Table of Contents

 

 

 

**U****NITED STATES**

**SECURITIESAND 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 December 31,2009**

 

**Or**

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

 

**Commission file number 001-31387**

 

# **NORTHERNSTATES POWER COMPANY**

(Exact name of registrant as specified in itscharter)

 

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

 

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

(Address of principal executive offices)

 

Registrant’s Telephone number, including areacode:  **612-330-5500**

 

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

 

Securities registered pursuant to section 12(g) ofthe Act:  **Common Stock**

 

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

 

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) ofthe Act.  o Yes  x No

 

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

 

Indicateby check mark whether the registrant has submitted electronically and posted onits corporate Web site, if any, every Interactive Data File required to besubmitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 ofthis chapter) during the preceding 12 months (or for such shorter period thatthe registrant was required to submit and post such files).  o Yes  o No

 

Indicate by check mark if disclosure of delinquent filerspursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is notcontained herein, and will not be contained, to the best of the registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

 

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, a non-accelerated filer, or asmaller reporting company.  See thedefinitions of “large accelerated filer,” “accelerated filer” and “smallerreporting company” in Rule 12b-2 of the Exchange Act.

 

| Large accelerated filer o                |   | Accelerated filer o         |
|-----------------------------------------------|--------|----------------------------------|
| Non-accelerated filer x                  |   | Smaller Reporting Company o |
| (Do not check if a smaller reporting company) |   |                             |

 

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

 

As of March 1, 2010, 1,000,000 shares of commonstock, par value $0.01 per share, were outstanding, all of which were held byXcel Energy Inc., a Minnesota corporation.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Xcel Energy Inc.’s Definitive Proxy Statement for its2010 Annual Meeting of Shareholders is incorporated by reference into Part IIIof this Form 10-K.

 

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

 

 

 

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Table ofContents

 

**INDEX**

 
| **PART I**                                                                                                                        |   |   |
|----------------------------------------------------------------------------------------------------------------------------------------|--------|--------|
| Item 1 — Business                                                                                                                 |   | 3      |
| DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS                                                                                         |   | 3      |
| COMPANY OVERVIEW                                                                                                                       |   | 7      |
| ELECTRIC  UTILITY OPERATIONS                                                                                                           |   | 7      |
| Overview                                                                                                                               |   | 7      |
| Public  Utility Regulation                                                                                                             |   | 8      |
| Capacity and Demand                                                                                                                    |   | 9      |
| Energy Sources and Related Transmission Initiatives                                                                                    |   | 9      |
| Fuel Supply and Costs                                                                                                                  |   | 13     |
| Fuel Sources                                                                                                                           |   | 13     |
| Wholesale Commodity Marketing Operations                                                                                               |   | 14     |
| Summary of Recent Federal Regulatory Developments                                                                                      |   | 14     |
| Electric Operating Statistics                                                                                                          |   | 16     |
| NATURAL GAS UTILITY  OPERATIONS                                                                                                        |   | 17     |
| Public Utility  Regulation                                                                                                             |   | 17     |
| Capability  and Demand                                                                                                                 |   | 17     |
| Natural Gas Supply and  Costs                                                                                                          |   | 18     |
| Natural Gas  Operating Statistics                                                                                                      |   | 19     |
| ENVIRONMENTAL MATTERS                                                                                                                  |   | 19     |
| EMPLOYEES                                                                                                                              |   | 19     |
| Item 1A — Risk Factors                                                                                                            |   | 20     |
| Item 1B —  Unresolved Staff Comments                                                                                              |   | 27     |
| Item 2 — Properties                                                                                                               |   | 28     |
| Item 3 — Legal Proceedings                                                                                                        |   | 29     |
| Item 4 — Reserved                                                                                                                 |   | 29     |
|                                                                                                                                   |   |   |
| **PART II**                                                                                                                       |   |   |
| Item 5 —  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer  Purchases of Equity Securities |   | 29     |
| Item 6 — Selected  Financial Data                                                                                                 |   | 29     |
| Item 7 — Management’s Discussion and Analysis of  Financial Condition and Results of Operations                              |   | 30     |
| Item 7A — Quantitative and Qualitative Disclosures  About Market Risk                                                             |   | 33     |
| Item 8 — Financial Statements and Supplementary Data                                                                              |   | 36     |
| Item 9 —  Changes in and Disagreements with Accountants on Accounting and Financial  Disclosure                                   |   | 86     |
| Item 9A —  Controls and Procedures                                                                                           |   | 86     |
| Item 9B — Other  Information                                                                                                      |   | 86     |
|                                                                                                                                   |   |   |
| **PART III**                                                                                                                      |   |   |
| Item 10 —  Directors, Executive Officers and Corporate Governance                                                                 |   | 87     |
| Item 11 — Executive  Compensation                                                                                                 |   | 87     |
| Item 12 —  Security Ownership of Certain Beneficial Owners and Management and Related  Stockholder Matters                        |   | 87     |
| Item 13 —  Certain Relationships and Related Transactions, and Director Independence                                              |   | 87     |
| Item 14 —  Principal Accountant Fees and Services                                                                                 |   | 87     |
|                                                                                                                                   |   |   |
| **PART IV**                                                                                                                       |   |   |
| Item 15 —  Exhibits and Financial Statement Schedules                                                                             |   | 87     |
|                                                                                                                                   |   |   |
| **SIGNATURES**                                                                                                                         |   | 92     |

 

ThisForm 10-K is filed by Northern States Power Co., a Minnesota corporation(NSP-Minnesota).  NSP-Minnesota is awholly owned subsidiary of Xcel Energy Inc. Additional information on XcelEnergy is available in various filings with the U. S. Securities and ExchangeCommission (SEC).  This report should beread in its entirety.

 

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**PART I**

 

**Item l — Business**

 

# **DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS**

 
| ***Xcel Energy Subsidiaries and Affiliates***                 |         | * *                                                                                                                                                                                                                                                                                                                                                                                                         |
|---------------------------------------------------------------|--------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| NMC                                                           |         | Nuclear Management  Company, LLC a wholly owned subsidiary of NSP Nuclear Corporation                                                                                                                                                                                                                                                                                                                            |
| NSP-Minnesota                                                 |         | Northern States Power  Company, a Minnesota corporation                                                                                                                                                                                                                                                                                                                                                          |
| NSP-Wisconsin                                                 |         | Northern States Power  Company, a Wisconsin corporation                                                                                                                                                                                                                                                                                                                                                          |
| PSCo                                                          |         | Public Service Company of  Colorado, a Colorado corporation                                                                                                                                                                                                                                                                                                                                                      |
| SPS                                                           |         | Southwestern Public Service  Company, a New Mexico corporation                                                                                                                                                                                                                                                                                                                                                   |
| utility subsidiaries                                          |         | NSP-Minnesota,  NSP-Wisconsin, PSCo, SPS                                                                                                                                                                                                                                                                                                                                                                         |
| Xcel Energy                                                   |         | Xcel Energy Inc., a  Minnesota corporation                                                                                                                                                                                                                                                                                                                                                                       |
| *** ***                                                  | *** *** | *** ***                                                                                                                                                                                                                                                                                                                                                                                                     |
| ***Federal and State Regulatory Agencies***                   |         |                                                                                                                                                                                                                                                                                                                                                                                                             |
| ASLB                                                          |         | Atomic Safety and  Licensing Board                                                                                                                                                                                                                                                                                                                                                                               |
| DOE                                                           |         | United States Department  of Energy                                                                                                                                                                                                                                                                                                                                                                              |
| EPA                                                           |         | United States  Environmental Protection Agency                                                                                                                                                                                                                                                                                                                                                                   |
| FERC                                                          |         | Federal Energy Regulatory  Commission. The U. S. agency that regulates the rates and services for  transportation of electricity and natural gas; the sale of wholesale electricity,  in interstate commerce, including the sale of electricity at market-based  rates; hydroelectric generation licensing; and accounting requirements for  utility holding companies, service companies, and public utilities. |
| IRS                                                           |         | Internal Revenue Service                                                                                                                                                                                                                                                                                                                                                                                         |
| MPCA                                                          |         | Minnesota Pollution Control  Agency                                                                                                                                                                                                                                                                                                                                                                              |
| 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 Corporation. A self-regulatory organization, subject to  oversight by the U. S. FERC and government authorities in Canada, to develop  and enforce reliability standards.                                                                                                                                                                                                   |
| 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.                                                                                                                                                                                                                                                                                                        |
| OES                                                           |         | Office of Energy Security,  Minnesota Department of Commerce.                                                                                                                                                                                                                                                                                                                                                    |
| 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 electric rate schedules that provides for 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.                         |

 

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| 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 natural gas costs collected  through PGA rates and the actual natural gas costs is collected or refunded  over the subsequent period.       |
|-------------------------------------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| RES                                 |   | Renewable energy standard                                                                                                                                                                                                                                                                                                                                                              |
| SEP                                 |   | State Energy Policy                                                                                                                                                                                                                                                                                                                                                                    |
| TCR                                 |   | Transmission cost recovery  adjustment. Allows NSP-Minnesota to recover the cost of transmission  facilities not included in the determination of NSP-Minnesota’s 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*** |   |                                                                                                                                                                                                                                                                                                                                                                                   |
| ACES                                |   | American Clean Energy and  Security Act                                                                                                                                                                                                                                                                                                                                                |
| AEP                                 |   | American Electric Power                                                                                                                                                                                                                                                                                                                                                                |
| AFUDC                               |   | Allowance for funds used  during construction. Defined in regulatory accounts as 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.                                                                                                                                                                                                                                                                                                              |
| ARC                                 |   | Aggregator of Retail Customers                                                                                                                                                                                                                                                                                                                                                         |
| ARO                                 |   | Asset retirement  obligation. Obligations associated with the retirement of tangible long-lived  assets and the associated asset retirement costs.                                                                                                                                                                                                                                     |
| ASC                                 |   | FASB Accounting Standards  Codification                                                                                                                                                                                                                                                                                                                                                |
| ASM                                 |   | Ancillary Services Market                                                                                                                                                                                                                                                                                                                                                              |
| BACT                                |   | Best Available Control  Technology                                                                                                                                                                                                                                                                                                                                                     |
| BART                                |   | Best Available Retrofit  Technology                                                                                                                                                                                                                                                                                                                                                    |
| CO2                                 |   | Carbon dioxide                                                                                                                                                                                                                                                                                                                                                                         |
| CAA                                 |   | Clean Air Act                                                                                                                                                                                                                                                                                                                                                                          |
| CAIR                                |   | Clean Air Interstate Rule                                                                                                                                                                                                                                                                                                                                                              |
| CAMR                                |   | Clean Air Mercury Rule                                                                                                                                                                                                                                                                                                                                                                 |
| CapX 2020                           |   | An alliance of electric  cooperatives, municipals and investor-owned utilities in the upper Midwest  involved in a joint transmission line planning and construction effort.                                                                                                                                                                                                           |
| Codification                        |   | FASB Accounting Standards  Codification                                                                                                                                                                                                                                                                                                                                                |
| CON                                 |   | Certificate of need                                                                                                                                                                                                                                                                                                                                                                    |
| 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.                                                                                                                                                                                                                                                       |
| FASB                                |   | Financial Accounting Standards  Board                                                                                                                                                                                                                                                                                                                                                  |
| Fitch                               |   | Fitch Ratings                                                                                                                                                                                                                                                                                                                                                                          |
| FTRs                                |   | Financial Transmission  Rights. Used to hedge the costs associated with transmission congestion.                                                                                                                                                                                                                                                                                       |
| GAAP                                |   | Generally accepted  accounting principles                                                                                                                                                                                                                                                                                                                                              |

 

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| 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 MW  (capacity) or MW hours (energy).                                                      |
|---------------------------------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| GHG                             |   | Greenhouse gas                                                                                                                                                                                                                                               |
| JOA                             |   | Joint operating agreement  among the utility subsidiaries                                                                                                                                                                                                    |
| LIBOR                           |   | London Interbank Offered  Rate                                                                                                                                                                                                                               |
| LLW                             |   | Low-level radioactive  waste                                                                                                                                                                                                                                 |
| LNG                             |   | Liquefied natural gas.  Natural gas that has been converted to a liquid.                                                                                                                                                                                     |
| MACT                            |   | Maximum Achievable Control  Technology                                                                                                                                                                                                                       |
| mark-to-market                  |   | The process whereby an  asset or liability is recognized at fair value.                                                                                                                                                                                      |
| MERP                            |   | Metropolitan Emissions  Reduction Project.                                                                                                                                                                                                                   |
| MISO                            |   | Midwest Independent  Transmission System Operator, Inc.                                                                                                                                                                                                 |
| Moody’s                    |   | Moody’s Investor Services                                                                                                                                                                                                                               |
| native load                     |   | The customer demand of  retail and wholesale customers that 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 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.                                                                                                 |
| O&M                         |   | Operating and maintenance                                                                                                                                                                                                                                    |
| OCI                             |   | Other comprehensive income                                                                                                                                                                                                                                   |
| 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.                                                                                    |
| PIIC                            |   | Prairie Island Indian  Community                                                                                                                                                                                                                             |
| PJM                             |   | Pennsylvania-New  Jersey-Maryland Interconnection                                                                                                                                                                                                            |
| rate base                       |   | The investor-owned plant  facilities for generation, transmission, and distribution and other assets  used in supplying utility service to the consumer.                                                                                                     |
| REC                             |   | Renewable energy credit                                                                                                                                                                                                                                      |
| RECB                            |   | Regional Expansion  Criteria Benefits                                                                                                                                                                                                                        |
| RFP                             |   | Request for Proposal                                                                                                                                                                                                                                         |
| ROE                             |   | Return on equity                                                                                                                                                                                                                                             |
| RPS                             |   | Renewable Portfolio Standard,  regulation that requires the increased production of energy from renewable  energy sources, such as wind, solar, biomass, and geothermal.                                                                                     |
| 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. |
| SO2                             |   | Sulfur dioxide                                                                                                                                                                                                                                               |
| Standard & Poor’s |   | Standard & Poor’s  Ratings Services                                                                                                                                                                                                            |
| 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.              |
| 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.                                                                                       |

 

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| ***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 (one KV equals  on the thousand volts)                                                                                                                                                                                       |
| KW                 |         | Kilowatts (one KW equals  one thousand watts)                                                                                                                                                                                          |
| Kwh                |         | Kilowatt hours                                                                                                                                                                                                                         |
| MMBtu              |         | One million Btus                                                                                                                                                                                                                       |
| MW                 |         | Megawatts (one MW equals  one thousand KW)                                                                                                                                                                                             |
| Volt               |         | The unit of measurement of  electromotive force. Equivalent to the force required to produce a current of  one ampere through a resistance of one ohm. The unit of measure for  electrical potential. Generally measured in kilovolts. |
| Watt               |         | A measure of power  production or usage.                                                                                                                                                                                               |

 

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# **COMPANY OVERVIEW**

#  

NSP-Minnesotawas incorporated in 2000 under the laws of Minnesota.  NSP-Minnesota is an operating utility engagedin the generation, purchase, transmission, distribution and sale of electricityin Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately10 percent of its total sales in 2009. 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 89 percent of NSP-Minnesota’sretail electric operating revenues were derived from operations in Minnesotaduring 2009.  Generally, NSP-Minnesota’searnings range from approximately 40 percent to 50 percent of Xcel Energy’sconsolidated net income.

 

Theelectric production and transmission system of NSP-Minnesota is managed as anintegrated system with that of NSP-Wisconsin, jointly referred to as the NSPSystem.  The electric production andtransmission costs of the entire NSP System are shared by NSP-Minnesota andNSP-Wisconsin.  A FERC-approvedInterchange Agreement between the two companies provides for the sharing of allgeneration and transmission costs of the NSP System.

 

NSP-Minnesotaowns the following direct subsidiaries: United Power and Land Co., which holdsreal estate; and NSP Nuclear Corp., which owns NMC.

 

NSP-Minnesotaconducts its utility business in the following reportable segments: regulatedelectric utility, regulated natural gas utility and all other.  Comparative segment revenues and relatedfinancial information for fiscal 2009, 2008 and 2007 are set forth in Note 17to the accompanying consolidated financial statements.

 

NSP-Minnesotafocuses on growing through investments in electric and natural gas rate base tomeet growing customer demands, environmental and renewable energy initiativesand to maintain or increase reliability and quality of service tocustomers.  NSP-Minnesota files periodicrate cases, establishes formula rate or automatic rate adjustment mechanismswith state and federal regulators to earn a return on its investments andrecover costs of operations.

 

# **ELECTRIC UTILITY OPERATIONS**

#  

**Overview**

 

***Climate Change andClean Energy *****—** Like most other utilities, NSP-Minnesota is subject toa significant array of environmental regulations.  Further, there are significant futureenvironmental regulations under consideration to encourage the use of cleanenergy technologies and regulate emissions of GHGs to address climatechange.  NSP-Minnesota is subject tostate RPS requirements which we believe they will be in a position to achieveby the applicable state deadlines. Although the exact form and design of anyfederal RPS policy is uncertain at this time, we believe that we will bewell-positioned to meet a federal standard as well, although the ultimatedesign of any federal policy could have a varied impact on NSP-Minnesotadepending upon the energy efficiency and other standards imposed.  In addition, NSP-Minnesota’s electricgenerating facilities have been and are likely to be further subject to climatechange legislation introduced at either the state or federal level within thenext few years.  In 2009, the EPA took anumber of steps toward the regulation of GHGs under the CAA.  By spring 2010, the EPA expects to promulgateregulations to control GHGs from mobile sources.   Thereafter, the EPA anticipates phasing-inpermit requirements and regulation of GHGs for large stationary sources, suchas power plants, in calendar year 2011.

 

While NSP-Minnesota is not currently subject to state orfederal limits on its GHG emissions, NSP-Minnesota has undertaken a number ofinitiatives to prepare for climate change regulation and reduce our GHGemissions.  These initiatives includeemission reduction programs, energy efficiency and conservation programs,renewable energy development and technology exploration projects.  Although the impact of climate change policyon NSP-Minnesota will depend on the specifics of state and federal policies,legislation and regulation, NSP-Minnesota believes that, based on prior statecommission practice, NSP-Minnesota would be granted the authority to recoverthe cost of these initiatives through rates.

 

***Utility Restructuring and RetailCompetition***— The FERC has continued with its efforts to promotemore competitive wholesale markets through open-access transmission and othermeans.  As a consequence, NSP-Minnesotacan purchase from competing wholesale suppliers and use the transmissionsystems of the utility subsidiaries on a comparable basis to the utilitysubsidiaries’ to serve their native load. In 2008, the FERC approved a MISO proposal to begin operation of aregional ASM in January 2009.

 

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TheFERC has approved the open access transmission planning processes for the MISO,the RTO serving the NSP System. NSP-Minnesota received MPUC approval in 2008 to construct three new 115KV transmission lines in 2009 to deliver additional wind generation even ifNSP-Minnesota does not purchase the generation. Several additional transmission expansion projects are pending finalMPUC action, including the CapX 2020 expansion.

 

Theretail electric business faces competition as industrial and large commercialcustomers have some ability to own or operate facilities to generate their ownelectricity.  In 2009, FERC adopted rules requiringMISO to allow ARCs to offer demand response aggregation services to end-usecustomers in the states served by NSP-Minnesota unless the applicable stateregulatory authority prohibits ARCs from serving retail customers in itsstate.  See further discussion in Public UtilityRegulation below.  In addition, customersmay have the option of substituting other fuels, such as natural gas orsteam/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.

 

**PublicUtility Regulation**

** **

***Summary of Regulatory Agencies andAreas of Jurisdiction *****—** Retail rates,services and other aspects of NSP-Minnesota’s operations are regulated by theMPUC, the NDPSC and the SDPUC within their respective states.  The MPUC has regulatory authority overaspects of NSP-Minnesota’s financial activities, including security issuances,property transfers, mergers and transactions between NSP-Minnesota and itsaffiliates.  In addition, the MPUCreviews and approves NSP-Minnesota’s electric resource plans for meetingcustomers’ future energy needs.  The MPUCalso certifies the need for generating plants greater than 50 MW andtransmission lines greater than 100 KV.

 

Nolarge power plant or transmission line may be constructed in Minnesota excepton a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over generating andtransmission facilities, and the siting and routing of new generation andtransmission facilities in North Dakota and South Dakota, respectively.

 

NSP-Minnesotais subject to the jurisdiction of the FERC with respect to its wholesaleelectric operations, hydroelectric licensing, accounting practices, wholesalesales for resale, transmission of electricity in interstate commerce andcertain natural gas transactions in interstate commerce.  NSP-Minnesota has received authorization fromthe FERC to make wholesale electric sales at market-based prices (see MarketBased Rate Rules discussion) and is a transmission-owner member of theMISO RTO.

 

***Fuel, Purchased Energy and ConservationCost-Recovery Mechanisms *****—**NSP-Minnesota has several retailadjustment clauses that recover fuel, purchased energy and other resourcecosts:

 

·                     *CIP* — The CIP invests in programs that helpcustomers save energy. CIP includes a comprehensive list of programs thatbenefit all customers including Saver’s Switch®, energy efficiency rebates andenergy audits.

·                     *EIR* — TheEIR recovers the costs of environmental improvements to the A. S. King, HighBridge and Riverside plants, which were renovated under the MERP program.

·                     *GAP* — TheGAP is a surcharge billed to all non-interruptible customers to recover thecosts of offering a low-income customer co-pay program designed to reducenatural gas service disconnections.

·                     *MCR* — The MCR recovers costs related toreducing Mercury emissions at two NSP-Minnesota fossil fuelpower plants.

·                     *RDF* — The RDF allocates money tosupport development of renewable energy projects research and development ofrenewable energy technologies.

·                     *RES* — In 2007, the Minnesotalegislature passed new requirements mandating that a certain percent of energyproduced by utilities like NSP-Minnesota come from renewable resources.  In order to ensure these mandates can be met,the legislature allows utilities to recover the costs of new renewablegeneration projects to meet the RES in a rider.

·                     *SEP* — The SEP recovers costs related tovarious energy policies approved by the Minnesota legislature.

·                     *TCR* — The TCR recovers costs associatedwith new investments in the electric transmission system necessary to deliverelectric energy to customers.

 

NSP-Minnesota’sretail electric rate schedules in Minnesota, North Dakota and South Dakotainclude a FCA for monthly billing adjustments for changes in prudently incurredcost of fuel, fuel related items and purchased energy.  NSP-Minnesota is permitted to recover thesecosts through FCA mechanisms approved by the regulators in each jurisdiction.

 

TheFCAs allow NSP-Minnesota to bill customers for the cost of fuel and fuelrelated costs used to generate electricity at its plants and energy purchasedfrom other suppliers.  In general,capacity costs are not recovered through the FCA.  In addition, costs associated with MISO aregenerally recovered through either the FCA or through rate cases.

 

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NSP-Minnesotais required by Minnesota law to spend a minimum of 2 percent of Minnesotaelectric revenue on conservation improvement programs.  These costs are recovered through an annualcost-recovery mechanism for electric conservation and energy management programexpenditures.  NSP-Minnesota is requiredto request a new cost-recovery level annually. While this law changed to a savings-based requirement beginning in 2010,the costs of providing qualified conservation improvement programs willcontinue to be recoverable through a rate adjustment mechanism.

 

***MERP Rider Regulation *****—** The MPUC approved a rate rider to recover prudent costs to convert twocoal-fueled electric generating plants to natural gas, and to install advancedpollution control equipment at a third coal-fired plant beginning Jan. 1,2006.  A. S. King, High Bridge andRiverside went into service in July 2007, May 2008 and March 2009,respectively.  In December 2009, theMPUC authorized the recovery of approximately $116.7 million in 2010rates.  The ROE for the A. S. King plant,the High Bridge plant and the Riverside plant, is 10.55 percent, 11.22 percentand 10.55 percent, respectively.  TheMERP projects will be included in rate base in the next general rate case andthe projects removed from the rider.

 

**Capacityand Demand**

** **

Uninterruptedsystem peak demand for the NSP System’s electric utility for each of the lastthree years and the forecast for 2010, assuming normal weather, is listedbelow.

 
| ** **  | ** ** | **System  Peak Demand (in MW)** | ** ** |
|-------------|------------|---------------------------------|------------|
| ** **  | ** ** | **2007**                        | ** ** | **2008** | ** ** | **2009** | ** ** | **2010  Forecast** | ** ** |
| NSP  System |       | 9,427                           |       | 8,697 |   | 8,615 |   | 9,280 |   |

 

Thepeak demand for the NSP System typically occurs in the summer.  The 2009 uninterrupted system peak demand forthe NSP System occurred on June 23, 2009.

 

**Energy Sources and Related Transmission Initiatives**

** **

NSP-Minnesota expects touse existing power plants, power purchases, DSM options, new generationfacilities and expansion of existing power plants to meet its system capacityrequirements.

 

***Purchased Power —***NSP-Minnesotahas contracts 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 ofelectricity produced from a particular generating source over a period oftime.  Long-term purchase power contractstypically require a periodic payment to secure the capacity from a particulargenerating source and a charge for the associated energy actually purchased fromsuch generating source.

 

NSP-Minnesotaalso makes short-term purchases to comply with minimum availabilityrequirements, to obtain energy at a lower cost and for various other operatingrequirements.

 

***Purchased Transmission Services —***Inaddition to using their integrated transmission system, NSP-Minnesota andNSP-Wisconsin have contractual arrangements with MISO and regional transmissionservice providers to deliver power and energy to the NSP System for native loadcustomers, which are retail and wholesale load obligations with terms of more thanone year.

 

***Excelsior Energy*****—**In December 2005, Excelsior, an independent energy developer, filed apower purchase agreement with the MPUC seeking a 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.  TheMPUC referred this matter to a contested case hearing before an ALJ to act onExcelsior’s petition.  The contested caseproceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit inPhase 2 of the Mesaba Energy Project.

 

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Inits August 2007 Phase 1 order, the MPUC, found among other things, thatExcelsior and NSP-Minnesota should resume negotiations toward an acceptablepurchase power agreement, with assistance from the OES and the guidanceprovided by the order.

