway Commission (COSO) in *InternalControl – Integrated Framework. *Basedon our assessment, we believe that, as of Dec. 31, 2007, the company’sinternal control over financial reporting is effective based on those criteria.

 

This annual report does not include an attestationreport of NSP-Minnesota’s registered public accounting firm regarding internalcontrol over financial reporting. Management’s report was not subject to attestation by NSP-Minnesota’sregistered public accounting firm pursuant to temporary rules of theSecurities and Exchange Commission that permit NSP-Minnesota to provide onlymanagement’s report in this annual report.

 
| /S/ DAVID M. SPARBY                                                        |     | /S/ BENJAMIN G.S. FOWKE III                  |
|----------------------------------------------------------------------------|----------|----------------------------------------------|
| David M. Sparby                                                            |     | Benjamin G.S. Fowke III                      |
| *Executive Vice President, Acting  President and  Chief Executive Officer* | * * | *Vice President and Chief Financial Officer* |
| February 25, 2008                                                     |     | February 25, 2008                       |

#  

34

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#  

# **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 Power Company –Minnesota and subsidiaries (the “Company”) as of December 31, 2007 and2006, 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, 2007.  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 includedconsideration of internal control as a basis for designing audit proceduresthat are appropriate in the circumstances, but not for the purpose ofexpressing an opinion on the effectiveness of the Company’s internal controlover financial reporting. Accordingly, we express no such opinion. An auditalso includes 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 31,2007 and 2006, and the results of their operations and their cash flows foreach of the three years in the period ended December 31, 2007, inconformity with accounting principles generally accepted in the United Statesof America.  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 Financial Accounting Standards Board (FASB)Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – aninterpretation of FASB Statement No. 109,” as of January 1, 2007.

 
| /S/ DELOITTE & TOUCHE LLP |   |
|------------------------------------|--------|
| Minneapolis, Minnesota             |
| February 20, 2008             |

 

35

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**NSP-MINNESOTA AND SUBSIDIARIES****CONSOLIDATED STATEMENTS OFINCOME (Thousands of Dollars)**

 
| ** **                                                                                    | ** ** | **Year Ended Dec. 31** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                    | ** ** | **2007**                              | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Operating revenues**                                                                        |       |                                  |       |   |   |   |   |
| Electric utility                                                                              |       | $                                     | 3,476,674  |   | $ | 3,265,371 |   | $ | 3,010,957 |   |
| Natural gas utility                                                                           |       | 776,971                               |       | 744,635 |   | 821,922 |   |
| Other                                                                                         |       | 18,569                                |       | 17,609 |   | 20,705 |   |
| Total operating revenues                                                                      |       | 4,272,214                             |       | 4,027,615 |   | 3,853,584 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Operating expenses**                                                                        |       |                                  |       |   |   |   |   |
| Electric fuel and purchased power                                                             |       | 1,576,901                             |       | 1,445,590 |   | 1,329,553 |   |
| Cost of natural gas sold and transported                                                      |       | 602,617                               |       | 590,094 |   | 664,551 |   |
| Cost of sales — nonregulated and other                                                   |       | 9,212                                 |       | 7,769 |   | 7,762 |   |
| Operating and maintenance expenses                                                            |       | 957,466                               |       | 902,237 |   | 882,552 |   |
| Depreciation and amortization                                                                 |       | 405,569                               |       | 425,511 |   | 372,956 |   |
| Taxes (other than income taxes)                                                               |       | 130,094                               |       | 135,903 |   | 129,928 |   |
| Total operating expenses                                                                      |       | 3,681,859                             |       | 3,507,104 |   | 3,387,302 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Operating income**                                                                          |       | 590,355                               |       | 520,511 |   | 466,282 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| Interest and other income — net                                                          |       | 6,105                                 |       | 9,431 |   | 2,964 |   |
| Allowance for funds used during  construction — equity                                   |       | 21,826                                |       | 20,896 |   | 16,416 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Interest charges and financing costs**                                                      |       |                                  |       |   |   |   |   |
| Interest charges — including financing  costs of $5,271, $6,480 and $7,292, respectively |       | 186,293                               |       | 165,381 |   | 150,261 |   |
| Allowance for funds used during  construction — debt                                     |       | (17,334                               | )          | (14,459 | ) | (14,126 | ) |
| Total interest charges and financing costs                                                    |       | 168,959                               |       | 150,922 |   | 136,135 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| Income before income taxes                                                                    |       | 449,327                               |       | 399,916 |   | 349,527 |   |
| Income taxes                                                                                  |       | 182,025                               |       | 127,606 |   | 111,783 |   |
| Net income                                                                                    |       | $                                     | 267,302    |   | $ | 272,310 |   | $ | 237,744 |   |

 

See Notes to Consolidated FinancialStatements

 

36

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**NSP-MINNESOTA AND SUBSIDIARIES****CONSOLIDATED STATEMENTS OF CASH FLOWS(Thousands of Dollars)**

 
| ** **                                                                               | ** ** | **Year Ended Dec. 31** | ** ** |
|------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                               | ** ** | **2007**                              | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Operating activities**                                                                 |       |                                  |       |   |   |   |   |
| Net income                                                                               |       | $                                     | 267,302    |   | $ | 272,310 |   | $ | 237,744 |   |
| Adjustments to reconcile net income to cash  provided by operating activities:           | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Depreciation and amortization                                                            |       | 415,651                               |       | 433,883 |   | 378,884 |   |
| Nuclear fuel amortization                                                                |       | 53,453                                |       | 47,531 |   | 45,158 |   |
| Deferred income taxes                                                                    |       | 172,004                               |       | (83,361 | ) | 28,846 |   |
| Amortization of investment tax credits                                                   |       | (3,897                                | )          | (4,846 | ) | (6,611 | ) |
| Allowance for equity funds used during  construction                                     |       | (21,826                               | )          | (20,896 | ) | (16,416 | ) |
| Net realized and unrealized hedging and  derivative transactions                         |       | (5                                    | )          | 17,587 |   | (2,885 | ) |
| Impairment of assets                                                                     |       | —                                |       | — |   | 2,887 |   |
| Changes in operating assets and liabilities  (net of the effects of consolidation of NMC |       |                                  |       |   |   |   |   |
| Accounts receivable                                                                      |       | (62,772                               | )          | 28,043 |   | (102,347 | ) |
| Accounts receivable from affiliates                                                      |       | 1,858                                 |       | 20,479 |   | (45,064 | ) |
| Accrued unbilled revenues                                                                |       | (6,367                                | )          | 37,994 |   | (85,516 | ) |
| Inventories                                                                              |       | (52,226                               | )          | (6,475 | ) | (27,855 | ) |
| Recoverable purchased natural gas and  electric energy costs                             |       | (19,184                               | )          | (1,347 | ) | (3,954 | ) |
| Other current assets                                                                     |       | (2,790                                | )          | (1,905 | ) | 2,071 |   |
| Accounts payable                                                                         |       | (66,920                               | )          | 49,691 |   | 121,975 |   |
| Net regulatory assets and liabilities                                                    |       | (14,661                               | )          | (79,181 | ) | (23,511 | ) |
| Other current liabilities                                                                |       | 7,624                                 |       | (1,264 | ) | (22,933 | ) |
| Change in other noncurrent assets                                                        |       | 17,719                                |       | 28,675 |   | (5,373 | ) |
| Change in other noncurrent liabilities                                                   |       | (38,139                               | )          | 16,626 |   | 13,618 |   |
| Net cash provided by operating activities                                                |       | 646,824                               |       | 753,544 |   | 488,718 |   |
|                                                                                     |       |                                  |       |   |   |   |   |
| **Investing activities**                                                                 |       |                                  |       |   |   |   |   |
| Utility capital/construction expenditures                                                |       | (1,060,796                            | )          | (905,352 | ) | (693,028 | ) |
| Allowance for equity funds used during  construction                                     |       | 21,826                                |       | 20,896 |   | 16,416 |   |
| Purchase of investments in external  decommissioning fund                                |       | (712,462                              | )          | (1,288,104 | ) | (576,001 | ) |
| Proceeds from sale of investments in  external decommissioning fund                      |       | 669,070                               |       | 1,240,034 |   | 494,529 |   |
| Cash obtained from consolidation of NMC                                                  |       | 38,950                                |       | — |   | — |   |
| Investments in utility money pool  arrangement                                           |       | (423,500                              | )          | (1,359,000 | ) | — |   |
| Receipts from utility money pool  arrangement                                            |       | 423,500                               |       | 1,359,000 |   | — |   |
| Proceeds from sale of assets                                                             |       | —                                |       | — |   | 11,228 |   |
| Investments in affiliates                                                                |       | (371,250                              | )          | (345,500 | ) | (374,904 | ) |
| Advances from affiliates                                                                 |       | 342,950                               |       | 379,200 |   | 342,404 |   |
| Other investments                                                                        |       | 5,224                                 |       | 6,439 |   | (13,929 | ) |
| Net cash used in investing activities                                                    |       | (1,066,488                            | )          | (892,387 | ) | (793,285 | ) |
|                                                                                     |       |                                  |       |   |   |   |   |
| **Financing activities**                                                                 |       |                                  |       |   |   |   |   |
| Proceeds from (repayment of) short-term  borrowings — net                           |       | 252,500                               |       | 89,000 |   | (90,000 | ) |
| Proceeds from issuance of long-term debt                                                 |       | 343,670                               |       | 393,724 |   | 250,000 |   |
| Repayment of long-term debt, including  reacquisition premiums                           |       | (186,689                              | )          | (210,662 | ) | (82,031 | ) |
| Borrowings under utility money pool  arrangement                                         |       | 937,600                               |       | — |   | — |   |
| Repayments under utility money pool  arrangement                                         |       | (842,500                              | )          | — |   | — |   |
| Borrowings under 5-year unsecured credit  facility                                       |       | 200,000                               |       | 194,000 |   | 1,000,000 |   |
| Repayments under 5-year unsecured credit  facility                                       |       | (200,000                              | )          | (444,000 | ) | (750,000 | ) |
| Capital contributions from parent                                                        |       | 150,514                               |       | 313,856 |   | 224,247 |   |
| Dividends paid to parent                                                                 |       | (226,824                              | )          | (219,598 | ) | (215,341 | ) |
| Net cash provided by financing activities                                                |       | 428,271                               |       | 116,320 |   | 336,875 |   |
|                                                                                     |       |                                  |       |   |   |   |   |
| Net increase (decrease) in cash and cash  equivalents                                    |       | 8,607                                 |       | (22,523 | ) | 32,308 |   |
| Cash and cash equivalents at beginning of  year                                          |       | 16,019                                |       | 38,542 |   | 6,234 |   |
| Cash and cash equivalents at end of year                                                 |       | $                                     | 24,626     |   | $ | 16,019 |   | $ | 38,542 |   |
|                                                                                     |       |                                  |       |   |   |   |   |
| Supplemental disclosure of cash flow  information                                        |       |                                  |       |   |   |   |   |
| Cash paid for interest (net of amounts  capitalized)                                     |       | $                                     | 151,409    |   | $ | 145,585 |   | $ | 124,516 |   |
| Cash paid for income taxes (net of refunds  received)                                    |       | 50,016                                |       | 227,285 |   | 122,456 |   |
|                                                                                     |       |                                  |       |   |   |   |   |
| Supplemental disclosure of non-cash flow  information                                    |       |                                  |       |   |   |   |   |
| Property, plant and equipment additions in  accounts payable                             |       | $                                     | 15,670     |   | $ | 36,613 |   | $ | 20,535 |   |

 

See Notes to Consolidated FinancialStatements

 

37

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**NSP-MINNESOTAAND SUBSIDIARIES**

**CONSOLIDATED BALANCE SHEETS**

**(Thousands of Dollars)**

 
| ** **                                                                                        | ** ** | **Dec. 31, 2007** | ** ** | **Dec. 31, 2006** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| **ASSETS**                                                                                        | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Current assets:                                                                                   |       |                        |       |                        |       |
| Cash and cash equivalents                                                                         |       | $                           | 24,626     |                        | $          | 16,019 |   |
| Notes receivable from affiliates                                                                  |       | 58,600                      |       | 30,300                      |       |
| Accounts receivable, net of allowance for  bad debts of $20,103 and $13,408, respectively         |       | 441,930                     |       | 370,635                     |       |
| Accounts receivable from affiliates                                                               |       | 31,078                      |       | 32,936                      |       |
| Accrued unbilled revenues                                                                         |       | 226,401                     |       | 220,034                     |       |
| Recoverable purchased natural gas and  electric energy costs                                      |       | 36,857                      |       | 17,673                      |       |
| Materials and supplies inventories                                                                |       | 93,853                      |       | 93,183                      |       |
| Fuel inventories                                                                                  |       | 77,257                      |       | 40,257                      |       |
| Natural gas inventories                                                                           |       | 99,528                      |       | 85,016                      |       |
| Derivative instruments valuation                                                                  |       | 51,233                      |       | 62,211                      |       |
| Prepayments and other                                                                             |       | 52,875                      |       | 32,708                      |       |
| Total current assets                                                                              |       | 1,194,238                   |       | 1,000,972                   |       |
|                                                                                              |       |                        |       |                        |       |
| Property, plant and equipment:                                                                    |       |                        |       |                        |       |
| Electric utility plant                                                                            |       | 8,855,144                   |       | 8,245,632                   |       |
| Natural gas utility plant                                                                         |       | 890,371                     |       | 859,533                     |       |
| Construction work in progress                                                                     |       | 818,276                     |       | 917,275                     |       |
| Common utility and other property                                                                 |       | 447,527                     |       | 416,635                     |       |
| Total property, plant and equipment                                                               |       | 11,011,318                  |       | 10,439,075                  |       |
| Less accumulated depreciation                                                                     |       | (4,708,496                  | )          | (4,590,719                  | )          |
| Nuclear fuel — net of accumulated  amortization: $1,291,370 and $1,237,917, respectively     |       | 179,859                     |       | 140,152                     |       |
| Net property, plant and equipment                                                                 |       | 6,482,681                   |       | 5,988,508                   |       |
|                                                                                              |       |                        |       |                        |       |
| Other assets:                                                                                     |       |                        |       |                        |       |
| Nuclear decommissioning fund investments                                                          |       | 1,317,564                   |       | 1,200,688                   |       |
| Regulatory assets                                                                                 |       | 359,782                     |       | 372,349                     |       |
| Prepaid pension asset                                                                             |       | 270,436                     |       | 276,571                     |       |
| Derivative instruments valuation                                                                  |       | 156,975                     |       | 181,616                     |       |
| Other investments                                                                                 |       | 20,034                      |       | 30,892                      |       |
| Other                                                                                             |       | 18,622                      |       | 27,452                      |       |
| Total other assets                                                                                |       | 2,143,413                   |       | 2,089,568                   |       |
| Total assets                                                                                      |       | $                           | 9,820,332  |                        | $          | 9,079,048 |   |
| **LIABILITIES AND EQUITY**                                                                        | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Current liabilities:                                                                              |       |                        |       |                        |       |
| Current portion of long-term debt                                                                 |       | $                           | 31         |                        | $          | 40 |   |
| Short-term debt                                                                                   |       | 341,500                     |       | 89,000                      |       |
| Borrowings under utility money pool  arrangement                                                  |       | 95,100                      |       | —                      |       |
| Accounts payable                                                                                  |       | 369,394                     |       | 468,727                     |       |
| Accounts payable to affiliates                                                                    |       | 53,975                      |       | 39,139                      |       |
| Taxes accrued                                                                                     |       | 122,648                     |       | 126,104                     |       |
| Accrued interest                                                                                  |       | 61,485                      |       | 48,308                      |       |
| Dividends payable to parent                                                                       |       | 56,094                      |       | 56,105                      |       |
| Derivative instruments valuation                                                                  |       | 23,311                      |       | 36,167                      |       |
| Other                                                                                             |       | 64,968                      |       | 38,572                      |       |
| Total current liabilities                                                                         |       | 1,188,506                   |       | 902,162                     |       |
|                                                                                              |       |                        |       |                        |       |
| Deferred credits and other liabilities:                                                           |       |                        |       |                        |       |
| Deferred income taxes                                                                             |       | 898,725                     |       | 708,772                     |       |
| Deferred investment tax credits                                                                   |       | 43,757                      |       | 47,654                      |       |
| Asset retirement obligations                                                                      |       | 1,264,368                   |       | 1,311,271                   |       |
| Regulatory liabilities                                                                            |       | 639,228                     |       | 658,571                     |       |
| Derivative instruments valuation                                                                  |       | 236,832                     |       | 248,981                     |       |
| Pension and employee benefit obligations                                                          |       | 201,624                     |       | 209,548                     |       |
| Other liabilities                                                                                 |       | 68,585                      |       | 69,229                      |       |
| Total deferred credits and other  liabilities                                                     |       | 3,353,119                   |       | 3,254,026                   |       |
|                                                                                              |       |                        |       |                        |       |
| Commitments and contingent liabilities                                                            |       |                        |       |                        |       |
| Capitalization:                                                                                   |       |                        |       |                        |       |
| Long-term debt                                                                                    |       | 2,463,078                   |       | 2,299,188                   |       |
| Common stock — authorized 5,000,000 shares  of $0.01 par value; outstanding 1,000,000 shares |       | 10                          |       | 10                          |       |
| Additional paid in capital                                                                        |       | 1,711,994                   |       | 1,561,480                   |       |
| Retained earnings                                                                                 |       | 1,097,357                   |       | 1,055,983                   |       |
| Accumulated other comprehensive income                                                            |       | 6,268                       |       | 6,199                       |       |
| Total common stockholder’s equity                                                            |       | 2,815,629                   |       | 2,623,672                   |       |
| Total liabilities and equity                                                                      |       | $                           | 9,820,332  |                        | $          | 9,079,048 |   |

 

See Notes to Consolidated Financial Statements

 

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**NSP-MINNESOTA AND SUBSIDIARIES****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, 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)                                             |       |                  |       |                     |       |                |       |                                  |       | (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 |   |
|                                                                                           |       |                  |       |                     |       |                |       |                                  |       |                          |       |   |   |
| FIN 48 adoption                                                                                |       |                  |       |                     |       |                |       | 884                                   |       |                          |       | 884 |   |
| Net income                                                                                     |       |                  |       |                     |       |                |       | 267,302                               |       |                          |       | 267,302 |   |
| Changes in unrecognized amounts of pension and retiree medical  benefits, net of tax of $(551) |       |                  |       |                     |       |                |       |                                  |       | 797                           |       | 797 |   |
| Net derivative instrument fair value changes during the period, net  of tax of $503            |       |                  |       |                     |       |                |       |                                  |       | (728                          | )          | (728 | ) |
| Comprehensive income for 2007                                                                  |       |                  |       |                     |       |                |       |                                  |       |                          |       | 268,255 |   |
| Common dividends declared to parent                                                            |       |                  |       |                     |       |                |       | (226,812                              | )          |                          |       | (226,812 | ) |
| Contribution of capital by parent                                                              |       |                  |       |                     |       | 150,514             |       |                                  |       |                          |       | 150,514 |   |
| **Balance at Dec. 31, 2007**                                                              |       | 1,000,000             |       | $                        | 10         |                | $          | 1,711,994                             |       | $                             | 1,097,357  |   | $ | 6,268 |   | $ | 2,815,629 |   |

 

See Notes to Consolidated Financial Statements

 

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**NSP-MINNESOTA AND SUBSIDIARIES********CONSOLIDATED STATEMENTS OF CAPITALIZATION********(Thousands of Dollars)**

 
| ** **                                                                                                         | ** ** | **Dec. 31** | ** ** |
|--------------------------------------------------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                                                         | ** ** | **2007**         | ** ** | **2006** | ** ** |
| **Long-Term Debt**                                                                                                 |       |             |       |   |   |
| First Mortgage Bonds, Series due:                                                                             |       |             |       |   |   |
| 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          |       | 400,000 |   |
| July 1, 2037, 6.2%                                                                                            |       | 350,000          |       | — |   |
| Senior Notes due Aug. 1, 2009, 6.875%                                                                         |       | 250,000          |       | 250,000 |   |
| Retail Notes due July 1, 2042, 8%                                                                             |       | —           |       | 185,000 |   |
| Other                                                                                                              |       | 31               |       | 89 |   |
| Unamortized discount                                                                                               |       | (8,822           | )          | (7,761 | )  |
| Total                                                                                                              |       | 2,463,109        |       | 2,299,228 |   |
| Less current maturities                                                                                            |       | 31               |       | 40 |   |
| Total long-term debt                                                                                               |       | $                | 2,463,078  |   | $ | 2,299,188 |   |
|                                                                                                               |       |             |       |   |   |
| **Common Stockholder’s Equity**                                                                               |       |             |       |   |   |
| Common stock — authorized 5,000,000 shares of $0.01 par value;  outstanding 1,000,000 shares in 2007 and 2006 |       | $                | 10         |   | $ | 10 |   |
| Additional paid in capital                                                                                         |       | 1,711,994        |       | 1,561,480 |   |
| Retained earnings                                                                                                  |       | 1,097,357        |       | 1,055,983 |   |
| Accumulated other comprehensive income                                                                             |       | 6,268            |       | 6,199 |   |
| Total common stockholder’s equity                                                                             |       | $                | 2,815,629  |   | $ | 2,623,672 |   |

 

----

(a)             Resourcerecovery financing

(b)            Pollutioncontrol financing

 

See Notes to Consolidated Financial Statements

 

40

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**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**1. Summaryof Significant Accounting Policies**

 

***Business and System of Accounts*****— NSP-Minnesotais principally engaged in the generation, purchase, transmission, distributionand sale of electricity and in the purchase, transportation, distribution andsale of natural gas.  NSP-Minnesota issubject to regulation by the FERC and state utility commissions. All ofNSP-Minnesota’s accounting records conform to the FERC uniform system ofaccounts or to systems required by various state regulatory commissions, whichare the same in all material respects.

 

***Principles of Consolidation*****— NSP-Minnesotahas subsidiaries, which have been consolidated and for which all intercompanytransactions and balances have been eliminated.

 

During 2007, NSP-Minnesota became the sole remainingpartner of NMC.  This is the result oftwo of the remaining three partners leaving NMC during 2007.  As a result, both companies were required topay an exit fee and surrender their equity interest in NMC.  NSP-Minnesota owns 100 percent of the equityand has a controlling interest.

 

***Revenue Recognition*****— Revenuesrelated to the sale of energy are generally recorded when service is renderedor energy is delivered to customers. However, the determination of the energysales to individual customers is based on the reading of their meter, whichoccurs on a systematic basis throughout the month. At the end of each month,amounts of energy delivered to customers since the date of the last meterreading are estimated and the corresponding unbilled revenue is estimated.

 

NSP-Minnesota has variousrate-adjustment mechanisms in place that currently provide for the recovery ofpurchased natural gas and electric fuel and purchased energy costs. Thesecost-adjustment tariffs may increase or decrease the level of costs recoveredthrough base rates and are revised periodically, for any difference between thetotal amount collected under the clauses and the recoverable costs incurred.  Where applicable under governing stateregulatory commission rate orders, fuel costs over-recoveries (the excess offuel revenue billed to customers over fuel costs incurred) are deferred ascurrent regulatory liabilities and under-recoveries (the excess of fuel costsincurred over fuel revenues billed to customers) are deferred as currentregulatory assets.  In addition,NSP-Minnesota presents its revenue net of any excise or other fiduciary-typetaxes or fees. A summary of significant rate adjustment mechanisms follows:

 

·              NSP-Minnesota’s rates include acost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowingdollar-for-dollar recovery of the respective costs, which are trued-up on atwo-month and annual basis, respectively. The electric cost-of-fuel-and-purchased-energy mechanism also provides asharing among shareholders and customers of certain margins on short-termwholesale sales and commodity 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 Trading Operations*****— Allapplicable gains and losses related to commodity trading activities, whether ornot settled physically, are shown on a net basis in the consolidated statementsof income.

 

Pursuant to the JOA approvedby the FERC, some of the commodity trading margins from NSP-Minnesota areapportioned to PSCo and SPS. Commodity trading activities are not associatedwith energy produced from NSP-Minnesota’s generation assets or energy andcapacity purchased to serve native load. Commodity trading contracts arerecorded at fair market value in accordance with SFAS No. 133 “Accountingfor Derivative Instruments and Hedging Activities” (SFAS No. 133).  In addition, commodity-trading resultsinclude the impact of all margin-sharing mechanisms.   For more information, see Note 9 to theconsolidated financial statements.

 

***Types of and Accounting for DerivativeInstruments****—*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 designated and qualifying for the normalpurchases and normal sales exception, as defined by SFAS No. 133, arerecorded on the consolidated balance sheets at fair value 

 

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asderivative instruments valuation.  Theclassification of the fair value for those derivative instruments is dependenton 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 asset or liability.  The classification is dependent on theapplicability of specific regulation. This includes certain instruments used to mitigate market risk for theutility operations and all instruments related to the commodity tradingoperations.

 

Gainsor losses on hedging transactions for the sales of energy or energy-relatedproducts are primarily recorded as a component of revenue; hedging transactionsfor fuel used in energy generation are recorded as a component of fuel costs;hedging transactions for natural gas purchased for resale are recorded as acomponent of natural gas costs; and interest rate hedging transactions arerecorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric ornatural gas rates the costs of certain financial instruments purchased toreduce commodity cost volatility.

 

*Cash Flow Hedges* – Qualifying hedgingrelationships are designated as a hedge of a forecasted transaction or futurecash flow (cash flow hedge).  Thedesignation of a cash flow hedge permits the classification of fair value to berecorded within Other Comprehensive Income (OCI), to the extent effective.

 

SFASNo. 133 requires that the hedging relationship be highly effective andthat a company formally designate a hedging relationship to apply hedgeaccounting.  NSP-Minnesota formallydocuments all hedging relationships in accordance with SFAS No. 133.  The documentation includes, among otherfactors, the identification of the hedging instrument and the hedgedtransaction, as well as the risk management objectives and strategies forundertaking the hedged transaction.  Inaddition, at inception and on a quarterly basis, NSP-Minnesota formallyassesses whether the derivative instruments being used are highly effective inoffsetting changes in either the fair value or cash flows of the hedged items.

 

Changesin the fair value of a derivative designated and qualified as a cash flowhedge, to the extent effective, are included in OCI, until earnings areaffected by the hedged transaction. NSP-Minnesota discontinues hedge accountingprospectively when it has determined that a derivative no longer qualifies asan effective hedge, or when it is no longer probable that the hedged forecastedtransaction will occur. To test the effectiveness of hedges, a hypotheticalhedge is used to mirror all the critical terms of the underlying debt and thedollar-offset method is utilized to assess the effectiveness of the actualhedge at inception and on an ongoing basis. The fair value of interest ratederivatives is determined through counterparty valuations, internal valuationsand broker quotes. Gains and losses related to discontinued hedges that werepreviously accumulated in OCI will remain in OCI until the underlying contractis reflected in earnings; unless it is probable that the hedged forecastedtransaction will not occur at which time associated deferred amounts in OCI areimmediately recognized in current earnings.

 

*Normal Purchases and Normal Sales* –NSP-Minnesota enters into contracts for the purchase and sale of commoditiesfor use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determinewhether the contracts are derivatives. Certain contracts that meet thedefinition of a derivative may be exempted from SFAS No. 133 as normalpurchases 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 of the contracts entered into withinthe commodity trading operations qualify for a normal designation..  For further discussion of NSP-Minnesota’srisk management and derivative activities, see Note 9 to the consolidatedfinancial statements.

 

***Property, Plant, and Equipment and Depreciation*****— Property, plant and equipment is stated at original cost. The cost ofplant includes direct labor and materials, contracted work, overhead costs andapplicable interest expense. The cost of plant retired is charged toaccumulated depreciation and amortization. Removal costs associated withregulatory 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 charged tooperating 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 of property.  Property, plant and equipment also includescosts associated with property held for future use.

 

NSP-Minnesota recordsdepreciation expense related to its plant by using the straight-line methodover the plant’s useful life. Actuarial and semi-actuarial life studies areperformed on a periodic basis and submitted to the state and federalcommissions for review.  Upon acceptanceby the various commissions, the resulting lives and net salvage rates 

 

42

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are used to calculatedepreciation.  Depreciation expense,expressed as a percentage of average depreciable property, for the years ended Dec. 31,2007, 2006 and 2005 was 3.6 percent, 3.9 percent and 3.9 percent, respectively.

 

***AFDC*****— AFDC represents the costof capital used to finance utility construction activity. AFDC is computed byapplying a composite pretax rate to qualified construction work in progress.The amount of AFDC capitalized as a utility construction cost is credited toother income and deductions (for equity capital) and interest charges (for debtcapital). AFDC amounts capitalized are included in NSP-Minnesota’s rate basefor establishing utility service rates. In addition to construction-relatedamounts, AFDC also is recorded to reflect returns on capital used to financeconservation programs in Minnesota.

 

GenerallyAFDC costs are recovered from customers, in future rates, as the relatedproperty is depreciated.  In 2003, theMPUC voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueledelectric generating plants located in the Minneapolis-St. Paul metropolitanarea to natural gas and to install advanced pollution control equipment at athird coal-fired plant.  Theseimprovements are expected to significantly reduce air emissions from thesefacilities, while increasing the capacity at system peak by 300 MW.  The first of these projects began operatingin July 2007 with the remaining two expected to begin operations in 2008and 2009, at a cumulative investment of approximately $1 billion. The MPUC hasapproved a more current recovery of the financing costs related to the MERP.The in-service plant costs, including the financing costs during construction,are recovered from customers through a MERP rider resulting in a lowerrecognition of AFDC.

 

***Decommissioning*****— NSP-Minnesotaaccounts for the future cost of decommissioning, or retirement, of its nucleargenerating plants through annual depreciation accruals using an annuityapproach designed to provide for full rate recovery of the futuredecommissioning costs. The decommissioning calculation covers all expenses,including decontamination and removal of radioactive material and extends overthe estimated lives of the plants. The calculation assumes that NSP-Minnesotawill recover those costs through rates. The fair value of external nucleardecommissioning fund investments are determined based on quoted market pricesfor those or similar investments. Unrealized gains or losses on the fund’sassets are included with regulatory assets on the consolidated balance sheets.

 

***Nuclear Fuel Expense*****— Nuclear fuelexpense, which is recorded as NSP-Minnesota’s nuclear generating plants usefuel, includes the cost of fuel used in the current period (including AFDC), aswell as future disposal costs of spent nuclear fuel, costs associated with theend-of-life fuel segments and fees assessed by the DOE for NSP-Minnesota’sportion of the cost of decommissioning the DOE’s fuel enrichment facility.

 

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

 

Estimated remediation costs,excluding inflationary increases, are recorded. The estimates are based onexperience, an assessment of the current situation and the technology currentlyavailable for use in the remediation. The recorded costs are regularly adjustedas estimates are revised and remediation proceeds. If several designatedresponsible parties exist, costs are estimated and recorded only forNSP-Minnesota’s expected share of the cost. Any future costs of restoring siteswhere operation may extend indefinitely are treated as a capitalized cost ofplant retirement. The depreciation expense levels recoverable in rates includea provision for removal expenses, which may include final remediation costs.Removal costs recovered in rates are classified as a regulatory liability.

 

***Legal Costs*** — Litigation accruals are recorded when itis probable NSP-Minnesota is liable for the costs and the liability can bereasonably estimated.  External legalfees related to settlements are expensed as incurred.

 

***Income Taxes*****— NSP-Minnesotaaccounts for income taxes using the asset and liability method under FAS 109,which requires the recognition of deferred tax assets and liabilities for theexpected future tax consequences of events that have been included in thefinancial statements.  NSP-Minnesotadefers income taxes for all temporary differences between pretax financial andtaxable income, and between the book and tax bases of assets and liabilities.NSP-Minnesota uses the tax rates that are scheduled to be in effect when thetemporary differences are expected to turn around, or reverse. The effect of achange in tax rates on deferred tax assets and liabilities is recognized inincome in the period that includes the enactment date.

 

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Deferredtax assets are reduced by a valuation allowance if, based on the weight ofavailable evidence, it is more likely than not that some portion or all of thedeferred tax asset will not be realized. In making such a determination, allavailable positive and negative evidence, including scheduled reversals ofdeferred tax liabilities, projected future taxable income, tax planningstrategies and recent financial operations, is considered.

 

Due to the effects of pastregulatory practices, when deferred taxes were not required to be recorded, thereversal of some temporary differences are accounted for as current income taxexpense. Investment tax credits are deferred and their benefits amortized overthe estimated lives of the related property. Utility rate regulation also hascreated certain regulatory assets and liabilities related to income taxes,which are summarized in Note 14 to the consolidated financial statements. Formore information on income taxes, see Note 6 to the consolidated financialstatements.

 

InJuly 2006, the FASB issued FIN 48, which prescribes how a company shouldrecognize, measure, present and disclose uncertain tax positions that suchcompany has taken or expects to take in its income tax returns. FIN 48 requiresthat only income tax benefits that meet the “more likely than not” recognitionthreshold be recognized or continue to be recognized on its effective date. Asrequired, NSP-Minnesota adopted FIN 48 as of Jan. 1, 2007 and the initialderecognition amounts were reported as a cumulative effect of a change inaccounting principle. The cumulative effect of the change, which was reportedas an adjustment to the beginning balance of retained earnings, was notmaterial. Following implementation, the ongoing recognition of changes inmeasurement of uncertain tax positions will be reflected as a component ofincome tax expense.

 

NSP-Minnesota reportsinterest and penalties related to income taxes within the interest chargessection in the consolidated statements of income.

 

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 as a contribution ofcapital.

 

***Use of Estimates*****— In recordingtransactions and balances resulting from business operations, NSP-Minnesotauses estimates based on the best information available. Estimates are used forsuch items as plant depreciable lives, AROs, decommissioning, tax provisions,uncollectible amounts, environmental costs, unbilled revenues, jurisdictionalfuel and energy cost allocations and actuarially determined benefit costs. Therecorded estimates are revised when better information is obtained or actualamounts are determinable. Those revisions can affect operating results. Eachyear the depreciable lives of certain plant assets are reviewed and revised, ifappropriate.

 

***Cash and Cash Equivalents*****— NSP-Minnesotaconsiders investments in certain instruments, including commercial paper andmoney market funds, with a remaining maturity of three months or less at thetime of purchase to be cash equivalents.

 

***Restricted Cash*** — At Dec. 31, 2007 and2006, NSP-Minnesota had restricted cash of $8.4 million and $9.6 million,respectively.  The restricted cashbalances primarily represent margin deposits held in conjunction with electricfutures trading contracts.  Thesebalances are presented as a component of other long-term assets on the consolidatedbalance sheets.

 

***Inventory*****— All inventoryfor NSP-Minnesota is recorded at average cost.

 

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

 

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

 

·              certaincredits, which would otherwise be reflected as income, are deferred asregulatory liabilities based on the expectation they will be returned tocustomers in future rates.

 

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

 

44

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If restructuring or otherchanges in the regulatory environment occur, NSP-Minnesota may no longer beeligible to apply this accounting treatment and may be required to eliminatesuch regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect onNSP-Minnesota’s results of operations in the period the write-off isrecorded.  See more discussion ofregulatory assets and liabilities at Note 14 to the consolidated financialstatements.

 

***Deferred Financing Costs*****— Other assetsinclude deferred financing costs, net of amortization, of approximately $18.2million and $20.4 million at Dec. 31, 2007 and 2006, respectively.  NSP-Minnesota is amortizing these financingcosts over the remaining maturity periods of the related debt.

 

Debt premiums, discounts,expenses and amounts received or incurred to settle hedges are amortized overthe life of the related debt.  Thepremiums and costs associated with modified debt are deferred and amortizedover the life of the related new issuance, in accordance with regulatory guidelines.  If NSP-Minnesota extinguishes the debt, allunamortized balances shall be expensed at the time of the redemption.

 

***Accounts Receivable and Allowance for Bad Debts*****—**Accounts receivable are stated at the actual billedamount net of the allowance for uncollectibles. NSP-Minnesota establishes an allowance for uncollectibles based on areserve policy that reflects its expected exposure to the credit risk ofcustomers.

 

***Renewable Energy Credits******—***Renewable Energy Credits (RECs) are******marketable environmentalcommodities that represent proof that energy was generated from eligible renewableenergy sources.  These credits can be bought and sold. RECs aretypically used as a form of measurement of compliance to Renewable PortfolioStandards (RPS) enacted by those states that are encouraging construction andconsumption of renewable energy, but can also be sold separately from theenergy produced.  Currently, NSP-MNacquires RECs from the generation or purchase of renewable power.

 

***WhenRECs are acquired in the course of generation or purchase as a result ofmeeting the load obligation, they are recorded as inventory at actualcost.  REC’s acquired for tradingpurposes are recorded as other investments at actual cost.  The cost of RECs that are retired forcompliance purposes is recorded as electric fuel and purchased power.  The net margin on sales of RECs for tradingpurposes is recorded as electric utility operating revenues net of any marginsharing requirements.  As a result ofstate regulatory orders, we reduce recoverable fuel costs for the value ofcertain RECs and record the cost of RECs to satisfy future compliancerequirements that are recoverable in future rates as regulatory assets underthe criteria of SFAS No. 71.***

*** ***

***Emission Allowances*****—**Emission allowances are recorded at cost, includingthe annual SO2 and NOx emission allowance entitlement received at nocost from the EPA.  NSP-Minnesota followsthe inventory model for all allowances. The sales of allowances are reported in the operating activities sectionof the consolidated statements of cash flows. The net margin on sales of emission allowances is included in electricutility operating revenues as it is integral to the production process ofenergy and our revenue optimization strategy for our utility operations.

 

***Reclassifications*****—**Theconsolidated statements of cash flows have been reclassified from prior-periodpresentation. The reclassifications reflect the presentation of unbilledrevenues, recoverable purchased natural gas and electric energy costs andregulatory assets and liabilities as separate items rather than components ofother assets and other liabilities within net cash provided by operatingactivities. In addition, activity related to derivative transactions have beencombined into net realized and unrealized hedging and derivativetransactions.  These reclassificationsdid not affect total operating, investing or financing within the consolidatedstatements of cash flows.

 

**2.**             Recently Issued Accounting Pronouncements

** **

***Fair ValueMeasurements (SFAS No. 157)***— In September 2006, the FASB issued SFAS No. 157, whichprovides a single definition of fair value, together with a framework formeasuring it and requires additional disclosure about the use of fair value tomeasure assets and liabilities.  SFAS No. 157also emphasizes that fair value is a market-based measurement and sets out afair value hierarchy with the highest priority being quoted prices in activemarkets. Fair value measurements are disclosed by level within thathierarchy.  SFAS No. 157 iseffective for financial statements issued for fiscal years beginning after Nov. 15,2007. NSP-Minnesota is evaluating the impact of SFAS No. 157 on itsconsolidated financial statements and does not expect the impact ofimplementation to be material.

** **

***The FairValue Option for Financial Assets and Financial Liabilities - Including anAmendment of FASB Statement No. 115 (SFAS No. 159)***— In February 2007, the FASB issued SFAS No. 159,which provides companies with an 

 

45

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**option to measure, at specified election dates, manyfinancial instruments and certain other items at fair value that are notcurrently measured at fair value. A company that adopts SFAS No. 159 willreport unrealized gains and losses on items, for which the fair value optionhas been elected, in earnings at each subsequent reporting date. This statementalso establishes presentation and disclosure requirements designed tofacilitate comparisons between entities that choose different measurementattributes for similar types of assets and liabilities. This statement iseffective for fiscal years beginning after Nov. 15, 2007, effective Jan. 1,2008.  NSP-Minnesota adopted** SFAS No. 159 and theadoption did not have a material impact on its consolidated financial statements.