 

InMay 2009, the MPUC affirmed its previous order to deny Excelsior Energy’sPhase 2 request to approve a power purchase agreement related to its proposedsecond 600 MW IGCC generating facility**, which closed the docket**.  In August 2009, Excelsior appealed theMPUC decision to the Minnesota Court of Appeals.  The Minnesota Court of Appeals heardarguments on Feb. 23, 2010, and a decision is anticipated in 2010.

 

***GHG Emissions *****—**The 2007 Minnesota legislature adopted the goal toreduce statewide GHG emissions across all sectors to a level at least15 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 2005levels by 2050.

 

Thelegislation also prohibits the construction within Minnesota of a new largeenergy facility, the import or commitment to import from outside Minnesotapower from a new large energy facility, or entering into a new long-term powerpurchase agreement that would increase statewide power sector CO2 emissions. The statute does not impose limitations on CO2 or other GHGemissions on NSP-Minnesota and provides for certain exemptions.

 

In November 2008, theMPUC approved NSP-Minnesota’s request to include the costs of a natural gascast iron pipe replacement project in its SEP Rider.  The proposed cost recovery was enabled by the2007 legislation, as the pipe replacement is expected to reduce GHGemissions.  NSP-Minnesota expects torecover approximately $1.4 million over the 2009-2013 period, when the projectis scheduled to be complete.

 

***2009 Minnesota Legislative Session***** —**The 2009 Minnesota legislature considered andadopted several measures related to energy policy and regulation, including:

 

·                  Permitting enhanced recovery for costsassociated with the urban central corridor development;

·                  Encouraging the development of solarresources; and

·                  Continued encouragement of DSM.

 

Thelegislature considered, but did not adopt, increased taxes on utility property.

 

***Minnesota Resource Plan*****—**In July 2009, the MPUC approvedNSP-Minnesota’s 2007 resource plan.  The plan wouldreduce CO2 emissions by 22 percent from 2005 to 2020, a 6 millionton reduction. The plan includes the following components:

 

·                     Energyefficiency savings of 1.15 percent in 2010, 1.2 percent in 2011 and 1.3 percentin 2012;

·                     Installsufficient renewables to meet the Minnesota RES;

·                     Obtain requiredapprovals to extend the life of the Prairie Island nuclear plant and toincrease the output at both Prairie Island and Monticello;

·                     Continueongoing capacity expansion at Sherco Unit 3;

·                     Continue to investigate repoweringBlack Dog Units 3 and 4, and provide the MPUC with specific plans and timelinesfor the repowering;

·                     Obtain approvalfor the 375 MW intermediate and 350 MW diversity exchange with Manitoba Hydrobeginning in 2015; and

·                     Continue toensure sufficient transmission available to deliver generation to load.

 

Additionally,the MPUC required NSP-Minnesota to consider higher levels of DSM and energyefficiency and provide recommendations in NSP-Minnesota’s next resource plan,which is to be filed no later than Aug. 1, 2010.

 

***RES —*** In 2007, the Minnesota legislature changed the state’s renewable energyobjective into a standard that requires NSP-Minnesota to generate or cause tobe generated electricity from renewable resources equaling:

 

·                     At least 15 percent ofits retail sales by 2010;

·                     18 percent of retailsales by 2012;

·                     25 percentof retail sales by 2016; and

·                     30 percent by2020.

 

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Of the 30 percent, at least25 percent must be generated by wind energy conversion systems and theremaining five percent by other eligible energy technology.  The law allows for a modification or delay inthe implementation of the standard if the implementation would causesignificant rate impact, require significant measures to address reliability orraises significant technical issues.  Allother Minnesota utilities are required to meet a 25 percent RES by 2025.  No Minnesota utility has requested amodification or delay of the standard at this time.

 

Minnesota Statutes alsoallow for recovery of eligible renewable energy investments through a costrecovery rider.  NSP-Minnesota beganrecovering eligible investments through this mechanism in 2008.

 

***Wind Generation******—***NSP-Minnesota is investing approximately$900 million over three years for a 201 MW project in southwestern Minnesota,called the Nobles Wind Project, and a 150 MW project in southeastern NorthDakota, called the Merricourt Wind Project. These projects are expected to be operational by the end of 2010 and2011, respectively.  In June 2009,the MPUC approved the Nobles and Merricourt Wind Projects.  In August 2009, the NDPSC grantedadvanced determinations of prudence for the Nobles and Merricourt Wind Projectsand a certificate of public convenience and necessity (CPCN) for the MerricourtWind project.

 

***NSP-Minnesota Transmission CONs —*** In April 2009,the MPUC granted a CON to construct three 345 KV electric transmission lines aspart of the CapX 2020 project.  Theproject to build the three lines includes construction of approximately 600miles of new facilities at a cost of approximately $1.7 billion.  The cost of the project to NSP-Minnesota andNSP-Wisconsin is estimated to be approximately $900 million.  These cost estimates will be revised afterthe regulatory process is completed.  TheMPUC also included a condition assuring a portion of the capacity of theBrookings, S.D. to Hampton, Minn. line is used for renewable energy.  In September 2009, two intervenorsappealed the MPUC’s CON decisions in the Minnesota Court of Appeals.

 

Aspart of the regulatory process for the CapX 2020 345 KV projects, NSP-Minnesotaand Great River Energy have filed four route permit applications with theMPUC.  Route permit applications for the remaining parts of the threelines are expected to be filed in adjoining states in 2010.  Three filedroute permit applications are now in evidentiary hearing processes before ALJs.  The fourth application is expected to be sentto an evidentiary hearing process later in 2010.  NSP-Minnesota anticipates the first routingdecisions in mid 2010.

 

Aspart of CapX 2020, Otter Tail Power Company, Minnesota Power and Minnkota PowerCooperative (on behalf of themselves and NSP-Minnesota and Great River Energy)filed a CON application in March 2008 for a 230 KV transmission linebetween Bemidji and Grand Rapids, Minn. The CON application was approved in July 2009.  Route hearings are scheduled to begin March 30,2010, and an MPUC decision is anticipated by the third quarter of 2010.  The Bemidji-Grand Rapids line is expected toentail construction of approximately 68 miles of new facilities at a cost of$100 million, with construction to be completed by the end of 2011.  The estimated cost to NSP-Minnesota isapproximately $26 million.

 

***ARCs******—*** In 2009, the FERC adopted rules requiring MISO toallow ARCs to offer demand response aggregation services to end-use customersin the states served by NSP-Minnesota, unless the applicable state regulatoryauthority prohibits ARCs from serving retail customers in their state.  ARCs would operate in competition with thestate-regulated retail demand response programs offered by NSP-Minnesota.  The MISO ARC tariff provisions are effectivein June 2010.  The MPUC has openedan investigation regarding possible operation of ARCs in Minnesota.  NSP-Minnesota expects to file requests withthe NDPSC and SDPUC by the end of the first quarter of 2010 asking the regulatoryagencies to prohibit operations of ARCs in their respective states, and to takeaction prior to June 2010.

 

***FCA Investigation *****—** In 2003, the MPUC opened an investigation to consider the continuingusefulness of the FCA for electric utilities in Minnesota.  Continued discussions among utilities, theOES, MOAG and business customers regarding appropriate FCA reporting detail andprovision of additional information to customers is ongoing.

 

***Mercury Reduction and Emissions ReductionFilings *****—** The MPUC has approvedmercury control plans for reducing mercury emissions at the Sherco Unit 3 andA. S. King plants.  A sorbent injectioncontrol system was put into service at Sherco Unit 3 in December 2009,with installation at A. S. King scheduled to be completed in December 2010.  Currently, the estimated project costs areapproximately $6.6 million for these two units, and the MPUC authorizedNSP-Minnesota to collect the 2010 revenue requirement associated with theseprojects, which is approximately $3.5 million, from customers through a mercuryrider in 2010.  On Dec. 21, 2009, NSP-Minnesotafiled the plans for mercury control at Sherco Units 1 and 2 with the MPUC andMPCA.  Assuming these plans are approved,NSP-Minnesota expects to file for recovery of the costs to implement theseplans through the mercury cost rider.

 

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***Nuclear Power Operations and WasteDisposal *****—** NSP-Minnesotaowns two nuclear generating plants: the Monticello plant and the Prairie Islandplant, which has two units.  Seeadditional discussion regarding the nuclear generating plants in Note 15to the consolidated financial statements.

 

Nuclearpower plant operation produces gaseous, liquid and solid radioactivewastes.  The discharge and handling ofsuch wastes are controlled by federal regulation.  High-level radioactive wastes primarilyinclude used nuclear fuel.  LLW consistsprimarily of demineralizer resins, paper, protective clothing, rags, tools andequipment that have become contaminated through use in the plant.

 

*LLW Disposal *— Federal law placesresponsibility on each state for disposal of LLW generated within itsborders.  LLW from NSP-Minnesota’sMonticello and Prairie Island nuclear plants is currently disposed at the Clivefacility located in Utah.  NSP-Minnesotais also able to utilize the Clive facility through various LLW processors.  NSP-Minnesota has storage capacity availableon-site at Prairie Island and Monticello that would allow both plants tocontinue to operate until the end of their current licensed lives, if off-siteLLW disposal facilities were not available.

 

*High-Level Radioactive Waste Disposal *— The federalgovernment has the responsibility to permanently dispose of domestic spentnuclear 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 spent nuclear fuel from civiliannuclear power reactors and other high-level radioactive wastes at a permanentfederal storage or disposal facility.  Todate, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel.  See Item 3 — Legal Proceedings and Note 15 tothe consolidated financial statements for further discussion of this matter.

 

NSP-Minnesotahas on-site storage for spent nuclear fuel at its Monticello and Prairie Islandnuclear generating plants.  At thefollowing dates casks for storage were either authorized or casks were loadedand stored:

 

·                  In 2003, the Minnesotalegislature enacted revised legislation that will allow NSP-Minnesota tocontinue to operate the Prairie Island nuclear plant and to store spent fuelthere until its current licenses with the NRC expire in 2013 and 2014.  It is estimated that operation through theend of the current license will require 29 storage casks at Prairie Island.

·                  In October 2006,effective June 2007, the MPUC authorized an on-site storage facility anddry cask storage of 30 casks at Monticello, which will allow the plant tooperate to 2030.

·                  In December 2009, the MPUC authorized additionalcask storage at Prairie Island to allow operation through 2033 for Unit 1 and2034 for Unit 2.  The MPUC decision iscurrently stayed to allow the Minnesota legislature the opportunity to reviewthe MPUC decision during the 2010 legislative session.  If no action is taken by the Minnesotalegislature during the 2010 legislative session the MPUC order will go intoeffect on June 1, 2010.

·                  Asof Dec. 31, 2009, there were 25 casks loaded and storedat the Prairie Island plant and 10casks loaded and stored at the Monticello plant.

 

*PFS *— NSP-Minnesota is part of aconsortium of private parties working to establish a private facility for interimstorage of spent nuclear fuel.  In December 2005,NSP-Minnesota indicated that it would hold in abeyance future investments inthe construction of PFS as long as there is apparent and continuing progress infederally sponsored initiatives for storage, reuse, and/or disposal for thenation’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.  In July 2007, PFS and the SkullValley Band filed a lawsuit challenging these two Departments of the Interioractions.  The lawsuit remainspending.  A judicial appeal of the NRClicensing decision has been held in abeyance pending the outcome of the lawsuitchallenging the Department of the Interior decisions.  The existence of PFS as a licensedout-of-state storage option remains a credible alternative if PFS and the SkullValley Band can prevail in the pending litigation and if the federal governmentfails to make progress with their obligation to take title and remove spentnuclear fuel from Xcel Energy’s and other nuclear reactor sites.

 

*NuclearPlant Power Uprates and Life Extension***—** NSP-Minnesota is pursuing life extensions andcapacity increases of all three of its nuclear units that will totalapproximately 235 MW, if approved, between 2011 and 2015.  The life extension and a capacity increasefor Prairie Island Unit 2 is contingent on the replacement of the originalsteam generators, currently planned for replacement during the refueling outagein 2013.  Capital investments for lifecycle management and power uprate activities through 2009 have totaled overapproximately $257 million.  For theyears 2010 through 2015, spending is estimated at over $1.0 billion.

 

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In December 2008,the MPUC approved the Monticello CON for approximately 71 MW of poweruprates.  In 2008, NSP-Minnesota re-submitted its NRCapplication for the Monticello plant extended power uprate, and the NRC’s sufficiency review of the license amendment re-submittal was completed.  NSP-Minnesota expects to receive NRC approval andachieve the extended power uprate during 2011. The operating life of the Monticello nuclear plant has already beenextended through 2030.

 

In December 2009,the MPUC approved both the additional dry spent fuel storage capacity tosupport life extension and the approximately 164 MW of power uprates at PrairieIsland Units 1 and 2.  If no action istaken by the Minnesota legislature during the 2010 legislative session, theMPUC decision on dry spent fuel storage capacity to support life extension willgo into effect on June 1, 2010.

 

In April 2008,NSP-Minnesota filed an application with the NRC to renew the operating licenseof its two nuclear reactors at Prairie Island for an additional 20 years, until2033 and 2034, respectively.  The PIICfiled contentions in the NRC’s license renewal proceeding in August 2008,which was referred to an ASLB for review. The ASLB granted the PIIC hearing request and has admitted seven of the11 contentions filed.  To date, all sevenadmitted contentions have been resolved and removed from the ASLB docket.  Subsequent to the NRC issuance of the finalSafety Evaluation Report and the draft supplemental environmental impact statement,the PIIC filed four additional contentions. The ASLB has admitted one of the contentions and has not issued adecision on the other three. NSP-Minnesota is challenging the admitted contention, and a decision onwhether the other contentions will be accepted will be made in early 2010.  If the contentions are not resolved, theresulting adjudicatory process is expected to add approximately eight monthsonto the NRC’s standard 22 month review schedule, resulting in a decision onthe Prairie Island license renewal in late 2010.

 

**Fuel Supply and Costs**

 

Thefollowing table shows the delivered cost per MMBtu of each significant categoryof fuel consumed for electric generation, the percentage of total fuelrequirements represented by each category of fuel and the total weightedaverage cost of all fuels.

 
| ** **                        | ** ** | ** ** | ** ** | ** **  | ** ** | ** **       | ** ** | ** **  | ** ** | ** ** | ** ** | ** **  | ** ** | **Weighted**   | ** ** |
|-----------------------------------|------------|------------|------------|-------------|------------|------------------|------------|-------------|------------|------------|------------|-------------|------------|----------------|------------|
| ** **                        | ** ** | **Coal***  | ** ** | **Nuclear** | ** ** | **Natural  Gas** | ** ** | **Average** | ** ** |
| **NSP  System Generating Plants** | ** ** | **Cost**   | ** ** | **Percent** | ** ** | **Cost**         | ** ** | **Percent** | ** ** | **Cost**   | ** ** | **Percent** | ** ** | **Fuel  Cost** | ** ** |
| 2009                              |       | $          | 1.78       |        | 57         | %                | $          | 0.70        |       | 39         | %          | $           | 7.36       |           | 4          | % | $ | 1.61 |   |
| 2008                              |       | 1.73       |       | 58          |       | 0.56             |       | 39          |       | 10.09      |       | 3           |       | 1.55           |       |
| 2007                              |       | 1.56       |       | 57          |       | 0.51             |       | 38          |       | 7.60       |       | 4           |       | 1.47           |       |
|                                   |            |            |            |             |            |                  |            |             |            |            |            |             |            |                |            |  |  |  |  |

 

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*  Includes refuse-derived fueland wood

 

Seeadditional discussion of fuel supply and costs under Item 1A — Risks Associatedwith Our Business.

 

**Fuel Sources**

 

*Coal*— The NSP System normally maintains approximately40 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2009and 2008, were approximately 43 and 49 days usage, respectively.  NSP-Minnesota’s generation stations uselow-sulfur western coal purchased primarily under long-term contracts withsuppliers operating in Wyoming and Montana. Estimated coal requirements at NSP-Minnesota’s and NSP-Wisconsin’s majorcoal-fired generating plants were approximately 10.2 and 11.0 million tonsper year at Dec. 31, 2009 and 2008, respectively.

 

NSP-Minnesotaand NSP-Wisconsin have contracted for coal supplies to provide 91 percentof their coal requirements in 2010, 60 percent of their coal requirements in2011 and 14 percent of their coal requirements in 2012.  Any remaining requirements will be filledthrough a RFP process or through over-the-counter transactions.

 

NSP-Minnesotaand NSP-Wisconsin have a number of coal transportation contracts that providefor delivery of 100 percent of their coal requirements in 2010, 28 percent oftheir coal requirements in 2011 and 28 percent of their coal requirements2012.  Coal delivery may be subject toshort-term interruptions or reductions due to operation of the mines,transportation problems, weather and availability of equipment.

 

*Nuclear* — NSP-Minnesota securescontracts for uranium concentrates, uranium conversion, uranium enrichment andfuel fabrication for the operation of its nuclear generation plants.  The contract strategy involves a portfolio ofspot purchases and medium and long-term contracts for uranium, conversion andenrichment with multiple producers to minimize potential impacts caused bysupply interruptions due to geographical and world political issues.

 

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·                     Current nuclear fuel supplycontracts cover 100 percent of uranium concentrates requirements through2010, approximately 85 percent of the requirements for 2011 through 2014,and 49 percent of the requirements for 2015 through 2017, with noarrangements for 2018 and beyond. Contracts for additional uranium concentrate supplies are currently invarious stages of negotiations that are expected to provide a portion of theremaining open requirements through 2025.

·                     Current contracts forconversion services cover 100 percent of the requirements through 2011 andapproximately 70 percent of the requirements from 2012 through 2016, withno arrangements for 2017 and beyond. Contracts for additional conversion services are being evaluated andnegotiated to provide a portion of remaining open requirements for 2014 andbeyond.

·                     Current enrichment servicescontracts cover 100 percent of 2010 through 2013 requirements.  Contracts for additional enrichment servicesare being evaluated and negotiated to provide a portion of the remaining openrequirements for 2014 and beyond.

·                     Fabrication services forMonticello are covered through 2011. Responses from the fuel fabrication vendors to our RFPs for additionalsupply for Monticello are being reviewed with plans to enter into a contractwith one of the vendors in 2010. Prairie Island’s fuel fabrication is100 percent committed through 2014.

 

NSP-Minnesotaexpects sufficient uranium, conversion and enrichment to be available for thetotal fuel requirements of its nuclear generating plants.   Some exposure to price volatility willremain, due to index-based pricing structures on the contracts.

 

*Natural gas*— The NSP System uses bothfirm and interruptible natural gas and standby oil in combustion turbines andcertain boilers.  Natural gas suppliesand associated transportation and storage services for power plants areprocured under contracts with various terms to provide an adequate supply of fuel.  The supply, transportation and storagecontracts expire in various years from 2010 to 2028.  Certain natural gas supply and transportationagreements include obligations for the purchase and/or delivery of specifiedvolumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2009, NSP-Minnesota’scommitments related to supply contracts were $53 million and commitmentsrelated to transportation and storage contracts were approximately $538million.  The NSP System has limitedon-site fuel oil storage facilities and relies on the spot market forincremental supplies, if needed.

 

**Wholesale Commodity Marketing Operations**

 

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

 

**Summary of Recent Federal RegulatoryDevelopments**

** **

TheFERC has jurisdiction over rates for electric transmission service ininterstate commerce and electricity sold at wholesale, hydro facilitylicensing, natural gas transportation, accounting practices and certain otheractivities of Xcel Energy’s utility subsidiaries, including enforcement of NERCmandatory electric reliability standards. State and local agencies have jurisdiction over many of Xcel Energy’sutility activities, including regulation of retail rates and environmentalmatters.  In addition to the mattersdiscussed below, see Note 13 to the consolidated financial statementsfor a discussion of other regulatory matters.

 

***FERC Rules Implementing Energy Policy Act of 2005(Energy Act) *****—** The Energy Act required the FERC to adopt newregulations to implement various aspects of the Energy Act.  Violations of FERC rules are potentiallysubject to enforcement action by the FERC including financial penalties up to$1 million per day per violation.

 

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 new FERC rules and regulationsas they become effective.

 

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***Electric Reliability StandardsCompliance***

 

Compliance Audits

 

NSP-Minnesota and NSP-Wisconsin share all NSP Systemgeneration and transmission costs by means of a FERC-approved tariff commonlyreferred to as the Interchange Agreement. In 2008, the NSP System filed self-reports with the Midwest ReliabilityOrganization (MRO) regional entity relating to failure to complete certaingeneration station battery tests, relay maintenance intervals and recordkeeping associated with certain critical infrastructure protectionstandards.  In 2009, the NSP Systemreached agreement with the MRO that would resolve all open audit findings andself reports by payment of a non-material penalty.  Xcel Energy, the parent company ofNSP-Minnesota and NSP-Wisconsin, is in the process of developing a definitivesettlement agreement.  The settlementagreement will be subject to NERC and FERC approval.

 

MRO/NERCCompliance Investigation

 

On Sept. 18, 2007,portions of the NSP System and transmission systems west and north of the NSPSystem briefly islanded from the rest of the Eastern Interconnection, as aresult of a series of transmission line outages.  In addition, service to approximately 790 MWof load was temporarily interrupted, primarily in Saskatchewan, Canada.  The initial transmission line outagesoccurred on the NSP System.  In March 2008,NSP-Minnesota received notice that the MRO was commencing a complianceinvestigation of the September 2007 event. Because the event affected more than one region, the NERC took over theinvestigation.  In January 2010,the NERC issued a preliminary report alleging the NSP System violated certainNERC reliability standards.  The reportrepresents the preliminary conclusions of the NERC and is subject to additionalprocedures at NERC, and ultimately FERC review. Xcel Energy disagrees with many aspects of the preliminary report andfiled its response with NERC on Feb. 19, 2010.  The final outcome of the NERC complianceinvestigation, and whether and to what extent penalties for violations may beassessed, is unknown at this time.

 

***Electric Transmission Rate Regulation***** —**The FERC regulates the rates charged and terms and conditionsfor electric transmission services.  FERCpolicy encourages utilities to turn over the functional control of theirelectric transmission assets for the sale of electric transmission services toan RTO.  NSP-Minnesota and NSP-Wisconsinare members of the MISO RTO.  Each RTOseparately files regional transmission tariff rates for approval by theFERC.  All members within that RTO are thensubjected to those rates.

 

***Centralized Regional Wholesale Markets***** —**The FERC rules allow RTOs to operatecentralized regional wholesale energy markets. In April 2005, MISO began operation of a Day 2 regional day-aheadand real time wholesale energy market. The Day 2 market is designed to provide more efficient generationdispatch over the 15 state MISO region, including the NSP System.  In 2007, SPP began operation of an energyimbalance service (EIS) market, which provides a more limited wholesale energybalancing market for the region that includes the SPS system.

 

InJanuary 2009, MISO began ASM operations, which 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.

 

***Market Based Rate Rules *****—** Each of the Xcel Energy utility subsidiaries has been grantedmarket-based rate authority.  Undermarket based rate rules, the NSP System was reauthorized to sell atmarket-based rates in June 2009.

 

On Dec. 22, 2008, theNSP System submitted their Triennial Market Power Analysis to the FERC tosupport their market-based rate authority. Applying the FERC’s required tests, the Market Power Analysis submitted bythe NSP System demonstrates that they have neither horizontal market power norvertical market power in the relevant geographic market.  Consequently, the NSP System has requestedthat the FERC permit them to retain their market-based rate authority.

 

***MISO Long-Term Transmission Pricing —*** Transmissionservice rates in the MISO region have historically used a rate design in whichthe transmission cost depends on the location of the load being served, whichis referred to as license plate rates. Costs of existing transmission facilities are thus notregionalized.  MISO has implementedseveral changes regarding the allocation of costs for new transmissionfacilities.  In 2006 and 2007, the FERCissued orders accepting the so-called RECB tariff, which provide a20 percent limitation on the portion of transmission expansion costs thatmay be regionalized and recovered from all loads in the 15 state MISO region.

 

In2007, AEP filed a proposal that would regionalize certain costs of the existingAEP system over the MISO and PJM RTO regions. The AEP proposal would shift several million dollars in transmissioncosts annually to the NSP System.  Theimpact of the AEP proposal on transmission cost allocation in MISO isuncertain.

 

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InJuly 2009, MISO filed a proposed change to the RECB tariff with the FERCto address concerns regarding allocation of costs associated with new transmissionrequired to deliver new wind generation. This tariff would regionalize 10 percent of the cost of new 345 KVtransmission facilities associated with new generation interconnections acrosstransmission users in MISO, with the interconnecting generator paying theremaining 90 percent of the costs.  Thegenerator is required to fund 100 percent of the costs for facilities less than345 KV.  The FERC approved the tariff changein October 2009, subject to a permanent replacement cost allocation tariffto be filed with the FERC in July 2010. The uncertainty surrounding allocation of costs associated with windgeneration interconnection could affect the timing or location of suchinterconnections, which could affect near term NSP System transmission investmentneeds.

 

***FERC Audit of Wholesale FCA*****—** In October 2009, the FERC notified NSP-Minnesota andNSP-Wisconsin that the FERC audit division began an audit of compliance withthe FERC’s accounting and reporting regulations related to the calculation of theNSP-Minnesota and NSP-Wisconsin wholesale FCA for the period commencing Jan. 1,2008.  The audit is a periodic financialaudit, and NSP-Minnesota is fully cooperating with the audit.