** **

***BusinessCombinations (SFAS No. 141 (revised 2007))***— In December 2007, the FASB issued SFAS No. 141R,which establishes principles and requirements for how an acquirer in a businesscombination recognizes and measures in its financial statements theidentifiable assets acquired, the liabilities assumed and any noncontrollinginterest; recognizes and measures the goodwill acquired in the businesscombination or a gain from a bargain purchase; and determines what informationto disclose to enable users of the financial statements to evaluate the natureand financial effects of the business combination.  SFAS No. 141R is to be appliedprospectively to business combinations for which the acquisition date is on orafter the beginning of an entity’s fiscal year that begins on or after Dec. 15,2008.  NSP-Minnesota is evaluating the impactof SFAS No. 141R on its consolidated financial statements for anypotential business combinations subsequent to Jan. 1, 2009.

** **

***NoncontrollingInterests in Consolidated Financial Statements, an Amendment of ARB No. 51(SFASNo. 160)***— In December 2007,the FASB issued SFAS No. 160, which establishes accounting and reportingstandards that require the ownership interest in subsidiaries held by partiesother than the parent be clearly identified and presented in the consolidatedbalance sheets within equity, but separate from the parent’s equity; the amountof consolidated net income attributable to the parent and the noncontrollinginterest be clearly identified and presented on the face of the consolidatedstatement of earnings; and changes in a parent’s ownership interest while theparent retains its controlling financial interest in its subsidiary beaccounted for consistently. This statement is effective for fiscal years beginningon or after Dec. 15, 2008. NSP-Minnesota is evaluating the impact of SFAS No. 160on its consolidated financial statements.

** **

**3.**             Short-Term Borrowings

** **

***Commercial Paper**** *— At Dec. 31, 2007 and2006, NSP-Minnesota had commercial paper outstanding of $341.5 million and$89.0 million, respectively.  Theweighted average interest rates at Dec. 31, 2007 and 2006 were 5.58percent and 5.45 percent, respectively.

 

***Money Pool*****- Xcel Energy has established a utility money pool arrangement thatallows for short-term loans between the utility subsidiaries and from theholding company to the utility subsidiaries at market-based interest rates. Theutility 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.  At Dec. 31, 2007,NSP-Minnesota had money pool borrowings of $95.1 million with a weightedaverage interest rate of 5.64 percent.

 

**4.    Long-Term Debt**

** **

***Credit Facilities***— At Dec. 31,2007, NSP-Minnesota had the following committed credit facility in effect, inmillions of dollars:

 
| **Credit   Facility** | ** ** | **Credit Facility   Borrowings** | ** ** | **Available*** | ** ** | **Term** | ** ** | **Maturity** | ** ** |
|----------------------------|------------|--------------------------------------------|------------|----------------|------------|----------|------------|--------------|------------|
| $                          | 500        |                                       | $          | —         |       | $        | 152.4      |         | Five  year |   | December 2011 |   |
|                            |            |                                            |            |                |            |          |            |              |            |  |  |  |

 

----

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

 

Theline of credit provides short-term financing in the form of notes payable tobanks, letters of credit and back-up support for commercial paperborrowings.  NSP-Minnesota has the rightto request an extension of the final maturity date by one year.  The maturity extension is subject to majoritybank group approval.  The credit facilityhas one financial covenant requiring that NSP-Minnesota’s debt-to-totalcapitalization ratio be less than or equal to 65 percent with whichNSP-Minnesota was in compliance at Dec. 31, 2007.  If NSP-Minnesota does not comply with thecovenant, it is deemed an event of default and any outstanding amounts dueunder the facility can be declared due by the lender.  The credit facility has a cross defaultprovision that provides the borrower will be in default on its borrowings underthe facility if any of its subsidiaries, comprising more than 15 percent of theconsolidated assets, defaults on any of its 

 

46

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indebtednessgreater than $50 million.  The interestrate is based on either the agent bank’s prime rate or the applicable LIBOR,plus a borrowing margin as based on NSP-Minnesota’s senior unsecured creditratings from Moody, Standard & Poor and Fitch.

 

·                  At Dec. 31, 2007, NSP-Minnesota had nodirect borrowings on this line of credit; however, the credit facility was usedto provide back-up support for $341.5 million of commercial paper outstandingand $6.1 million of letters of credit

 

·                  At Dec. 31, 2006, NSP-Minnesota had nodirect borrowings on this line of credit; however, the credit facility was usedto provide back-up support for $89.0 million of commercial paper outstandingand $34.5 million of letters of credit.

 

·                  At Dec. 31, 2007, $7.2 million lettersof credit were outstanding, of which $6.1 million were outstanding under theabove credit facility.

 

·                  At Dec. 31, 2006, $35.3 million lettersof credit were outstanding, of which $34.5 million were outstanding under theabove credit facility.

 

***Long-Term Borrowings***

*** ***

OnJune 26, 2007, NSP-Minnesota issued $350 million of 6.20 percent firstmortgage bonds, series due July 1, 2037. NSP-Minnesota added the net proceeds from the sale of the first mortgagebonds to its general funds and applied a portion of the proceeds to therepayment of commercial paper.

 

OnAug. 1, 2007, NSP-Minnesota redeemed all of its outstanding 8.00 percentnotes, series due 2042, at a redemption price equal to 100 percent of theprincipal amount of the notes ($25.00), plus accrued and unpaid interest on thenotes, if any, to the redemption date. Upon redemption, Xcel Energy recognized approximately $9.3 million ininterest expense due to unwinding a fair value interest rate derivative.

 

Allproperty of NSP-Minnesota is subject to the lien of its first mortgageindenture.  NSP-Minnesota’s firstmortgage indenture places certain restrictions on the amount of cash dividendsit can pay Xcel Energy, the holder of its common stock. Even with theserestrictions, NSP-Minnesota could have paid more than $946 million inadditional cash dividends on common stock at Dec. 31, 2007.

 

Maturitiesof long-term debt are:

 
| **(Millions of Dollars)** | ** ** | ** ** | ** ** |
|-------------------------------------|------------|------------|------------|
| 2008                                |       | $          | —     |   |
| 2009                                |       | 250.0      |       |
| 2010                                |       | 175.0      |       |
| 2011                                |       | —     |       |
| 2012                                |       | 450.0      |       |
|                                     |            |            |            |  |

 

**5.    Joint PlantOwnership**

 

Following are theinvestments by NSP-Minnesota in jointly owned plants and the related ownershippercentages as of Dec. 31, 2007:

 
| **(Thousands of Dollars)**             | ** ** | **Plant in   Service** | ** ** | **Accumulated  Depreciation** | ** ** | **Construction   Work in   Progress** | ** ** | **Ownership%** | ** ** |
|--------------------------------------------------|------------|----------------------------------|------------|-------------------------------|------------|------------------------------------------------------|------------|----------------|------------|
| Sherco Unit 3                                    |       | $                                | 503,311    |                          | $          | 313,733                                              |       | $              | 6,165      |   | 59.0 |   |
| Sherco Common Facilities Units 1, 2 & 3 |       | 109,836                          |       | 61,681                        |       | 62                                                   |       | 75.0           |       |
| Transmission facilities, including substations   |       | 4,832                            |       | 2,130                         |       | —                                               |       | 59.0           |       |
| Total                                            |       | $                                | 617,979    |                          | $          | 377,544                                              |       | $              | 6,227      |   |   |   |

 

NSP-Minnesotais part owner of Sherco 3, an 860-MW, coal-fueled electric generating unit.NSP-Minnesota is the operating agent under the joint ownership agreement.NSP-Minnesota’s share of operating expenses and construction 

 

47

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expendituresare included in the applicable utility accounts.  Each of the respective owners is responsiblefor funding its portion of the construction costs.

 

**6.**          Income Taxes

 

***Accounting forUncertainty in Income Taxes — an interpretation of FASB Statement No. 109(FIN 48)*** —NSP-Minnesota adopted FIN 48 as of Jan. 1,2007. NSP-Minnesota is a member of the Xcel Energy affiliated group that filesconsolidated income tax returns.  XcelEnergy has been audited by the Internal Revenue Service (IRS) through tax year2003, with a limited exception for 2003 research tax credits.  The IRS commenced an examination of XcelEnergy’s federal income tax returns for 2004 and 2005 (and research credits for2003) in the third quarter of 2006, and that examination is anticipated to becomplete by March 31, 2008.  As of Dec. 31,2007, the IRS had not proposed any material adjustments to tax years 2003through 2005.  The statute of limitationsapplicable to Xcel Energy’s 2000 through 2002 federal income tax returnsexpired as of June 30, 2007.

 

NSP-Minnesota is currentlyunder examination by the state of Minnesota for years 1998 through 2001.  No material adjustments have been proposed asof Dec. 31, 2007.  As of Dec. 31,2007, NSP-Minnesota’s earliest open tax years in which an audit can beinitiated by state taxing authorities under applicable statutes of limitationsis 1998.

 

The amount of unrecognizedtax benefits reported was $22.5 million Jan. 1, 2007 and $14.3 million on Dec. 31,2007.  A reconciliation of the beginningand ending amount of unrecognized tax benefit is as follows:

 
| ** **                                                    | ** ** | **(Millions of Dollars)** | ** ** |
|---------------------------------------------------------------|------------|-------------------------------------|------------|
| Balance at Jan. 1, 2007                                  |       | $                                   | 22.5       |   |
| Additions based on tax positions related to the current year  |       | 5.6                                 |       |
| Reductions based on tax positions related to the current year |       | (0.2                                | )          |
| Additions for tax positions of prior years                    |       | 8.4                                 |       |
| Reductions for tax positions of prior years                   |       | (3.4                                | )          |
| Settlements with taxing authorities                           |       | (18.6                               | )          |
| Balance at Dec. 31, 2007                                 |       | $                                   | 14.3       |   |

 

These unrecognized taxbenefit amounts were reduced by the tax benefits associated with tax creditcarryovers of $4.1 million and $2.2 million as of Jan. 1, 2007 and Dec. 31,2007, respectively.

 

The unrecognized tax benefitbalance was $5.5 million and $6.6 million of tax positions on Jan. 1, 2007and Dec. 31, 2007, respectively, which if recognized would affect theannual effective tax rate.  In addition,the unrecognized tax benefit balance included $17.0 million and $7.7 million oftax positions on Jan. 1, 2007 and Dec. 31, 2007, respectively, forwhich the ultimate deductibility is highly certain but for which there isuncertainty about the timing of such deductibility.  A change in the period of deductibility wouldnot affect the effective tax rate but would accelerate the payment of cash tothe taxing authority to an earlier period.

 

The decrease in the unrecognized tax benefit balanceof $8.2 million from Jan. 1, 2007 to Dec. 31, 2007, was due to theaddition of similar uncertain tax positions related to ongoing activity and theresolution of certain federal and state audit matters. NSP-Minnesota’s amount of unrecognized tax benefits could significantlychange in the next 12 months as the IRS and state tax audits progress.  At this time, due to the uncertain nature ofthe audit process, it is not reasonably possible to estimate an overall rangeof possible change.  However, as the IRSand state taxing authorities complete the audits that are currently inprogress, it is reasonably possible that the amount of unrecognized taxbenefits could decrease up to $3 million.

 

The liability for interestrelated to unrecognized tax benefits is partially offset by the interestbenefit associated with tax credit carryovers. The amount of interest income related to unrecognized tax benefitsreported within interest charges in 2007 was $0.6 million.  The liability for interest related tounrecognized tax benefits was $1.9 million on Dec. 31, 2007.

 

No amounts were accrued forpenalties as of Dec. 31, 2007.

 

***Other Income Tax Matters –***NSP-Minnesota’sfederal net operating loss and tax credit carry forwards are estimated to be$20.6 million and $11.9 million, respectively, as of Dec. 31, 2007.  The carry forward periods expire between 2021and 2027.  NSP-Minnesota also has statetax credit carry forwards of $1.3 million as of Dec. 31, 2007.  The state carry forward periods expirebetween 2018 and 2022.

 

48

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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:

 
| ** **                                                | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal statutory rate                                    |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases (decreases) in tax from:                        |       |     |       |     |       |     |       |
| State income taxes, net of federal income tax benefit     |       | 8.4      |       | 3.6      |       | 4.6      |       |
| Resolution of income tax audits and other                 |       | 0.4      |       | (2.5     | )          | (1.2     | )          |
| Tax credits recognized, net of federal income tax expense |       | (1.5     | )          | (2.0     | )          | (2.8     | )          |
| Regulatory differences — utility plant items         |       | (1.7     | )          | (1.6     | )          | (1.5     | )          |
| Life insurance policies                                   |       | (0.2     | )          | (0.2     | )          | (0.2     | )          |
| FIN 48 expense – unrecognized tax benefits           |       | 0.2      |       | —   |       | —   |       |
| Other — net                                          |       | (0.1     | )          | (0.4     | )          | (1.9     | )          |
| Effective income tax rate                                 |       | 40.5     | %          | 31.9     | %          | 32.0     | %          |

 

The components of income taxexpense (benefit) for the years ending Dec. 31 were:

 
| **(Thousands of Dollars)**   | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current federal tax expense            |       | $        | 15,277     |     | $          | 178,668  |       | $ | 81,518 |   |
| Current state tax expense              |       | 4,987    |       | 37,145   |       | 8,065    |       |
| Current FIN 48 tax expense (benefit)   |       | (6,346   | )          | —   |       | —   |       |
| Current tax credits                    |       | —   |       | —   |       | (35      | )          |
| Deferred federal tax expense (benefit) |       | 117,433  |       | (66,226  | )          | 21,491   |       |
| Deferred state tax expense (benefit)   |       | 50,151   |       | (13,752  | )          | 10,629   |       |
| Deferred FIN 48 tax expense            |       | 7,416    |       | —   |       | —   |       |
| Deferred tax credits                   |       | (2,996   | )          | (3,383   | )          | (3,274   | )          |
| Deferred investment tax credits        |       | (3,897   | )          | (4,846   | )          | (6,611   | )          |
| Total income tax expense               |       | $        | 182,025    |     | $          | 127,606  |       | $ | 111,783 |   |

 

The components of deferredincome tax at Dec. 31 were:

 
| **(Thousands of Dollars)**                                                                           | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax expense (benefit) excluding items below                                                           |       | $        | 185,214    |     | $          | (144,209 | ) |
| Amortization and adjustments to deferred income taxes on income tax regulatory  assets and liabilities         |       | (26,444  | )          | 65,142   |       |
| FIN 48 adoption: Deferred tax expense reported as an adjustment to  the beginning balance of retained earnings |       | 13,981   |       | —   |       |
| Tax expense allocated to other comprehensive income and other                                                  |       | (747     | )          | (4,294   | )          |
| Deferred tax expense (benefit)                                                                                 |       | $        | 172,004    |     | $          | (83,361 | ) |

 

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

 

49

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| **(Thousands of Dollars)**               | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax liabilities:                          |       |     |       |     |       |
| Differences between book and tax bases of property |       | $        | 905,225    |     | $          | 756,427 |   |
| Regulatory assets                                  |       | 74,831   |       | 60,897   |       |
| Deferred costs                                     |       | 14,135   |       | 11,275   |       |
| Unbilled revenue                                   |       | 9,934    |       | 9,886    |       |
| Other                                              |       | 19,079   |       | 12,563   |       |
| Total deferred tax liabilities                     |       | $        | 1,023,204  |     | $          | 851,048 |   |
|                                               |       |     |       |     |       |
| Deferred tax assets:                               |       |     |       |     |       |
| Employee benefits                                  |       | $        | 71,314     |     | $          | 57,738 |   |
| Deferred investment tax credits                    |       | 17,872   |       | 19,463   |       |
| Regulatory liabilities                             |       | 15,013   |       | 20,590   |       |
| Tax credit carry forward                           |       | 13,141   |       | 14,817   |       |
| Bad debts                                          |       | 8,211    |       | 5,476    |       |
| Rate refund reserve                                |       | 6,710    |       | 23,255   |       |
| Net operating loss carry forward                   |       | 3,358    |       | 9,060    |       |
| Other                                              |       | 6,126    |       | 4,404    |       |
| Total deferred tax assets                          |       | $        | 141,745    |     | $          | 154,803 |   |
| Net deferred tax liability                         |       | $        | 881,459    |     | $          | 696,245 |   |

 

**7.    Benefit Plans and Other Postretirement Benefits**

** **

Pensionand other postretirement benefit disclosures below generally represent XcelEnergy consolidated information unless specifically identified as beingattributable to NSP-Minnesota.

 

XcelEnergy offers various benefit plans to its benefit employees, including thoseof NSP-Minnesota.  Approximately 52percent of Xcel Energy employees that receive benefits are represented byseveral local labor unions under several collective-bargaining agreements. At Dec. 31,2007, NSP-Minnesota had 2,287 bargaining employees covered under acollective-bargaining agreement, which expires at the end of 2010.

 

**Employers’ Accounting for Defined Benefit Pension and OtherPostretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and132(R) (SFAS No. 158) —** In September 2006, theFASB issued SFAS No. 158, which requires companies to fully recognize thefunded status of each pension and other postretirement benefit plan as aliability or asset on their balance sheets with all unrecognized amounts to berecorded in other comprehensive income. NSP-Minnesota applied regulatory accounting treatment for unrecognizedamounts of regulated utility subsidiary employees, which allowed recognition asa regulatory liability reduction rather than as a charge to accumulated othercomprehensive income.  The effect ofadopting in 2006 for the remaining unrecognized amounts was a decrease inaccumulated other comprehensive income of $3.2 million.

 

**Pension Benefits**

 

XcelEnergy has several noncontributory, defined benefit pension plans that coveralmost all employees. Benefits are based on a combination of years of service,the employee’s average pay and Social Security benefits.

 

XcelEnergy’s policy is to fully fund into an external trust the actuariallydetermined pension costs recognized for ratemaking and financial reportingpurposes, subject to the limitations of applicable employee benefit and taxlaws.

 

***Pension Plan Assets*****—**Plan assets principally consist of the common stockof public companies, corporate bonds and U.S. government securities. The targetrange for our pension asset allocation is 60 percent in equity investments, 20percent in fixed income investments and 20 percent in nontraditional investments,such as real estate, private equity and a diversified commodities index.

 

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

 

50

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| ** **                 | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|----------------------------|------------|------------|------------|------------|------------|
| ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Equity securities          |       | 60         | %          | 63         | %          |
| Debt securities            |       | 22         |       | 22         |       |
| Real estate                |       | 4          |       | 4          |       |
| Cash                       |       | 2          |       | 2          |       |
| Nontraditional investments |       | 12         |       | 9          |       |
|                       |       | 100        | %          | 100        | %          |

 

XcelEnergy bases its investment-return assumption on expected long-term performancefor each of the investment types included in its pension asset portfolio. XcelEnergy considers the actual historical returns achieved by its asset portfolioover the past 20-year or longer period, as well as the long-term return levelsprojected and recommended by investment experts. The historical weighted averageannual return for the past 20 years for the Xcel Energy portfolio of pensioninvestments is 11.8 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.  A higher weighting in equity investments canincrease the volatility in the return levels achieved by pension assets in anyyear.  Investment returns in 2007 werebelow the assumed level of 8.75 percent while returns in 2006 and 2005 exceededthe assumed level of 8.75 percent.  XcelEnergy continually reviews its pension assumptions.  In 2008, Xcel Energy will continue to use aninvestment-return assumption of 8.75 percent.