 

**ElectricOperating Statistics**

 
| ** **                                   | ** ** | **Year  Ended Dec. 31,** | ** ** |
|----------------------------------------------|------------|-------------------------------|------------|
| ** **                                   | ** ** | **2009**                      | ** ** | **2008** | ** ** | **2007** | ** ** |
|                                         |       |                          |       |   |   |   |   |
| **Electric sales (Millions of Kwh)**         | ** ** | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Residential                                  |       | 9,887                         |       | 10,099 |   | 10,534 |   |
| Commercial  and industrial                   |       | 24,603                        |       | 25,847 |   | 25,844 |   |
| Public  authorities and other                |       | 265                           |       | 260 |   | 275 |   |
| **Total retail**                             |       | 34,755                        |       | 36,206 |   | 36,653 |   |
| Sales  for resale                            |       | 3,899                         |       | 3,692 |   | 4,073 |   |
| **Total energy sold**                        |       | 38,654                        |       | 39,898 |   | 40,726 |   |
|                                         |       |                          |       |   |   |   |   |
| **Number of customers at end of period**     |       |                          |       |   |   |   |   |
| Residential                                  |       | 1,231,752                     |       | 1,227,889 |   | 1,218,340 |   |
| Commercial  and industrial                   |       | 149,187                       |       | 148,060 |   | 146,487 |   |
| Public  authorities and other                |       | 6,055                         |       | 6,067 |   | 6,072 |   |
| **Total retail**                             |       | 1,386,994                     |       | 1,382,016 |   | 1,370,899 |   |
| Wholesale                                    |       | 16                            |       | 31 |   | 31 |   |
| **Total customers**                          |       | 1,387,010                     |       | 1,382,047 |   | 1,370,930 |   |
|                                         |       |                          |       |   |   |   |   |
| **Electric revenues (Thousands of Dollars)** |       |                          |       |   |   |   |   |
| Residential                                  |       | $                             | 1,006,380  |   | $ | 1,018,810 |   | $ | 1,015,315 |   |
| Commercial  and industrial                   |       | 1,739,992                     |       | 1,853,451 |   | 1,774,027 |   |
| Public  authorities and other                |       | 31,981                        |       | 31,837 |   | 31,446 |   |
| **Total retail**                             |       | 2,778,353                     |       | 2,904,098 |   | 2,820,788 |   |
| Wholesale                                    |       | 102,786                       |       | 180,618 |   | 198,248 |   |
| Interchange  revenues from NSP-Wisconsin     |       | 389,023                       |       | 390,143 |   | 372,215 |   |
| Other  electric revenues                     |       | 137,111                       |       | 109,250 |   | 85,423 |   |
| **Total electric revenues**                  |       | $                             | 3,407,273  |   | $ | 3,584,109 |   | $ | 3,476,674 |   |
|                                         |       |                          |       |   |   |   |   |
| Kwh  sales per retail customer               |       | 25,058                        |       | 26,198 |   | 26,737 |   |
| Revenue  per retail customer                 |       | $                             | 2,003      |   | $ | 2,101 |   | $ | 2,058 |   |
| Residential  revenue per Kwh                 |       | 10.18                         | ¢     | 10.09 | ¢ | 9.64 | ¢ |
| Commercial  and industrial revenue per Kwh   |       | 7.07                          |       | 7.17 |   | 6.86 |   |
| Wholesale  revenue per Kwh                   |       | 2.64                          |       | 4.89 |   | 4.87 |   |

 

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**NATURAL GAS UTILITY OPERATIONS**

 

The most significant recentdevelopments in the natural gas operations of NSP-Minnesota are continuedvolatility in natural gas market prices and the continued trend of declininguse per customer by residential customers, as well as small commercial andindustrial (C&I) customers, as a result of improved building constructiontechnologies, higher appliance efficiencies and conservation.  From 1999 to 2009, average annual sales tothe typical residential customer declined from 108 MMBtu per year to 87 MMBtuper year, and to a typical small C&I customer declined from 516 MMBtu to355 MMBtu per year, on a weather-normalized basis.  Although recent wholesale price increases donot directly affect earnings because of natural gas cost recovery mechanisms,high prices can encourage further efficiency efforts by customers.

 

# **PublicUtility Regulation**

#  

***Summary of Regulatory Agencies and Areas ofJurisdiction***** —**Retail rates,services and other aspects of NSP-Minnesota’s operations are regulated by theMPUC and the NDPSC within their respective states.  The MPUC has regulatory authority overaspects of NSP-Minnesota’s financial activities, including security issuances,certain property transfers, mergers with other utilities and transactionsbetween NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s natural gassupply plans for meeting customers’ future energy needs.  NSP-Minnesota is subject to the jurisdictionof the FERC with respect to certain natural gas transactions in interstatecommerce.

 

***Purchased Gas and ConservationCost-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 the natural gas cost revenues collectedthrough PGA rates and the actual natural gas costs are collected or refundedover the subsequent 12-month period.  TheMPUC and NDPSC have the authority to disallow recovery of certain costs if theyfind the utility was not prudent in its procurement activities.

 

NSP-Minnesotais required by Minnesota law to spend a minimum of 0.5 percent ofMinnesota natural gas revenue on conservation improvement programs in the stateof Minnesota.  These costs are recoveredfrom Minnesota customers through an annual cost-recovery mechanism for naturalgas conservation and energy management program expenditures.  This law will change to an energysavings-based requirement beginning in 2010, and the costs of conservationimprovement programs will continue to be recoverable in Minnesota through arate adjustment mechanism.

 

Fora further discussion of rate and regulatory matters see Note 13 to theconsolidated financial statements.

 

**Capability and Demand**

 

Naturalgas supply requirements are categorized as firm or interruptible (customerswith an alternate energy supply).  Themaximum daily send-out (firm and interruptible) for NSP-Minnesota was 720,983MMBtu for 2009, which occurred on Jan. 15, 2009.

 

NSP-Minnesotapurchases natural gas from independent suppliers.  These purchases are generally priced based onmarket indices that reflect current prices. The natural gas is delivered undertransportation agreements with interstate pipelines. These agreements providefor firm deliverable pipeline capacity of 589,492 MMBtu per day.  In addition, NSP-Minnesota has contractedwith providers of underground natural gas storage services.  These storage agreements provide storage forapproximately 26 percent of winter natural gas requirements and32 percent of peak day firm requirements of NSP-Minnesota.

 

NSP-Minnesotaalso owns and operates one LNG plant with a storage capacity of 2.0 Bcfequivalent and three propane-air plants with a storage capacity of 1.3 Bcfequivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to246,000 MMBtu of natural gas per day, or approximately 32 percent of peakday firm requirements.  LNG andpropane-air plants provide a cost-effective alternative to annual fixedpipeline transportation charges to meet the peaks caused by firm space heatingdemand on extremely cold winter days.

 

NSP-Minnesotais required to file for a change in natural gas supply contract levels to meetpeak demand, to redistribute demand costs among classes, or to exchange oneform of demand for another.  The2008-2009 and 2009-2010 entitlement levels are pending MPUC action.

 

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**Natural Gas Supply and Costs**

 

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

 

Thefollowing table summarizes the average delivered cost per MMBtu of natural gaspurchased for resale by NSP-Minnesota’s regulated retail natural gasdistribution business:

 
| 2009 |   | $    | 5.78   |   |
|------|--------|------|--------|--------|
| 2008 |   | 8.41 |   |
| 2007 |   | 7.67 |   |

 

Thecost of natural gas supply, transportation service and storage service isrecovered through the PGA cost recovery mechanism.

 

NSP-Minnesotahas firm natural gas transportation contracts with several pipelines, whichexpire in various years from 2010 through 2027.

 

NSP-Minnesotahas certain natural gas supply, transportation and storage agreements thatinclude obligations for the purchase and/or delivery of specified volumes ofnatural gas or to make payments in lieu of delivery.  At Dec. 31, 2009, NSP-Minnesota wascommitted to approximately $637 million in such obligations under thesecontracts.

 

NSP-Minnesotapurchases firm natural gas supply utilizing long-term and short-term agreementsfrom approximately 31 domestic suppliers and Canadian suppliers.  This diversity of suppliers and contractlengths allows NSP-Minnesota to maintain competition from suppliers andminimize supply costs.

 

**Other**

 

***Minnesota Office of Pipeline Safety (MnOPS)-Noticeof Probable Violation (NPV)*****—** On Feb. 1,2010, a plumber working to clear a sewer line at a residence in St. Paul, Minn.struck a gas line, which ignited a fire that destroyed the house.  The plumber received minor burns, was treatedand released that night, and no other injuries resulted.  An investigation revealed that the gas lineto the house had penetrated and intersected the sewer line to the home.  On Feb. 5, 2010, MnOPS delivered an NPVto NSP-Minnesota. The NPV states that NSP-Minnesota failed to take appropriatemeasures to prevent this accident from occurring in violation of state andfederal regulations.  The NPV also setsforth a four-part proposed compliance plan and a $1 million fine. Thecompliance order requires, among other things, that NSP-Minnesota submit aninspection and remediation plan. NSP-Minnesota subsequently investigated thesewer lines in the vicinity of the accident and determined that no additionalconflicts exist. NSP-Minnesota intends to respond to the NPV on March 8,2010.

 

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**Natural Gas Operating Statistics**

 
| ** **                                      | ** ** | **Year  Ended Dec. 31,** | ** ** |
|-------------------------------------------------|------------|-------------------------------|------------|
| ** **                                      | ** ** | **2009**                      | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Natural gas deliveries (Thousands of MMBtu)** | ** ** | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Residential                                     |       | 39,329                        |       | 41,589 |   | 38,024 |   |
| Commercial  and industrial                      |       | 40,408                        |       | 42,640 |   | 40,184 |   |
| Other                                           |       | 320                           |       | 529 |   | 2,276 |   |
| **Total retail**                                |       | 80,057                        |       | 84,758 |   | 80,484 |   |
| Transportation  and other                       |       | 12,618                        |       | 12,484 |   | 8,528 |   |
| **Total deliveries**                            |       | 92,675                        |       | 97,242 |   | 89,012 |   |
|                                            |       |                          |       |   |   |   |   |
| **Number of customers at end of period**        |       |                          |       |   |   |   |   |
| Residential                                     |       | 437,517                       |       | 434,987 |   | 430,048 |   |
| Commercial  and industrial                      |       | 40,468                        |       | 40,174 |   | 39,570 |   |
| **Total retail**                                |       | 477,985                       |       | 475,161 |   | 469,618 |   |
| Transportation  and other                       |       | 15                            |       | 15 |   | 14 |   |
| **Total customers**                             |       | 478,000                       |       | 475,176 |   | 469,632 |   |
|                                            |       |                          |       |   |   |   |   |
| **Natural gas revenues (Thousands of Dollars)** |       |                          |       |   |   |   |   |
| Residential                                     |       | $                             | 347,348    |   | $ | 467,751 |   | $ | 413,790 |   |
| Commercial  and industrial                      |       | 283,953                       |       | 413,871 |   | 350,640 |   |
| **Total retail**                                |       | 631,301                       |       | 881,622 |   | 764,430 |   |
| Transportation  and other                       |       | 9,022                         |       | 8,336 |   | 12,541 |   |
| **Total natural gas revenues**                  |       | $                             | 640,323    |   | $ | 889,958 |   | $ | 776,971 |   |
|                                            |       |                          |       |   |   |   |   |
| MMBtu  sales per retail customer                |       | 167.49                        |       | 178.38 |   | 171.38 |   |
| Revenue  per retail customer                    |       | $                             | 1,321      |   | $ | 1,855 |   | $ | 1,628 |   |
| Residential  revenue per MMBtu                  |       | 8.83                          | ¢     | 11.25 | ¢ | 10.88 | ¢ |
| Commercial  and industrial revenue per MMBtu    |       | 7.03                          |       | 9.71 |   | 8.73 |   |
| Transportation  and other per MMBtu             |       | 0.72                          |       | 0.67 |   | 1.47 |   |

 

**ENVIRONMENTAL MATTERS**

 

NSP-Minnesota’s facilitiesare regulated by federal and state environmental agencies.  These agencies have jurisdiction over airemissions, water quality, wastewater discharges, solid wastes and hazardoussubstances.  Various company activitiesrequire registrations, permits, licenses, inspections and approvals from theseagencies.  NSP-Minnesota has received allnecessary authorizations for the construction and continued operation of itsgeneration, transmission and distribution systems.  NSP-Minnesota facilities have been designedand constructed to operate in compliance with applicable environmentalstandards.

 

NSP-Minnesota strives tocomply with all environmental regulations applicable to its operations.  However, it is not possible to determine whenor to what extent additional facilities or modifications of existing or plannedfacilities will be required as a result of changes to environmentalregulations, interpretations or enforcement policies or, what effect futurelaws or regulations may have upon NSP-Minnesota’s operations.  For more information on environmentalcontingencies, see Notes 14 and 15 to the consolidated financial statements.

 

**EMPLOYEES**

** **

Thenumber of full-time NSP-Minnesota employees at Dec. 31, 2009 and 2008 was3,763 and 3,637, respectively.  Of thesefull-time employees, 2,341 or 62 percent and 2,279, or 63 percent, respectively,are covered under collective bargaining agreements.  See Note 8 to 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.

 

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# **Item 1A — Risk Factors**

#  

**Oversight of Risk and Related Processes**

** **

The goal of Xcel Energy’srisk management process, which includes NSP-Minnesota, is to understand andmanage material risk; management is responsible for identifying and managingthe risks, while directors oversee and hold management accountable.  Our risk management process has three parts:identification and analysis, management and mitigation, and communication anddisclosure.  Our management identifiesand analyzes risks to determine materiality and other attributes like timing,probability and controllability.  

 

Management broadlyconsiders our business, the utility industry, the domestic and global economy,and the environment to identify risks. Identification and analysis occurs formally through a key riskassessment process conducted by senior management, the securities disclosureprocess, the hazard risk management process, and internal auditing andcompliance with financial and operational controls.  Management also identifies and analyzes riskthrough its business planning process and development of goals and keyperformance indicators, which include risk identification to determine barriersto implementing our strategy.  At thesame time, the business planning process identifies areas where a business areamay take inappropriate risk to meet goals.

 

Thegoal of the risk management process is to mitigate the risks inherent in theimplementation of Xcel Energy’s and NSP-Minnesota’s strategy.  The process for risk management andmitigation includes our code of conduct and other compliance policies, formalstructures and groups, and overall business management.  At a threshold level, we have developed arobust compliance program and promotes a culture of compliance, which mitigatesrisk.  In addition to the code ofconduct, we have a robust compliance program, including policies, training andreporting options.  

 

Buildingon the culture of compliance, we manage and mitigate risks through formalstructures and groups, including management councils, risk committees, and theservices of corporate areas such as internal audit, the corporate controllerand legal services.  While we havedeveloped a number of formal structures for risk management, many materialrisks affect the business as a whole and are managed across businessareas.  

 

Weconfront legislative and regulatory policy and compliance risks, includingrisks related to climate change and emission of CO2 and risks forrecovery of capital and operating costs; resource planning and other long-termplanning risks, including resource acquisition risks; financial risks,including credit, interest rate and capital market risks; and macroeconomicrisks, including risks related to economic conditions and changes in demand forour products and services.  Cross-cuttingrisks such as these are discussed and managed across business areas andcoordinated by Xcel Energy’s and NSP-Minnesota’s senior management.

 

Management providesinformation to the Xcel Energy’s Board in presentations and communications overthe course of the Board calendar.  Seniormanagement presents an assessment of key risks to the Board annually.  The presentation of the key risks and thediscussion provides the Board with information on the risks management believesare material, including the earnings impact, timing, likelihood andcontrollability.  Based on thispresentation, the Board reviews risks at an enterprise level and confirms riskmanagement and mitigation are included in Xcel Energy’s and NSP-Minnesota’s strategy.   

 

The guidelines oncorporate governance and committee charters define the scope of review andinquiry for the Board and committees. The standing committees also oversee risk management as part of theircharters.  Each committee has responsibilityfor overseeing aspects of risk and our management and mitigation of therisk.  The Xcel Energy Board has overallresponsibility for risk oversight.  Asdescribed above, the Board reviews the key risk assessment process presented bysenior management.  This key riskassessment analyzes the most likely areas of future risk to Xcel Energy.  The Xcel Energy Board also reviews theperformance and annual goals of each business area.  This review, when combined with the oversightof specific risks by the committees, allows the Board to confirm risk isconsidered in the development of goals and that risk has been adequatelyconsidered and mitigated in the execution of corporate strategy.

 

**Risks Associated with Our Business**

 

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

 

We are subject tocomprehensive regulation by federal and state utility regulatory agencies.  The state utility commissions regulate manyaspects of our utility operations, including siting and construction offacilities, customer service and the rates that we can charge customers.  The FERC has jurisdiction, among otherthings, over wholesale rates for electric transmission service, the sale ofelectric energy in interstate commerce and certain natural gas transactions ininterstate commerce.

 

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Our profitability is dependent on our ability torecover the costs of providing energy and utility services to our customers andearn a return on our capital investment in our utility operations.  We currently provide service at ratesapproved by one or more regulatory commissions. These rates are generally regulated based on an analysis of our costsincurred in a test year.  Thus, the rateswe are allowed to charge may or may not match our costs at any given time.  While rate regulation is premised onproviding a reasonable opportunity to earn a reasonable rate of return oninvested capital, there can be no assurance that the applicable regulatory commissionwill judge all of our costs to have been prudently incurred or that theregulatory process in which rates are determined will always result in ratesthat will produce full recovery of our costs. Rising fuel costs could increase the risk that we will not be able tofully recover our fuel costs from our customers.  Furthermore, there could be changes in theregulatory environment that would impair our ability to recover costshistorically collected from our customers. If all of our costs are not recovered through customer rates, we couldincur financial operating losses, which, over the long term, could jeopardizeour ability to meet our financial obligations.

 

Management currently believes these prudently incurredcosts are recoverable given the existing regulatory mechanisms in place.  However, changes in regulations or theimposition of additional regulations, including additional environmentalregulation or regulation related to climate change, could have an adverseimpact on our results of operations and hence could materially and adverselyaffect our ability to meet our financial obligations, including debt payments.

 

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

 

We cannot be assured that any of our current ratingswill remain in effect for any given period of time or that a rating will not belowered or withdrawn entirely by a rating agency.  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 & 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 &Poor’s methodology.  Therefore, ourcredit ratings could be adversely affected based on the level of capacitypayments associated with purchase power contracts or changes in how imputeddebt is determined.  Any downgrade couldlead to higher borrowing costs.

 

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

 

If interest rates increase, we may incur increasedinterest expense on variable interest rate debt, short-term borrowings orincremental long-term debt, which could have an adverse impact on our operatingresults.

 

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

*** ***

Our operations require significant capital investmentin property, plant and equipment; consequently, we are an active participant indebt markets.  Any disruption in capitalmarkets could have a material impact on our ability to fund ouroperations.  Capital markets are globalin nature and are impacted by numerous events throughout the worldeconomy.  Capital market disruptionevents, such as the collapse in the U. S. sub-prime mortgage market andsubsequent broad financial market stress, could prevent us from issuing newsecurities or cause us to issue securities with less than ideal terms andconditions, such as higher interest rates.

 

***Weare subject to credit risks.***

 

Credit risk includes therisk that our retail customers will not pay their bills, which may lead to areduction in liquidity and an eventual increase in bad debt expense.  Retail credit risk is comprised of numerousfactors including the overall economy and the price of products and servicesprovided.

 

Credit risk also includesthe risk that various counterparties that owe us money or product will breachtheir obligations.  Should thecounterparties to these arrangements fail to perform, we may be forced to enterinto alternative arrangements.  In thatevent, our financial results could be adversely affected and we could incurlosses.

 

One alternative availableto address counterparty credit risk is to transact on liquid commodityexchanges.  The credit risk is then socializedthrough the exchange central clearinghouse function.  While exchanges do remove counterparty creditrisk, all participants are subject to margin requirements, which create anadditional need for liquidity to post margin as exchange positions change valuedaily.  Additional margin requirementscould impact our liquidity.

 

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We may at times havedirect credit exposure in our short-term wholesale andcommodity trading activity to various financial institutions trading fortheir own accounts or issuing collateral support on behalf of othercounterparties.  We may also have someindirect credit exposure due to participation in organized markets such as thePJM Interconnection and MISO in which any credit losses are socialized to allmarket participants.

 

We do have additionalindirect credit exposures to various financial institutions in the form ofletters of credit provided as security by power suppliers undervarious long-term physical purchased power contracts.  If any of the credit ratings of the letter ofcredit issuers were to drop below the designated investment grade ratingstipulated in the underlying long-term purchased power contracts, the supplierwould need to replace that security with an acceptable substitute.  If thesecurity were not replaced, the party would be in technical default underthe contract, which would enable us to exercise our contractual rights.

 

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

 

We engage in wholesale sales and purchases of electriccapacity, energy and energy-related products and are subject to market supplyand commodity price risk.  Commodityprice changes can affect the value of our commodity trading derivatives.  We mark certain derivatives to estimated fairmarket value on a daily basis (mark-to-market accounting), which may causeearnings volatility.  Actual settlementscan vary significantly from these estimates, and significant changes from theassumptions underlying our fair value estimates could cause significantearnings 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 supply shortages could cause us toseek alternative supply services at potentially higher costs or sufferincreased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costsrelative to corresponding sales commitments would have a negative impact on ourcash flows and could potentially result in economic losses.  Potential market supply shortages may not befully resolved through alternative supply sources and such interruptions maycause short-term disruptions in our ability to provide electric and/or naturalgas services to our customers.  Theimpact of these cost and reliability issues depends on unique operatingconditions such as generation fuels mix, availability of water for cooling,availability of fuel transportation, electric generation capacity,transmission, etc.

 

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

 

We are subject to environmental laws and regulationsthat affect many aspects of our past, present and future operations, includingair emissions, water quality, wastewater discharges and the generation,transport and disposal of solid wastes and hazardous substances.  These laws and regulations require us toobtain and comply with a wide variety of environmental registrations, licenses,permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict orlimit the output of certain facilities or the use of certain fuels, to installpollution control equipment at our facilities, clean up spills and correctenvironmental hazards and other contamination. Both public officials and private individuals may seek to enforce theapplicable environmental laws and regulations against us.  We may be required to pay all or a portion ofthe cost to remediate (i.e. clean-up) sites where our past activities, or theactivities of certain other parties, caused environmental contamination.  At Dec. 31, 2009, these sites included:

 

·                  Sites of former MGPs operated by us, our predecessors,or other entities; and

·                  Third party sites, such as landfills, for which we arealleged to be a potentially responsible party that sent hazardous materials andwastes.

 

We are also subject to mandates to provide customerswith clean energy, renewable energy and energy conservation offerings.  These mandates are designed in part tomitigate the potential environmental impacts of utility operations.  Failure to meet the requirements of thesemandates may result in fines or penalties, which could have a material adverseeffect on our results of operations.  Ifour regulators do not allow us to recover all or a part of the cost of capitalinvestment or the operating and maintenance costs incurred to comply with themandates, it could have a material 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, including but notlimited to regulation of mercury, NOx, SO2, CO2, particulates and coal ash.  We may also incur additional unanticipatedobligations or liabilities under existing environmental 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 creates physical and financialrisk. **Physicalrisks from climate change include an increase in sea level and changes in weatherconditions, such as an increase in changes in precipitation and extreme weatherevents.  We do not serve any coastalcommunities so the possibility of sea level rises does not directly affect usor our customers.  Our customers’ energyneeds vary with weather conditions, primarily temperature and humidity.  For residential customers, heating andcooling represent their largest energy use. To the extent weather conditions are affected by climate change,customers’ energy use could increase or decrease depending on the duration andmagnitude of the changes.  Increasedenergy use due to weather changes may require us to invest in more generatingassets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changesmay affect our financial condition, through decreased revenues.  Extreme weather conditions in general requiremore system backup, adding to costs, and can contribute to increased systemstresses, including service interruptions. Weather conditions outside of our service territory could also have animpact on our revenues.  We buy and sellelectricity depending 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 our service territories, primarily whenthunderstorms, tornadoes and snow or ice storms occur.  We include storm restoration in our budgetingprocess as a normal business expense and we anticipate continuing to doso.  To the extent the frequency ofextreme weather events increases, this could increase our cost of providingservice.  Changes in precipitationresulting in droughts or water shortages could adversely affect our operations,principally our fossil generating units. A negative impact to water supplies due to long-term drought conditionscould adversely impact our ability to provide electricity to customers, as wellas increase the price they pay for energy. We may not recover all costs related to mitigating these physical andfinancial risks.

 

Tothe extent climate change impacts a region’s economic health, it may alsoimpact our revenues.  Our financialperformance is tied to the health of the regional 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 andservices, has an impact on the economic health of our communities.  The cost of additional regulatoryrequirements, such as a tax on GHGs or additional environmental regulationcould impact the availability of goods and prices charged by our supplierswhich 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 cause us toreceive 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 andregulatory responses related to climate change and new interpretations ofexisting laws through climate change litigation create financial risk.  Increased public awareness and concern mayresult in more regional and/or federal requirements to reduce or mitigate theeffects of GHGs.  Numerous states haveannounced or adopted programs to stabilize and reduce GHG and federallegislation has been introduced in both houses of Congress.  Our electric generating facilities are likelyto be subject to regulation under climate change laws introduced at either thestate or federal level within the next few years.

 

TheEPA has taken steps to regulate GHGs under the CAA.  On Dec. 7, 2009, the EPA issued afinding that GHG emissions endanger public health and welfare and that motorvehicle emissions contribute to the GHGs in the atmosphere.  This endangerment finding creates a mandatoryduty for the EPA to regulate GHGs from light duty motor vehicles.  The EPA has proposed to finalize GHGefficiency standards for light duty vehicles by spring 2010. Thereafter, theEPA anticipates phasing-in permit requirements and regulation of GHGs for largestationary sources, such as power plants, in calendar year 2011.  Xcel Energy, our parent company, is alsocurrently a party to climate change lawsuits and may be subject to additional climatechange lawsuits, including lawsuits similar to those described in Note 14,Commitments and Contingent Liabilities, in our notes to the consolidatedfinancial statements.  While Xcel Energybelieves such lawsuits are without merit, an adverse outcome in any of thesecases could require substantial capital expenditures that cannot be determinedat this time and could possibly require payment of substantial penalties ordamages.  Defense costs associated withsuch litigation can also be significant. Such payments or expenditures could affect results of operations, cashflows, and financial condition if such costs are not recovered throughregulated rates.