 

***Benefit Obligations***— A comparisonof the actuarially computed pension benefit obligation and plan assets, on acombined basis, is presented in the following table:

 
| **(Thousands of Dollars)**                                                                | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| **Accumulated Benefit Obligation at Dec. 31**                                                  |       | $          | 2,497,898  |       | $          | 2,486,370 |   |
|                                                                                                |       |       |       |       |       |
| **Change in Projected Benefit Obligation**                                                          |       |       |       |       |       |
| Obligation at Jan. 1                                                                           |       | $          | 2,666,555  |       | $          | 2,796,780 |   |
| Service cost                                                                                        |       | 61,392     |       | 61,627     |       |
| Interest cost                                                                                       |       | 162,774    |       | 155,413    |       |
| Plan amendments                                                                                     |       | (19,955    | )          | (16,569    | )          |
| Actuarial (gain) loss                                                                               |       | 23,325     |       | (82,339    | )          |
| Benefit payments                                                                                    |       | (231,332   | )          | (248,357   | )          |
| Obligation at Dec. 31                                                                          |       | $          | 2,662,759  |       | $          | 2,666,555 |   |
| ** **                                                                                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Change in Fair Value of Plan Assets**                                                             |       |       |       |       |       |
| Fair value of plan assets at Jan. 1                                                            |       | $          | 3,183,375  |       | $          | 3,093,536 |   |
| Actual return on plan assets                                                                        |       | 199,230    |       | 306,196    |       |
| Employer contributions                                                                              |       | 35,000     |       | 32,000     |       |
| Benefit payments                                                                                    |       | (231,332   | )          | (248,357   | )          |
| Fair value of plan assets at Dec. 31                                                           |       | $          | 3,186,273  |       | $          | 3,183,375 |   |
|                                                                                                |       |       |       |       |       |
| **Funded Status of Plans at Dec. 31**                                                          |       |       |       |       |       |
| Funded Status                                                                                       |       | $          | 523,514    |       | $          | 516,820 |   |
| Noncurrent assets                                                                                   |       | 568,055    |       | 586,712    |       |
| Noncurrent liabilities                                                                              |       | (44,541    | )          | (69,892    | )          |
| Net pension amounts recognized on consolidated balance sheets                                       |       | $          | 523,514    |       | $          | 516,820 |   |
|                                                                                                |       |       |       |       |       |
| NSP-Minnesota prepaid pension asset recorded                                                        |       | $          | 270,436    |       | $          | 276,571 |   |
| ** **                                                                                          |       |       |       |       |       |
| **NSP-Minnesota Amounts Not Yet Recognized as  Components of Net Periodic Benefit Cost:**           |       |       |       |       |       |
| Net loss                                                                                            |       | $          | 72,479     |       | $          | 37,217 |   |
| Prior service cost                                                                                  |       | 57,948     |       | 77,393     |       |
| Total                                                                                               |       | $          | 130,427    |       | $          | 114,610 |   |
|                                                                                                |       |       |       |       |       |
| **SFAS No. 158 Amounts Have Been Recorded as  Follows Based Upon Expected Recovery in Rates:** |       |       |       |       |       |
| Regulatory liabilities                                                                              |       | $          | 130,427    |       | $          | 114,610 |   |
| Total                                                                                               |       | $          | 130,427    |       | $          | 114,610 |   |

 
| **Measurement  Date**                                            | ** ** | **Dec. 31,  2007** | ** ** | **Dec. 31,  2006** | ** ** |
|------------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|
|                                                             |       |                    |       |                    |       |
| **Significant Assumptions Used to Measure Benefit  Obligations** |       |                    |       |                    |       |
| Discount rate for year-end valuation                             |       | 6.25                    | %          | 6.00                    | %          |
| Expected average long-term increase in compensation level        |       | 4.00                    |       | 4.00                    |       |

 

51

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***Cash Flows***— Cash fundingrequirements can be impacted by changes to actuarial assumptions, actual assetlevels and other calculations prescribed by the funding requirements of incometax and other pension-related regulations. These regulations did not requirecash funding for 2005 through 2007 for Xcel Energy’s pension plans and are notexpected to require cash funding in 2008.

 

***Plan Changes*****—** The Pension Protection Act of 2006 (PPA) was effective Dec. 31,2006.  PPA requires a change in theconversion basis for lump-sum payments, three-year vesting for plans withaccount balance or pension equity benefits.  These changes are reflected as a planamendment for purposes of SFAS No. 87 – “Employers’ Accounting forPensions.”

 

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

 
| **(Thousands of Dollars)**                      | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service cost                                              |       | $        | 61,392     |     | $          | 61,627   |       | $ | 60,461 |   |
| Interest cost                                             |       | 162,774  |       | 155,413  |       | 160,985  |       |
| Expected return on plan assets                            |       | (264,831 | )          | (268,065 | )          | (280,064 | )          |
| Amortization of prior service cost                        |       | 25,056   |       | 29,696   |       | 30,035   |       |
| Amortization of net loss                                  |       | 15,845   |       | 17,353   |       | 6,819    |       |
| Net periodic pension cost (credit) under SFAS No. 87 |       | $        | 236        |     | $          | (3,976   | )          | $ | (21,764 | ) |
|                                                      |       |     |       |     |       |     |       |
| **NSP-Minnesota**                                         |       |     |       |     |       |     |       |
| Net periodic pension credit                               |       | $        | (9,682     | )        | $          | (11,373  | )          | $ | (18,362 | ) |
| Credits not recognized due to effects of regulation       |       | 11,147   |       | 12,637   |       | 19,368   |       |
| Net benefit cost recognized for financial reporting       |       | $        | 1,465      |     | $          | 1,264    |       | $ | 1,006 |   |
|                                                      |       |     |       |     |       |     |       |
| **Significant Assumptions Used to Measure Costs**         |       |     |       |     |       |     |       |
| Discount rate                                             |       | 6.00     | %          | 5.75     | %          | 6.00     | %          |
| Expected average long-term increase in compensation level |       | 4.00     |       | 3.50     |       | 3.50     |       |
| Expected average long-term rate of return on assets       |       | 8.75     |       | 8.75     |       | 8.75     |       |

 

Pension costs include anexpected return impact for the current year that may differ from actualinvestment performance in the plan. The return assumption used for 2008 pensioncost calculations will be 8.75 percent. The cost calculation uses amarket-related valuation of pension assets. Xcel Energy uses a calculated value method to determine themarket-related value of the plan assets. The market-related value begins withthe fair market value of assets as of the beginning of the year. Themarket-related value is determined by adjusting the fair market value of assetsto reflect the investment gains and losses (the difference between the actualinvestment return and the expected investment return on the market-relatedvalue) during each of the previous five years at the rate of 20 percent peryear.

 

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

 

**Defined Contribution Plans**

** **

XcelEnergy maintains 401(k) plans that cover substantially all employees. Thecontributions for NSP-Minnesota were approximately $4.2 million in 2007, $3.9million in 2006 and  $3.8 million in 2005.

 

52

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**Postretirement Health CareBenefits**

** **

XcelEnergy has a contributory health and welfare benefit plan that provides healthcare and death benefits to most Xcel Energy retirees. The former NSPdiscontinued contributing toward health care benefits for nonbargainingemployees retiring after 1998 and for bargaining employees of NSP-Minnesota andNSP-Wisconsin who retired after 1999. Employees of the former NSP who retiredafter 1998 are eligible to participate in the Xcel Energy health care programwith no employer subsidy.

 

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

 

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

 

***Plan Assets***— Certain stateagencies that regulate Xcel Energy’s utility subsidiaries also have issuedguidelines related to the funding of SFAS No. 106 costs.  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.

 

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

 
| ** **                               | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|
| Equity and equity mutual fund securities |       | 67       | %          | 67       | %          |
| Fixed income/debt securities             |       | 21       |       | 21       |       |
| Cash equivalents                         |       | 11       |       | 11       |       |
| Nontraditional investments               |       | 1        |       | 1        |       |
|                                     |       | 100      | %          | 100      | %          |

 

XcelEnergy bases its investment-return assumption for the postretirement healthcare fund assets on expected long-term performance for each of the investmenttypes included in its postretirement health care asset portfolio.Investment-return volatility is not considered to be a material factor inpostretirement health care costs.

 

***Benefit Obligations***— A comparisonof the actuarially computed benefit obligation and plan assets for Xcel Energypostretirement health care plans that benefit employees of its utilitysubsidiaries is presented in the following table:

 

53

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| **(Thousands of Dollars)**                                                                | ** ** | **2007**            | ** ** | **2006**            | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|---------------------|------------|---------------------|------------|
| ** **                                                                                          | ** ** | ** **          | ** ** | ** **          | ** ** |
| **Change in Benefit Obligation**                                                                    |       |                |       |                |       |
| Obligation at Jan. 1                                                                           |       | $                   | 918,693    |                | $          | 938,172 |   |
| Service cost                                                                                        |       | 5,813               |       | 6,633               |       |
| Interest cost                                                                                       |       | 50,475              |       | 52,939              |       |
| Medicare subsidy reimbursements                                                                     |       | 2,526               |       | 3,561               |       |
| Plan amendments                                                                                     |       | —              |       | (945                | )          |
| Plan participants’ contributions                                                               |       | 13,211              |       | 11,870              |       |
| Actuarial gain                                                                                      |       | (86,576             | )          | (27,511             | )          |
| Benefit payments                                                                                    |       | (73,827             | )          | (66,026             | )          |
| Obligation at Dec. 31                                                                          |       | $                   | 830,315    |                | $          | 918,693 |   |
|                                                                                                |       |                |       |                |       |
| **Change in Fair Value of Plan Assets**                                                             |       |                |       |                |       |
| Fair value of plan assets at Jan. 1                                                            |       | $                   | 406,305    |                | $          | 351,863 |   |
| Actual return on plan assets                                                                        |       | 24,623              |       | 41,409              |       |
| Plan participants’ contributions                                                               |       | 13,211              |       | 11,870              |       |
| Employer contributions                                                                              |       | 57,147              |       | 67,188              |       |
| Benefit payments                                                                                    |       | (73,827             | )          | (66,025             | )          |
| Fair value of plan assets at Dec. 31                                                           |       | $                   | 427,459    |                | $          | 406,305 |   |
|                                                                                                |       |                |       |                |       |
| **Funded Status at Dec. 31**                                                                   |       |                |       |                |       |
| Funded status                                                                                       |       | $                   | (402,856   | )                   | $          | (512,388 | ) |
| Current liabilities                                                                                 |       | (1,755              | )          | (2,211              | )          |
| Noncurrent liabilities                                                                              |       | (401,101            | )          | (510,177            | )          |
| Net amounts recognized in consolidated balance sheets                                               |       | $                   | (402,856   | )                   | $          | (512,388 | ) |
|                                                                                                |       |                |       |                |       |
|                                                                                                |       |                |       |                |       |
| **NSP-Minnesota Amounts Not Yet Recognized as  Components of Net Periodic Benefit Cost:**           |       |                |       |                |       |
| Net loss                                                                                            |       | $                   | 88,968     |                | $          | 105,868 |   |
| Transition obligation                                                                               |       | 6,765               |       | 8,111               |       |
| Total                                                                                               |       | $                   | 95,733     |                | $          | 113,979 |   |
| ** **                                                                                          | ** ** | ** **          | ** ** | ** **          | ** ** |
| **SFAS No. 158 Amounts Have Been Recorded as  Follows Based Upon Expected Recovery in Rates:** |       |                |       |                |       |
| Regulatory liabilities                                                                              |       | $                   | 91,757     |                | $          | 108,513 |   |
| Deferred income taxes                                                                               |       | 1,624               |       | 2,233               |       |
| Net-of-tax AOCI                                                                                     |       | 2,352               |       | 3,233               |       |
| Total                                                                                               |       | $                   | 95,733     |                | $          | 113,979 |   |
|                                                                                                |       |                |       |                |       |
| NSP-Minnesota accrued benefit liability recorded                                                    |       | $                   | 164,405    |                | $          | 184,868 |   |
|                                                                                                |       |                |       |                |       |
| **Measurement Date**                                                                                |       | Dec. 31,  2007 |       | Dec. 31,  2006 |       |
| ** **                                                                                          |       |                |       |                |       |
| **Significant Assumptions Used to Measure Benefit  Obligations**                                    |       |                |       |                |       |
| Discount rate for year-end valuation                                                                |       | 6.25                | %          | 6.00                | %          |

 

EffectiveDec. 31, 2007, Xcel Energy reduced its initial medical trend assumptionfrom 9.0 percent to 8.0 percent.  Theultimate trend assumption remained unchanged at 5.0 percent. The period untilthe ultimate rate is reached is six years. Xcel Energy bases its medical trendassumption on the long-term cost inflation expected in the health care market,considering the levels projected and recommended by industry experts, as wellas recent actual medical cost increases experienced by Xcel Energy’s retireemedical plan.

 

A1-percent change in the assumed health care cost trend rate would have thefollowing effects on NSP-Minnesota:

 

54

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| **(Millions of Dollars)**                                             | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------|------------|------------|------------|
| 1-percent increase in APBO components at Dec. 31, 2007                     |       | $          | 19.3       |   |
| 1-percent decrease in APBO components at Dec. 31, 2007                     |       | (16.1      | )          |
| 1-percent increase in service and interest components of the net  periodic cost |       | 1.4        |       |
| 1-percent decrease in service and interest components of the net  periodic cost |       | (1.1       | )          |
|                                                                                 |            |            |            |  |

 

***Cash Flows***— Thepostretirement health care plans have no funding requirements under income taxand other retirement-related regulations other than fulfilling benefit paymentobligations, when claims are presented and approved under the plans. Additionalcash funding requirements are prescribed by certain state and federal rateregulatory authorities, as discussed previously. Xcel Energy expects tocontribute approximately $49 million during 2008.

 

***Benefit Costs***— Thecomponents of net periodic postretirement benefit cost are:

 
| **(Thousands of Dollars)**                                               | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                                       |       | $          | 5,813      |       | $          | 6,633      |       | $ | 6,684 |   |
| Interest cost                                                                      |       | 50,475     |       | 52,939     |       | 55,060     |       |
| Expected return on plan assets                                                     |       | (30,401    | )          | (26,757    | )          | (25,700    | )          |
| Amortization of transition obligation                                              |       | 14,577     |       | 14,444     |       | 14,578     |       |
| Amortization of prior service credit                                               |       | (2,178     | )          | (2,178     | )          | (2,178     | )          |
| Amortization of net loss                                                           |       | 14,198     |       | 24,797     |       | 26,246     |       |
| Net periodic postretirement benefit cost under SFAS No. 106                   |       | $          | 52,484     |       | $          | 69,878     |       | $ | 74,690 |   |
|                                                                               |       |       |       |       |       |       |       |
| **NSP-Minnesota**                                                                  |       |       |       |       |       |       |       |
| Net periodic postretirement benefit cost recognized —  SFAS No. 106 |       | $          | 13,761     |       | $          | 17,154     |       | $ | 17,569 |   |
|                                                                               |       |       |       |       |       |       |       |
| **Significant assumptions used to measure costs  (income)**                        |       |       |       |       |       |       |       |
| Discount rate                                                                      |       | 6.00       | %          | 5.75       | %          | 6.00       | %          |
| Expected average long-term rate of return on assets (before tax)              |       | 7.5        |       | 7.5        |       | 5.5-8.5    |       |

#  

# **Projected Benefit Payments**

#  

Thefollowing table lists Xcel Energy’s projected benefit payments for the pensionand postretirement benefit plans.

 
| **(Thousands of Dollars)** | ** ** | **Projected Pension  Benefit Payments** | ** ** | **Gross Projected  Postretirement Health  Care Benefit  Payments** | ** ** | **Expected Medicare  Part D Subsidies** | ** ** | **Net Projected  Postretirement Health  Care Benefit  Payments** | ** ** |
|--------------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|--------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| 2008                                 |       | $                                                 | 215,127    |                                                                              | $          | 60,706                                                 |       | $                                                                               | 5,841      |   | $ | 54,865 |   |
| 2009                                 |       | 215,407                                           |       | 62,674                                                                            |       | 6,280                                                  |       | 56,394                                                                          |       |
| 2010                                 |       | 222,771                                           |       | 64,508                                                                            |       | 6,693                                                  |       | 57,815                                                                          |       |
| 2011                                 |       | 222,743                                           |       | 66,428                                                                            |       | 7,031                                                  |       | 59,397                                                                          |       |
| 2012                                 |       | 227,616                                           |       | 67,497                                                                            |       | 7,415                                                  |       | 60,082                                                                          |       |
| 2013-2017                            |       | 1,196,905                                         |       | 348,035                                                                           |       | 40,849                                                 |       | 307,186                                                                         |       |
|                                      |            |                                                   |            |                                                                                   |            |                                                        |            |                                                                                 |            |  |  |  |  |

 

**8.**    **Detail of Interest and Other Income (Expense), Net**

 

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

 
| **(Thousands of Dollars)**       | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|--------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest income                            |       | $          | 10,208     |       | $          | 13,294     |       | $ | 7,805 |   |
| Equity income in unconsolidated affiliates |       | 770        |       | 1,312      |       | 248        |       |
| Other nonoperating income                  |       | 1,048      |       | 945        |       | 1,171      |       |
| Insurance policy expenses                  |       | (5,921     | )          | (6,120     | )          | (5,914     | )          |
| Other nonoperating expense                 |       | —     |       | —     |       | (346       | )          |
| Total interest and other income, net       |       | $          | 6,105      |       | $          | 9,431      |       | $ | 2,964 |   |

 

55

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**9.    Derivative Instruments**

** **

Inthe normal course of business, NSP-Minnesota is exposed to a variety of marketrisks.  Market risk is the potential lossor gain that may occur as a result of changes in the market or fair value of aparticular instrument or commodity. NSP-Minnesota utilizes, in accordance with approved risk managementpolicies, a variety of derivative instruments to mitigate market risk and toenhance its operations.

 

***Commodity Price Risk —*** NSP-Minnesotais exposed to commodity price risk in its electric and natural gasoperations.  Commodity price risk ismanaged by entering into 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 utilityoperations.  Commodity risk is alsomanaged through the use of financial derivative instruments.  NSP-Minnesota utilizes these derivativeinstruments to reduce the volatility in the cost of commodities acquired onbehalf of its retail customers even though regulatory jurisdiction may providefor recovery of actual costs.  The use ofderivative instruments is done consistently with the local jurisdictional cost-recoverymechanism.  NSP-Minnesota’s risk-managementpolicy allows it to manage commodity price risk within each rate-regulatedoperation to the extent such exposure exists.

 

***Short-Term Wholesale and Commodity TradingRisk —*** NSP-Minnesota conducts various short-term wholesaleand commodity trading activities, including the purchase and sale of electriccapacity and energy and other energy-related instruments.  NSP-Minnesota’s risk-management policy allowsmanagement to conduct these activities within guidelines and limitations asapproved by our risk management committee, which is made up of managementpersonnel not directly involved in the activities governed by this policy.

 

***Interest Rate Risk —***NSP-Minnesotais subject 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-Minnesotauses derivative instruments in connection with its utility commodity price,interest rate, short-term wholesale and commodity trading activities, includingforward contracts, futures, swaps and options. Qualifying hedging relationships are designated as a hedge of aforecasted transaction or future cash flow (cash flow hedge).  The types of qualifying hedging transactionsthat NSP-Minnesota is currently engaged in are discussed below.

 

**Cash Flow Hedges**

** **

***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, 2007,NSP-Minnesota had various commodity-related contracts designated as cash flowhedges extending through December 2008.

 

AtDec. 31, 2007, NSP-Minnesota had $0.2 million in accumulated othercomprehensive income that is expected to be recognized in earnings during thenext 12 months as the hedged transactions settle.

 

NSP-Minnesotahad immaterial ineffectiveness related to commodity cash flow hedges during2007 and 2006.

 

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

 

AtDec. 31, 2007, NSP-Minnesota had net gains related to interest rate swapsof approximately $0.2 million in accumulated other comprehensive income that itexpects to recognize in earnings during the next 12 months.

 

NSP-Minnesotahad no ineffectiveness related to interest rate cash flow hedges during 2007and 2006.

 

The following table shows the major components of thederivative instruments valuation in the consolidated balance sheets at Dec. 31:

*** ***

***56***

----

*** ***
| ** **                                                              | ** ** | **2007**                                                         | ** ** | **2006**                                                         | ** ** |
|-------------------------------------------------------------------------|------------|------------------------------------------------------------------|------------|------------------------------------------------------------------|------------|
| **(Thousands of Dollars)**                                    | ** ** | **Derivative  Instruments  Valuation –   Assets** | ** ** | **Derivative  Instruments  Valuation -   Liabilities** | ** ** | **Derivative  Instruments  Valuation -   Assets** | ** ** | **Derivative  Instruments  Valuation -   Liabilities** | ** ** |
| Long term purchased power agreements                                    |       | $                                                                | 176,443    |                                                             | $          | 245,240 |   | $ | 201,003 |   | $ | 259,765 |   |
| Electricity and natural gas trading and hedging derivative  instruments |       | 31,765                                                           |       | 12,176                                                           |       | 42,824 |   | 25,383 |   |
| Interest rate hedging instruments                                       |       | —                                                           |       | 2,727                                                            |       | — |   | — |   |
| Total                                                                   |       | $                                                                | 208,208    |                                                             | $          | 260,143 |   | $ | 243,827 |   | $ | 285,148 |   |

 

In 2003, as a result of FASB Statement 133Implementation Issue No. C20, NSP-Minnesota began recording severallong-term purchased power agreements at fair value due to accountingrequirements related to underlying price adjustments.  As these purchases are recovered throughnormal regulatory recovery mechanisms in the respective jurisdictions, thechanges in fair value for these contracts were offset by regulatory assets andliabilities.  During the first quarter of2006, NSP-Minnesota qualified these contracts under the normal purchaseexception.  Based on this qualification,the contracts are no longer adjusted to fair value and the previous carryingvalue of these contracts will be amortized over the remaining contract livesalong with the offsetting regulatory assets and liabilities.

 

***Financial Impact of Qualifying Cash Flow Hedges*** — The impactof qualifying cash flow hedges on NSP-Minnesota’s accumulated othercomprehensive income, included in the consolidated statements of commonstockholder’s equity and comprehensive income, is detailed in the followingtable:

 
| ** **                                                                          | ** ** | **(Million of Dollars)** | ** ** |
|-------------------------------------------------------------------------------------|------------|------------------------------------|------------|
| 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        |   |
|                                                                                |       |                               |       |
| After-tax net unrealized losses related to derivatives accounted for  as hedges     |       | (0.3                               | )          |
| After-tax net realized gains on derivative transactions reclassified  into earnings |       | (0.4                               | )          |
| Accumulated other comprehensive income related to hedges at  Dec. 31, 2007     |       | $                                  | 8.7        |   |

 

**10. Financial Instruments**

** **

Theestimated Dec. 31 fair values of NSP-Minnesota’s recorded financialinstruments are as follows:

 
| ** **                                | ** ** | **2007**             | ** ** | **2006**            | ** ** |
|-------------------------------------------|------------|----------------------|------------|---------------------|------------|
| **(Thousands of Dollars)**      | ** ** | **Carrying  Amount** | ** ** | **Fair Value** | ** ** | **Carrying  Amount** | ** ** | **Fair Value** | ** ** |
| Nuclear decommissioning fund              |       | $                    | 1,317,564  |                | $          | 1,317,564 |   | $ | 1,200,688 |   | $ | 1,200,688 |   |
| Other investments                         |       | 9,154                |       | 9,154               |       | 10,415 |   | 10,415 |   |
| Long-term debt, including current portion |       | 2,463,109            |       | 2,628,580           |       | 2,229,228 |   | 2,466,465 |   |
|                                           |            |                      |            |                     |            |  |  |  |  |  |  |  |  |

 

Thefair value of cash and cash equivalents, notes and accounts receivable andnotes and accounts payable are not materially different from their carryingamounts.  The fair value of NSP-Minnesota’sdebt securities in an external nuclear decommissioning fund and otherinvestments are estimated based on quoted market prices for those or similarinvestments. The fair value of NSP-Minnesota’s long-term debt is estimatedbased on the quoted market prices for the same or similar issues, or thecurrent rates for debt of the same remaining maturities and credit quality.

 

Thefair value estimates presented are based on information available to managementas of Dec. 31, 2007 and 2006. These fair value estimates have not beencomprehensively revalued for purposes of these consolidated financialstatements since that date and current estimates of fair values may differsignificantly.

 

57

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

 
| **(Thousands of Dollars)** | ** ** | **2007**   | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------|------------|------------|------------|----------|------------|----------|------------|
| Realized gains                       |       | $          | 38,745     |     | $          | 310,066  |       | $ | 8,967 |   |
| Realized losses                      |       | 35,794     |       | 32,412   |       | 8,990    |       |
| Proceeds from sale of securities     |       | 669,070    |       | 958,294  |       | 489,697  |       |
| ** **                           | ** ** | ** ** | ** ** |     |       |     |
| **(Thousands of Dollars)** | ** ** | **2007**   | ** ** | **2006** | ** ** |     |
| Unrealized gains                     |       | $          | 80,960     |     | $          | 41,355   |       |   |
| Unrealized losses                    |       | —     |       | —   |       |     |
|                                      |            |            |            |          |            |          |            |  |  |  |  |

 

**Letters of Credit**

 

NSP-Minnesota uses letters of credit, generally with terms of one year,to provide financial guarantees for certain operating obligations.  At Dec. 31, 2007 and 2006, there were$7.2 million and $35.3 million of letters of credit outstanding.  The contract amounts of these letters ofcredit approximate their fair value and are subject to fees determined in themarketplace.

 

**11.Rate Matters**

 

**NSP-Minnesota**

** **

***Pendingand Recently Concluded Regulatory Proceedings — MPUC***

 

***Base Rate***

 

***NSP-Minnesota Natural GasRate Case****** —***In November 2006, NSP-Minnesotafiled a request with the MPUC to increase Minnesota natural gas rates by $18.5million annually, or 2.4 percent. The request was based on 11.0 percent ROE, aprojected equity ratio of 51.98 percent and a natural gas rate base of $439million. Interim rates, subject to refund, were set at a $15.9 million increaseand went into effect on Jan. 8, 2007.

 

In September 2007,the MPUC issued an order approving a rate increase of approximately $11.9million, based on an authorized ROE of 9.71 percent and an equity ratio of51.98 percent. The MPUC subsequently denied NSP-Minnesota’s request forrehearing on the ROE.  NSP-Minnesota hasfiled a compliance filing and refund plan, proposing to implement final rateson Feb. 1, 2008.  In January 2008,the MPUC approved the compliance filing.

 

***NSP-Minnesota Electric Rate Case****** —***In November 2005,NSP-Minnesota requested an electric rate increase of $168 million or 8.05percent. This increase was based on a requested an 11 percent ROE, a projectedcommon equity to total capitalization ratio of 51.7 percent and a projectedelectric rate base of $3.2 billion.

 

In September 2006,the MPUC issued an order approving a rate increase of approximately $131million for 2006 based on an authorized ROE of 10.54 percent. This amount wasreduced in 2007 to $115 million to reflect the return of a large industrialcustomer, to the NSP-Minnesota system. The MPUC order became effective in November 2006and final rates were implemented on Feb. 1, 2007.

 

In March 2007,a citizen intervenor submitted a brief asking that the Minnesota Court ofAppeals remand to the MPUC on various issues decided by the MPUC.  TheCourt of Appeals issued an Order in January 2008 upholding the MPUC’sdecision.

 

**Electric,Purchased Gas and Resource Adjustment Clauses**

 

***TCR**** **—*** InNovember 2006, the MPUC approved  aTCR rider pursuant to 2005 legislation. The TCR mechanism would allow recoveryof incremental transmission investments between rate cases.

 

·                  In October 2006, NSP-Minnesotafiled for approval of recovery of $14.7 million in 2007 under the TCRtariff.

·                  In March 2007, the MPUC approvedrecovery of $11.5 million in 2007.

·                  In August 2007, NSP-Minnesotafiled for approval of recovery of $19.7 million in Minnesota retail electricrates in 2008 under the TCR tariff.

·                  In December 2007, NSP-Minnesotafiled tariff sheets proposing to implement TCR rate factors that would recover

 

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only the non-disputed costs effective Jan. 1,2008, subject to true-up.  In December 2007,the MDOC recommended 2008 recovery of approximately $18.5 million, assertingthat certain costs did yet not meet statutory criteria.  After further comment and reply, the partiesresolved all disputed issues.

·                  The filing, as amended, is pendingMPUC action.

 

***RES Rider –*** In June 2007,NSP-Minnesota filed an application for a new rate rider to recover the costsassociated with utility-owned projects implemented in compliance with the RESadopted by the 2007 Minnesota legislature. The proposed rate adjustment wouldrecover the costs associated with the Grand Meadow wind farm, a 100-MW windproject proposed by NSP-Minnesota. The rate rider would recover the 2008revenue requirements associated with the project of approximately $14.6million.  MPUC action on this request ispending.

 

***Mercury Cost Recovery******—***In December 2006,NSP-Minnesota requested approval of a Mercury Emissions Reduction Rider torecover approximately $5.4 million during 2007 from Minnesota electric retailcustomers for costs associated with implementing both the mercury and otherenvironmental improvement portions of the Mercury Emissions Reduction Act of2006. NSP-Minnesota subsequently withdrew the filing and obtained approval todefer costs associated  as a regulatoryasset for potential future recovery. NSP-Minnesota has since filed a mercury reduction plan with the MPCA andMPUC and expects to file for rate rider recovery in the first half of 2008.

 

***AnnualAutomatic Adjustment Report for 2007 —******In September 2007,NSP-Minnesota filed its annual automatic adjustment report for July 1,2006 through June 30, 2007, which is the basis for the MPUC review ofcharges that flow through the FCA and PGA mechanisms. During that time period,$1.16 billion in fuel and purchased energy costs, including $384 million ofMISO Day 2 energy market charges were recovered from electric customers throughthe FCA.  In addition, approximately $590million of purchased natural gas and transportation costs were recovered throughthe PGA.  The 2007 annual automaticadjustment report is pending comments and MPUC action.***

 

***Other***

 

***MISO Day 2 Market Cost Recovery***— In December 2006,the MPUC issued an order ruling that NSP-Minnesota may recover all MISO Day 2costs, except Schedules 16 and 17 administrative charges, through its FCAeffective April 1, 2005.

 

In April 2007, theMOAG filed an appeal of the MPUC order to the Minnesota Court of Appealschallenged the MPUC’s decision to allow FCA recovery of these MISO charges.NSP-Minnesota and the other affected utilities intervened in the appeal andfiled briefs urging the court to uphold the MPUC order. The oral argument inthe appeal is scheduled for Feb. 27, 2008. The date for a court decision in the appeal is not known.

 

***Annual Review of Remaining Lives DepreciationFiling —******In September 2007, the MPUCapproved NSP-Minnesota’s remaining lives depreciation filing effective to Jan. 1,2007, lengthening the life of the Monticello nuclear plant by 20 years to 2030as well as certain other smaller life adjustments. These adjustments reducedthe depreciation expense of NSP-Minnesota by approximately $41 million for theperiod ended Dec. 31, 2007. The MPUC also approved an adjustment to ratebase to be used in the next electric rate case that will hold ratepayersindifferent to this change in remaining lives between rate cases. NSP-Minnesotacalculated the revenue requirement associated with this adjustment to beapproximately $1.4 to $2.8 million, depending on the timing of the next electricrate case. In addition, the lengthening of the remaining life for theMonticello nuclear plant decreased the related ARO by $121 million in the thirdquarter of 2007 with no impact to net income in 2007.***

 

***Nuclear RefuelingOutage Costs*—** In November 2007, NSP-Minnesota fileda request asking for a change in the recovery method for costs associated withrefueling outages at its nuclear plants. The request seeks approval to amortize refueling outage costs over the periodbetween refueling outages to better match revenue and expenses.  This request, if approved, would reduce 2008expenses for NSP-Minnesota jurisdiction by $25 million due to deferral andamortization over an 18-month period versus expensed as incurred.  Comparable filings have been made in NorthDakota and South Dakota.

 

***Pending Regulatory Proceedings — NDPSC and SDPUC***

** **

***NSP-Minnesota North Dakota Electric Rate Case*—**In December 2007, NSP-Minnesota filed a request with the NDPSC toincrease North Dakota retail electric rates by $20.5 million, or about 14percent.  The request was based on an11.50 percent ROE, an equity ratio of 51.77 percent, and a jurisdictional ratebase of approximately $242 million. Interim rates of $17.2 million became effective in February 2008.  Hearings are expected to be held in lateJune, and

 

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final ratesare expected to be effective Oct. 1, 2008. NSP-Minnesota and the NDPSC staff reached a stipulation settlement inthe rate case in which both parties recommended an ROE of 10.75 percent, with asharing mechanism for earnings about 10.75 percent.  This stipulation settlement is subject toapproval by the NDPSC.

 

***Pendingand Recently Concluded Regulatory Proceedings — FERC***

 

***FERC TransmissionRate Case*****—**In September 2007, Xcel Energy and MISO filed proposed changes to the MISOTEMT to establish a revised formula transmission rate for the integrated NSPSystem.  The rate filing would establishthe transmission service rates for the NSP System based on annual forward looking(rather than historic) transmission costs; provide more current recovery of NSPSystem transmission investments and allow recovery of certain transmissionincentives authorized by the Energy Act and the implementation of FERC rules.  Xcel Energy made the filing in anticipationof significant transmission capital additions by NSP-Minnesota andNSP-Wisconsin.  A forward looking formularate will facilitate the financing and construction of the new transmission facilitieswhile providing a current return on invested capital for the portion of theinvestment subject to FERC rate jurisdiction. In December 2007, the FERC issued an order accepting the ratechange effective Jan. 1, 2008, subject to Xcel Energy and MISO makingcertain changes to the procedures for pre-filing notice of the annual formularate changes.  No party filed forrehearing and Xcel Energy submitted the required compliance filing on Jan. 22,2008.  The rate change is expected toincrease 2008 NSP System transmission revenues by $2.7 million.

 

***MISO Long-Term Transmission Pricing**** **—***InOctober 2005, MISO filed a proposed change to its Open Access TEMT toregionalize future cost recovery of certain high voltage transmission projectsto be constructed for reliability improvements. The tariff, called the RegionalExpansion Criteria Benefits phase I (RECB I) and a subsequent proposal based onregional economic benefits (RECB II), would recover varying percentages ofeligible reliability transmission costs from all transmission service customersin the MISO 15 state region. In November 2006, the FERC issued an orderaccepting the RECB I tariff, including the 20 percent limitation. In December 2006,the PSCW and other parties filed an appeal of the RECB I order to the federalCourt of Appeals for the District of Columbia. The appeal is pending.

 

In March 2007, theFERC issued an order approving most aspects of the RECB II proposal. Variousparties filed requests for rehearing, which the FERC subsequently denied.

 

Transmission servicerates in the MISO region presently use a rate design in which the transmissioncost depends on the location of the load being served (referred to as “licenseplate” rates). Costs of existing transmission facilities are thus notregionalized. MISO and its transmission owners filed a successor ratemethodology in August 2007, to be effective Feb. 1, 2008. Otherentities sought to regionalize some of these costs.  The impact of the regionalization of futurefacilities would depend on the specific facilities placed in service. In January 2008,the FERC issued an order accepting the MISO filing to continue use of licenseplate rates for existing facilities and RECB (limited regionalization) pricingfor certain new facilities.  The FERCrejected proposals to regionalize a larger share of the cost of existing or newtransmission facilities.

 

***Revenue Sufficiency Guarantee Charges**** **—***InApril 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 2005. The RSG charges arecollected from  MISO customers and paidto generators. In October 2006, the FERC issued an order granting rehearingin part and reversed the prior ruling requiring MISO to issue retroactiverefunds and ordered MISO to submit a compliance filing to implement prospectivechanges.

 

In March 2007,the FERC issued orders separately denying rehearing of the FERC order.  Several parties have filed separate appealsto the D.C. Circuit Court seeking judicial review of the FERC’s determinationsof the allocation of RSG costs among MISO market participants. Xcel Energy hasintervened in each of these proceedings. In August 2007, Ameren Services Company (Ameren) and the NorthernIndiana Public Service Company (NIPSCO) filed a joint complaint against MISO atthe FERC, challenging the MISO’s current FERC-approved methodology for therecovery of RSG costs. Subsequently, eight other entities filed complaints atthe FERC effectively adopting the substantive arguments raised by Ameren andNIPSCO.  In November 2007, the FERCissued an order that instituted a proceeding in these dockets to reviewevidence and to establish a RSG cost allocation methodology for marketparticipants under the Midwest ISO Tariff. The refund-effective date established is Aug. 10, 2007.  FERC action is pending.

 

**12. Commitments and Contingent Liabilities**

 

***Capital Commitments —***Theestimated cost, as of Dec. 31, 2006, of the capital expenditure programsand other capital

 

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requirementsof NSP-Minnesota is approximately $1.0 billion in 2008, $805 million in 2009and $910 million in 2010.  NSP-Minnesota’scapital forecast includes the following major projects.

 

*CAPX 2020** —*In June 2006,CapX 2020, an alliance of electric cooperatives, municipals and investor-ownedutilities in the upper Midwest, including Xcel Energy, announced that it hadidentified several groups of transmission projects that proposed to be completeby 2020.****Group 1 projectinvestments are expected to total approximately $1.3 billion, with majorconstruction targeted to begin in 2009 or 2010 and ending three or four yearslater. Xcel Energy’s investment is expected to be approximately $700 million.Approximately 75 percent of the capital expenditures and return on investmentfor transmission projects are expected to be recovered under an NSP-MinnesotaTCR tariff rider mechanism authorized by Minnesota legislation, as well assimilar TCR mechanisms passed in North Dakota and South Dakota.

 

*Nuclear Capacity Increases and Life Extension** —*In August 2004,NSP-Minnesota announced plans to pursue 20-year license renewals for theMonticello and Prairie Island nuclear plants, whose licenses will expirebetween 2010 and 2014. License renewal for Monticello was approved by the NRCin November 2006 and the MPUC issued its approval in October 2006allowing additional spent fuel storage. Similar applications will be submitted for Prairie Island in 2008, withfinal state and federal approvals expected in 2010.

 

NSP-Minnesota is pursuing capacity increases of allthree units that will total approximately 230 MW, to be implemented, ifapproved, between 2009 and 2015. The life extension and a capacity increase forPrairie Island Unit 2 is contingent on replacement of Unit 2’s original steamgenerators, currently planned for replacement during the refueling outage in2013. Total capital investment for these activities is estimated to beapproximately $1 billion between 2006 and 2015. NSP-Minnesota plans to seekapproval for an alternative recovery mechanism from customers of its nuclearcosts. It is NSP-Minnesota’s plan to submit the certificate of need for Monticelloin the first quarter of 2008 and the certificate of need for Prairie Island inthe second quarter of 2008.

 

*MERP Project**** ****—*In December 2003,the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueledelectric generating plants to natural gas and to install advanced pollutioncontrol equipment at a third coal-fired plant. These improvements are expectedto significantly reduce air emissions from these facilities, while increasingthe capacity at system peak by 300 MW. Major construction for the MERP projectbegan in 2005 and these projects are expected to come on line between 2007 and2009. The cumulative investment is approximately $1 billion. The MPUC hasapproved a more current recovery of the financing costs related to the MERP.The in-service plant costs, including the financing costs during construction,are recovered from customers through a MERP rider, which was effective Jan. 1,2006.