 

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Many of the federal andstate climate change legislative proposals, such as ACES, use a cap and tradepolicy structure, in which GHG emissions from a broad cross-section of theeconomy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage oftime.  The proposals establish mechanismsfor GHG sources, such as power plants, to obtain “allowances” or permits toemit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sellthem to other sources that do not hold enough emission allowances for their ownoperations.  Proponents of the cap andtrade policy believe it will result in the most cost effective, flexible emissionreductions.  There are many uncertainties,however, regarding when and in what form climate change legislation will beenacted.  The impact of legislation andregulations, including a cap and trade structure, on us and our customers willdepend on a number of factors, including whether GHG sources in multiplesectors of the economy are regulated, the overall GHG emissions cap level, thedegree to which GHG offsets are allowed, the allocation of emission allowancesto specific sources and the indirect impact of carbon regulation on natural gasand coal prices.  While we do not haveoperations outside of the United States, any international treaties or accordscould have an impact to the extent they lead to future federal or stateregulations.  Another important factor isour ability to recover the costs incurred to comply with any regulatoryrequirements that are ultimately imposed. We may not recover all costs related to complying with regulatoryrequirements imposed on us.  If ourregulators do not allow us to recover all or a part of the cost of capitalinvestment or the operating and maintenance costs incurred to comply with themandates, it could have a material adverse effect on our results of operations.

 

For further discussion,see Note 14 to the consolidated financial statements.

 

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

 

Our two nuclear stations, Prairie Island andMonticello, subject us to the risks of nuclear generation, which include:

 

·                  The risks associated with storage, handling anddisposal of radioactive materials and the current lack of a long-term disposalsolution for radioactive materials;

·                  Limitations on the amounts and types of insurancecommercially available to cover losses that might arise in connection withnuclear operations; and

·                  Uncertainties with respect to the technological andfinancial aspects of decommissioning nuclear plants at the end of licensedlives.

 

The NRC has authority to impose licensing andsafety-related requirements for the operation of nuclear generationfacilities.  In the event ofnon-compliance, the NRC has the authority to impose fines or shut down a unit,or both, depending upon its assessment of the severity of the situation, untilcompliance is achieved.  Revised NRCsafety requirements could necessitate substantial capital expenditures at ournuclear plants.  In addition, theInstitute for Nuclear Power Operations (INPO) reviews our nuclear operationsand nuclear generation facilities. Compliance with INPO recommendations couldresult in substantial capital expenditures or a substantial increase inoperating expenses.

 

If an incident did occur, it could have a materialadverse effect on our results of operations or financial condition.  Furthermore, the non-compliance of othernuclear facilities operators with applicable regulations or the occurrence of aserious nuclear incident at other facilities could result in increasedregulation of the industry as a whole, which could then increase our compliancecosts and impact the results of operations of its facilities.

 

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

 

Our operations are affected by local, national andworldwide economic conditions.  Theconsequences of a prolonged recession may include a lower level of economicactivity and uncertainty with respect to energy prices and the capital andcommodity markets.  A lower level ofeconomic activity might result in a decline in energy consumption, which mayadversely affect our revenues and future growth.  Instability in the financial markets, as aresult of recession or otherwise, also may affect the cost of capital and ourability to raise capital, which are discussed in greater detail in the capitalmarket risk section above.

 

Current economicconditions may be exacerbated by insufficient financial sector liquidityleading to potential increased unemployment, and may impact customers’ abilityto pay timely, increase customer bankruptcies, and may lead to increased baddebt.  It is expected that commercial andindustrial customers will be impacted first with residential customersfollowing, if such circumstances occur. See credit risk section for more related information.

 

Further, worldwide economic activity has an impact onthe demand for basic commodities needed for utility infrastructure, such assteel, copper, aluminum, etc., which may impact our ability to acquiresufficient supplies.  Additionally, thecost of those commodities may be higher than expected.

 

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***Our utility operations are subject tolong-term planning risks.***

*** ***

On a periodic basis, or as needed, our utilityoperations file long-term resource plans with our regulators.  These plans are based on numerous assumptionsover the relevant planning horizon such as: sales growth, economic activity,costs, regulatory mechanisms, impact of technology on sales and production,customer response and continuation of the existing utility business model.  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 impactedby war, acts of terrorism, threats of terrorism or disruptions in normaloperating conditions due to localized or regional events.***

 

Our generation plants, fuel storage facilities, transmission and distributionfacilities and information systems may be targets of terrorist activities thatcould disrupt our ability to produce or distribute some portion of our energyproducts.  Any such disruption couldresult in a significant decrease in revenues and significant additional coststo repair and insure our assets, which could have a material adverse impact onour 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.  Wehave also already incurred increased costs for compliance with NERC reliabilitystandards associated with critical infrastructure protection, and mayexperience additional capital and operating costs to implement the NERCcritical infrastructure protection standards as they are implemented andclarified.

 

The insurance industry has also been affected by these events and theavailability of insurance covering risks we and our competitors 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 the actions of a neighboring utility oran event (severe storm, severe temperature extremes, generator or transmissionfacility outage, pipeline rupture, railroad disruption, sudden and significantincrease or decrease in wind generation, or any disruption of work force suchas may be caused by flu epidemic) within our operating systems or on aneighboring system.  Any such disruptioncould result in a significant decrease in revenues and significant additionalcosts to repair assets, which could have a material adverse impact on ourfinancial condition and results.

 

***We are subject to businesscontinuity risks associated with our ability to respond to unforeseen events.***

 

The term business continuity refers to the ability of an entity tomaintain day-to-day operations in response to unforeseen events.  While the immediate response to such eventsmay be part of a pre-existing disaster recovery plan, business continuity is abroader concept that refers to how well the company responds to subsequentpressures on its day-to-day operations. The company’s response may have been initially triggered by an event,but when combined with other factors, it has an even greater and longer lastingimpact on the firm’s on going business operations.

 

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.

 

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

 

Higher fuel costs couldsignificantly impact our results of operations if requests for recovery areunsuccessful.  In addition, higher fuelcosts could reduce customer demand or increase bad debt expense, which couldalso have a material impact on our results of operations.  Delays in the timing of the collection offuel cost recoveries as compared with expenditures for fuel purchases couldhave an impact on our cash flows.  We areunable to predict future prices or the ultimate impact of such prices on ourresults of operations or cash flows.

 

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

 

Our electric and natural gas utility businesses areseasonal businesses, and weather patterns can have a material impact on ouroperating performance.  Demand forelectricity is often greater in the summer and winter months associated withcooling and heating.  Because natural gasis heavily used for residential and commercial heating, the demand for thisproduct depends heavily upon weather patterns throughout our service territory,and a significant amount of natural gas revenues are recognized in the firstand fourth quarters related to the heating season.  Accordingly, our operations have historicallygenerated less revenues and income when weather conditions are milder in thewinter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on ourfinancial condition and results of operations.

 

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

 

There are inherent in our natural gas distributionactivities a variety of hazards and operating risks, such as leaks, explosionsand mechanical problems, which could cause substantial financial losses.  In addition, these risks could result in lossof human life, significant damage to property, environmental pollution,impairment of our operations and substantial losses to us.  In accordance with customary industrypractice, we maintain insurance against some, but not all, of these risks andlosses.

 

The occurrence of any of these events not fullycovered by insurance could have a material adverse effect on our financialposition and results of operations.  Forour distribution lines located near populated areas, including residentialareas, commercial business centers, industrial sites and other public gatheringareas, the level of damages resulting from these risks is greater.

 

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

 

The Energy Act increased the FERC’s civil penaltyauthority for violation of FERC statutes, rules and orders.  The FERC can now impose penalties of$1 million per violation per day. In addition, more than 120 electric reliability standards that werehistorically subject to voluntary compliance are now mandatory and subject topotential financial penalties by NERC or FERC for violations.  If a serious reliability incident did occur,it could have a material adverse effect on our operations or financial results.

 

***Increasing costs associated withour defined benefit retirement plans and other employee benefits may adverselyaffect our results of operations, financial position or liquidity.***

 

We have defined benefit pension and postretirementplans that cover substantially all of our employees.  Assumptions related to future costs, returnon investments, interest rates and other actuarial assumptions have asignificant impact on our funding requirements related to these plans.  These estimates and assumptions may changebased on economic conditions, actual stock market performance, changes ininterest rates and changes in governmental regulations.  In addition, the Pension Protection Act of2006 changed the minimum funding requirements for defined benefit pension plansbeginning in 2008.  Therefore, ourfunding requirements and related contributions may change in the future.

 

***Increasingcosts associated with health care plans may adversely affect our results ofoperations, financial position or liquidity.***

** **

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

 

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***As we are 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 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.***

 

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, 2009, Xcel Energy had approximately $7.9 billion oflong-term debt and $1.0 billion of short-term debt and 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. 31,2009, Xcel Energy had guarantees outstanding with a maximum stated amount ofapproximately $76.4 million and $18.0 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, 2009, was approximately $29.9million.  Xcel Energy’s total exposureunder these indemnities cannot be estimated 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.***

 

All of the members of our board of directors, as well as many of ourexecutive officers, are officers of Xcel Energy.  Our board makes determinations with respectto a number of significant corporate events, including the payment of ourdividends.

 

We have historically paid quarterly dividends to XcelEnergy.  In 2009, 2008 and 2007 we paid$232.7 million, $229.7 million and $226.8 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 limited to some extent by our indenture for our first mortgagebonds.

 

**Item 1B — Unresolved StaffComments**

 

None.

 

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**Item 2 —Properties**

 

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

 

Electric utility generatingstations:

 
| ** **                                       | ** ** | ** **       | ** ** | ** **    | ** ** | **Summer  2009**     | ** ** |
|--------------------------------------------------|------------|------------------|------------|---------------|------------|----------------------|------------|
| ** **                                       | ** ** | ** **       | ** ** | ** **    | ** ** | **Net  Dependable**  | ** ** |
| **Station, City and Unit**                       | ** ** | **Fuel**         | ** ** | **Installed** | ** ** | **Capability  (MW)** | ** ** |
| ***Steam:***                                     |       |             |       |          |       |                 |       |
| Sherburne-Becker,  Minn.                         |       |             |       |          |       |                 |       |
| Unit 1                                           |       | Coal             |       | 1976          |       | 697                  |       |
| Unit 2                                           |       | Coal             |       | 1977          |       | 697                  |       |
| Unit 3                                           |       | Coal             |       | 1987          |       | 521                  | (a)        |
| Prairie  Island-Welch, Minn.                     |       |             |       |          |       |                 |       |
| Unit 1                                           |       | Nuclear          |       | 1973          |       | 551                  |       |
| Unit 2                                           |       | Nuclear          |       | 1974          |       | 545                  |       |
| Monticello-Monticello,  Minn                     |       | Nuclear          |       | 1971          |       | 572                  |       |
| King-Bayport,  Minn                              |       | Coal             |       | 1968          |       | 510                  |       |
| Black  Dog-Burnsville, Minn.                     |       |             |       |          |       |                 |       |
| 2 Units                                          |       | Coal/Natural Gas |       | 1955-1960     |       | 282                  |       |
| 2 Units                                          |       | Natural Gas      |       | 1987-2002     |       | 298                  |       |
| Riverside-Minneapolis,  Minn., 3 Units           |       | Natural Gas      |       | 2009          |       | 511                  |       |
| ***Combustion Turbine:***                        |       |             |       |          |       |                 |       |
| Angus  Anson-Sioux Falls, S.D., 3 Units          |       | Natural Gas      |       | 1994-2005     |       | 384                  |       |
| High Bridge-St.  Paul, Minn., 3 Units            |       | Natural Gas      |       | 2008          |       | 566                  |       |
| Inver  Hills-Inver Grove Heights, Minn., 6 Units |       | Natural Gas      |       | 1972          |       | 350                  |       |
| Blue  Lake-Shakopee, Minn., 6 Units              |       | Natural Gas      |       | 1974-2005     |       | 490                  |       |
| Various  locations, 23 Units                     |       | Various          |       | Various       |       | 181                  |       |
| ***Wind:***                                      |       |             |       |          |       |                 |       |
| Grand Meadow -  Mower County, Minn.              |       | Wind             |       | 2008          |       | 101                  | (b)        |
|                                             |       |             |       |  Total   |       | 7,256                |       |

 

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| (a)    | Based on NSP-Minnesota’s  ownership of 59 percent.                                                                           |
|--------|-----------------------------------------------------------------------------------------------------------------------------------|
| (b)    | This capacity is only  available when wind conditions are sufficiently high enough to support the  noted generation values above. |
|   | Therefore, the on-demand  net maximum capacity is zero.                                                                           |

 

Electric utility overheadand underground transmission and distribution lines (measured in conductormiles) at Dec. 31, 2009:

 
| **Conductor Miles** | ** ** | ** ** | ** ** |
|---------------------|------------|------------|------------|
| 500 KV              |       | 2,917      |       |
| 345 KV              |       | 6,385      |       |
| 230 KV              |       | 1,801      |       |
| 161 KV              |       | 428        |       |
| 115 KV              |       | 7,103      |       |
| Less than 115 KV    |       | 82,782     |       |

 

NSP-Minnesota had 375electric utility transmission and distribution substations at Dec. 31,2009.

 

Natural gas utility mains at Dec. 31, 2009:

 
| **Miles**    | ** ** | ** ** | ** ** |
|--------------|------------|------------|------------|
| Transmission |       | 135        |       |
| Distribution |       | 9,586      |       |

 

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**Item 3 —Legal Proceedings**

 

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

 

**Additional Information**

** **

For a discussion of legalclaims and environmental proceedings, see Note 14 to the consolidatedfinancial statements.  For a discussionof proceedings involving utility rates and other regulatory matters, seeItem 1 for Public Utility Regulation and Summary of Recent FederalRegulatory Developments and Note 13 to the consolidated financialstatements.

 

**Item 4 —Reserved**

 

**PART II**

 

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

 

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

 

NSP-Minnesota’s firstmortgage indenture places certain restrictions on the amount of cash dividendsit can pay to Xcel Energy, the holder of its common stock.  Even with these restrictions, NSP-Minnesotacould have paid more than $1.1 billion and $1.0 billion in additional cashdividends on common stock at Dec. 31, 2009 and 2008, respectively.

 

In addition, NSP-Minnesotahad dividend restrictions imposed by its credit facility, FERC rules andstate regulatory commissions.

 

·                     NSP-Minnesota’scredit facility includes a financial covenant that requires the equity-to-totalcapitalization ratio to be greater than or equal to 35 percent.  NSP-Minnesota was in compliance as itsequity-to-total capitalization ratio was 52 percent and 50 percent at Dec. 31,2009 and 2008, respectively.

·                     Dividends aresubject to the FERC’s jurisdiction under the Federal Power Act, which prohibitsthe payment of dividends out of capital accounts; payment of dividends isallowed out of retained earnings only.

·                     Stateregulatory commissions indirectly limit the amount of dividends NSP-Minnesotacan pay to Xcel Energy by requiring an equity-to-total capitalization ratiobetween 45.99 percent and 56.21 percent. NSP-Minnesota was in compliance as described above.  Total capitalization for NSP-Minnesota cannotexceed $7.5 billion.

 

The dividends declaredduring 2009 and 2008 were as follows:

 
| **(Thousands of Dollars)** | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------|------------|----------|------------|----------|------------|
| First quarter              |       | $        | 57,256     |     | $          | 56,668 |   |
| Second quarter             |       | 58,575   |       | 58,449   |       |
| Third quarter              |       | 58,463   |       | 58,501   |       |
| Fourth quarter             |       | 58,415   |       | 58,414   |       |
|                            |            |          |            |          |            |  |  |

 

**Item 6 — Selected Financial Data**

 

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

 

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

 

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

 

**ForwardLooking Information**

 

The following discussion andanalysis by management focuses on those factors that had a material effect onthe financial condition and results of operations of NSP-Minnesota during theperiods presented, or are expected to have a material impact in thefuture.  It should be read in conjunctionwith the respective accompanying consolidated financial statements and notes tothe consolidated financial statements.

 

Except for the historicalstatements contained in this report, the matters discussed in the followingdiscussion and analysis are forward-looking statements that are subject tocertain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in thisdocument by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,”“objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should”and similar expressions.  Actual resultsmay vary materially.  Forward-lookingstatements speak only as of the date they are made and we do not undertake anyobligation to update them to reflect changes that occur after that date.  Factors that could cause actual results todiffer materially include, but are not limited to: general economic conditions,including the availability of credit and its impact on capital expenditures andthe ability of NSP- Minnesota to obtain financing on favorable terms; businessconditions in the energy industry; actions of credit rating agencies;competitive factors, including the extent and timing of the entry of additionalcompetition in the markets served by NSP-Minnesota; unusual weather; effects ofgeopolitical events, including war and acts of terrorism; state, federal andforeign legislative and regulatory initiatives that affect cost and investmentrecovery, have an impact on rates or have an impact on asset operation orownership or impose environmental compliance conditions; structures that affectthe speed and degree to which competition enters the electric and natural gasmarkets; costs and other effects of legal and administrative proceedings,settlements, investigations and claims; environmental laws and regulations;actions of accounting regulatory bodies; and the other risk factors listed fromtime to time by NSP-Minnesota in reports filed with the SEC, including “RiskFactors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31,2009 and Exhibit 99.01 to NSP-Minnesota’s Form 10-K for the yearended Dec. 31, 2009.

 

**Results of Operations**

** **

NSP-Minnesota’snet income was approximately $293.8 million for 2009, compared withapproximately $285.1 million for 2008.

 

***Electric Revenues and Margins***

*** ***

Electricfuel and purchased power expenses tend to vary with changing retail andwholesale sales requirements and unit cost changes in fuel and purchasedpower.  Due to fuel and purchased energycost-recovery mechanisms for customers, fluctuations in these costs do not materially affect electric utilitymargin.

 

NSP-Minnesotahas two distinct forms of wholesale sales: short-term wholesale and commoditytrading activities.  Short-term wholesalerefers to energy-related purchase and sales activity and the use of certainfinancial instruments associated with the fuel required for and energy producedfrom, NSP-Minnesota’s generation assets and energy and capacity purchased toserve native load.  Commodity trading isnot associated with NSP-Minnesota’s generation assets or the energy or capacitypurchased to serve native load. Wholesale sales were immaterial to revenue and gross margin as apercentage of revenue at Dec. 31, 2009 and 2008.

 

***Electric***—******The following tables detailthe electric revenues and margin:

 
| **(Millions  of Dollars)**         | ** ** | **2009** | ** ** | **2008**   | ** ** |
|------------------------------------|------------|----------|------------|------------|------------|
| Electric  revenues                 | ** ** | **$**    | 3,407      | ** ** | **$**      | 3,584 | ** ** |
| Electric  fuel and purchased power |       | (1,412   | )          | (1,681     | )          |
| Electric  margin                   | ** ** | **$**    | 1,995      | ** ** | **$**      | 1,903 | ** ** |

 

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Thefollowing summarizes the components of the changes in electric revenues andelectric margin for the year ended Dec. 31:

 

***Electric Revenues***

 
| **(Millions  of Dollars)**                                                         | ** ** | **2009  vs. 2008** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------|------------|
| Fuel  and purchased power cost recovery                                            | ** ** | **$**              | (209       | ) |
| Trading                                                                            |       | (54                | )          |
| Retail  sales decline (excluding weather impact)                                   |       | (20                | )          |
| Firm  wholesale                                                                    |       | (14                | )          |
| Estimated  impact of weather                                                       |       | (12                | )          |
| Minnesota  retail rate increase                                                    |       | 88                 |       |
| MERP  rider                                                                        |       | 17                 |       |
| 2008  refund of nuclear refueling outage revenues due to change in recovery method |       | 16                 |       |
| Non-fuel  riders                                                                   |       | 9                  |       |
| Transmission  revenue                                                              |       | 5                  |       |
| Other,  net                                                                        |       | (3                 | )          |
| Total  decrease in electric revenues                                               | ** ** | **$**              | (177       | ) |

 

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

 
| **(Millions  of Dollars)**                                                         | ** ** | **2009  vs. 2008** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------|------------|
| Minnesota  retail rate increase                                                    | ** ** | **$**              | 88         | ** ** |
| Interchange  agreement billing with NSP-Wisconsin                                  |       | 28                 |       |
| MERP  rider                                                                        |       | 17                 |       |
| 2008  refund of nuclear refueling outage revenues due to change in recovery method |       | 16                 |       |
| Non-fuel  riders                                                                   |       | 9                  |       |
| Retail  sales decline (excluding weather impact)                                   |       | (20                | )          |
| Estimated  impact of weather                                                       |       | (12                | )          |
| Transmission  revenue, net of expense                                              |       | (8                 | )          |
| Higher  purchased capacity costs                                                   |       | (5                 | )          |
| Firm  wholesale                                                                    |       | (5                 | )          |
| Trading                                                                            |       | (4                 | )          |
| Other,  net                                                                        |       | (12                | )          |
| Total  increase in electric margin                                                 | ** ** | **$**              | 92         | ** ** |

 

**Natural GasRevenues and Margins**

 

The cost of natural gastends to vary with changing sales requirements and unit cost of natural gaspurchases.  However, due to purchasednatural gas cost recovery mechanisms for retail customers, fluctuations in thecost of natural gas have little effect on natural gas margin.

 

***Natural Gas***— The following tables detail natural gas revenues and margin:

 
| **(Millions  of Dollars)**                | ** ** | **2009** | ** ** | **2008**   | ** ** |
|-------------------------------------------|------------|----------|------------|------------|------------|
| Natural  gas revenues                     | ** ** | **$**    | 640        | ** ** | **$**      | 890 | ** ** |
| Cost  of natural gas sold and transported |       | (464     | )          | (702       | )          |
| Natural  gas margin                       | ** ** | **$**    | 176        | ** ** | **$**      | 188 | ** ** |

 

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The following summarizes thecomponents of the changes in natural gas revenues and margin for the year endedDec. 31:

 

***Natural Gas Revenues***

 
| **(Millions  of Dollars)**                                                 | ** ** | **2009  vs. 2008** | ** ** |
|----------------------------------------------------------------------------|------------|--------------------|------------|
| Purchased  natural gas adjustment clause recovery                          | ** ** | **$**              | (241       | ) |
| Conservation  program revenue and incentive (generally offset by expenses) |       | (9                 | )          |
| Estimated  impact of weather                                               |       | (5                 | )          |
| Other,  net                                                                |       | 5                  |       |
| Total  decrease in natural gas revenues                                    | ** ** | **$**              | (250       | ) |

 

Natural Gas Margin

 
| **(Millions  of Dollars)**                                                 | ** ** | **2009  vs. 2008** | ** ** |
|----------------------------------------------------------------------------|------------|--------------------|------------|
| Conservation  program revenue and incentive (generally offset by expenses) | ** ** | **$**              | (9         | ) |
| Estimated  impact of weather                                               |       | (5                 | )          |
| Other,  net                                                                |       | 2                  |       |
| Total  decrease in natural gas margin                                      | ** ** | **$**              | (12        | ) |

 

Non-Fuel Operating Expense and Other Items

** **

***Other Operating and Maintenance Expenses****—* Operating and maintenance expenses for 2009 increased $90.9 million,or 10.4 percent, compared to 2008.  Thefollowing summarizes the components of the changes for the year ended Dec. 31:

 
| **(Millions  of Dollars)**                                  | ** ** | **2009  vs. 2008** | ** ** |
|-------------------------------------------------------------|------------|--------------------|------------|
| Higher  employee benefit costs                              | ** ** | **$**              | 37         | ** ** |
| Nuclear  outage costs, net of deferral                      |       | 30                 |       |
| Higher  nuclear plant operation costs                       |       | 21                 |       |
| Higher  insurance costs                                     |       | 6                  |       |
| Higher  labor costs                                         |       | 4                  |       |
| Higher  information technology costs                        |       | 3                  |       |
| Interchange  agreement billing with NSP-Wisconsin           |       | 3                  |       |
| Lower  consulting costs                                     |       | (9                 | )          |
| Lower  uncollectible receivable costs                       |       | (6                 | )          |
| Other,  net                                                 |       | 2                  |       |
| Total  increase in other operating and maintenance expenses | ** ** | **$**              | 91         | ** ** |

 

·                     Higher employee benefits costs areprimarily attributable to 2009 employee based incentive compensation expensesand increased medical expenses.  In 2008,no employee based incentive benefits were earned.

·                     The increase in nuclear outage costs is due to thetiming of outages in conjunction with the MPUC’s approval of the change in thenuclear refueling outage recovery method from the direct expense method to thedeferral and amortization method in 2008.

·                     The increase in nuclear plant operation costs is drivenprimarily by an increase in security costs and regulatory fees, resulting fromnew NRC requirements.

 

***Conservation Program Expenses****—* Conservationprogram expenses decreased $6.6 million, or 10.1 percent, for 2009, comparedwith 2008.  The decrease was primarilydue to an adjustment in the 2009 rider for over-recovery in 2008, whichresulted from the timing of the rider rate approval.

 

***Depreciation and Amortization****—* Depreciationand amortization expense decreased by approximately $23.0 million, or 5.6percent, for 2009, compared with 2008. In September 2009, as a result of the MPUC decision in the Minnesota electric rate case,NSP-Minnesota began recognizing a 10-year life extension of the Prairie Islandnuclear plant for purposes of determining depreciation, effective Jan. 1,2009.  In addition, in June 2009,the MPUC extended the recovery period of decommissioning expense by 10 yearsfor the Prairie Island and the Monticello nuclear plants.  These decreases were partially offset bynormal system expansion.

 

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***Taxes Other than Income****—* Taxes otherthan income increased by approximately $9.0 million, or 6.5 percent, for 2009,compared with 2008.  The increase wasprimarily due to increased property taxes.

 

***Other Income, Net****—*Other income,net, decreased by approximately $9.3 million for 2009, compared with 2008.  The decrease was primarily due to lower interest incomein 2009 and changes in non-qualified benefit plan liabilities related to marketactivity.

 

***Allowance for FundsUsed During Construction, Equity and Debt (AFUDC)***— AFUDC is a non-cash amount capitalizedas a part of construction costs representing the cost of financing theconstruction.  Generally, these costs arerecovered from customers, in future rates, as the related property isdepreciated.  AFUDC, resulting in partfrom these projects, increased by approximately $2.9 million, or 6.8 percent,for the twelve months of 2009 compared with the same period in 2008.  NSP-Minnesota’s overall increase in AFUDC isdue to the Monticello Extended Power Uprate Project and various nuclearprojects.

 

***Interest Charges****—* Interestcharges decreased by approximately $3.6 million, or 1.8 percent, for 2009,compared with 2008.  The decrease was dueto lower interest rates on short-term debt.

 

***Income Taxes —***Income taxexpense decreased by $3.1 million for 2009, compared with 2008.  Theeffective tax rate was 37.3 percent for 2009, compared with 38.5 percent for2008.  The decrease in income tax expense and the lowereffective tax rate for 2009 were primarily due to reduced state unitary taxexpense in 2009.  If state unitary taxexpense in 2008 would have been consistent with 2009, the effective tax ratefor 2008 would have been 37.0 percent.

 

Theeffective tax rates for 2009 and 2008 differ from their statutory federalincome tax rates, primarily due to state income tax expense partially offset bytax credits recognized and tax benefit from plant related regulatorydifferences.   See Note 7 to theconsolidated financial statements.

 

**Item7A — Quantitative and Qualitative Disclosures About Market Risk**

** **

**Derivatives, Risk Managementand Market Risk**

** **

In the normal course ofbusiness, NSP-Minnesota is exposed to a variety of market risks.  Market risk is the potential loss or gainthat may occur as a result of changes in the market or fair value of aparticular instrument or commodity.  Allfinancial and commodity-related instruments, including derivatives, are subjectto market risk.  Market risks associatedwith derivatives are discussed in further detail in Note 10 to the consolidatedfinancial statements.

 

NSP-Minnesota is exposedto the impact of changes in price for energy and energy related products, whichis partially mitigated by NSP-Minnesota’s use of commodity derivatives.  Though no material non-performance riskcurrently exists with the counterparties to NSP-Minnesota’s commodityderivative contracts, distress in the financial markets may in the futureimpact that risk to the extent it impacts those counterparties.  Distress in the financial markets may alsoimpact the fair value of the debt and equity securities in the nucleardecommissioning trust fund and master pension trust, as well as NSP-Minnesota’sability to earn a return on short-term investments of excess cash.

 

***Commodity Price Risk —*** NSP-Minnesota is exposed to commodity price risk inits electric and natural gas operations. Commodity price risk is managed by entering into long- and short-termphysical purchase and sales contracts for electric capacity, energy andenergy-related products and for various fuels used in 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.

 

***Short-Term Wholesale and Commodity Trading Risk —***NSP Minnesota conducts various short-termwholesale and commodity trading activities, including the purchase and sale ofelectric capacity, energy and energy-related instruments.  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.

 

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Changes in the fair valueof commodity trading contracts before the impacts of margin-sharing mechanismsfor the years ended Dec. 31 were as follows:

 
| **(Thousands of Dollars)**                                             | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Fair  value of commodity trading net contract assets outstanding at Jan. 1  |       | $        | 3,615      |     | $          | 2,112 |   |
| Contracts  realized or settled during the period                                 |       | (11,681  | )          | (2,391   | )          |
| Commodity  trading contract additions and changes during period                  |       | 17,042   |       | 3,894    |       |
| Fair  value of commodity trading net contract assets outstanding at Dec. 31 |       | $        | 8,976      |     | $          | 3,615 |   |

 

At Dec. 31, 2009,the fair values by source for the commodity trading net asset balance were asfollows:

 
| ** **                           | ** ** | **Futures  / Forwards** | ** ** |
|--------------------------------------|------------|-------------------------|------------|
| ** **                           | ** ** | ** **              | ** ** | **Maturity** | ** ** | ** ** | ** ** | ** ** | ** ** | **Maturity** | ** ** | **Total  Futures/** | ** ** |
| ** **                           | ** ** | **Source  of**          | ** ** | **Less  Than** | ** ** | **Maturity** | ** ** | **Maturity** | ** ** | **Greater  Than** | ** ** | **Forwards** | ** ** |
| **(Thousands of Dollars)** | ** ** | **Fair  Value**         | ** ** | **1  Year** | ** ** | **1  to 3 Years** | ** ** | **4  to 5 Years** | ** ** | **5  Years** | ** ** | **Fair  Value** | ** ** |
| NSP-Minnesota                        |       | 1                       |       | $ | (319 | ) | $ | 2,577 |   | $ | — |   | $ | — |   | $ | 2,258 |   |
|                                 |       |  2                 |       | 2,338 |   | 4,220 |   | 160 |   | — |   | 6,718 |   |
|                                 |       |                    |       | $ | 2,019 |   | $ | 6,797 |   | $ | 160 |   | $ | — |   | $ | 8,976 |   |

 

----

1 — Prices activelyquoted or based on actively quoted prices.

 

2 — Prices based on models and other valuation methods. These representthe fair value of positions calculated using internal models when directly andindirectly quoted external prices or prices derived from external sources arenot available.  Internal modelsincorporate the use of options pricing and estimates of the present value ofcash flows based upon underlying contractual terms.  The models reflect management’s estimates,taking into account observable market prices, estimated market prices in theabsence of quoted market prices, the risk-free market discount rate, volatilityfactors, estimated correlations of commodity prices and contractualvolumes.  Market price uncertainty andother risks also are factored into the model.

 

Normal purchases and sales transactions, as defined by*ASC 815 Derivatives and Hedging*, 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.

 

At Dec. 31, 2009, a10 percent increase in market prices over the next 12 months for commoditytrading contracts would decrease pretax income from continuing operations byapproximately $0.8 million, whereas a 10 percent decrease would increasepretax income from continuing operations by approximately $0.8 million.

 

NSP-Minnesota’sshort-term wholesale and commodity trading operations measure the outstandingrisk exposure to price changes on transactions, contracts and obligations thathave been entered into, but not closed, using an industry standard methodologyknown as Value-at-Risk (VaR).  VaRexpresses the potential change in fair value on the outstanding transactions,contracts and obligations over a particular period of time under normal marketconditions.

 

TheVaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated ona consolidated basis, were as follows:

 
| ** **                 | ** ** | **Year  Ended**  | ** ** | ** **     | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** |
|----------------------------|------------|------------------|------------|----------------|------------|-------------|------------|------------|------------|------------|------------|
| **(Millions  of Dollars)** | ** ** | **Dec. 31** | ** ** | **VaR  Limit** | ** ** | **Average** | ** ** | **High**   | ** ** | **Low**    | ** ** |
| 2009                       |       | $                | 0.50       |           | $          | 5.00        |       | $          | 0.44       |       | $          | 2.02 |   | $ | 0.06 |   |
|                       |       |             |       |           |       |        |       |       |       |       |       |
| 2008                       |       | 0.30             |       | 5.00           |       | 0.30        |       | 1.14       |       | 0.01       |       |
|                            |            |                  |            |                |            |             |            |            |            |            |            |  |  |  |  |  |

 

***Interest Rate Risk —***NSP-Minnesota is subject to the risk of fluctuatinginterest 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.

 

At Dec. 31, 2009, a100-basis-point change in the benchmark rate on NSP-Minnesota’s variable ratedebt would have no impact pretax interest expense.  See Note 10 to the consolidatedfinancial statements for a discussion of NSP-Minnesota’s interest ratederivatives.

 

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NSP-Minnesota alsomaintains trust funds, as required by the NRC, to fund certain costs of nucleardecommissioning.  These trust funds aresubject to interest rate risk and equity price risk.  At Dec. 31, 2009, these funds wereinvested in a diversified portfolio of taxable and municipal fixed incomesecurities and equity securities.  Thesefunds may be used only for 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-Minnesota is also exposed to creditrisk.  Credit risk relates to the risk ofloss resulting from counterparties’ nonperformance on their contractualobligations.  NSP-Minnesota maintains creditpolicies intended to minimize overall credit risk and actively monitors thesepolicies to reflect changes and scope of operations.

 

At Dec. 31, 2009, a10 percent increase in prices would have resulted in an increase in creditexposure of $2.3 million, while a decrease of 10 percent in prices would haveresulted in an increase in credit exposure of $3.0 million.

 

NSP-Minnesota conductsstandard credit reviews for all counterparties. NSP-Minnesota employs additional credit risk control mechanisms whenappropriate, such as letters of credit, parental guarantees, standardizedmaster netting agreements and termination provisions that allow for offsettingof positive and negative exposures.  Thecredit exposure is monitored and, when necessary, the activity with a specificcounterparty is limited until credit enhancement is provided.  Distress in financial markets could increaseNSP-Minnesota’s credit risk.

 

**Fair Value Measurements**

** **

NSP-Minnesota adopted newaccounting and disclosure guidance on fair value measurements on Jan. 1,2008 which established a hierarchy for inputs used in measuring fair value, andgenerally requires that the most observable inputs available be used for fairvalue measurements.  Note 12 to theconsolidated financial statements describes the fair value hierarchy, anddiscloses the amounts of assets and liabilities measured at fair value thathave been assigned to Level 3.

 

***Commodity Derivatives***— NSP-Minnesota continuously monitors thecreditworthiness of the counterparties to its commodity derivative contractsand assesses each counterparty’s ability to perform on the transactions setforth in the contracts.  Given thisassessment and the typically short duration of these contracts, the impact ofdiscounting commodity derivative assets for counterparty credit risk was notmaterial to the fair value of commodity derivative assets at Dec. 31,2009.  Adjustments to fair value forcredit risk of commodity trading instruments are recorded in electricrevenues.  Credit risk adjustments forother commodity derivative instruments are deferred as OCI or regulatory assetsand liabilities.  The classification as aregulatory asset or liability is based on commission approved regulatoryrecovery mechanisms NSP-Minnesota also assesses the impact of its own creditrisk when determining the fair value of commodity derivative liabilities.  The impact of discounting commodityderivative liabilities for credit risk was immaterial to the fair value ofcommodity derivative liabilities at Dec. 31, 2009.

 

Commodity derivativesassets and liabilities assigned to Level 3 consist primarily of FTRs, as wellas forwards and options that are either long-term in nature or related tocommodities and delivery points with limited observability.  Level 3 commodity derivative assets andliabilities represent approximately 3 percent and 79 percent of total assetsand liabilities measured at fair value, respectively, at Dec. 31, 2009.

 

Determining the fairvalue of a FTR requires numerous management forecasts that vary in observability,including various forward commodity prices, retail and wholesale demand,generation and resulting transmission system congestion.  Given the limited observability of management’sforecasts for several of these inputs, these instruments have been assigned aLevel 3.  Level 3 commodity derivativesassets and liabilities include $23.6 million and $3.3 million of estimated fairvalues, respectively, for FTRs held at Dec. 31, 2009.

 

Determiningthe fair value of certain commodity forwards and options can require managementto make use of subjective forward price and volatility forecasts forcommodities and locations with limited observability, or subjective forecastswhich extend to periods beyond those readily observable on active exchanges orquoted by brokers.  When less observableforward price and volatility forecasts are significant to determining the valueof commodity forwards and options, these instruments are assigned to Level 3.  Level 3 commodity derivatives assets andliabilities include $17.8 million and $10.9 million of estimated fair values,respectively, for commodity forwards and options held at Dec. 31, 2009.

 

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***Nuclear Decommissioning Fund*** — Nuclear decommissioning fund assetsassigned to Level 3 consist of asset-backed and mortgage-backedsecurities.  To the extent appropriate,observable market inputs are utilized to estimate the fair value of thesesecurities, however, less observable and subjective risk-based adjustments toestimated yield and forecasted prepayments are often significant to thesevaluations.  Therefore, estimated fairvalues for all asset-backed and mortgage-backed securities totaling $93.1million in the nuclear decommissioning fund at Dec. 31, 2009(approximately 7 percent of total assets measured at fair value), are assignedto Level 3.  Realized and unrealizedgains and losses on nuclear decommissioning fund investments are deferred as acomponent of a nuclear decommissioning regulatory asset

 

**Item 8 — Financial Statements andSupplementary Data**

 

See Item 15 -1 in Part IV for an index offinancial statements included herein.

 

See Note 19 to the consolidated financialstatements for summarized quarterly financial data.

 

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**Management Report on Internal Controls Over Financial Reporting**

** **

The management ofNSP-Minnesota is responsible for establishing and maintaining adequate internalcontrol over financial reporting. NSP-Minnesota’s internal control system was designed to providereasonable assurance to the company’s management and board of directorsregarding the preparation and fair presentation of published financialstatements.

 

All internal controlsystems, no matter how well designed, have inherent limitations.  Therefore, even those systems determined tobe effective can provide only reasonable assurance with respect to financialstatement preparation and presentation.

 

NSP-Minnesota managementassessed the effectiveness of the company’s internal control over financialreporting as of Dec. 31, 2009.  Inmaking this assessment, it used the criteria set forth by the Committee ofSponsoring Organizations of the Treadway Commission (COSO) in *Internal Control — Integrated Framework. *Based on our assessment, webelieve that, as of Dec. 31, 2009, the company’s internal control overfinancial reporting is effective based on those criteria.

 

NSP-Minnesota’sindependent auditors have issued an audit report on the company’s internalcontrol over financial reporting.  Theirreport appears herein.

 

 
| /S/  JUDY M. POFERL                     |     | /S/  DAVID M. SPARBY                          |
|-----------------------------------------|----------|-----------------------------------------------|
| Judy  M. Poferl                         |     | David  M. Sparby                              |
| *President and Chief Executive Officer* | * * | *Vice  President and Chief Financial Officer* |
| March 1,  2010                     |     | March 1,  2010                           |

 

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**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

Board of Directors and Stockholder

Northern States Power Company — Minnesota

 

We have auditedthe accompanying consolidated balance sheets and consolidated statements ofcapitalization of Northern States Power Company, a Minnesota Corporation, andsubsidiaries (the “Company”) as of December 31, 2009 and 2008, and therelated consolidated statements of income, common stockholder’s equity andcomprehensive income, and cash flows for each of the three years in the periodended December 31, 2009.  Our audits also included the financialstatement schedule listed in the Index at Item 15.  These financial statements and financialstatement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements andfinancial statement schedule based on our audits.

 

We conducted ouraudits in accordance with the standards of the Public Company AccountingOversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well as evaluatingthe overall financial statement presentation.  We believe that our auditsprovide a reasonable basis for our opinion.

 

In our opinion,such consolidated financial statements present fairly, in all materialrespects, the financial position of Northern States Power Company, a Minnesotacorporation, and subsidiaries as of December 31, 2009 and 2008, and theresults of their operations and their cash flows for each of the three years inthe period ended December 31, 2009, in conformity with accounting principlesgenerally accepted in the United States of America.  Also, in our opinion,such financial statement schedule, when considered in relation to the basicconsolidated financial statements taken as a whole, presents fairly, in allmaterial respects, the information set forth therein.

 

We have alsoaudited, in accordance with the standards of the Public Company AccountingOversight Board (United States), the Company’s internal control over financialreporting as of December 31, 2009, based on the criteria established in *Internal Control—Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commissionand our report dated March 1, 2010 expressed an unqualified opinion on theCompany’s internal control over financial reporting.

 

 
| /S/  DELOITTE & TOUCHE LLP |   |
|-------------------------------------|--------|
| Minneapolis,  Minnesota             |   |
| March 1,  2010                 |   |

 

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**REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING****FIRM**

 

Board of Directors and Stockholder

Northern Power States Company, a Minnesota corporation

 

We have audited the internal control over financialreporting of Northern Power States Company, a Minnesota corporation, andsubsidiaries (the “Company”) as of December 31, 2009, based on criteriaestablished *Internal Control — IntegratedFramework*issued by the Committee of Sponsoring Organizations of theTreadway Commission.  The Company’s management is responsible formaintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financial reporting,included in the accompanying Management Report on Internal Controls overFinancial Reporting.  Our responsibilityis to express an opinion on the Company’s internal control over financialreporting based on our audit.

 

We conducted our audit in accordance with thestandards of the Public Company Accounting Oversight Board (UnitedStates).  Those standards require that we plan and perform the audit toobtain reasonable assurance about whether effective internal control overfinancial reporting was maintained in all material respects.  Our auditincluded obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, testing andevaluating the design and operating effectiveness of internal control based onthe assessed risk, and performing such other procedures as we considerednecessary in the circumstances.  We believe that our audit provides areasonable basis for our opinion.

 

A company’s internal control over financialreporting is a process designed by, or under the supervision of, the company’sprincipal executive and principal financial officers, or persons performingsimilar functions, and effected by the company’s board of directors,management, and other personnel to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accountingprinciples.  A company’s internal control over financial reportingincludes those policies and procedures that (1) pertain to the maintenanceof records that, in reasonable detail, accurately and fairly reflect thetransactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding preventionor timely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

 

Because of the inherent limitations of internalcontrol over financial reporting, including the possibility of collusion orimproper management override of controls, material misstatements due to erroror fraud may not be prevented or detected on a timely basis.  Also,projections of any evaluation of the effectiveness of the internal control overfinancial reporting to future periods are subject to the risk that the controlsmay become inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

 

In our opinion, the Company maintained, inall material respects, effective internal control over financial reporting asof December 31, 2009, based on the criteria established in *Internal Control — Integrated Framework*issuedby the Committee of Sponsoring Organizations of the Treadway Commission.

 

We have also audited, in accordance with thestandards of the Public Company Accounting Oversight Board (United States) theconsolidated financial statements and financial statement schedule as of andfor the year ended December 31, 2009 of the Company and our report dated March 1,2010 expressed an unqualified opinion on those financial statements andfinancial statement schedule.

 

 
| /S/  DELOITTE & TOUCHE LLP |   |
|-------------------------------------|--------|
| Minneapolis,  Minnesota             |   |
| March 1,  2010                 |   |

 

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**NSP-MINNESOTA AND SUBSIDIARIES********CONSOLIDATED STATEMENTS OF INCOME*******(amounts in thousands of dollars)*

 
| ** **                                                                                           | ** ** | **Year  Ended Dec. 31,** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|-------------------------------|------------|
| ** **                                                                                           | ** ** | **2009**                      | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Operating revenues**                                                                               |       |                          |       |   |   |   |   |
| Electric                                                                                             |       | $                             | 3,407,273  |   | $ | 3,584,109 |   | $ | 3,476,674 |   |
| Natural  gas                                                                                         |       | 640,323                       |       | 889,958 |   | 776,971 |   |
| Other                                                                                                |       | 19,093                        |       | 19,569 |   | 18,569 |   |
| Total  operating revenues                                                                            |       | 4,066,689                     |       | 4,493,636 |   | 4,272,214 |   |
|                                                                                                 |       |                          |       |   |   |   |   |
| **Operating expenses**                                                                               |       |                          |       |   |   |   |   |
| Electric  fuel and purchased power                                                                   |       | 1,411,877                     |       | 1,680,795 |   | 1,576,901 |   |
| Cost  of natural gas sold and transported                                                            |       | 464,043                       |       | 701,687 |   | 602,617 |   |
| Cost  of sales — other                                                                          |       | 11,076                        |       | 10,034 |   | 9,212 |   |
| Other  operating and maintenance expenses                                                            |       | 968,370                       |       | 877,497 |   | 884,554 |   |
| Conservation  program expenses                                                                       |       | 59,244                        |       | 65,876 |   | 72,912 |   |
| Depreciation  and amortization                                                                       |       | 389,367                       |       | 412,362 |   | 405,569 |   |
| Taxes  (other than income taxes)                                                                     |       | 147,193                       |       | 138,184 |   | 130,094 |   |
| Total  operating expenses                                                                            |       | 3,451,170                     |       | 3,886,435 |   | 3,681,859 |   |
|                                                                                                 |       |                          |       |   |   |   |   |
| **Operating income**                                                                                 |       | 615,519                       |       | 607,201 |   | 590,355 |   |
|                                                                                                 |       |                          |       |   |   |   |   |
| Other  income, net                                                                                   |       | 1,572                         |       | 10,895 |   | 6,105 |   |
| Allowance  for funds used during construction — equity                                          |       | 28,848                        |       | 26,510 |   | 21,826 |   |
|                                                                                                 |       |                          |       |   |   |   |   |
| **Interest charges and financing costs**                                                             |       |                          |       |   |   |   |   |
| Interest  charges — includes other financing costs of $5,778, $5,834, and $5,271,  respectively |       | 194,808                       |       | 198,369 |   | 186,293 |   |
| Allowance  for funds used during construction — debt                                            |       | (17,760                       | )          | (17,140 | ) | (17,334 | ) |
| Total  interest charges and financing costs                                                          |       | 177,048                       |       | 181,229 |   | 168,959 |   |
|                                                                                                 |       |                          |       |   |   |   |   |
| **Income before income taxes**                                                                       |       | 468,891                       |       | 463,377 |   | 449,327 |   |
| Income  taxes                                                                                        |       | 175,121                       |       | 178,236 |   | 182,025 |   |
| **Net income**                                                                                       |       | $                             | 293,770    |   | $ | 285,141 |   | $ | 267,302 |   |

 

See Notes toConsolidated Financial Statements

 

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**NSP-MINNESOTA AND SUBSIDIARIES****CONSOLIDATED STATEMENTS OF CASH FLOWS*******(amounts in thousands of dollars)*

 
| ** **                                                                     | ** ** | **Year Ended Dec. 31,** | ** ** |
|--------------------------------------------------------------------------------|------------|------------------------------|------------|
| ** **                                                                     | ** ** | **2009**                     | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Operating activities**                                                       | ** ** | ** **                   | ** ** | ** ** |   |   |   |
| Net income                                                                     |       | $                            | 293,770    |   | $ | 285,141 |   | $ | 267,302 |   |
| Adjustments to reconcile net income to cash  provided by operating activities: |       |                         |       |   |   |   |   |
| Depreciation and amortization                                                  |       | 394,712                      |       | 407,343 |   | 415,651 |   |
| Nuclear fuel amortization                                                      |       | 80,104                       |       | 64,203 |   | 53,453 |   |
| Deferred income taxes                                                          |       | 177,347                      |       | 140,701 |   | 172,004 |   |
| Amortization of investment tax credits                                         |       | (3,120                       | )          | (3,503 | ) | (3,897 | ) |
| Allowance for equity funds used during construction                            |       | (28,848                      | )          | (26,510 | ) | (21,826 | ) |
| Provision for bad debts                                                        |       | 19,408                       |       | 25,506 |   | 23,336 |   |
| Net realized and unrealized hedging and derivative  transactions               |       | (4,960                       | )          | (4,484 | ) | (5 | ) |
| Changes in operating assets and liabilities                                    |       |                         |       |   |   |   |   |
| Accounts receivable                                                            |       | 74,818                       |       | 21,928 |   | (84,250 | ) |
| Accrued unbilled revenues                                                      |       | 19,113                       |       | (22,050 | ) | (6,367 | ) |
| Inventories                                                                    |       | 89,984                       |       | (75,265 | ) | (52,226 | ) |
| Recoverable purchased natural gas and electric  energy costs                   |       | (3,823                       | )          | 10,252 |   | (19,184 | ) |
| Other current assets                                                           |       | (13,589                      | )          | 11,394 |   | (2,790 | ) |
| Accounts payable                                                               |       | 39,229                       |       | 14,557 |   | (66,920 | ) |
| Net regulatory assets and liabilities                                          |       | (67,056                      | )          | (23,128 | ) | (14,661 | ) |
| Other current liabilities                                                      |       | 19,066                       |       | (13,348 | ) | 7,624 |   |
| Change in other noncurrent assets                                              |       | 44                           |       | 15,781 |   | 17,719 |   |
| Change in other noncurrent liabilities                                         |       | (25,122                      | )          | (37,139 | ) | (38,139 | ) |
| Net cash provided by operating activities                                      |       | 1,061,077                    |       | 791,379 |   | 646,824 |   |
|                                                                           |       |                         |       |   |   |   |   |
| **Investing activities**                                                       |       |                         |       |   |   |   |   |
| Utility capital/construction expenditures                                      |       | (844,556                     | )          | (1,015,827 | ) | (1,060,796 | ) |
| Allowance for equity funds used during construction                            |       | 28,848                       |       | 26,510 |   | 21,826 |   |
| Purchase of investments in external decommissioning  fund                      |       | (1,644,278                   | )          | (957,752 | ) | (712,462 | ) |
| Proceeds from sale of investments in external  decommissioning fund            |       | 1,664,957                    |       | 914,514 |   | 669,070 |   |
| Cash obtained from consolidation of NMC                                        |       | —                       |       | — |   | 38,950 |   |
| Investments in utility money pool arrangement                                  |       | (132,500                     | )          | (943,400 | ) | (423,500 | ) |
| Repayments from utility money pool arrangement                                 |       | 125,500                      |       | 943,400 |   | 423,500 |   |
| Advances to affiliate                                                          |       | (62,500                      | )          | (337,600 | ) | (371,250 | ) |
| Advances from affiliate                                                        |       | 47,000                       |       | 396,200 |   | 342,950 |   |
| Other investments                                                              |       | (6,415                       | )          | 10,501 |   | 5,224 |   |
| Net cash used in investing activities                                          |       | (823,944                     | )          | (963,454 | ) | (1,066,488 | ) |
|                                                                           |       |                         |       |   |   |   |   |
| **Financing activities**                                                       |       |                         |       |   |   |   |   |
| (Repayment of) proceeds from short-term borrowings,  net                       |       | (65,000                      | )          | (276,500 | ) | 252,500 |   |
| Borrowings under utility money pool arrangement                                |       | 601,700                      |       | 433,300 |   | 937,600 |   |
| Repayments under utility money pool arrangement                                |       | (665,200                     | )          | (464,900 | ) | (842,500 | ) |
| Proceeds from issuance of long-term debt                                       |       | 295,340                      |       | 493,751 |   | 343,670 |   |
| Repayment of long-term debt, including  reacquisition premiums                 |       | (250,041                     | )          | (10 | ) | (186,689 | ) |
| Borrowings under 5-year unsecured credit facility                              |       | —                       |       | — |   | 200,000 |   |
| Repayments under 5-year unsecured credit facility                              |       | —                       |       | — |   | (200,000 | ) |
| Capital contributions from parent                                              |       | 112,736                      |       | 203,863 |   | 150,514 |   |
| Dividends paid to parent                                                       |       | (232,708                     | )          | (229,712 | ) | (226,824 | ) |
| Net cash (used in) provided by financing activities                            |       | (203,173                     | )          | 159,792 |   | 428,271 |   |
|                                                                           |       |                         |       |   |   |   |   |
| Net increase (decrease) in cash and cash  equivalents                          |       | 33,960                       |       | (12,283 | ) | 8,607 |   |
| Cash and cash equivalents at beginning of period                               |       | 12,343                       |       | 24,626 |   | 16,019 |   |
| Cash and cash equivalents at end of period                                     |       | $                            | 46,303     |   | $ | 12,343 |   | $ | 24,626 |   |
|                                                                           |       |                         |       |   |   |   |   |
| Supplemental disclosure of cash flow information:                              |       |                         |       |   |   |   |   |
| Cash paid for interest (net of amounts capitalized)                            |       | $                            | (178,017   | ) | $ | (170,168 | ) | $ | (151,409 | ) |
| Cash received (paid) for income taxes, net                                     |       | 24,719                       |       | (27,292 | ) | (50,016 | ) |
| Supplemental disclosure of non-cash investing  transactions:                   |       |                         |       |   |   |   |   |
| Property, plant and equipment additions in accounts  payable                   |       | $                            | 34,172     |   | $ | 24,109 |   | $ | 15,670 |   |