 

*Sherco Project** —*NSP-Minnesota has proposed a $1.1billion upgrade at the Sherco coal-fired power plant. The project will increasecapacity and reduce emissions. The MPUC is expected to rule on the projectin 2008. If approved, construction would start in late 2010 and be completed onthe final unit in 2014.

 

*Wind Generation** —*NSP-Minnesotaplans to invest $212.5 million to acquire 100-MW of wind generation. Theproject would be eligible for rider recovery in Minnesota. The project receivedapproval by the MPUC in December 2007.

 

The capitalexpenditure programs of NSP-Minnesota are subject to continuing review andmodification. Actual utility construction expenditures may vary from theestimates due to changes in electric and natural gas projected load growthregulatory decisions, the desired reserve margin and the availability ofpurchased power, as well as alternative plans for meeting NSP-Minnesota’slong-term energy needs. In addition, NSP-Minnesota’s ongoing evaluation ofcompliance with future requirements to install emission-control equipment andmerger, acquisition and divestiture opportunities to support corporatestrategies may impact actual capital requirements.

 

***Leases*****— NSP-Minnesota leases a variety ofequipment and facilities used in the normal course of business, which areaccounted for as operating leases. Rental expense under operating lease obligations was approximately $53.3million, $35.7 million and $26.1 million for 2007, 2006 and 2005,respectively.  Purchase power agreementscontributed $29.5 million and $14.5 million in 2007 and 2006, respectively.

 

Included in the future commitments under operating leases are estimatedfuture payments under purchase power agreements that have been accounted for asoperating leases in accordance with Emerging Issues Task Force 01-8, “*Determining whether an Arrangement Contains a Lease*”and SFAS No. 13, “*Accounting for Leases*.”  Future commitments under leases forcontinuing operations are:

 

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| **(Millions of Dollars)** | ** ** | **Other  Operating Leases** | ** ** | **Purchased Power  Agreement  Operating Leases** | ** ** | **Total  Operating Leases** | ** ** |
|-------------------------------------|------------|----------------------------------|------------|------------------------------------------------------------|------------|----------------------------------|------------|
| 2008                                |       | $                                | 7.4        |                                                       | $          | 31.6                             |       | $ | 39.0 |   |
| 2009                                |       | 5.9                              |       | 32.1                                                       |       | 38.0                             |       |
| 2010                                |       | 4.1                              |       | 32.6                                                       |       | 36.7                             |       |
| 2011                                |       | 2.5                              |       | 33.1                                                       |       | 35.6                             |       |
| 2012                                |       | 2.1                              |       | 33.6                                                       |       | 35.7                             |       |
| Thereafter                          |       | 4.2                              |       | 485.4                                                      |       | 489.6                            |       |
|                                     |            |                                  |            |                                                            |            |                                  |            |  |  |  |

 

***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 2008 and 2028. 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 and transportationcosts.

 

The estimatedminimum purchases for NSP-Minnesota under these contracts as of Dec. 31,2007, is as follows:

 
| **Coal**                            | ** ** | **Nuclear Fuel** | ** ** | **Natural Gas  Supply** | ** ** | **Gas Storage &  Transportation** | ** ** |
|-------------------------------------|------------|-----------------------|------------|------------------------------|------------|-------------------------------------------------|------------|
| **(Millions of Dollars)** | ** ** |
| $                                   | 895        |                  | $          | 476                          |       | $                                               | 403        |   | $ | 985 |   |
|                                     |            |                       |            |                              |            |                                                 |            |  |  |  |  |

 

***Purchased PowerAgreements****—*NSP-Minnesotahas entered into agreements with utilities and other energy suppliers forpurchased power to meet system load and energy requirements, replace generationfrom company-owned units under maintenance and during outages and meetoperating reserve obligations. NSP-Minnesota has various pay-for-performancecontracts with expiration dates through the year 2033. In general, thesecontracts provide for capacity payments, subject to meeting certain contractobligations and energy payments based on actual power taken under thecontracts. Certain contractual payment obligations are adjusted based onindices.  However, the effects of theseprice adjustments are mitigated through cost-of-energy rate adjustmentmechanisms.

 

NSP-Minnesotahas also executed one additional purchase power agreement that is conditionalupon achievement of certain conditions, including becoming operational.Estimated payments under this conditional obligation are $13.3 million, $20.1million, $20.4 million, $20.8 million, $21.2 million and $299.5 million for2008 to 2012 and thereafter, respectively.

 

At Dec. 31,2007, the estimated future payments for capacity, accounted for as executorycontracts, that NSP-Minnesota is obligated to purchase, subject to availability,were as follows:

 
| ** **          | ** ** | **(Millions of Dollars)** | ** ** |
|---------------------|------------|-------------------------------------|------------|
| 2008                |       | $                                   | 109.3      |   |
| 2009                |       | 112.2                               |       |
| 2010                |       | 113.8                               |       |
| 2011                |       | 112.5                               |       |
| 2012                |       | 111.7                               |       |
| 2013 and thereafter |       | 620.7                               |       |
| Total*              |       | $                                   | 1,180.2    |   |

 

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

 

**Environmental Contingencies**

 

NSP-Minnesota has been, or is currently, involved with the cleanup ofcontamination from certain hazardous substances at several sites. In manysituations, NSP-Minnesota believes it will recover some portion of these coststhrough insurance claims. Additionally, where applicable, NSP-Minnesota ispursuing, or intends to pursue, recovery from other potentially responsibleparties and through the rate regulatory process. New and changing federal andstate environmental mandates can also create added financial liabilities forNSP-Minnesota, which are normally recovered

 

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through the rate regulatory process. To the extent any costs are notrecovered through the options listed above, NSP-Minnesota would be required torecognize 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. Environmentalcontingencies could arise from various situations including the followingcategories of sites:

 

·                  Sites of  former MGPs operated by NSP-Minnesota’ssubsidiaries, predecessors, or other entities; and

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

 

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

 

To estimate the remediation cost for these sites, assumptions are madewhen facts are not fully known. For instance, assumptions may be made about thenature and extent of site contamination, the extent of required cleanupefforts, costs of alternative cleanup methods and pollution-controltechnologies, the period over which remediation will be performed and paid for,changes in environmental remediation and pollution-control requirements, thepotential effect of technological improvements, the number and financialstrength of other PRPs and the identification of new environmental cleanupsites.

 

Estimates are revised as facts become known. At Dec. 31, 2007, theliability for the cost of remediating these sites was estimated to be $0.9 million,of which $0.3 million was considered to be a current liability. Some of thecost of remediation may be recovered from:

 

·                  Insurancecoverage;

·                  Other partiesthat have contributed to the contamination; and

·                  Customers.

 

Neither the total remediation cost nor the final method of costallocation among all PRPs of the unremediated sites has been determined.Estimates have been recorded for NSP-Minnesota’s future costs for these sites.

 

***Third Party andOther 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 anestimate for final removal of the asbestos as an ARO. See additional discussionof AROs below. It may be necessary to remove some asbestos to performmaintenance or make improvements to other equipment. The cost of removingasbestos as part of other work is immaterial and is recorded as incurred asoperating expenses for maintenance projects, capital expenditures forconstruction projects or removal costs for demolition projects.

 

***Other EnvironmentalRequirements***

 

***CAIR***— In March 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. Theobjective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, includingMinnesota.  CAIR addresses thetransportation of fine particulates, ozone and emission precursors tononattainment downwind states. CAIR has a two-phase compliance schedule,beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for bothemissions. Under CAIR, each affected state will be allocated an emissionsbudget for SO2 and NOx that will result in significantemission reductions. It will be based on stringent emission controls and formsthe basis for a cap-and-trade program. State emission budgets or caps declineover time.  States can choose toimplement an emissions reduction program based on the EPA’s proposed modelprogram, or they can propose another method, which the EPA would need toapprove.

 

NSP- Minnesota has generating facilities that will be impacted byCAIR.  On May 30, 2007, the MPCAissued a notice for implementing CAIR. This notice stated that Minnesota will administer the CAIR and the EPA’sFederal Implementation Plan.  Preliminaryestimates of capital expenditures associated with compliance with CAIR for theNSP System (Minnesota and Wisconsin) range from $30 million to $40 million.  To date NSP-Minnesota has spent $16.0 millionon CAIR compliance.

 

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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. NSP-Minnesota believes the cost of any required capitalinvestment or allowance purchases will be recoverable from customers.

 

***CAMR***— In March 2005, the EPA issued the CAMR, which regulated mercury emissionsfrom power plants.  On Feb. 8, 2008,the D.C. Circuit Court of Appeals vacated CAMR, which impacts federal CAMRrequirements, but not necessarily state-only mercury rules andlegislation.  Costs to comply with theMinnesota Mercury Emissions Reduction Act of 2006 are discussed below.

 

***Minnesota MercuryLegislation*** — In May 2006, the Minnesotalegislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providinga process for plans, implementation and cost recovery for utility efforts tocurb mercury emissions at certain power plants. For Xcel Energy, the Act coversunits at the A. S. King and Sherco generating facilities. Under the Act, XcelEnergy is operating and maintaining continuous mercury emission monitoringsystems. The information obtained will be used to establish a baseline fromwhich to measure mercury emission reductions. Mercury emission reduction planswere required to be filed by utilities by Dec. 31, 2007 (dry scrubbedunits) and Dec. 31, 2009 (wet scrubbed units) that propose to implementtechnologies most likely to reduce emissions by 90 percent. Implementationwould occur by Dec. 31, 2009 for one of the dry scrubbed units, Dec. 31,2010 for the remaining dry scrubbed unit and Dec. 31, 2014 for wetscrubbed units. The cost of controls will be determined as part of theengineering analysis portion of the mercury reduction plans and is currentlyestimated to range from $26.5 to $854.5 million for the mercury control andcontinuous monitoring equipment for Sherco units 1, 2 and 3 and for A.S. King,with increased operating and maintenance expenses estimated to range fromapproximately $24.7 to $77.2 million. The lower values include costs to achievea 50 percent mercury reduction for Sherco units 1 and 2 and a 90 percentmercury reduction for Sherco unit 3 and A. S. King.  The higher values include costs to achieve a90 percent mercury reduction for all Sherco units, as well as for A. S.King.  Utilities subject to the Act mayalso submit plans to address non-mercury pollutants subject to federal andstate statutes and regulations, which became effective after Dec. 31,2004. Cost recovery provisions of the Act also apply to these otherenvironmental initiatives. In September 2006, NSP-Minnesota filed arequest with the MPUC for recovery of up to $6.3 million of certainenvironmental improvement costs that are expected to be recoverable under theAct. In January 2007, the MPUC approved this request to defer these costsas a regulatory asset with a cap of $6.3 million. To date NSP-Minnesota hasspent approximately $1.3 million on mercury monitoring implementation.

 

***Regional Haze Rules ***—In June 2005, the EPA finalized amendments to the July 1999 regionalhaze rules. These amendments apply to the provisions of the regional haze rule thatrequire emission controls, known as BART, for industrial facilities emittingair pollutants that reduce visibility by causing or contributing to regionalhaze.

 

The EPArequires states to develop implementation plans to comply with BART by December 2007.NSP-Minnesota submitted its BART alternatives analysis for Sherco units 1 and 2in October 2006. The MPCA reviewed the BART analyses for all units inMinnesota and determined that overall, compliance with CAIR is better thanBART. At this time, the MPCA is not requiring any BART specific controls thatgo beyond controls required for CAIR compliance.

 

***Voluntary CapacityUpgrade and Emissions Reduction Filing*** — In December 2007,NSP-Minnesota filed a plan with the MPCA and MPUC for reducing mercuryemissions by up to 90 percent at the Sherco unit 3 and King plants.  Estimated project costs amount toapproximately $9.1 million.  At the sametime, NSP-Minnesota submitted a revised filing to the MPUC for a majoremissions reduction project at Sherco Units 1and 2 to reduce emissions andexpand capacity.  The revised filing hasestimated  project costs of approximately$1.1 billion and encompasses the higher value mercury control costs discussedabove in the Minnesota Mercury Legislation section. The filing also containsalternatives for the MPUC to consider to add additional capacity and to achieveeven lower emissions.  If selected, thesealternatives could range from $90.8 to $330.8 million in addition to the $1.1billion proposal.  NSP-Minnesota’sinvestments are subject to MPUC approval of a cost recovery mechanism.

 

***Federal Clean Water Act —***The federal Clean WaterAct requires the EPA to regulate cooling water intake structures to assure thatthese structures 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. In January 2007,the court issued its decision and remanded virtually every aspect of the rule tothe EPA for reconsideration. In June 2007, the EPA suspended the deadlinesand referred any implementation to each state’s best professional judgmentuntil the EPA is able to fully respond to the court-ordered

 

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remand. As aresult, the rule’s compliance requirements and associated deadlines arecurrently unknown. It is not possible to provide an accurate estimate of theoverall cost of this rulemaking at this time due to the many uncertaintiesinvolved.

 

# **AssetRetirement Obligations**

 

NSP-Minnesota records future plant removal obligations as a liabilityat fair value with a corresponding increase to the carrying values of therelated long-lived assets in accordance with SFAS No. 143 — “Accountingfor Asset Retirement Obligations” (SFAS No. 143). This liability will beincreased over time by applying the interest method of accretion to theliability and the capitalized costs will be depreciated over the useful life ofthe related long-lived assets.  Therecording of the obligation for regulated operations has no income statementimpact due to the deferral of the adjustments through the establishment of aregulatory asset pursuant to SFAS No. 71.

 

***Recorded ARO —***ARO’shave been recorded for plant related to nuclear production, steam production,electric transmission and distribution, gas distribution and office buildings.  The steam production obligation includesasbestos, ash containment facilities and decommissioning.  The asbestos recognition associated with thesteam production includes certain plants at NSP-Minnesota.  NSP-Minnesota also recorded asbestos recognitionfor its general office building. Generally, this asbestos abatement removal obligation originated in 1973with the Clean Air Act, which applied to the demolition of buildings or removalof equipment containing asbestos that can become airborne on removal.  AROs also have been recorded forNSP-Minnesota steam production related to ash-containment facilities such asbottom ash ponds, evaporation ponds and solid waste landfills. The originationdate on the ARO recognition for ash-containment facilities at steam plants wasthe in-service date of various facilities.

 

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

 

For thenuclear assets, the ARO associated with the decommissioning of twoNSP-Minnesota nuclear generating plants, Monticello and Prairie Island,originates with the in-service date of the facility.  Monticello began operation in 1971.  Prairie Island units 1 and 2 began operationin 1973 and 1974, respectively.  See Note13 to the consolidated financial statements for further discussion of nuclearobligations.

 

Areconciliation of the beginning and ending aggregate carrying amounts ofNSP-Minnesota’s AROs is shown in the table below for the 12 months ended Dec. 31,2007 and Dec. 31, 2006, respectively:

 
| **(Thousands of Dollars)**   | ** ** | **Beginning  Balance  Jan. 1, 2007** | ** ** | **Liabilities  Recognized** | ** ** | **Liabilities  Settled** | ** ** | **Accretion** | ** ** | **Revisions  To Prior  Estimates** | ** ** | **Ending  Balance  Dec. 31, 2007** | ** ** |
|----------------------------------------|------------|------------------------------------------------|------------|-----------------------------|------------|--------------------------|------------|---------------|------------|-----------------------------------------|------------|----------------------------------------------|------------|
| ** **                             | ** ** | ** **                                     | ** ** | ** **                  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                              | ** ** | ** **                                   | ** ** |
| **Electric Utility Plant:**            | ** ** | ** **                                     | ** ** | ** **                  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                              | ** ** | ** **                                   | ** ** |
| Steam production asbestos              |       | $                                              | 22,169     |                        | $          | —                   |       | $             | —     |                                    | $          | 1,262                                        |       | $ | (1,008 | ) | $ | 22,423 |   |
| Steam production ash containment       |       | 17,163                                         |       | —                      |       | —                   |       | 948           |       | —                                  |       | 18,111                                       |       |
| Nuclear production decommissioning     |       | 1,256,763                                      |       | —                      |       | —                   |       | 73,914        |       | (120,931                                | )          | 1,209,746                                    |       |
| Electric transmission and distribution |       | 940                                            |       | —                      |       | —                   |       | 20            |       | (835                                    | )          | 125                                          |       |
| **Gas Utility Plant:**                 |       |                                           |       |                        |       |                     |       |          |       |                                    |       |                                         |       |
| Gas transmission and distribution      |       | 12,378                                         |       | —                      |       | —                   |       | 307           |       | —                                  |       | 12,685                                       |       |
| **Common Utility and Other Property:** |       |                                           |       |                        |       |                     |       |          |       |                                    |       |                                         |       |
| Common general plant asbestos          |       | 1,858                                          |       | —                      |       |                     |       | 100           |       | (680                                    | )          | 1,278                                        |       |
| Total liability                        |       | $                                              | 1,311,271  |                        | $          | —                   |       | $             | —     |                                    | $          | 76,551                                       |       | $ | (123,454 | ) | $ | 1,264,368 |   |

 

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| **(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 |   |

 

The fair valueof NSP-Minnesota assets legally restricted for purposes of settling the nuclearAROs is $1.3 billion as of Dec. 31, 2007, including external nucleardecommissioning investment funds and internally funded amounts.

 

***On Sept. 21, 2007,the MPUC approved NSP-Minnesota’s remaining lives depreciation filinglengthening the life of the Monticello nuclear plant by 20 years, effective Jan. 1,2007, which decreased the related ARO and related regulatory asset by $120.9million in the third quarter of 2007.***

 

***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 ofestimated future removal costs are considered regulatory liabilities under SFASNo. 71. Removal costs as of Dec. 31, 2007 and 2006 were $342 millionand $355 million, respectively.

 

**Nuclear Insurance**

 

NSP-Minnesota’s public liability for claims resultingfrom any nuclear incident is limited to $10.8 billion under thePrice-Anderson amendment to the Atomic Energy Act of 1954, as amended.NSP-Minnesota has secured $300 million of coverage for its public liabilityexposure with a pool of insurance companies. The remaining $10.5 billion ofexposure is funded by the Secondary Financial Protection Program, available fromassessments by the federal government in case of a nuclear accident.NSP-Minnesota is subject to assessments of up to $100.6 million per reactor peraccident for each of its three licensed reactors, to be applied for publicliability arising from a nuclear incident at any licensed nuclear facility inthe United States. The maximum funding requirement is $15 million per reactorduring any one year.  These maximumassessment amounts are both subject to inflation adjustment by the NRC andstate premium taxes.  The NRC’s lastadjustment was effective Aug. 20, 2003. The next adjustment is due on or before Aug. 20, 2008.

 

NSP-Minnesota purchases insurance for property damage and sitedecontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). Thecoverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plantsites. NEIL also provides business interruption insurance coverage, includingthe cost of replacement power obtained during certain prolonged accidentaloutages of nuclear generating units. Premiums are expensed over the policyterm. All companies insured with NEIL are subject to retroactive premiumadjustments if losses exceed accumulated reserve funds. Capital has beenaccumulated in the reserve funds of NEIL to the extent that NSP-Minnesota wouldhave no exposure for retroactive premium assessments in case of a singleincident under the business interruption and the property damage insurancecoverage. However, in each calendar year, NSP-Minnesota could be subject tomaximum assessments of

 

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approximately $15.0 million for business interruption insurance and$32.1 million for property damage insurance if losses exceed accumulatedreserve funds.