 

See Notes to Consolidated Financial Statements

 

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**NSP-MINNESOTAAND SUBSIDIARIES**

**CONSOLIDATED BALANCE SHEETS**

*(amounts in thousands of dollars)*

 
| ** **                                                                                        | ** ** | **Dec. 31,** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|-------------------|------------|
| ** **                                                                                        | ** ** | **2009**          | ** ** | **2008** | ** ** |
| **Assets**                                                                                        |       |              |       |   |   |
| Current assets                                                                                    |       |              |       |   |   |
| Cash and cash equivalents                                                                         |       | $                 | 46,303     |   | $ | 12,343 |   |
| Notes receivable from affiliates                                                                  |       | 15,500            |       | — |   |
| Investments in utility money pool arrangement                                                     |       | 7,000             |       | — |   |
| Accounts receivable, net                                                                          |       | 300,103           |       | 413,156 |   |
| Accounts receivable from affiliates                                                               |       | 31,245            |       | 12,418 |   |
| Accrued unbilled revenues                                                                         |       | 229,338           |       | 248,451 |   |
| Inventories                                                                                       |       | 255,919           |       | 345,903 |   |
| Recoverable purchased natural gas and energy costs                                                |       | 30,428            |       | 26,605 |   |
| Derivative instruments valuation                                                                  |       | 59,482            |       | 70,252 |   |
| Prepayments and other                                                                             |       | 81,688            |       | 48,493 |   |
| Total current assets                                                                              |       | 1,057,006         |       | 1,177,621 |   |
|                                                                                              |       |              |       |   |   |
| Property, plant and equipment, net                                                                |       | 6,958,656         |       | 6,804,794 |   |
|                                                                                              |       |              |       |   |   |
| Other assets                                                                                      |       |              |       |   |   |
| Nuclear decommissioning fund and other investments                                                |       | 1,264,687         |       | 1,084,827 |   |
| Regulatory assets                                                                                 |       | 797,663           |       | 828,712 |   |
| Derivative instruments valuation                                                                  |       | 117,216           |       | 129,605 |   |
| Other                                                                                             |       | 23,581            |       | 21,266 |   |
| Total other assets                                                                                |       | 2,203,147         |       | 2,064,410 |   |
| Total assets                                                                                      |       | $                 | 10,218,809 |   | $ | 10,046,825 |   |
|                                                                                              |       |              |       |   |   |
| **Liabilities and Equity**                                                                        |       |              |       |   |   |
| Current liabilities                                                                               |       |              |       |   |   |
| Current portion of long-term debt                                                                 |       | $                 | 175,037    |   | $ | 250,060 |   |
| Short-term debt                                                                                   |       | —            |       | 65,000 |   |
| Borrowings under utility money pool arrangement                                                   |       | —            |       | 63,500 |   |
| Accounts payable                                                                                  |       | 407,500           |       | 389,676 |   |
| Accounts payable to affiliates                                                                    |       | 83,759            |       | 52,291 |   |
| Taxes accrued                                                                                     |       | 125,650           |       | 121,163 |   |
| Accrued interest                                                                                  |       | 62,780            |       | 68,009 |   |
| Dividends payable to parent                                                                       |       | 58,415            |       | 58,414 |   |
| Derivative instruments valuation                                                                  |       | 24,661            |       | 39,816 |   |
| Other                                                                                             |       | 59,353            |       | 50,696 |   |
| Total current liabilities                                                                         |       | 997,155           |       | 1,158,625 |   |
|                                                                                              |       |              |       |   |   |
| Deferred credits and other liabilities                                                            |       |              |       |   |   |
| Deferred income taxes                                                                             |       | 1,234,366         |       | 987,050 |   |
| Deferred investment tax credits                                                                   |       | 37,134            |       | 40,254 |   |
| Asset retirement obligations                                                                      |       | 797,476           |       | 1,055,689 |   |
| Regulatory liabilities                                                                            |       | 469,769           |       | 459,880 |   |
| Pension and employee benefit obligations                                                          |       | 310,066           |       | 269,537 |   |
| Derivative instruments valuation                                                                  |       | 209,528           |       | 219,421 |   |
| Other                                                                                             |       | 83,965            |       | 77,775 |   |
| Total deferred credits and other liabilities                                                      |       | 3,142,304         |       | 3,109,606 |   |
|                                                                                              |       |              |       |   |   |
| Commitments and contingent liabilities                                                            |       |              |       |   |   |
| Capitalization                                                                                    |       |              |       |   |   |
| Long-term debt                                                                                    |       | 2,838,141         |       | 2,712,689 |   |
| Common stock — authorized 5,000,000 shares of $0.01  par value; outstanding 1,000,000 shares |       | 10                |       | 10 |   |
| Additional paid-in capital                                                                        |       | 2,028,593         |       | 1,915,857 |   |
| Retained earnings                                                                                 |       | 1,210,894         |       | 1,149,833 |   |
| Accumulated other comprehensive income                                                            |       | 1,712             |       | 205 |   |
| Total common stockholder’s equity                                                            |       | 3,241,209         |       | 3,065,905 |   |
| Total liabilities and equity                                                                      |       | $                 | 10,218,809 |   | $ | 10,046,825 |   |

 

See Notes to Consolidated Financial Statements

 

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**NSP-MINNESOTA AND SUBSIDIARIES****CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’SEQUITY****AND COMPREHENSIVE INCOME***(amounts in thousands of dollars)*

 
| ** **                                                                                             | ** ** | **Common Stock** | ** ** | ** ** | ** ** | **Accumulated**  | ** ** | **Total**    | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|------------|------------|------------------|------------|--------------|------------|
| ** **                                                                                             | ** ** | ** **            | ** ** | ** ** | ** ** | **Additional**   | ** ** | ** **   | ** ** | **Other** | ** ** | **Common** | ** ** |
| ** **                                                                                             | ** ** | ** **            | ** ** | **Par**    | ** ** | **Paid In** | ** ** | **Retained** | ** ** | **Comprehensive** | ** ** | **Stockholder’s** | ** ** |
| ** **                                                                                             | ** ** | **Shares**            | ** ** | **Value**  | ** ** | **Capital**      | ** ** | **Earnings** | ** ** | **Income (Loss)** | ** ** | **Equity** | ** ** |
| **Balance at Dec. 31, 2006**                                                                      |       | 1,000,000             |       | $          | 10         |             | $          | 1,561,480    |       | $ | 1,055,983 |   | $ | 6,199 |   | $ | 2,623,672 |   |
| Adoption of new accounting guidance for uncertainty  in income taxes                                   |       |                  |       |       |       |             |       | 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 |   |
| Adoption of new accounting guidance for endorsement  split-dollar life insurance, net of tax of $(401) |       |                  |       |       |       |             |       | (633         | )          |   |   | (633 | ) |
| Net income                                                                                             |       |                  |       |       |       |             |       | 285,141      |       |   |   | 285,141 |   |
| Changes in unrecognized amounts of pension and retiree  medical benefits, net of tax of $228           |       |                  |       |       |       |             |       |         |       | 331 |   | 331 |   |
| Net derivative instrument fair value changes during  the period, net of tax of $(3,901)                |       |                  |       |       |       |             |       |         |       | (5,651 | ) | (5,651 | ) |
| Unrealized loss - marketable securities, net of tax  of $(513)                                         |       |                  |       |       |       |             |       |         |       | (743 | ) | (743 | ) |
| Comprehensive income for 2008                                                                          |       |                  |       |       |       |             |       |         |       |   |   | 279,078 |   |
| Common dividends declared to parent                                                                    |       |                  |       |       |       |             |       | (232,032     | )          |   |   | (232,032 | ) |
| Contribution of capital by parent                                                                      |       |                  |       |       |       | 203,863          |       |         |       |   |   | 203,863 |   |
| **Balance at Dec. 31, 2008**                                                                      |       | 1,000,000             |       | $          | 10         |             | $          | 1,915,857    |       | $ | 1,149,833 |   | $ | 205 |   | $ | 3,065,905 |   |
| Net income                                                                                             |       |                  |       |       |       |             |       | 293,770      |       |   |   | 293,770 |   |
| Changes in unrecognized amounts of pension and  retiree medical benefits, net of tax of $143           |       |                  |       |       |       |             |       |         |       | 208 |   | 208 |   |
| Net derivative instrument fair value changes during  the period, net of tax of $615                    |       |                  |       |       |       |             |       |         |       | 888 |   | 888 |   |
| Unrealized loss - marketable securities, net of tax  of $284                                           |       |                  |       |       |       |             |       |         |       | 411 |   | 411 |   |
| Comprehensive income for 2009                                                                          |       |                  |       |       |       |             |       |         |       |   |   | 295,277 |   |
| Common dividends declared to parent                                                                    |       |                  |       |       |       |             |       | (232,709     | )          |   |   | (232,709 | ) |
| Contribution of capital by parent                                                                      |       |                  |       |       |       | 112,736          |       |         |       |   |   | 112,736 |   |
| **Balance at Dec. 31, 2009**                                                                      |       | 1,000,000             |       | $          | 10         |             | $          | 2,028,593    |       | $ | 1,210,894 |   | $ | 1,712 |   | $ | 3,241,209 |   |

 

See Notes to Consolidated Financial Statements

 

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**NSP-MINNESOTA AND SUBSIDIARIES********CONSOLIDATED STATEMENTS OF CAPITALIZATION*******(amounts in thousands of dollars)*

 
| ** **                                                                                                          | ** ** | **Dec. 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|
| ** **                                                                                                          | ** ** | **2009**          | ** ** | **2008** | ** ** |
| **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,  2018, 5.25%                                                                                          |       | 500,000           |       | 500,000 |   |
| March 1,  2019, 8.5% (a)                                                                                       |       | 27,900            |       | 27,900 |   |
| Sept.  1, 2019, 8.5% (a)                                                                                            |       | 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% (a)                                                                                       |       | 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           |       | 350,000 |   |
| Nov. 1,  2039, 5.35%                                                                                           |       | 300,000           |       | — |   |
| Senior  Notes, due Aug. 1, 2009, 6.875%                                                                        |       | —            |       | 250,000 |   |
| Other                                                                                                               |       | 66                |       | 107 |   |
| Unamortized  discount                                                                                               |       | (8,788            | )          | (9,258 | ) |
| Total                                                                                                               |       | 3,013,178         |       | 2,962,749 |   |
| Less  current maturities                                                                                            |       | 175,037           |       | 250,060 |   |
| Total  long-term debt                                                                                               |       | $                 | 2,838,141  |   | $ | 2,712,689 |   |
|                                                                                                                |       |              |       |   |   |
| **Common Stockholder’s Equity**                                                                                |       |              |       |   |   |
| Common  stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000  shares in 2009 and 2008 |       | $                 | 10         |   | $ | 10 |   |
| Additional  paid in capital                                                                                         |       | 2,028,593         |       | 1,915,857 |   |
| Retained  earnings                                                                                                  |       | 1,210,894         |       | 1,149,833 |   |
| Accumulated  other comprehensive income                                                                             |       | 1,712             |       | 205 |   |
| Total  common stockholder’s equity                                                                             |       | $                 | 3,241,209  |   | $ | 3,065,905 |   |

 

----

(a)  Pollution control financing

 

See Notes to Consolidated Financial Statements

 

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**NOTES TOCONSOLIDATED 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 of NSP-Minnesota’s accounting recordsconform to the FERC uniform system of accounts or to systems required byvarious state regulatory commissions, which are the same in all materialrespects.

 

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

 

In2007, NSP-Minnesota obtained 100 percent ownership in NMC.  Accordingly, the results of operations of NMCand the estimated fair value of assets and liabilities were included inNSP-Minnesota’s consolidated financial statements from the transactiondate.  NSP-Minnesota has reintegrated itsnuclear operations into its generation operations.  The NRC approved the transfer of the nuclearoperating licenses from NMC to NSP-Minnesota on Sept. 22, 2008.

 

***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 energy sales to individual customersis based on the reading of their meter, which occurs on a systematic basisthroughout the month.  At the end of eachmonth, amounts of energy delivered to customers since the date of the lastmeter reading are estimated and the corresponding unbilled revenue isestimated.  NSP-Minnesota presents itsrevenue net of any excise or other fiduciary-type taxes or fees.

 

NSP-Minnesota has variousrate-adjustment mechanisms in place that currently provide for the recovery ofnatural gas and electric fuel costs, as well as purchased energy costs.  These cost-adjustment tariffs may increase ordecrease the level of costs recovered through base rates and are revisedperiodically for any difference between the total amount collected under theclauses and the recoverable costs incurred. Where applicable, under governing state regulatory commission rateorders, fuel costs over-recoveries (the excess of fuel revenue billed tocustomers over fuel costs incurred) are deferred as current regulatoryliabilities and under-recoveries (the excess of fuel costs incurred over fuelrevenues billed to customers) are deferred as current regulatory assets.  A summary of significant rate adjustmentmechanisms follows:

 

·                  NSP-Minnesota’s rates include acost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowingrecovery of the respective costs, which are trued-up on a two-month and annualbasis, respectively.  The electriccost-of-fuel-and-purchased-energy mechanism in North Dakota also provides asharing among shareholders and customers of certain margins on short-termwholesale and commodity trading. NSPMinnesota’s rates include a rider for cost recovery of DSM program costs aswell as recovery of a financial incentive for meeting energy savings goals.

 

·                     NSP-Minnesota operates undervarious service quality standards, which could require customer refunds ifcertain criteria are not met. NSP-Minnesota’s rates in Minnesota include monthly adjustments for therecovery of conservation and energy-management program costs, which arereviewed annually.  NSP-Minnesota isallowed to recover certain costs associated with new transmission facilities todeliver renewable energy resources and certain costs associated with productionfacilities through rate riders.

 

·                     NSP-Minnesota sells firmpower and energy in wholesale markets, which are regulated by the FERC.  Certain of these rates include monthlywholesale fuel cost-recovery mechanisms through prices that are indexed to NSP-Minnesotaretail rates, including the monthly cost of fuel and purchased energy recoverymechanism.

 

***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.  Commoditytrading activities are not associated with energy produced from NSP-Minnesota’sgeneration assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded atfair market value in accordance with *ASC 815 Derivatives andHedging.* In addition,commodity trading results include the impact of all margin-sharing mechanisms.  For more information, see Note 10 to theconsolidated financial statements.

 

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***Fair Value Measurements******—*********NSP-Minnesota presents cashequivalents, interest rate derivatives, commodity derivatives and nucleardecommissioning fund assets at estimated fair values in its consolidatedfinancial statements.  Cash equivalents arerecorded at cost plus accrued interest to approximate fair value.  Changes in the observed trading prices andliquidity of cash equivalents, including commercial paper and money marketfunds, are also monitored as additional support for determining fair value andlosses are recorded in earnings if fair value falls below recorded cost.  For interest rate derivatives, quoted pricesbased primarily on observable market interest rate curves are used as a primaryinput to establish fair value.  Forcommodity derivatives, the most observable inputs available are generally usedto determine the fair value of each contract. In the absence of a quoted price for an identical contract in an activemarket, NSP-Minnesota may use quoted prices for similar contracts, orinternally prepared valuation models to determine fair value.  For the nuclear decommissioning fund,published trading data and pricing models, generally using the most observableinputs available, are utilized to estimate fair value for each class of security.

 

***Types of and Accounting for DerivativeInstruments****—*NSP-Minnesota usesderivative instruments in connection with its interest rate, utility commodityprice, vehicle fuel price, short-term wholesale and commodity tradingactivities, including forward contracts, futures, swaps and options.  All derivative instruments not designated andqualifying for the normal purchases and normal sales exception, as defined by *ASC 815 Derivatives and Hedging*, are recorded on theconsolidated balance sheets at fair value as derivative instruments valuation.  This includes certain instruments used tomitigate market risk for the utility operations and all instruments related tothe commodity trading operations.  Theclassification of changes in fair value for those derivative instruments isdependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivativeinstruments not designated in a qualifying hedging relationship are reflectedin current earnings or as a regulatory asset or liability.  The classification is dependent on theapplicability of specific regulation.

 

Gainsor losses on hedging transactions for the sale 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; hedging transactions for vehicle fuel costs arerecorded as a component of capital projects or O&M costs; and interest ratehedging transactions are recorded as a component of interest expense.  NSP-Minnesota is allowed to recover inelectric or natural gas rates the costs of certain financial instrumentspurchased to reduce commodity cost volatility.

 

*Cash Flow Hedges* — Qualifying hedgingrelationships are designated as a hedge of a forecasted transaction or futurecash flow (cash flow hedge).  Theaccounting for derivatives requires that the hedging relationship be highlyeffective and that a company formally designate a hedging relationship to applyhedge accounting.  NSP-Minnesota formallydocuments all hedging relationships in accordance with this guidance.  The documentation includes, among otherfactors, the identification of the hedging instrument and the hedged transaction,as well as the risk management objectives and strategies for undertaking thehedging transaction.  In addition, atinception and on a quarterly basis, NSP-Minnesota formally assesses whether thederivative instruments being used are highly effective in offsetting changes inthe 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, or deferred as a regulatoryasset or liability based on recovery mechanisms until earnings are affected bythe hedged transaction.  NSP-Minnesotadiscontinues hedge accounting prospectively when it has determined that aderivative no longer qualifies as an effective hedge, or when it is no longerprobable that the hedged forecasted transaction will occur.  To test the effectiveness of hedges, ahypothetical hedge is used to mirror all the critical terms of the hedgedtransaction and the dollar-offset method is utilized to assess theeffectiveness of the actual hedge at inception and on an ongoing basis.  Gains and losses related to discontinuedhedges that were previously deferred in OCI or deferred as regulatory assets orliabilities will remain deferred until the hedged transaction is reflected inearnings, unless it is probable that the hedged forecasted transaction will notoccur, in which case, associated deferred amounts are immediately recognized incurrent earnings.

 

*Normal Purchases and Normal Sales* —NSP-Minnesota enters into contracts for the purchase and sale of commoditiesfor use in their business operations.  *ASC 815 Derivatives and Hedging* requires a company toevaluate these contracts to determine whether the contracts arederivatives.  Certain contracts that meetthe definition of a derivative may be exempted from derivative accounting asnormal purchases or normal sales.

 

NSP-Minnesotaevaluates all of its contracts at inception to determine if they arederivatives and if they meet the normal purchases and normal sales designationrequirements.  None of the contractsentered into within the commodity trading operations qualify for a normalpurchases and normal sales designation.

 

Forfurther discussion of NSP-Minnesota’s risk management and derivativeactivities, see Note 10 to the consolidated financial statements.

 

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***Property, Plant and Equipment and Depreciation*****— Property, plant and equipment is stated at original cost.  The cost of plant includes direct labor andmaterials, contracted work, overhead costs and applicable interestexpense.  The cost of plant retired ischarged to accumulated depreciation and amortization.  Regulatory obligations to incur removal costsare recorded as regulatory liabilities. Significant additions or improvements extending asset lives arecapitalized, while repairs and maintenance costs are charged to expense asincurred.  Maintenance and replacement ofitems determined to be less than units of property are charged to operatingexpenses as incurred.  Planned majormaintenance activities are charged to operating expense unless the costrepresents the acquisition of an additional unit of property or the replacementof an existing unit of property. Property, plant and equipment also includes costs associated withproperty held for future use.

 

NSP-Minnesota recordsdepreciation expense related to its plant by using the straight-line methodover the plant’s useful life.  Actuarialand semi-actuarial life studies are performed on a periodic basis and submittedto the state and federal commissions for review.  Upon acceptance by the various commissions,the resulting lives and net salvage rates are used to calculate depreciation. Depreciationexpense, expressed as a percentage of average depreciable property, for theyears ended Dec. 31, 2009, 2008 and 2007 was 3.2, 3.6 and 3.6 percent,respectively.

 

***AFUDC*****— AFUDC represents the costof capital used to finance utility construction activity.  AFUDC is computed by applying a compositepretax rate to qualified construction work in progress.  The amount of AFUDC capitalized as a utilityconstruction cost is credited to nonoperating income (for equity capital) andinterest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base forestablishing utility service rates.  Inaddition to construction-related amounts, AFUDC also is recorded to reflectreturns on capital used to finance conservation programs in Minnesota.

 

GenerallyAFUDC costs are recovered from customers as the related property isdepreciated.  In 2003, the MPUC voted toapprove NSP-Minnesota’s MERP proposal to convert two coal-fueled electricgenerating plants located in the Minneapolis-St. Paul metropolitan area tonatural gas and to install advanced pollution control equipment at a thirdcoal-fired plant.  These improvements areexpected to significantly reduce air emissions from these facilities, whileincreasing the capacity at system peak by 300 MW.  The first of these projects began operatingin July 2007, the second of these projects began operating in May 2008and the remaining projects began operations in March 2009, at a cumulativeinvestment of approximately $1 billion. The MPUC has approved a more current recovery of the financing costsrelated to the MERP.  The in-serviceplant costs, including the financing costs during construction, are recoveredfrom customers through a MERP rider resulting in a lower recognition of AFUDC.

 

***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 future decommissioningcosts.  The decommissioning calculationcovers all expenses, including decontamination and removal of radioactivematerial and extends over the estimated lives of the plants.  The calculation assumes that NSP-Minnesotawill recover those costs through rates. The fair value of external nuclear decommissioning fund investments isdetermined based on quoted market prices for those or similar investments.  Unrealized gains or losses on the fund’sassets are included with regulatory assets on the consolidated balancesheets.  For more information on nucleardecommissioning, see Note 15 to the consolidated financial statements.

 

***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 AFUDC),as well as future disposal costs of spent nuclear fuel, costs associated withthe end-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.

 

***Nuclear Refueling Outage Costs***** —** Effective Jan. 1, 2008, NSP-Minnesota expensedthe costs associated with refueling outages as incurred at its nuclearplants.  In September 2008, the MPUCauthorized NSP-Minnesota to use a deferral and amortization method for thenuclear refueling O&M costs effective Jan. 1, 2008.  This method amortizes refueling outage costsover the period between refueling outages to better match revenues andexpenses.

 

***Environmental Costs*****— Environmentalcosts are recorded when it is probable NSP-Minnesota is liable for the costsand the liability can be reasonably estimated. Costs may be deferred as a regulatory asset if it is probable that thecosts will be recovered from customers in future rates.  Otherwise, the costs are expensed.  If an environmental expense is related tofacilities currently in use, such as emission-control equipment, the cost iscapitalized and depreciated over the life of the plant, assuming the costs arerecoverable in future rates or future cash flow.

 

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Estimated remediation costs,excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the currentsituation and the technology currently available for use in theremediation.  The recorded costs areregularly adjusted as estimates are revised and remediation proceeds.  If several designated responsible partiesexist, costs are estimated and recorded only for NSP-Minnesota’s expected shareof the cost.  Any future costs ofrestoring sites where operation may extend indefinitely are treated as acapitalized cost of plant retirement.  Thedepreciation expense levels recoverable in rates include a provision forremoval expenses, which may include final remediation costs.  Removal costs recovered in rates areclassified 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, which requiresthe recognition of deferred tax assets and liabilities for the expected futuretax consequences of events that have been included in the financialstatements.  NSP-Minnesota defers incometaxes for all temporary differences between pretax financial and taxableincome, and between the book and tax bases of assets and liabilities.  NSP-Minnesota uses the tax rates that arescheduled to be in effect when the temporary differences are expected toreverse.  The effect of a change in taxrates on deferred tax assets and liabilities is recognized in income in theperiod that includes the enactment date. Deferred tax assets are reduced by a valuation allowance if, based onthe weight of available evidence, it is more likely than not that some portionor all of the deferred tax asset will not be realized.  In making such a determination, all availablepositive and negative evidence, including scheduled reversals of deferred taxliabilities, projected future taxable income, tax planning strategies andrecent 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 aredeferred and their benefits amortized over the book depreciable lives of therelated property.  Utility rateregulation also has created certain regulatory assets and liabilities relatedto income taxes, which are summarized in Note 16 to the consolidated financialstatements.  For more information onincome taxes, see Note 7 to the consolidated financial statements.