 

**LegalContingencies**

 

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

 

***EnvironmentalLitigation***

 

***Carbon Dioxide Emissions Lawsuit******—***In  July 2004, the attorneys general ofeight states and New York City, as well as several environmental groups, filedlawsuits in U.S. District Court in the Southern District of New York againstfive utilities, including Xcel Energy, to force reductions in CO2emissions. The other utilities include American Electric Power Co., SouthernCo., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2emitted by each company is a public nuisance as defined under state and federalcommon law because it has contributed to global warming. The lawsuits do notdemand monetary damages. Instead, the lawsuits ask the court to order eachutility to cap and reduce its CO2 emissions. In October 2004,Xcel Energy and the other defendants filed a motion to dismiss the lawsuit. OnSept. 19, 2005, the court granted the motion to dismiss on constitutionalgrounds. Plaintiffs filed an appeal to the Second Circuit Court ofAppeals.  In June 2007 the SecondCircuit Court of Appeals issued an order requesting the parties to file aletter brief regarding the impact of the United States Supreme Court’s decisionin Massachusetts v. EPA, 127 S.Ct. 1438 ( April 2, 2007) on the issuesraised by the parties on appeal. Among other things, in its decision inMassachusetts v. EPA, the United States Supreme Court held that CO2emissions are a “ pollutant” subject to regulation by the EPA under the CleanAir Act. In response to the request of the Second Circuit Court of Appeals, in June 2007,the defendant utilities filed a letter brief stating the position that theUnited States Supreme Court’s decision supports the arguments raised by theutilities on appeal.  The Court ofAppeals has taken the matter under advisement ***and is expected to issue anopinion in due course.***

 

***Comer vs. Xcel Energy Inc. et al.******—***In April 2006, Xcel Energy received notice of a purported class action lawsuit filed inU.S. District Court in the Southern District of Mississippi. The lawsuit namesmore than 45 oil, chemical and utility companies, including Xcel Energy, asdefendants and alleges that defendants’ CO2 emissions “were aproximate and direct cause of the increase in the destructive capacity of HurricaneKatrina.” Plaintiffs allege in support of their claim, several legal theories,including negligence and public and private nuisance and seek damages relatedto the loss resulting from the hurricane. Xcel Energy believes this lawsuit iswithout merit and intends to vigorously defend itself against theseclaims.  In August 2007, the courtdismissed the lawsuit in its entirety against all defendants on constitutionalgrounds.  In  September 2007, plaintiffs filed anotice of appeal to the Fifth Circuit Court of Appeals.  ***The Court of Appeals has taken the matter underadvisement and is expected to issue an opinion in due course.***

 

**Employment,Tort and Commercial Litigation**

 

***Hoffman vs. Northern States Power Company******—***In March 2006,a purported class action complaint was filed in Minnesota state court, onbehalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota andSouth Dakota for alleged breach of a contractual obligation to maintain andinspect the points of connection between NSP-Minnesota’s wires and customers’homes within the meter box. Plaintiffs claim NSP-Minnesota’s alleged breachresults in an increased risk of fire and is in violation of tariffs on filewith the MPUC. Plaintiffs seek injunctive relief and damages in an amount equalto the value of inspections plaintiffs claim NSP-Minnesota was required toperform over the past six years. In August 2006, NSP-Minnesota filed amotion for dismissal on the pleadings. In November 2006, the court issuedan order denying NSP-Minnesota’s motion, but later, pursuant to a motion byNSP-Minnesota, certified the issues raised in NSP-Minnesota’s original motionfor appeal as important and doubtful and NSP-Minnesota filed an appeal with theMinnesota Court of Appeals.  On Jan. 22,2008, the Minnesota Court of Appeals determined the plaintiffs’ claims arebarred by the filed rate doctrine and remanded the case to the district courtfor dismissal.

 

***Nuclear WasteDisposal Litigation******—*** In 1998,NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against theUnited States requesting breach of contract damages for the DOE’s failure tobegin accepting spent nuclear fuel by Jan. 31, 1998, as required by thecontract between the DOE and NSP-Minnesota. At trial, NSP-Minnesota claimeddamages in excess of $100 million through Dec. 31, 2004. On Sept. 26,2007, the court awarded NSP-Minnesota $116.5 million in damages. In December 2007,the court denied the DOE’s motion for reconsideration.  In February 2008 the DOE filed an appealto the U.S. Court of Appeals for the Federal Circuit. Results of the judgmentwill not be recorded in earnings until the appeal and regulatory treatment andamounts to be shared with ratepayers have

 

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been resolved. Given the uncertainties, it is unclear as to how much,if any, of this judgment will ultimately have a net impact on earnings.

 

In August 2007, NSP-Minnesota filed a second complaint against theDOE in the Court of Federal Claims (NSP II), again claiming breach of contractdamages for the DOE’s continuing failure to abide by the terms of the contract.This lawsuit claims damages for the period Jan. 1, 2005 through June 30,2007, which includes costs associated with the storage of spent nuclear fuel atPrairie Island and Monticello, as well as the costs of complying with stateregulation relating to the storage of spent nuclear fuel. The amount of suchdamages is expected to exceed $40 million. In January 2008, the court granted the DOE’s motion to stay,subject to reevaluation after a decision has been filed in any one of the fivepending appeals of nuclear waste storage cases.

 

***Siewert vs. Xcel Energy******—***In June 2004,plaintiffs, the owners and operators of a Minnesota dairy farm, brought an actionin Minnesota state court against NSP-Minnesota alleging negligence in thehandling, supplying, distributing and selling of electrical power systems;negligence in the construction and maintenance of distribution systems; andfailure to warn or adequately test such systems. Plaintiffs allege decreasedmilk production, injury and damage to a dairy herd as a result of stray voltageresulting from NSP-Minnesota’s distribution system. Plaintiffs claim losses ofapproximately $7 million. NSP-Minnesota denies all allegations. After itsmotion to dismiss plaintiffs’ claims was denied, NSP-Minnesota filed a motionto certify questions for immediate appellate review.  In October 2007 the court granted NSP-Minnesota’s motion for certification and the parties have filed briefs onappeal.

 

***Saemrow DairyPartnership vs. Xcel Energy******—***In December 2006,plaintiffs, the owners and operators of a Minnesota dairy farm, brought anaction in Minnesota state court against NSP-Minnesota alleging negligence inthe handling, supplying, distributing and selling of electrical power systemsand in the construction and maintenance of distribution systems.  They also alleged failure to warn oradequately 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 claim losses approximately $9 million. NSP-Minnesota deniesall allegations.  Mediation has been setfor March 2008; and in the event the matter is not resolved, trial is setfor October 2008.

 

**13. NuclearObligations**

 

***Fuel Disposal —***NSP-Minnesotais responsible for temporarily storing used or spent nuclear fuel from itsnuclear plants. 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 2007, $13million in 2006 and $12 million in 2005. In total, NSP-Minnesota had paidapproximately $373 million to the DOE through Dec. 31, 2007. 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 NuclearWaste Policy Act of 1982 required the DOE to begin accepting spent nuclear fuelno later than Jan. 31, 1998. In 1996, the DOE notified commercialspent-fuel owners of an anticipated delay in accepting spent nuclear fuel bythe required date and conceded that a permanent storage or disposal facilitywill not be available until at least 2010. NSP-Minnesota and other utilitieshave commenced lawsuits against the DOE to recover damages caused by the DOE’sfailure to meet its statutory and contractual obligations.

 

NSP-Minnesotahas its own temporary on-site storage facilities for spent fuel at itsMonticello and Prairie Island nuclear plants, which consist of storage pools atboth sites and a dry cask facility at Prairie Island. With the dry cask storagefacility licensed by the NRC, approved in 1994 and again in 2003, managementbelieves it has adequate storage capacity to continue operation of its PrairieIsland nuclear plant until at least the end of its current license terms in2013 and 2014. The Monticello nuclear plant has storage capacity in the storagepool to continue operations until 2010. In 2005, NSP-Minnesota filed acertificate of need to allow interim storage of spent fuel at the Monticellonuclear plant to support license renewal and operation for an additional 20years.  In October 2006, the MPUC issuedits approval allowing additional interim spent fuel storage.  Minnesota Statutes provide that the MPUCdecision become effective June 1, 2007, which allowed the legislature theopportunity to review the MPUC action if desired.  On Nov. 8, 2006, the NRC renewed theoperating license of the Monticello nuclear plant for an additional 20years.  All of the alternatives for spentfuel storage are being investigated until a DOE facility is available,including pursuing the establishment of a private facility for interim storageof spent nuclear fuel as part of a consortium of electric utilities.

 

Nuclear fuelexpense includes payments to the DOE for the decommissioning anddecontamination of the DOE’s

 

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uranium-enrichmentfacilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46million, which was payable in annual installments for 15 years until 2007.NSP-Minnesota amortized each installment to expense on a monthly basis. Thefinal annual assessment was received and paid in 2006.  The amortization of this annual assessmentwas completed in September 2007. NSP-Minnesota has obtained rate recoveryof these DOE assessments through the cost-of-energy adjustment clause as theassessments were amortized.

 

***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 recording 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 ARO in accordance with SFAS No. 143.

 

Monticellobegan operation in 1971 with an original license to operate until 2010. PrairieIsland units 1 and 2 began operation in 1973 and 1974, respectively and arecurrently licensed to operate until 2013 and 2014, respectively. In 2003, theMinnesota legislature changed a law that had limited expansion of on-sitestorage.  On Sept. 28, 2006, the MPUCapproved Xcel Energy’s request for a certificate of need to authorizeconstruction and operation of a dry spent fuel storage facility at Monticelloto become effective June 1, 2007. On Nov. 8, 2006, the NRC renewed the operating license of theMonticello nuclear plant for an additional 20 years to 2030.   In June 2007, NSP-Minnesota filed fordepreciation life extension of the Monticello nuclear plant based on previousNRC and MPUC process approvals.  TheMonticello 20-year depreciation life extension until September 2030 wasgranted by the MPUC on Sept. 21, 2007. Construction of the Monticello Independent Spent Fuel Storage facility,as allowed by the certificate of need approved in 2006, commenced on June 4,2007.  Installation of the horizontalstorage modules began in October of 2007 with a fuel loading campaignanticipated to begin in the Spring of 2008. Plant assessments and other work for the Prairie Island applicationsstarted in 2006.  The Prairie Islandoperating license extension for an additional 20 years of operation isanticipated to be filed by the end of the first quarter of 2008 with the NRC.

 

The total obligation for decommissioning currently is expected to befunded 100 percent by external funds, as approved by the MPUC whendecommissioning commences.  The MPUC lastapproved NSP-Minnesota’s nuclear decommissioning study request in March 2006,using 2005 cost data with the next update due in October 2008.  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,primarily consisted of investments in fixed income securities, such astax-exempt municipal bonds and U.S. government securities that mature in one to20 years and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioningbegins.

 

Consistentwith cost recovery in utility customer rates, NSP-Minnesota records annualdecommissioning expense 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 5.40 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) fund also recorded thesale of certain investments in the non-qualified fund and the reinvestment ofthe proceeds into the qualified fund. The sale and reinvestment, along with the transfer of securities waspart of a transaction intended to consolidate trust fund accounts into anincome tax advantaged fund, resulting from the Energy Act.  The transfer of funds was completed in thefourth quarter of 2006.

 

At Dec. 31, 2007, NSP-Minnesota had recorded and recovered inrates cumulative decommissioning expense of $1.2 billion. The following tablesummarizes the funded status of NSP-Minnesota’s decommissioning obligationbased on approved regulatory recovery parameters.  Xcel Energy believes future decommissioningcost expense will continue to be recovered in customer rates.  These amounts are not those recorded in thefinancial statements for the ARO in accordance with SFAS No. 143.

 

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| **(Thousands of Dollars)**                                                        | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|---------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| Estimated decommissioning cost obligation  from most recently approved study (2005 dollars) |       | $          | 1,683,750  |       | $          | 1,683,750 |   |
| Effect of escalating costs to 2007 and 2006  dollars (3.61 percent per year)                |       | 123,761    |       | 60,783     |       |
| Estimated decommissioning cost obligation  in current dollars                               |       | 1,807,511  |       | 1,744,533  |       |
| Effect of escalating costs to payment date  (3.61 percent per year)                         |       | 1,319,315  |       | 1,382,293  |       |
| Estimated future decommissioning costs  (undiscounted)                                      |       | 3,126,826  |       | 3,126,826  |       |
| Effect of discounting obligation (using  risk-free interest rate)                           |       | (1,502,030 | )          | (1,675,114 | )          |
| Discounted decommissioning cost obligation                                                  |       | 1,624,796  |       | 1,451,712  |       |
| Assets held in external decommissioning  trust                                              |       | 1,317,564  |       | 1,200,688  |       |
| Discounted decommissioning obligation in  excess of assets currently held in external trust |       | $          | 307,232    |       | $          | 251,024 |   |

 

Decommissioning expenses recognized include the following components:

 
| **(Thousands of Dollars)**                                   | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Annual decommissioning cost expense  reported as depreciation expense: |       |     |       |     |       |     |       |
| Externally funded                                                      |       | $        | 43,392     |     | $          | 48,069   |       | $ | 80,582 |   |
| Internally funded (including interest  costs)                          |       | (759     | )          | (5,046   | )          | (57,561  | )          |
| Net decommissioning expense recorded                                   |       | $        | 42,633     |     | $          | 43,023   |       | $ | 23,021 |   |

 

Reductions to expense for internally-funded portions in 2007, 2006 and2005 are a direct result of the 2005 decommissioning study jurisdictionalallocation and 100 percent external funding approval, effectively unwinding theremaining internal fund over the remaining operating life of the unit.  The 2005 nuclear decommissioning filingapproved in 2006 has been used for the regulatory presentation and all theupdated parameters were used for 2005. The change in estimated decommissionobligations was calculated using a life extension cost estimate for Monticello.

 

**14.Regulatory Assets and Liabilities**

 

NSP-Minnesota’s consolidated financial statements are prepared inaccordance with the provisions of SFAS No. 71, as discussed in Note 1 tothe consolidated financial statements. Under SFAS No. 71, regulatoryassets and liabilities can be created for amounts that regulators may allow tobe collected, or may require to be paid back to customers in future electricand natural gas rates. Any portion of the business that is not rate regulatedcannot use SFAS No. 71 accounting. If changes in the utility industry or the business of NSP-Minnesota nolonger allow for the application of SFAS No. 71 under GAAP, NSP-Minnesotawould be required to recognize the write-off of regulatory assets andliabilities in its consolidated statement of income.  The components of unamortized regulatoryassets and liabilities on the consolidated balance sheets of NSP-Minnesota are:

 

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| ** **                                              | ** ** | ** **           | ** ** | **Remaining Amortization**              | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------------------|------------|----------------------|------------|----------------------------------------------|------------|------------|------------|------------|------------|
| **(Thousands of Dollars)**                    | ** ** | **See Note(s)** | ** ** | **Period**                                   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
| ** **                                              | ** ** | ** **           | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Regulatory Assets**                                   |       |                 |       |                                         |       |       |       |       |       |
|                                                    |       |                 |       |                                         |       |       |       |       |       |
| Current regulatory asset – Unrecovered fuel  costs |       | 1                    |       | Less than  one year                          |       | $          | 36,857     |       | $          | 17,673 |   |
|                                                    |       |                 |       |                                         |       |       |       |       |       |
| AFDC recorded in plant (a)                              |       |                 |       | Plant lives                                  |       | $          | 112,750    |       | $          | 106,088 |   |
| Contract valuation adjustments (b)                      |       | 9                    |       | Term of  contract                            |       | 82,137     |       | 68,188     |       |
| Renewable resource costs                                |       |                 |       | Two to three  years                          |       | 44,238     |       | 49,902     |       |
| Losses on reacquired debt                               |       | 1                    |       | Term of  related debt                        |       | 28,666     |       | 25,944     |       |
| Unrecovered natural gas costs                           |       | 1                    |       | One to two  years                            |       | 22,505     |       | 17,943     |       |
| Net asset retirement obligations (c)                    |       | 12                   |       | Plant lives                                  |       | 20,776     |       | 36,945     |       |
| Conservation programs (a)                               |       |                 |       | Various                                      |       | 18,293     |       | 31,448     |       |
| Nuclear fuel storage                                    |       |                 |       | Four years                                   |       | 11,578     |       | 14,473     |       |
| MISO day 2 costs                                        |       |                 |       | To be  determined in future rate proceedings |       | 5,826      |       | 2,960      |       |
|                                                    |       |                 |       |                                         |       |       |       |       |       |
| State commission accounting  adjustments (a)       |       |                 |       | Plant lives                                  |       | 4,158      |       | 4,187      |       |
| Other                                                   |       |                 |       | Various                                      |       | 8,855      |       | 14,271     |       |
| Total noncurrent regulatory assets                      |       |                 |       |                                         |       | $          | 359,782    |       | $          | 372,349 |   |
|                                                    |       |                 |       |                                         |       |       |       |       |       |
| **Regulatory Liabilities**                              |       |                 |       |                                         |       |       |       |       |       |
|                                                    |       |                 |       |                                         |       |       |       |       |       |
| Plant removal costs                                     |       | 12                   |       |                                         |       | $          | 342,207    |       | $          | 355,390 |   |
| Pension and employee benefit obligations                |       | 7                    |       |                                         |       | 195,394    |       | 185,425    |       |
| Deferred income tax adjustments                         |       |                 |       |                                         |       | 42,611     |       | 48,644     |       |
| Investment tax credit deferrals                         |       |                 |       |                                         |       | 30,211     |       | 32,902     |       |
| Contract valuation adjustments (b)                      |       |                 |       |                                         |       | 14,275     |       | 16,420     |       |
| Interest on income tax refunds                          |       |                 |       |                                         |       | 3,472      |       | 5,208      |       |
| Gain on sale of emission allowances                     |       |                 |       |                                         |       | 2,885      |       | 2,956      |       |
| Other                                                   |       |                 |       |                                         |       | 8,173      |       | 11,626     |       |
| Total noncurrent regulatory liabilities                 |       |                 |       |                                         |       | $          | 639,228    |       | $          | 658,571 |   |

 

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

 

(b)            Includesthe fair value of certain long-term purchased power agreements used to meetenergy capacity requirements.

 

(c)             Includesamounts recorded for future recovery of AROs, less amounts recovered throughnuclear decommissioning accruals and gains from decommissioning investments.

 

**15.Segments and Related Information**

 

NSP-Minnesota has two reportable segments, regulated electric utilityand regulated natural gas utility.

 

·                  NSP-Minnesota’s regulated electricutility generates, transmits and distributes electricity in Minnesota, NorthDakota and South Dakota. In addition, this segment includes sales for resaleand provides wholesale transmission service to various entities in the UnitedStates.  Regulated electric utility also includesNSP-Minnesota’s commodity trading operations.

 

·                  NSP-Minnesota’s regulated natural gasutility transports, stores and distributes natural gas in portions of Minnesotaand North Dakota.

 

Revenues fromoperating segments not included above are below the necessary quantitative thresholdsand are therefore included in the all other category. Those primarily includeappliance repair services, nonutility real estate activities and revenuesassociated with processing solid waste into refuse-derived fuel.

 

71

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Operatingresults from the regulated electric utility and regulated natural gas utilityserve as the primary basis for the chief operating decision maker (CODM) toevaluate the dual performance of NSP-Minnesota.

 

To report net income for regulated electric and regulated natural gasutility segments, NSP-Minnesota must assign or allocate all costs and certainother income. In general, costs are:

 

·              directly assigned wherever applicable;

·              allocated based on cost causationallocators wherever applicable; or

·              allocated based on a general allocatorfor all other costs not assigned by the above two methods.