 

NSP-Minnesotafollows the guidance in *ASC 740 Income Taxes*to measure and disclose uncertain tax positions that NSP-Minnesota has taken orexpects to take in its income tax returns. In accordance with this guidance, NSP-Minnesota recognizes a taxposition in its consolidated financial statements when it is more likely thannot that the position will be sustained upon examination based on the technicalmerits of the position.  Recognition ofchanges in uncertain tax positions are reflected as a component of income taxexpense.

 

NSP-Minnesota reportsinterest and penalties related to income taxes within the other income andinterest charges sections in the consolidated statements of income.

 

Xcel Energy and itssubsidiaries, including NSP- Minnesota, file consolidated federal income taxreturns and combined and separate state income tax returns.  Federal income taxes paid by Xcel Energy, asparent of the Xcel Energy consolidated group, are allocated to the Xcel Energysubsidiaries based on separate company computations of tax.  A similar allocation is made for state incometaxes paid by Xcel Energy in connection with combined state filings.  The holding company also allocates its ownnet income tax benefits to its direct subsidiaries based on the positive taxliability of each company.

 

***Use of Estimates*****— In recordingtransactions and balances resulting from business operations, NSP-Minnesotauses estimates based on the best information available.  Estimates are used for such items as plantdepreciable lives, AROs, decommissioning, tax provisions, uncollectibleamounts, environmental costs, unbilled revenues, jurisdictional fuel and energycost allocations and actuarially determined benefit costs.  The recorded estimates are revised whenbetter information becomes available or when actual amounts can be determined.  Those revisions can affect operatingresults.  The depreciable lives ofcertain plant assets are reviewed annually and revised, if appropriate.

 

***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.

 

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

 

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***Regulatory Accounting*****— NSP-Minnesotaaccounts for certain income and expense items in accordance with *ASC 980 Regulated Operations*.  Under this guidance:

 

·                     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 are amortized consistent with theperiod of expected regulatory treatment. If restructuring or other changes in the regulatory environment occur,NSP-Minnesota may no longer be eligible to apply this accounting treatment andmay be required to eliminate such regulatory assets and liabilities from itsbalance sheet.  Such changes could have amaterial effect on NSP-Minnesota’s results of operations in the period thewrite-off is recorded.  See morediscussion of regulatory assets and liabilities in Note 16 to the consolidatedfinancial statements.

 

***Deferred Financing Costs*****— Other assetsincluded deferred financing costs, net of amortization, of approximately $23.7million and $21.3 million at Dec. 31, 2009 and 2008, respectively.  NSP-Minnesota is amortizing these financingcosts over the remaining maturity periods of the related debt.

 

Debtpremiums, discounts and expenses are amortized over the life of the relateddebt.  The premiums, discounts andexpenses associated with refinanced debt are deferred and amortized over thelife of the related new issuance, in accordance with regulatory guidelines.

 

***Accounts Receivable and Allowance for Bad Debts*****—**Accounts receivable are stated at the actual billedamount net of write-offs and an allowance for bad debts.  NSP-Minnesota establishes an allowance foruncollectible receivables based on a reserve policy that reflects its expectedexposure to the credit risk of customers.

 

***Renewable Energy Credits******—***RECsare******marketable environmentalcommodities that represent proof that energy was generated from eligible renewableenergy sources.  RECs are awarded upondelivery of the associated energy and can bebought and sold.  RECs aretypically used as a form of measurement of compliance to RPSs enacted by thosestates that are encouraging construction and consumption of renewable energy,but can also be sold separately from the energy produced.  Currently, NSP-Minnesota acquires RECs fromthe generation or purchase of renewable power.

 

***WhenRECs are acquired in the course of generation or purchase as a result ofmeeting load obligations, they are recorded as inventory at cost.  RECs acquired for trading purposes arerecorded as other investments and are also recorded at cost.  The cost of RECs that are retired for compliancepurposes is recorded as electric fuel and purchased power expense.  The net margin on sales of RECs for tradingpurposes is recorded as electric utility operating revenues, net of any marginsharing requirements.***

*** ***

***Emission Allowances*****—**Emission allowances are recorded at cost, includingthe annual SO2 and NOx emission allowance entitlementreceived at no cost from the EPA. NSP-Minnesota follows the inventory accounting model for all allowances.  The sales of allowances are reported in theoperating activities section of the consolidated statements of cash flows.  The net margin on sales of emissionallowances is included in electric utility operating revenues as it is integralto the production process of energy and our revenue optimization strategy forour utility operations.

 

***Subsequent Events*** —Management hasevaluated the impact of events occurring after Dec. 31, 2009 up to thedate of issuance of these consolidated financial statements.  These statements contain all necessaryadjustments and disclosures resulting from that evaluation.

 

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**2.**             Accounting Pronouncements

** **

***Recently Adopted***

 

***Business Combinations*******—****In December 2007,the FASB issued new guidance on business combinations which establishesprinciples and requirements for how an acquirer in a business combinationrecognizes and measures in its financial statements the identifiable assetsacquired, the liabilities assumed, and any noncontrolling interest; recognizesand measures the goodwill acquired in the business combination or a gain from abargain purchase; and determines what information to disclose to enable usersof the financial statements to evaluate the nature and financial effects of thebusiness combination. This new guidance is to be applied prospectively tobusiness combinations for which the acquisition date is on or after thebeginning of an entity’s fiscal year that begins on or after Dec. 15,2008.  NSP-Minnesota implemented theguidance on Jan. 1, 2009, and the implementation did not have a materialimpact on its consolidated financial statements.

 

***Noncontrolling Interests***— Also in December 2007,the FASB issued new guidance on noncontrolling interests in consolidatedfinancial statements which establishes accounting and reporting standards thatrequire the ownership interest in subsidiaries held by parties other than theparent be clearly identified and presented in the consolidated balance sheetswithin equity, but separate from the parent’s equity; the amount ofconsolidated 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 as equity transactions. This new guidance waseffective for fiscal years beginning on or after Dec. 15, 2008.  NSP-Minnesota implemented the guidance on Jan. 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.

 

***Derivatives and Hedging Disclosures***— In March 2008,the FASB issued new guidance on disclosures about derivative instruments andhedging activities which is intended to enhance disclosures to help users ofthe financial statements better understand how derivative instruments andhedging activities affect an entity’s financial position, financial performanceand cash flows.  The guidance amends andexpands previous disclosurerequirements for derivative instruments and hedging activities, includingdisclosures of objectives and strategies for using derivatives, gains andlosses on derivative instruments, and credit-risk-related contingent featuresin derivative contracts.  This newguidance was effective for fiscal years and interim periods beginning after Nov. 15,2008.  NSP-Minnesota implemented theguidance on Jan. 1, 2009, and the implementation did not have a materialimpact on its consolidated financial statements.  For further discussion and the requireddisclosures, see Note 10 to the consolidated financial statements.

 

***Interim Fair Value Disclosures***—******In April 2009,the FASB issued new guidance on interim disclosures about fair value offinancial instruments which requires that disclosures regarding the fair valueof financial instruments be included in interim financial statements.****** This new guidance was effective for interimperiods ending after June 15, 2009. NSP-Minnesota implemented the guidance on April 1, 2009, and theimplementation did not have a material impact on its consolidated financialstatements.

 

***Fair Value in Inactive Markets***—******Also in April 2009,the FASB issued new guidance for identifying market transactions that are notorderly and determining fair value when market trading activity has decreasedsignificantly.  The new guidanceemphasizes that even if there has been a significant decrease in the volume andlevel of market activity for an asset or liability, fair value still representsthe exit price in an orderly transaction between market participants.  This new guidance was effective for interimand annual periods ending after June 15, 2009.  NSP-Minnesota implemented the guidance on April 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.

 

***Other-Than-Temporary Impairments***—******Additionally in April 2009,the FASB issued new guidance on recognition and presentation of other-than-temporaryimpairments which changes the method for determining whether another-than-temporary impairment exists for debt securities, and also requiresadditional disclosures regarding other-than-temporary impairments.  This new guidance was effective for interimand annual periods ending after June 15, 2009.  NSP-Minnesota implemented the guidance on April 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.

 

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***Accounting Standards Codification***— In June 2009,the FASB issued *Topic 105 — GenerallyAccepted Accounting Principles Amendments Based on Statement of FinancialAccounting Standards No. 168 — The FASB Accounting Standards Codificationand the Hierarchy of Generally Accepted Accounting Principles (AccountingStandards Update (ASU) No. 2009-01)*, which updates the FASB ASCto state that the Codification is to be the single source of authoritativeGAAP, other than the guidance put forth by the SEC.  All other accounting literature not includedin the Codification is to be considered non-authoritative.  The updates to the Codification contained inASU No. 2009-01 were effective for interim and annual periods ending afterSept. 15, 2009.  NSP-Minnesotaimplemented the guidance set forth by ASU No. 2009-01, recognizing theCodification as the single source of authoritative GAAP, other than theguidance put forth by the SEC, on July 1, 2009.  The implementation did not have a materialimpact on NSP-Minnesota’s consolidated financial statements.

 

***Postretirement Benefit Plans***— In December 2008, the FASB issuednew guidance on employers’ disclosures about postretirement benefit planassets.  The guidance amends and expands previous disclosurerequirements for plan assets of a defined benefit pension or otherpostretirement plan to include investment policies and strategies, majorcategories of plan assets, and information regarding fair valuemeasurements.  This new guidance waseffective for disclosures for fiscal years ending after Dec. 15,2009.  NSP-Minnesota implemented theguidance on Jan. 1, 2009, and the implementation did not have a materialimpact on its consolidated financial statements.  For further discussion and the requireddisclosures, see Note 8 to the consolidated financial statements.

 

***Fair Value of Liabilities*****—****In August 2009, the FASB issued *Fair Value Measurements and Disclosures (Topic 820) —Measuring Liabilities at Fair Value (ASU No. 2009-05)*, whichupdates the Codification with clarifications for measuring the fair value ofliabilities.  The liability-specificguidance includes clarifications and guidelines for using, when available, themost observable prices in active markets for identical liabilities or similarliabilities, or the prices of identical liabilities or similar liabilitiestraded as assets, rather than more complex and less observable valuationtechniques and inputs such as those used in a present value model.  The updates to the Codification contained inASU No. 2009-05 were effective for interim and annual periods beginningafter its August, 2009 issuance.  NSP-Minnesota implemented the guidance onSept. 1, 2009, and the implementation did not have a material impact on itsconsolidated financial statements.

 

***Recently Issued***

*** ***

***Consolidation of Variable Interest Entities***— In June 2009, the FASB issued new guidance on consolidation ofvariable interest entities.****** The guidance willsignificantly affect various elements of consolidation under existingaccounting standards, including the determination of whether an entity is avariable interest entity and whether an enterprise is a variable interestentity’s primary beneficiary.  This newguidance is effective for interim and annual periods beginning after Nov. 15,2009.  NSP-Minnesota does not expect theimplementation of the guidance to have a material impact on its consolidatedfinancial statements.

 

***Fair Value Measurement Disclosures*** — In January 2010, theFASB issued *Fair Value Measurements and Disclosures (Topic 820)— Improving Disclosures about Fair Value Measurements (ASU No. 2010-06)*,which will update the Codification to require new disclosures for assets andliabilities measured at fair value.  Therequirements include expanded disclosure of valuation methodologies for Level 2and Level 3 fair value measurements, transfers in and out of Levels 1 and 2,and gross rather than net presentation of certain changes in Level 3 fair valuemeasurements.  The updates to theCodification contained in ASU No. 2010-06 are effective for interim andannual periods beginning after Dec. 15, 2009, except for requirementsrelated to gross presentation of certain changes in Level 3 fair value measurements,which are effective for interim and annual periods beginning after Dec. 15,2010.  NSP-Minnesota does not expect theimplementation of the guidance to have a material impact on its consolidatedfinancial statements.

 

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**3.****             ****SelectedBalance Sheet Data**

 
| ** **                             | ** ** | **Dec. 31,** | ** ** |
|----------------------------------------|------------|-------------------|------------|
| **(Thousands of Dollars)**   | ** ** | **2009**          | ** ** | **2008** | ** ** |
| **Accounts receivable, net**           |       |              |       |   |   |
| Accounts  receivable                   |       | $                 | 322,778    |   | $ | 438,855 |   |
| Less  allowance for bad debts          |       | (22,675           | )          | (25,699 | ) |
|                                   |       | $                 | 300,103    |   | $ | 413,156 |   |
| **Inventories**                        |       |              |       |   |   |
| Materials  and supplies                |       | $                 | 105,508    |   | $ | 97,945 |   |
| Fuel                                   |       | 99,705            |       | 141,190 |   |
| Natural  gas                           |       | 50,706            |       | 106,768 |   |
|                                   |       | $                 | 255,919    |   | $ | 345,903 |   |
| **Property, plant and equipment, net** |       |              |       |   |   |
| Electric  plant                        |       | $                 | 9,679,288  |   | $ | 9,472,073 |   |
| Natural  gas plant                     |       | 948,708           |       | 916,740 |   |
| Common  and other property             |       | 472,624           |       | 452,308 |   |
| Construction  work in progress         |       | 587,080           |       | 615,734 |   |
| Total  property, plant and equipment   |       | 11,687,700        |       | 11,456,855 |   |
| Less  accumulated depreciation         |       | (5,030,836        | )          | (4,907,681 | ) |
| Nuclear  fuel                          |       | 1,737,469         |       | 1,611,193 |   |
| Less  accumulated amortization         |       | (1,435,677        | )          | (1,355,573 | ) |
|                                   |       | $                 | 6,958,656  |   | $ | 6,804,794 |   |

 

**4.**             Short-Term Borrowings

** **

***Commercial Paper*****— At Dec. 31, 2008, NSP-Minnesota had commercial paper outstandingof $65.0 million.  NSP-Minnesota hasapproval by the Board of Directors to issue up to $500 million of commercialpaper.  The weighted average interestrate at Dec. 31, 2008 was 2.57 percent. NSP-Minnesota had no commercial paper outstanding at Dec. 31, 2009.

 

***Money Pool*****— Xcel Energyand its utility subsidiaries have established a utility money pool arrangementthat allows for short-term investments in and borrowings from the utilitysubsidiaries between each other.  TheHolding Company may make investments in the utility subsidiaries atmarket-based interest rates.  However,the money pool arrangement does not allow the utility subsidiaries to makeinvestments in the Holding Company.  NSP-Minnesota has approval to borrow up to$250 million under the arrangement.  At Dec. 31,2009 and 2008, NSP-Minnesota had money pool investments of $7.0 million andborrowings of $63.5 million, respectively. The weighted average interest rates at Dec. 31, 2009 and 2008 were0.36 percent and 3.48 percent, respectively.

 

**5.    Long-Term Debt**

** **

***Credit Facilities***— At Dec. 31,2009, NSP-Minnesota had the following committed credit facility in effect, inmillions of dollars:

 
| **Credit**   | ** ** | ** ** | ** ** | ** **    | ** ** | ** **         | ** ** | ** **   | ** ** |
|--------------|------------|------------|------------|---------------|------------|--------------------|------------|--------------|------------|
| **Facility** | ** ** | **Drawn*** | ** ** | **Available** | ** ** | **Original  Term** | ** ** | **Maturity** | ** ** |
| $            | 482        |       | $          | 6             |       | $                  | 476        |         | Five year  |   | December 2011 |   |
|              |            |            |            |               |            |                    |            |              |            |  |  |  |

 

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*Includes direct borrowings, outstanding commercial paper and issued andoutstanding letters of credit.

 

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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 facility has onefinancial covenant requiring that NSP-Minnesota’s debt-to-total capitalizationratio be less than or equal to 65 percent. NSP-Minnesota was in compliance as its debt-to-total capitalizationratio was 48 percent and 50 percent at Dec. 31, 2009 and 2008,respectively.** **IfNSP-Minnesota does not comply with the covenant, it is deemed an event ofdefault and any outstanding amounts due under the facility can be declared dueby the lender.

 

·                     The credit facility has a crossdefault provision that provides the borrower will be in default on itsborrowings under the facility if any of its subsidiaries, comprising more than15 percent of the consolidated assets, defaults on any of its indebtednessgreater than $50 million.

 

·                     The interest rate is based on theagent bank’s prime rate or the applicable LIBOR, plus a borrowing margin asbased on NSP-Minnesota’s senior unsecured credit ratings from Moody, Standard &Poor and Fitch.  Based on NSP-Minnesota’scurrent credit rating the borrowing margin is 25 basis points.  The commitment fees are calculated for theunused portion of the credit facility at 6 basis points for NSP-Minnesota.

 

·                     At Dec. 31,2009, NSP-Minnesota had no direct borrowings on this line of credit; however,the credit facility was used to provide back-up support for $5.8 million ofletters of credit.  At Dec. 31,2008, NSP-Minnesota had no direct borrowings on this line of credit; however,the credit facility was used to provide back-up support for $65.0 million ofcommercial paper outstanding and $5.8 million of letters of credit.

 

***Long-Term Borrowings***

*** ***

In November 2009, NSP-Minnesota issued $300 million of 5.35 percentfirst mortgage bonds, series due Nov. 1, 2039.  NSP-Minnesota added the net proceeds from thesale of the first mortgage bonds to its general funds and applied a portion ofthe proceeds to the repayment of commercial paper and borrowings under theutility money pool arrangement incurred to fund the repayment at maturity of$250 million of 6.875 percent unsecured senior notes due Aug. 1, 2009.

 

In March 2008, NSP-Minnesota issued $500 million of 5.25 percentfirst mortgage bonds, series due March 1, 2018.  NSP-Minnesota added the net proceeds from thesale of the first mortgage bonds to its general funds and applied a portion ofthe proceeds to the repayment of commercial paper and borrowings under theutility money pool arrangement.

 

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 these restrictions, NSP-Minnesotacould have paid more than $1.1 billion and $1.0 billion in additional cashdividends on common stock at Dec. 31, 2009 and 2008, respectively.

 

Maturitiesof long-term debt are:

 
| **(Millions of Dollars)** | ** ** | ** ** | ** ** |
|-------------------------------------|------------|------------|------------|
| 2010                                |       | $          | 175        |   |
| 2011                                |       | —     |       |
| 2012                                |       | 450        |       |
| 2013                                |       | —     |       |
| 2014                                |       | —     |       |
|                                     |            |            |            |  |

 

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**6.    Joint Plant Ownership**

** **

Following are theinvestments by NSP-Minnesota in jointly owned plants and the related ownershippercentages as of Dec. 31, 2009:

 
| ** **                                 | ** ** | ** **                                                         | ** **                                         | ** **                                                                         | ** ** | **Construction**                                                                   | ** ** | ** **                                                                    | ** **                                                               |
|--------------------------------------------|------------|--------------------------------------------------------------------|----------------------------------------------------|------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------|--------------------------------------------------------------------------|
| ** **                                 | ** ** | **Plant  in**                                                      | ** **                                         | **Accumulated**                                                                    | ** ** | **Work  in**                                                                       | ** ** | ** **                                                                    | ** **                                                               |
| **(Thousands of Dollars)**       | ** ** | **Service**                                                        | ** **                                         | **Depreciation**                                                                   | ** ** | **Progress**                                                                       | ** ** | **Ownership  %**                                                              | ** **                                                               |
| Sherco  Unit 3                             |       | $                                                                  |         535,643 |                                                                               | $          |         340,258                                 |       | $                                                                             |             8,172 |   |              59.0 |   |
| Sherco  common facilities Units 1, 2 and 3 |       |        124,319                       |                                               |          77,319                            |       |               640 |       |  59.0 - 100.0                                                            |                                                                     |
| Sherco  Substation                         |       |            4,790 |                                               |            2,354                 |       | —                                                                             |       |              59.0 |                                                                     |
| Grand  Meadow Line and Substation          |       |          11,204            |                                               |               378 |       | —                                                                             |       |              50.0 |                                                                     |
| CapX2020                                   |       | —                                                             |                                               | —                                                                             |       |          25,738                            |       |  26.2 - 72.1                                                             |                                                                     |
| Total                                      |       | $                                                                  |         675,956 |                                                                               | $          |         420,309                                 |       | $                                                                             |           34,550            |   |   |   |

 

NSP-Minnesotais part owner of Sherco Unit 3, an 860 MW, coal-fueled electric generatingunit.  NSP-Minnesota is the operatingagent under the joint ownership agreement. NSP-Minnesota’s share of operating expenses and constructionexpenditures are included in the applicable utility accounts.  Each of the respective owners is responsiblefor funding its portion of the construction costs.

 

**7.**             Income Taxes

** **

***Federal Audit******—***NSP-Minnesotais a member of the Xcel Energy affiliated group that files a consolidatedfederal income tax return.*** ***In 2008, the IRS completed an examinationof Xcel Energy’s federal income tax returns for 2004 and 2005 (and researchcredits for 2003).****** TheIRS did not propose any material adjustments for those tax years.  Thestatute of limitations applicable to Xcel Energy’s 2004 and 2005 federal incometax returns expired on Dec. 31, 2009.  The IRS commenced an examinationof tax years 2006 and 2007 in 2008, and this audit is expected to be completedin the first quarter of 2010.  As of Dec. 31, 2009, the IRS had notproposed any material adjustments to tax years 2006 and 2007.

 

***State Audits —***  NSP-Minnesota is a member of the Xcel Energyaffiliated group that files consolidated state income tax returns.  In 2008, the state of Minnesota concluded anincome tax audit through tax year 2001.  No material adjustments wereproposed for this audit.  As of Dec. 31, 2009, NSP-Minnesota’searliest open tax year that is subject to examination by state taxingauthorities under applicable statutes of limitations is 2004.  In thethird quarter of 2009, Xcel Energy received a request for information from thestate of Minnesota relating to tax years 2002 through 2007 in order todetermine whether to undertake an audit of those years.  As of Dec. 31, 2009, the state ofMinnesota had not informed Xcel Energy of its intentions.  There currently are no state income taxaudits in progress.

 

***Unrecognized Tax Benefits —***The amount of unrecognizedtax benefits was $12.5 million and $20.2 million on Dec. 31, 2009 and Dec. 31,2008, respectively.  A reconciliation ofthe beginning and ending amount of unrecognized tax benefit is as follows:

 
| **(Millions of Dollars)**                                  | ** ** | **2009**                                                                                                         | ** **                                      | **2008**                                                                                                         | ** ** |
|----------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------|-------------------------------------------------|------------------------------------------------------------------------------------------------------------------|------------|
| Balance  at Jan. 1                                    |       | $                                                                                                                |         20.2 |                                                                                                             | $          |      14.3 |   |
| Additions  based on tax positions related to the current year   |       |                    6.9 |                                            |                    5.4 |       |
| Reductions  based on tax positions related to the current year  |       |                  (1.4            | )                                               |                  (0.4            | )          |
| Additions  for tax positions of prior years                     |       |                    3.6 |                                            |                    4.9 |       |
| Reductions  for tax positions of prior years                    |       |                  (1.5            | )                                               | —                                                                                                           |       |
| Settlements  with taxing authorities                                 |       |                (15.3                       | )                                               |                  (4.0            | )          |
| Balance  at Dec. 31                                   |       | $                                                                                                                |       12.5             |                                                                                                             | $          |          20.2 |   |

 

The unrecognized taxbenefit amounts were reduced by the tax benefits associated with net operatingloss (NOL) and tax credit carryovers of $2.8 million on Dec. 31, 2009 and$4.4 million on Dec. 31, 2008.

 

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The unrecognized taxbenefit balance included $2.7 million and $7.2 million of tax positions on Dec. 31,2009 and Dec. 31, 2008, respectively, which if recognized would affect theannual effective tax rate.  In addition, the unrecognized tax benefitbalance included $9.8 million and $13.0 million of tax positions on Dec. 31,2009 and Dec. 31, 2008, respectively, for which the ultimate deductibilityis highly certain but for which there is uncertainty about the timing of suchdeductibility.  A change in the period of deductibility would not affectthe effective tax rate but would accelerate the payment of cash to the taxingauthority to an earlier period.

 

The decrease in theunrecognized tax benefit balance of $7.7 million in 2009, was due to theresolution of certain federal audit matters, partially offset by an increasedue to the addition of similar uncertain tax positions related to ongoingactivity.  NSP-Minnesota’s amount of unrecognized tax benefits couldsignificantly change in the next 12 months when the IRS and state auditsresume.  At this time, due to the uncertain nature of the audit process,it is not reasonably possible to estimate an overall range of possible change.

 

Areconciliation of the beginning and ending amount of the payable for interestrelated to unrecognized tax benefits is as follows:

 
| **(Millions of Dollars)**                                        | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Payable  for interest related to unrecognized tax benefits at Jan. 1  |       | $        | (1.3       | )        | $          | (1.9 | ) |
| Interest  income related to unrecognized tax benefits                      |       | 1.0      |       | 0.6      |       |
| Payable  for interest related to unrecognized tax benefits at Dec. 31 |       | $        | (0.3       | )        | $          | (1.3 | ) |

 

No amounts were accrued forpenalties related to unrecognized tax benefits as of Dec. 31, 2009 or Dec. 31,2008.

 

***Other Income Tax Matters****—*****NOL and tax credit carryforwards as of Dec. 31,2009 and 2008 were as follows:

 
| **(Millions of Dollars)**                       | ** ** | **2009** | ** ** | **2008** | ** ** |
|-----------------------------------------------------------|------------|----------|------------|----------|------------|
| Federal  NOL carryforward                                 |       | $        | 25.8       |     | $          | 22.1 |   |
| Federal  tax credit carryforwards                         |       | 23.0     |       | 14.8     |       |
| State  tax credit carryforwards, net of federal detriment |       | 1.8      |       | 1.6      |       |
|                                                           |            |          |            |          |            |  |  |

 

The federal carryforwardperiods expire between 2021 and 2029. The state carryforward periods expire between 2018 and 2024.