 

The accountingpolicies of the segments are the same as those described in Note 1 to theconsolidated financial statements.  Thesesegments are managed separately because the revenue streams are dependent uponregulated rate recovery, which are separately determined for each segment.

 
| **(Thousands of Dollars)**       | ** ** | **Regulated  Electric Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|--------------------------------------------|------------|--------------------------------------|------------|------------------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| **2007**                                   | ** ** | ** **                           | ** ** | ** **                               | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| Operating revenues from external customers |       | $                                    | 3,476,674  |                                     | $          | 776,971        |       | $                             | 18,569     |                    | $          | — |   | $ | 4,272,214 |   |
| Intersegment revenues                      |       | 655                                  |       | 16,261                                   |       | —         |       | (16,916                       | )          | —                  |       |
| Total revenues                             |       | $                                    | 3,477,329  |                                     | $          | 793,232        |       | $                             | 18,569     |                    | $          | (16,916 | ) | $ | 4,272,214 |   |
| Depreciation and amortization              |       | $                                    | 372,270    |                                     | $          | 32,896         |       | $                             | 403        |                    | $          | — |   | $ | 405,569 |   |
| Financing costs, mainly interest expense   |       | 151,012                              |       | 17,256                                   |       | 707            |       | (16                           | )          | 168,959                 |       |
| Income tax expense                         |       | 165,531                              |       | 11,315                                   |       | 5,179          |       | —                        |       | 182,025                 |       |
| Net income (loss)                          |       | $                                    | 246,086    |                                     | $          | 21,485         |       | $                             | (269       | )                       | $          | — |   | $ | 267,302 |   |
| ** **                                 | ** ** | ** **                           | ** ** | ** **                               | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| **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                 |       |
| 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                 |       |
| Net income                                 |       | $                                    | 199,964    |                                     | $          | 23,782         |       | $                             | 13,998     |                    | $          | — |   | $ | 237,744 |   |

 

72

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**16.  Related Party Transactions**

 

Xcel Energy Services Inc. provides management, administrative and otherservices for the subsidiaries of Xcel Energy, including NSP-Minnesota.  The services are provided and billed to eachsubsidiary in accordance with Service Agreements executed by eachsubsidiary.  Costs are charged directlyto the subsidiary which uses the service whenever possible and are allocated ifthey cannot be directly assigned.

 

Xcel Energy has established a utility money pool arrangement with theutility subsidiaries.  See Note 3 forfurther discussion of this borrowing arrangement.

 

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

 

***Nuclear PlantOperation*** — On Sept. 28, 2007, NSP-Minnesotaobtained 100 percent ownership in NMC as a result of WEC exiting thepartnership due to the sale of its Point Beach Nuclear Plant to FPLEnergy.  Accordingly, the results ofoperations of NMC and the estimated fair value of assets and liabilities wereconsolidated in NSP-Minnesota’s consolidated financial statements from theSept. 28, 2007 transaction date.  WEC wasrequired to pay an exit fee and surrender all of its equity interest in NMC uponexiting.  NSP-Minnesota is in the processof reintegrating its nuclear operations into its generation operations andapply to the NRC to transfer the nuclear operating licenses from NMC toNSP-Minnesota.  The transfer of licensesis expected to be completed in early 2008.

 

In accordance with the Nuclear Power Plant Operating ServicesAgreement, NSP-Minnesota also pays its proportionate share of the operatingexpenses and capital improvement costs incurred by NMC.  NSP-Minnesota paid the NMC $235.2 million in2007, $292.5 million in 2006 and $257.1 million in 2005.

 

The electric production and transmission costs of the entire NSP systemare shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generationand transmission facilities of the system, including capital costs.

 

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

 
| **(Thousands of Dollars)**                       | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Operating revenues:                                        |       |     |       |     |       |     |       |
| Electric utility                                           |       | $        | 372,215    |     | $          | 322,733  |       | $ | 305,202 |   |
| Natural gas utility                                        |       | 366      |       | 350      |       | 386      |       |
| Operating expenses:                                        |       |     |       |     |       |     |       |
| Purchased power                                            |       | 79,345   |       | 61,342   |       | 60,801   |       |
| Transmission expense                                       |       | 40,872   |       | 38,061   |       | 37,803   |       |
| Other operations — paid to Xcel Energy  Services Inc. |       | 267,281  |       | 284,108  |       | 284,906  |       |
| Interest expense                                           |       | 1,742    |       | 1,083    |       | 494      |       |
| Interest income                                            |       | 1,422    |       | 4,497    |       | 1,326    |       |
|                                                            |            |          |            |          |            |          |            |  |  |  |

 

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

 
| ** **                           | ** ** | **2007**                 | ** ** | **2006**              | ** ** |
|--------------------------------------|------------|--------------------------|------------|-----------------------|------------|
| **(Thousands of Dollars)** | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** |
| ** **                           | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** |
| NSP-Wisconsin                        |       | $                        | 20,918     |                  | $          | — |   | $ | 9,905 |   | $ | — |   |
| PSCo                                 |       | —                   |       | 17,440                |       | — |   | 6,598 |   |
| SPS                                  |       | —                   |       | 8,332                 |       | — |   | 4,015 |   |
| Other subsidiaries of Xcel Energy    |       | 10,160                   |       | 28,203                |       | 23,031 |   | 28,526 |   |
|                                 |       | $                        | 31,078     |                  | $          | 53,975 |   | $ | 32,936 |   | $ | 39,139 |   |

 

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota atNSP-Minnesota’s average daily interest rate, including the cost ofNSP-Minnesota’s compensating balance requirements.  At Dec. 31, 2007 and 2006, NSP-Minnesotahad notes receivable outstanding from NSP-Wisconsin in the amount of $58.6million and $30.3 million, respectively.

 

73

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**17. Summarized Quarterly Financial Data (Unaudited)**

 
| ** **                           | ** ** | **Quarter Ended**       | ** ** |
|--------------------------------------|------------|------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **March 31, 2007** | ** ** | **June 30, 2007** | ** ** | **Sept. 30, 2007** | ** ** | **Dec. 31, 2007** | ** ** |
| Revenue                              |       | $                            | 1,145,635  |   | $ | 976,725 |   | $ | 1,089,170 |   | $ | 1,060,684 |   |
| Operating income                     |       | 97,858                       |       | 122,804 |   | 244,430 |   | 125,263 |   |
| Net income                           |       | 42,503                       |       | 56,374 |   | 121,456 |   | 46,969 |   |
|                                      |            |                              |            |  |  |  |  |  |  |  |  |  |  |

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

 

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

 

During 2006 and 2007, and through the date of this report, there wereno disagreements with the independent public accountants for NSP-Minnesota onaccounting principles or practices, financial statement disclosures or auditingscope or procedures.

 

**Item 9A(T) — Controls and Procedures**

 

**DisclosureControls and Procedures**

 

NSP-Minnesota maintains a set of disclosure controls and proceduresdesigned to ensure that information required to be disclosed in reports that itfiles or submits under the Securities Exchange Act of 1934 is recorded,processed, summarized and reported within the time periods specified inSecurities and Exchange Commission rules and forms. In addition, thedisclosure controls and procedures ensure that information required to bedisclosed is accumulated and communicated to management, including the chiefexecutive officer (CEO) and chief financial officer (CFO), allowing timelydecisions regarding required disclosure. As of Dec. 31, 2007, based on an evaluation carried out under thesupervision and with the participation of NSP-Minnesota’s management, includingthe CEO and CFO, of the effectiveness of its disclosure controls and theprocedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosurecontrols and procedures are effective.

 

**InternalControl Over Financial Reporting**

 

No change in NSP-Minnesota’s internal control over financial reportinghas occurred during the most recent fiscal quarter that has materiallyaffected, or is reasonably likely to materially affect, NSP-Minnesota’sinternal control over financial reporting. NSP-Minnesota maintains internal control over financial reporting toprovide reasonable assurance regarding the reliability of the financialreporting.  NSP-Minnesota has evaluatedand documented its controls in process activities, in general computer activities,and on an entity-wide level.  During theyear and in preparation for issuing its report for the year ended Dec. 31,2007 on internal controls under section 404 of the Sarbanes-Oxley Act of2002, NSP-Minnesota conducted testing and monitoring of its internal controlover financial reporting.  Based on thecontrol evaluation, testing and remediation performed, NSP-Minnesota did notidentify any material control weaknesses, as defined under the standards and rules issuedby the Public Company Accounting Oversight Board (PCAOB) and as approved by theSEC and as indicated in Management Report on Internal Controls herein.

 

This annual report does not include an attestationreport of NSP-Minnesota’s registered public accounting firm regarding internalcontrol over financial reporting. Management’s report was not subject to attestation by NSP-Minnesota’sregistered public accounting firm pursuant to temporary rules of theSecurities and Exchange Commission that permit NSP-Minnesota to provide onlymanagement’s report in this annual report.

 

**Item 9B**— **Other Information**

 

None.

 

74

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**PART III**

 

Items 10, 11,12 and 13 of Part III of Form 10-K have been omitted from this reportfor NSP-Minnesota in accordance with conditions set forth in generalinstructions I (1) (a) and (b) of Form 10-K forwholly-owned subsidiaries.

 

**Item 10 — Directors, Executive Officers andCorporate Governance**

 

**Item 11 — Executive Compensation**

 

**Item 12 — Security Ownership of CertainBeneficial Owners and Management and Related Stockholder Matters**

 

**Item 13 — Certain Relationships, RelatedTransactions and Director Independence**

 

**Item 14 — Principal Accounting Fees andServices**

 

Informationconcerning fees paid to the principal accountant for each of the last two yearsis contained in the Xcel Energy Proxy Statement for its 2008 Annual Meeting ofShareholders, which is incorporated by reference.

 

**PART IV**

 

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

** **

1.               Consolidated Financial Statements:

Management Report on Internal Controls **—**For the year ended Dec. 31, 2007.

Report of Independent Registered PublicAccounting Firm **—**For the yearsended Dec. 31, 2007, 2006 and 2005.

Consolidated Statements of Income **—**For the threeyears ended Dec. 31, 2007, 2006 and 2005.

Consolidated Statements of Cash Flows **—** For the three years ended Dec. 31,2007, 2006 and 2005.

Consolidated Balance Sheets **—**As of Dec. 31, 2007 and 2006.

 

2.               Schedule II **—**Valuation and Qualifying Accounts andReserves for the years ended Dec. 31, 2007, 2006 and 2005.

 

3.               Exhibits

 

----

*Indicates incorporation by reference

+Executive Compensation Arrangements andBenefit Plans Covering Executive Officers and Directors

 
| 2.01* |   | Agreement and Plan of Merger, dated as of March 24,  1999, by and between Northern States Power Co. (a Minnesota corporation) and  New Century Energies, Inc. (Exhibit 2.1 to New Century  Energies, Inc. Form 8-K (file no. 001-12907) dated March 24,  1999).                                                                                                     |
|-------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.01* |   | Articles of Incorporation and Amendments of Northern  Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on  Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no.  000-31709) dated Oct. 5, 2000).                                                                                                                                                      |
| 3.02* |   | By-Laws of Northern States Power Co. (a Minnesota  corporation) (Exhibit 3.02 to Form 10-12G (file no. 000-31709)  dated Oct. 5, 2000).                                                                                                                                                                                                                                            |
| 4.01* |   | Supplemental and Restated Trust Indenture, dated  May 1, 1988, from Northern States Power Co. (a Minnesota corporation) to  Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to  Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034).  Supplemental Indentures between NSP-Minnesota and said Trustee, supplemental  to Exhibit 4.14, dated as follows: |
| 4.02* |   | July 1, 1989 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated July 7, 1989).                                                                                                                                                                                                                                                                                             |
| 4.03* |   | June 1, 1990 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated June 1, 1990).                                                                                                                                                                                                                                                                                             |
| 4.04* |   | Oct. 1, 1992 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated Oct. 13, 1992).                                                                                                                                                                                                                                                                                            |
| 4.05* |   | April 1, 1993 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated March 30, 1993).                                                                                                                                                                                                                                                                                          |
| 4.06* |   | Dec. 1, 1993 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated Dec. 7, 1993).                                                                                                                                                                                                                                                                                             |
| 4.07* |   | Feb. 1, 1994 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated Feb. 10, 1994).                                                                                                                                                                                                                                                                                            |
| 4.08* |   | Oct. 1, 1994 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated Oct. 5, 1994).                                                                                                                                                                                                                                                                                             |
| 4.09* |   | June 1, 1995 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated June 28, 1995).                                                                                                                                                                                                                                                                                            |
| 4.10* |   | April 1, 1997 (Exhibit 4.47 to  Form 10-K (file no. 001-03034) for the year 1997).                                                                                                                                                                                                                                                                                                 |

 

75

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| 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*   |   | 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).                   |
| 4.31*   |   | 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).                      |
| 4.32*   |   | $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).                                                                                                                                                                         |
| 4.33*   |   | Supplemental Indenture,  dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company,  as successor Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file  no. 001-31387) dated June 19, 2007).                                                                                                                                |
| 10.01*+ |   | Xcel Energy Omnibus Incentive Plan (Exhibit A  to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).                                                                                                                                                                                                                                        |
| 10.02*+ |   | Employment Agreement dated March 24, 1999,  among Northern States Power Co. (a Minnesota corporation), New Century  Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New  Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated  March 31, 1999).                                                               |
| 10.03*+ |   | 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).                                                                                                                                                                     |
| 10.04*+ |   | New Century Energies Omnibus Incentive Plan,  (Exhibit A to New Century Energies, Inc. Form DEF 14A (file  no. 001-12927) filed March 26, 1998.                                                                                                                                                                                             |

 

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| 10.05*+ |   | Supplemental Executive Retirement Plan  (Exhibit 10(e) (1) to New Century Energies, Inc.  Form 10-K (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                                                                          |
|---------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.06*+ |   | 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).                                                                                                                                 |
| 10.07*+ |   | 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).                                                                                                                                                                                   |
| 10.08*+ |   | 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).                                                                                                                                                             |
| 10.09*+ |   | 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).                                                                                                                                                       |
| 10.10*+ |   | 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).                                                                                                                                                                           |
| 10.11*+ |   | 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).                                                                                                                                                                              |
| 10.12*  |   | 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).                                                                                                                                                                          |
| 10.13*  |   | 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).                                                                                                                                                            |
| 10.14*  |   | 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).                                                                                                                                                                    |
| 10.15*  |   | 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).                                                                                                                                                    |
| 10.16*+ |   | 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).                                                                                                                        |
| 10.17*+ |   | 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).                                                                                                                                                         |
| 10.18*+ |   | 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).                                                                                                                                                                   |
| 10.19*+ |   | 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).                                                                                                                                                                       |
| 10.20*+ |   | 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).                                                                                                                                                                   |
| 10.21*  |   | Xcel Energy Omnibus 2005 Incentive Plan  (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated May 25,  2005).                                                                                                                                                                                                                         |
| 10.22*  |   | Xcel Energy Executive Annual Incentive Award Plan  (Exhibit 10.02 to Form 8-K (file no. 001-03034) dated May 25,  2005).                                                                                                                                                                                                               |
| 10.23*  |   | 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).                                                                                                                                                                       |
| 10.24*  |   | Xcel Energy Supplemental Executive Retirement Plan  (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated Dec. 13,  2005).                                                                                                                                                                                                             |
| 10.25*+ |   | First Amendment to the Xcel  Energy Senior Executive Severance and Change-In-Control Policy dated  Oct. 25, 2006.                                                                                                                                                                                                                                |
| 10.26*+ |   | Agreement, dated  March 20, 2007 between Mr. Gary R. Johnson and Xcel Energy Inc.  (Exhibit 10.1 to Form 8-K (file no. 001-03034) dated March 20,  2007).                                                                                                                                                                    |
| 10.27*  |   | Letter dated Sept. 19,  2007, from Xcel Energy Inc. to the U.S. Department of Justice (DOJ)  submitting its offer to settle the COLI tax dispute and Letter dated Sept.  21, 2007 from the DOJ to Xcel Energy Inc. accepting the settlement offer.  (Exhibit 10.1 to Form 10-Q (file no. 001-03034) for the quarter  ended Sept. 30, 2007). |
| 10.28*+ |   | Second Amendment to the  Xcel Energy Senior Executive Severance and Change-in-Control Policy.  (Exhibit 10.01 to Xcel Energy’s Form 8-K (file no. 001-03034) dated  May 23, 2007).                                                                                                                                                |
| 10.29*+ |   | Amendment Four to  Employment Agreement between Xcel Energy Inc. and Paul Bonavia  (Exhibit 10.02 to Xcel Energy’s Form 8-K (file no. 001-03034) dated  May 23, 2007).                                                                                                                                                            |
| 10.30*  |   | 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).                                                                                         |
| 10.31*  |   | 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).                                                                                                  |

 

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| 10.32* |   | 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).                                                                                                                           |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.33* |   | 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). |
| 10.34* |   | 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).                              |
| 10.35* |   | 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).                                                                                                                                                                    |
| 10.36* |   | 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).                                                                              |
|   |   |
| 10.37* |   | 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).                                                                                                                                              |
| 10.38* |   | 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).                                                                                                             |
| 10.39* |   | 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).                                                                                             |
| 10.40* |   | 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-MINNESOTA AND SUBSIDIARIES****VALUATION AND QUALIFYING ACCOUNTSYears Ended Dec. 31, 2007, 2006 and 2005(Thousands of Dollars)**

 
| ** **                            | ** ** | ** **                                     | ** ** | **Additions**                                 | ** ** | ** **                                    | ** ** | ** **                        | ** ** |
|---------------------------------------|------------|------------------------------------------------|------------|-----------------------------------------------|------------|-----------------------------------------------|------------|-----------------------------------|------------|
| ** **                            | ** ** | **Balance at  beginning  of period** | ** ** | **Charged  to costs and  expenses** | ** ** | **Charged  to other  accounts (1)** | ** ** | **Deductions  from  reserves(2)** | ** ** | **Balance  at end  of period** | ** ** |
| Reserve deducted from related assets: |       |                                           |       |                                          |       |                                          |       |                              |       |   |   |
| Allowance for bad debts:              |       |                                           |       |                                          |       |                                          |       |                              |       |   |   |
| 2007                                  |       | $                                              | 13,408     |                                          | $          | 23,336                                        |       | $                                 | 5,853      |   | $ | 22,494 |   | $ | 20,103 |   |
| 2006                                  |       | 10,128                                         |       | 19,972                                        |       | 6,102                                         |       | 22,794                            |       | 13,408 |   |
| 2005                                  |       | 7,845                                          |       | 13,997                                        |       | 4,089                                         |       | 15,803                            |       | 10,128 |   |
|                                       |            |                                                |            |                                               |            |                                               |            |                                   |            |  |  |  |  |  |  |  |

 

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(1)             Recoveryof amounts previously written off.

(2)             Principallybad debts written off or transferred.

 

79

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**SIGNATURES**

 

Pursuant to therequirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has duly caused this annual report to be signed on itsbehalf by the undersigned, thereunto duly authorized.

 
|                            | **NORTHERN STATES POWER COMPANY**                                                                  |
|----------------------------|----------------------------------------------------------------------------------------------------|
|                       |                                                                                               |
|                       | /s/ BENJAMIN G.S. FOWKE III                                                                        |
|                       | Benjamin G.S. Fowke III  Vice President and Chief Financial Officer  (Principal Financial Officer) |
|                       |                                                                                               |
| **February 25, 2008** | ** **                                                                                         |

 

Pursuant tothe requirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on the date indicated.

 
| /s/ DAVID M. SPARBY                                                                                                                           |   | /s/ RICHARD C. KELLY                                                                                         |
|-----------------------------------------------------------------------------------------------------------------------------------------------|--------|--------------------------------------------------------------------------------------------------------------|
| David M. Sparby  Executive Vice President, Acting President,    Chief Executive Officer and Director  (Principal Executive Officer) |   | Richard C. Kelly  Chairman and Director                                                                      |
|                                                                                                                                          |   |                                                                                                         |
| /s/ TERESA S. MADDEN                                                                                                                          |   | /s/ BENJAMIN G.S. FOWKE  III                                                                                 |
| Teresa S. Madden  Vice President and Controller  (Principal Accounting Officer)                                                               |   | Benjamin G.S. Fowke III  Vice President, Chief Financial Officer and Director  (Principal Financial Officer) |
|                                                                                                                                          |   |                                                                                                         |
| /s/ PAUL J. BONAVIA                                                                                                                           |   |                                                                                                         |
| Paul J. Bonavia  Vice President and Director                                                                                                  |   |                                                                                                         |

 

 

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

 

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

 

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