 

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 reconciles such differences forthe years ending Dec. 31:

 
| ** **                                                 | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal  statutory rate                                    |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases  (decreases) in tax from:                        |       |     |       |     |       |     |       |
| State  income taxes, net of federal income tax benefit     |       | 6.2      |       | 7.6      |       | 8.4      |       |
| Tax  credits recognized, net of federal income tax expense |       | (2.7     | )          | (1.6     | )          | (1.5     | )          |
| Regulatory  differences — utility plant items         |       | (1.6     | )          | (2.3     | )          | (1.7     | )          |
| Resolution  of income tax audits and other                 |       | 1.4      |       | —   |       | 0.4      |       |
| Change  in unrecognized tax benefits                       |       | (1.0     | )          | 0.1      |       | 0.2      |       |
| Life  insurance policies                                   |       | (0.3     | )          | (0.2     | )          | (0.2     | )          |
| Other,  net                                                |       | 0.3      |       | (0.1     | )          | (0.1     | )          |
| Effective  income tax rate                                 |       | 37.3     | %          | 38.5     | %          | 40.5     | %          |

 

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Thecomponents of NSP-Minnesota’s income tax expense for the years ending Dec. 31were:

 
| **(Thousands of Dollars)**                   | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current  federal tax expense (benefit)                 |       | $        | (12,136    | )        | $          | 9,527    |       | $ | 15,277 |   |
| Current  state tax expense                             |       | 19,195   |       | 27,802   |       | 4,987    |       |
| Current  change in unrecognized tax expense (benefit)  |       | (6,165   | )          | 3,709    |       | (6,346   | )          |
| Deferred  federal tax expense                          |       | 154,858  |       | 122,485  |       | 117,433  |       |
| Deferred  state tax expense                            |       | 30,364   |       | 25,653   |       | 50,151   |       |
| Deferred  change in unrecognized tax expense (benefit) |       | 1,667    |       | (3,106   | )          | 7,416    |       |
| Deferred  tax credits                                  |       | (9,542   | )          | (4,331   | )          | (2,996   | )          |
| Deferred  investment tax credits                       |       | (3,120   | )          | (3,503   | )          | (3,897   | )          |
| Total  income tax expense                              |       | $        | 175,121    |     | $          | 178,236  |       | $ | 182,025 |   |

 

The components of deferredincome tax at Dec. 31 were:

 
| **(Thousands of Dollars)**                                                                    | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred  tax expense excluding items below                                                             |       | $        | 228,821    |     | $          | 80,493 |   |
| Amortization  and adjustments to deferred income taxes on income tax regulatory assets and  liabilities |       | (50,432  | )          | 55,322   |       |
| Tax  expense (benefit) allocated to other comprehensive income and other                                |       | (1,042   | )          | 4,886    |       |
| Deferred  tax expense                                                                                   |       | $        | 177,347    |     | $          | 140,701 |   |

 

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

 
| **(Thousands of Dollars)**               | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred  tax liabilities:                         |       |     |       |     |       |
| Difference  between book and tax bases of property |       | $        | 1,224,338  |     | $          | 1,003,706 |   |
| Regulatory  assets                                 |       | 106,687  |       | 81,411   |       |
| Unbilled  revenue - fuel costs                     |       | 7,837    |       | 6,342    |       |
| Deferred  fuel costs                               |       | 6,677    |       | 9,211    |       |
| Other                                              |       | 10,088   |       | 17,083   |       |
| Total  deferred tax liabilities                    |       | $        | 1,355,627  |     | $          | 1,117,753 |   |
|                                               |       |     |       |     |       |
| Deferred  tax assets:                              |       |     |       |     |       |
| Employee  benefits                                 |       | $        | 62,046     |     | $          | 62,410 |   |
| Rate  refund                                       |       | 26,835   |       | 19,144   |       |
| Tax  credit carry forward                          |       | 24,831   |       | 16,392   |       |
| Regulatory  liabilities                            |       | 16,478   |       | 18,514   |       |
| Deferred  investment tax credits                   |       | 15,174   |       | 16,443   |       |
| Bad  debts                                         |       | 9,266    |       | 10,497   |       |
| Net  operating loss carry forward                  |       | 9,206    |       | 6,790    |       |
| Other                                              |       | 1,018    |       | 5,611    |       |
| Total  deferred tax assets                         |       | $        | 164,854    |     | $          | 155,801 |   |
| Net  deferred tax liability                        |       | $        | 1,190,773  |     | $          | 961,952 |   |

 

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**8.    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, which includes NSP-Minnesota, offers various benefit plans to itsemployees.  At Dec. 31, 2009,NSP-Minnesota had 2,119 bargaining employees covered under acollective-bargaining agreement, which expires at the end of 2010. NSP-Minnesota also had an additional 222 nuclear operation bargainingemployees covered under several collective-bargaining agreements, whichexpire at various dates through September 2010.

 

EffectiveJan. 1, 2009, Xcel Energy and NSP-Minnesota adopted new guidanceon employers’ disclosures about pension and postretirement benefit planassets.  The new guidance expandsemployers’ disclosure requirements for benefit plan assets, includinginvestment policies and strategies, major categories of plan assets, andinformation regarding fair value measurements consistent with the disclosuresfor entities’ recurring fair value measurements prescribed by *ASC 820**Fair Value Measurements*.

 

*ASC 820Fair Value Measurements* establishes a hierarchal framework fordisclosing the observability of the inputs utilized in measuring fairvalue.  The three levels defined by thehierarchy and examples of each level are as follows:

 

Level1 — Quoted prices are available in active markets for identical assets as ofthe reporting date.  The types of assetsincluded in Level 1 are highly liquid and actively traded instruments withquoted prices, such as common stocks listed by the New York Stock Exchange.

 

Level2 — Pricing inputs are other than quoted prices in active markets, but areeither directly or indirectly observable as of the reporting date.  The types of assets included in Level 2 aretypically either comparable to actively traded securities or contracts orpriced with models using highly observable inputs, such as corporate bonds withpricing based on market interest rate curves and recent trades of similarlyrated securities.

 

Level 3 — Significant inputsto pricing have little or no observability as of the reporting date.  The types of assets included in Level 3 arethose with inputs requiring significant management judgment or estimation, suchas asset and mortgage backed securities, for which subjective risk-basedadjustments to estimated yield and forecasted prepayments are significantinputs.

 

**Pension Benefits**

** **

XcelEnergy, which includes NSP-Minnesota, has several noncontributory, definedbenefit pension plans that cover almost all employees.  Benefits are based on a combination of yearsof service, the employee’s average pay and social security benefits.  Xcel Energy’s and NSP-Minnesota’s policy isto fully fund the actuarially determined pension costs recognized forratemaking and financial reporting purposes, subject to the limitations ofapplicable employee benefit and tax laws, into an external trust over time.

 

XcelEnergy and NSP-Minnesota base investment-return assumption on expectedlong-term performance for each of the investment types included in the pensionasset portfolio and consider the actual historical returns achieved by itsasset portfolio over the past 20-year or longer period, as well as thelong-term return levels projected and recommended by investment experts.  The historical weighted average annual returnfor the past 20 years for the portfolio of pension investmentsis 8.98 percent, which is greater than the current assumptionlevel.  The pension cost determination assumes a forecasted mix ofinvestment types over the long term.  Investment returns in 2009were above the assumed level of 8.50 percent while returns in2008 and 2007 were below the assumed level of8.75 percent.  Xcel Energy and NSP-Minnesota continuallyreview the pension assumptions.  In 2010, Xcel Energy will use aninvestment-return assumption, for all pension plans in aggregate,of 7.79 percent.

 

Theassets are invested in a portfolio according to Xcel Energy’s and NSP-Minnesota’sreturn, liquidity and diversification objectives to provide a source of fundingfor plan obligations and minimize the necessity of contributions to the plan,within appropriate levels of risk.  Theprincipal mechanism for achieving these objectives is the allocation of assetsto selected asset classes, given the long-term risk, return, and liquiditycharacteristics of each particular asset class. There were no significant concentrations of risk in any particularindustry, index, or entity, however, a higher weighting in equity investmentscan increase the volatility in the return levels achieved by pension assets inany year.

 

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Thefollowing table presents the target range pension asset allocations for 2009and 2008:

 
| ** **                                          | ** ** | **2009** | ** ** | **2008** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| Domestic  and international equity securities       |       | 24       | %          | 52       | %          |
| Long  duration fixed income securities              |       | 34       |       | —   |       |
| Short  to intermediate term fixed income securities |       | 19       |       | 25       |       |
| Alternative  investments                            |       | 18       |       | 23       |       |
| Cash                                                |       | 5        |       | —   |       |
| Total                                               |       | 100      | %          | 100      | %          |

 

In 2009, Xcel Energy andNSP-Minnesota engaged J.P. Morgan’s Pension Advisory Group to evaluate theallocation of the total assets in the master pension trust, taking intoconsideration the funded status of each individual pension plan.  The investment strategy employed during 2009is based on plan-specific investment recommendations that seek to minimizepotential investment and interest rate risk as a plan’s funded status increasesover time. The investment recommendations result in a greater percentage ofshort-to-intermediate term and long-duration fixed income securities beingallocated to specific plans having relatively higher funded status ratios, anda greater percentage of growth assets being allocated to plans havingrelatively lower funded status ratios. The aggregate asset allocation presentedin the table above for the master pension trust results from the plan-specificstrategies.

 

**PensionPlan Assets**

 

Thefollowing table presents, for each of the fair value hierarchy levels, pensionplan assets that are measured at fair value as of Dec. 31, 2009:

 
| **(Thousands of Dollars)**                       | ** ** | **Level  1** | ** ** | **Level  2** | ** ** | **Level  3** | ** ** | **Total** | ** ** |
|------------------------------------------------------------|------------|--------------|------------|--------------|------------|--------------|------------|-----------|------------|
| Cash  equivalents                                          |       | $            | —     |         | $          | 221,971      |       | $         | —     |   | $ | 221,971 |   |
| Short-term  investments & money market securities |       | —       |       | 324,683      |       | —       |       | 324,683   |       |
| Derivatives                                                |       | —       |       | 11,606       |       | —       |       | 11,606    |       |
| Government  securities                                     |       | —       |       | 94,949       |       | —       |       | 94,949    |       |
| Corporate  bonds                                           |       | —       |       | 522,403      |       | —       |       | 522,403   |       |
| Asset-backed &  mortgage-backed securities        |       | —       |       | —       |       | 191,831      |       | 191,831   |       |
| Common  stock                                              |       | 89,260       |       | —       |       | —       |       | 89,260    |       |
| Private  equity investments                                |       | —       |       | —       |       | 82,098       |       | 82,098    |       |
| Commingled  equity and bond funds                          |       | —       |       | 1,014,072    |       | —       |       | 1,014,072 |       |
| Real  estate                                               |       | —       |       | —       |       | 66,704       |       | 66,704    |       |
| Securities  lending collateral obligation and other        |       | —       |       | (170,251     | )          | —       |       | (170,251  | )          |
| Total                                                      |       | $            | 89,260     |         | $          | 2,019,433    |       | $         | 340,633    |   | $ | 2,449,326 |   |

 

Thefollowing table presents the changes in Level 3 pension plan assets for theyear ended Dec. 31, 2009:

 
| **(Thousands of Dollars)**                | ** ** | **Jan. 1,  2009** | ** ** | **Realized  and  Unrealized Gains  (Losses)** | ** ** | **Purchases,  Issuances, and  Settlements (net)** | ** ** | **Dec. 31,  2009** | ** ** |
|-----------------------------------------------------|------------|------------------------|------------|-----------------------------------------------|------------|---------------------------------------------------|------------|-------------------------|------------|
| Asset-backed &  mortgage-backed securities |       | $                      | 244,008    |                                          | $          | 151,755                                           |       | $                       | (203,932   | ) | $ | 191,831 |   |
| Real  estate                                        |       | 109,289                |       | (43,207                                       | )          | 622                                               |       | 66,704                  |       |
| Private  equity investments                         |       | 81,034                 |       | (5,682                                        | )          | 6,746                                             |       | 82,098                  |       |
| Total                                               |       | $                      | 434,331    |                                          | $          | 102,866                                           |       | $                       | (196,564   | ) | $ | 340,633 |   |

 

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***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)**                                                                                        | ** ** | **2009**            | ** ** | **2008**            | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|---------------------|------------|
| **Accumulated Benefit Obligation at Dec. 31**                                                                          |       | $                   | 2,676,174  |                | $          | 2,435,513 |   |
|                                                                                                                        |       |                |       |                |       |
| **Change in Projected Benefit Obligation:**                                                                                 |       |                |       |                |       |
| Obligation  at Jan. 1                                                                                                  |       | $                   | 2,598,032  |                | $          | 2,662,759 |   |
| Service  cost                                                                                                               |       | 65,461              |       | 62,698              |       |
| Interest  cost                                                                                                              |       | 169,790             |       | 167,881             |       |
| Plan  amendments                                                                                                            |       | (35,341             | )          | —              |       |
| Actuarial  loss (gain)                                                                                                      |       | 223,122             |       | (47,509             | )          |
| Benefit  payments                                                                                                           |       | (191,433            | )          | (247,797            | )          |
| Obligation  at Dec. 31                                                                                                 |       | $                   | 2,829,631  |                | $          | 2,598,032 |   |
|                                                                                                                        |       |                |       |                |       |
| **Change in Fair Value of Plan Assets:**                                                                                    |       |                |       |                |       |
| Fair  value of plan assets at Jan. 1                                                                                   |       | $                   | 2,185,203  |                | $          | 3,186,273 |   |
| Actual  return (loss) on plan assets                                                                                        |       | 255,556             |       | (788,273            | )          |
| Employer  contributions                                                                                                     |       | 200,000             |       | 35,000              |       |
| Benefit  payments                                                                                                           |       | (191,433            | )          | (247,797            | )          |
| Fair  value of plan assets at Dec. 31                                                                                  |       | $                   | 2,449,326  |                | $          | 2,185,203 |   |
|                                                                                                                        |       |                |       |                |       |
| **Funded Status of Plans at Dec. 31:**                                                                                 |       |                |       |                |       |
| Funded  status                                                                                                              |       | $                   | (380,305   | )                   | $          | (412,829 | ) |
| Noncurrent  assets                                                                                                          |       | —              |       | 15,612              |       |
| Noncurrent  liabilities                                                                                                     |       | (380,305            | )          | (428,441            | )          |
| Net  pension amounts recognized on consolidated balance sheets                                                              |       | $                   | (380,305   | )                   | $          | (412,829 | ) |
|                                                                                                                        |       |                |       |                |       |
| NSP-Minnesota  accrued benefit liability recorded                                                                           |       | $                   | 157,687    |                | $          | 91,095 |   |
|                                                                                                                        |       |                |       |                |       |
| **NSP-Minnesota Amounts Not Yet Recognized as Components of  Net Periodic Benefit Cost:**                                   |       |                |       |                |       |
| Net  loss                                                                                                                   |       | $                   | 530,197    |                | $          | 454,770 |   |
| Prior  service cost                                                                                                         |       | 34,496              |       | 46,222              |       |
| Total                                                                                                                       |       | $                   | 564,693    |                | $          | 500,992 |   |
|                                                                                                                        |       |                |       |                |       |
| **Amounts Related to the Funded Status of the Plans Have Been  Recorded as Follows Based Upon Expected Recovery in Rates:** |       |                |       |                |       |
| Regulatory  assets                                                                                                          |       | $                   | 564,693    |                | $          | 500,992 |   |
|                                                                                                                        |       |                |       |                |       |
| Measurement  date                                                                                                           |       | Dec. 31,  2009 |       | Dec. 31,  2008 |       |
|                                                                                                                        |       |                |       |                |       |
| **Significant Assumptions Used to Measure Benefit  Obligations:**                                                           |       |                |       |                |       |
| Discount  rate for year-end valuation                                                                                       |       | 6.00                | %          | 6.75                | %          |
| Expected  average long-term increase in compensation level                                                                  |       | 4.00                |       | 4.00                |       |
| Mortality  table                                                                                                            |       | RP 2000             |       | RP 2000             |       |

 

AtDec. 31, 2009, Xcel Energy’s pension plans, in the aggregate, had planassets of $2.4 billion and projected benefit obligations of $2.8 billion.  At Dec. 31, 2008, one of the pensionplans had plan assets of $259.9 million, which exceeded projected benefitobligations of $244.3 million and all other plans in the aggregate hadplan assets of $1.9 billion and projected benefit obligations of$2.4 billion.

 

***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 require cash funding for 2007 through 2009 forthe pension plans and are not expected to require cash funding in 2010.

 

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XcelEnergy accelerated its planned 2010 contribution of $100 million based onavailable liquidity, bringing its total pension contributions to $200 millionduring 2009.

 

·                     Voluntary contributions weremade to the PSCo Bargaining Pension Plan of $173 million in 2009,$35 million in 2008 and $35 million in 2007.

·                     Voluntary contributions weremade to the NCE Non-Bargaining Pension Plan of $27 million in 2009.  No voluntary contributions were made to theplan during 2007 or 2008.

·                     Pension fundingcontributions for 2011, which will be dependent on several factors including,realized asset performance, future discount rate, IRS and legislativeinitiatives as well as other actuarial assumptions, are estimated to rangebetween $100 million to $150 million.

 

***Plan Amendments —***The decrease inthe projected benefit obligation for the plan amendment is due to a change inthe average earnings calculation resulting from negotiations with the PSCoBargaining Pension Plan.

 

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

 
| **(Thousands of Dollars)**                         | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service  cost                                                |       | $        | 65,461     |     | $          | 62,698   |       | $ | 61,392 |   |
| Interest  cost                                               |       | 169,790  |       | 167,881  |       | 162,774  |       |
| Expected  return on plan assets                              |       | (256,538 | )          | (274,338 | )          | (264,831 | )          |
| Amortization  of prior service cost                          |       | 24,618   |       | 20,584   |       | 25,056   |       |
| Amortization  of net loss                                    |       | 12,455   |       | 11,156   |       | 15,845   |       |
| Net  periodic pension cost(credit)                           |       | $        | 15,786     |     | $          | (12,019  | )          | $ | 236 |   |
|                                                         |       |     |       |     |       |     |       |
| **NSP-Minnesota****:**                                       |       |     |       |     |       |     |       |
| Net  periodic pension cost (credit)                          |       | $        | 2,891      |     | $          | (9,034   | )          | $ | (9,682 | ) |
| (Costs)  credits not recognized due to effects of regulation |       | (2,891   | )          | 9,034    |       | 11,147   |       |
| Net  benefit cost recognized for financial reporting         |       | $        | —     |     | $          | —   |       | $ | 1,465 |   |
|                                                         |       |     |       |     |       |     |       |
| **Significant Assumptions Used to Measure Costs****:**       |       |     |       |     |       |     |       |
| Discount  rate for year-end valuation                        |       | 6.75     | %          | 6.25     | %          | 6.00     | %          |
| Expected  average long-term increase in compensation level   |       | 4.00     |       | 4.00     |       | 4.00     |       |
| Expected  average long-term rate of return on assets         |       | 8.50     |       | 8.75     |       | 8.75     |       |

 

Pensioncosts include an expected return impact for the current year that may differfrom actual investment performance in the plan. The return assumption used for 2010 pension cost calculations will be 7.79 percent.  The cost calculation uses a market-relatedvaluation of pension assets.  XcelEnergy, including NSP-Minnesota, uses a calculated value method to determinethe market-related value of the plan assets. The market-related value begins with the fair market value of assets asof 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 percentper year.

 

Xcel Energy, which includesNSP-Minnesota, also maintains noncontributory, defined benefit supplementalretirement income plans for certain qualifying executive personnel.  Benefits for these unfunded plans are paidout of their operating cash flows.

 

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** **

**Defined Contribution Plans**

** **

XcelEnergy, which includes NSP-Minnesota, maintains 401(k) and other definedcontribution plans that cover substantially all employees.  The contributions for NSP-Minnesota wereapproximately $7.5 million in 2009 and $4.2 million in 2008 and 2007.

 

**Postretirement Health CareBenefits**

** **

XcelEnergy, which includes NSP-Minnesota, has a contributory health and welfarebenefit plan that provides health care and death benefits to most Xcel Energyretirees.  The former NCE discontinuedcontributing toward health care benefits for nonbargaining employees retiringafter 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin whoretired after 1999.  Employees of theformer NCE who retired after 1998 are eligible to participate in the healthcare program with no employer subsidy.

 

In1993, Xcel Energy and NSP-Minnesota adopted accounting guidance regarding othernon-pension postretirement benefits and elected to amortize the unrecognizedaccumulated postretirement benefit obligation (APBO) on a straight-line basisover 20 years.

 

Regulatoryagencies for nearly all retail and wholesale utility customers have allowedrate recovery of accrued postretirement benefit costs.  NSP-Minnesota transitioned to full accrualaccounting for postretirement benefit costs, with regulatory differences fullyamortized prior to 1997.

 

***Plan Assets***— Certain stateagencies that regulate Xcel Energy’s utility subsidiaries also have issuedguidelines related to the funding of postretirement benefit costs.  Also, a portion of the assets contributed onbehalf of non-bargaining retirees has been funded into a sub-account of thepension plans.  These assets are investedin a manner consistent with the investment strategy for the pension plan.

 

XcelEnergy  and NSP-Minnesota baseinvestment-return assumption for the postretirement health care fund assets onexpected long-term performance for each of the investment types included in theasset portfolio.  The assets are investedin a portfolio according to Xcel Energy’s and NSP-Minnesota’s return, liquidityand diversification objectives to provide a source of funding for planobligations and minimize the necessity of contributions to the plan, withinappropriate levels of risk.  Theprincipal mechanism for achieving these objectives is the allocation of assetsto selected asset classes, given the long-term risk, return, and liquiditycharacteristics of each particular asset class. There were no significant concentrations of risk in any particular industry,index, or entity.  Investment-returnvolatility is not considered to be a material factor in postretirement healthcare costs.

 

The following tablepresents, for each of the fair value hierarchy levels, postretirement benefitplan assets that are measured at fair value as of Dec. 31, 2009:

 
| **(Thousands of Dollars)**                | ** ** | **Level  1** | ** ** | **Level  2** | ** ** | **Level  3** | ** ** | **Total** | ** ** |
|-----------------------------------------------------|------------|--------------|------------|--------------|------------|--------------|------------|-----------|------------|
| Cash  equivalents                                   |       | $            | —     |         | $          | 165,291      |       | $         | —     |   | $ | 165,291 |   |
| Short  term investments                             |       | —       |       | 2,226        |       | —       |       | 2,226     |       |
| Derivatives                                         |       | —       |       | 5,937        |       | —       |       | 5,937     |       |
| Government  securities                              |       | —       |       | 1,538        |       | —       |       | 1,538     |       |
| Corporate  bonds                                    |       | —       |       | 60,416       |       | —       |       | 60,416    |       |
| Asset-backed &  mortgage-backed securities |       | —       |       | —       |       | 55,371       |       | 55,371    |       |
| Preferred  stock                                    |       | —       |       | 540          |       | —       |       | 540       |       |
| Registered  investment companies (mutual funds)     |       | —       |       | 89,296       |       | —       |       | 89,296    |       |
| Securities  lending collateral obligation and other |       | —       |       | 4,074        |       | —       |       | 4,074     |       |
| Total                                               |       | $            | —     |         | $          | 329,318      |       | $         | 55,371     |   | $ | 384,689 |   |

 

The following table presentsthe changes in Level 3 postretirement benefit plan assets for the year ended Dec. 31,2009:

 
| **(Thousands of Dollars)**                | ** ** | **Jan. 1, 2009** | ** ** | **Realized and  Unrealized  Gains** | ** ** | **Purchases,  Issuances, and  Settlements  (net)** | ** ** | **Dec. 31, 2009** | ** ** |
|-----------------------------------------------------|------------|----------------------------|------------|------------------------------------------|------------|---------------------------------------------------------|------------|-----------------------------|------------|
| Asset-backed &  mortgage-backed securities |       | $                          | 78,693     |                                     | $          | 4,051                                                   |       | $                           | (27,373    | ) | $ | 55,371 |   |
|                                                     |            |                            |            |                                          |            |                                                         |            |                             |            |  |  |  |  |

 

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***Benefit Obligations***— A comparisonof the actuarially computed benefit obligation and plan assets, on a combinedbasis,  is presented in the followingtable:

 
| **(Thousands of Dollars)**                                                                                        | ** ** | **2009**            | ** ** | **2008**            | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|---------------------|------------|
| **Change in Projected Benefit Obligation:**                                                                                 |       |                |       |                |       |
| Obligation  at Jan. 1                                                                                                  |       | $                   | 794,597    |                | $          | 830,315 |   |
| Service  cost                                                                                                               |       | 4,665               |       | 5,350               |       |
| Interest  cost                                                                                                              |       | 50,412              |       | 51,047              |       |
| Medicare  subsidy reimbursements                                                                                            |       | 3,226               |       | 6,178               |       |
| Plan  amendments                                                                                                            |       | (27,407             | )          | —              |       |
| Plan  participants’ contributions                                                                                      |       | 13,786              |       | 13,892              |       |
| Actuarial  gain                                                                                                             |       | (47,446             | )          | (46,827             | )          |
| Benefit  payments                                                                                                           |       | (62,931             | )          | (65,358             | )          |
| Obligation  at Dec. 31                                                                                                 |       | $                   | 728,902    |                | $          | 794,597 |   |
|                                                                                                                        |       |                |       |                |       |
| **Change in Fair Value of Plan Assets:**                                                                                    |       |                |       |                |       |
| Fair  value of plan assets at Jan. 1                                                                                   |       | $                   | 299,566    |                | $          | 427,459 |   |
| Actual  return (loss) return on plan assets                                                                                 |       | 72,101              |       | (132,226            | )          |
| Plan  participants’ contributions                                                                                      |       | 13,786              |       | 13,892              |       |
| Employer  contributions                                                                                                     |       | 62,167              |       | 55,799              |       |
| Benefit  payments                                                                                                           |       | (62,931             | )          | (65,358             | )          |
| Fair  value of plan assets at Dec. 31                                                                                  |       | $                   | 384,689    |                | $          | 299,566 |   |
|                                                                                                                        |       |                |       |                |       |
| **Funded Status of Plans at Dec. 31:**                                                                                 |       |                |       |                |       |
| Funded  status                                                                                                              |       | $                   | (344,213   | )                   | $          | (495,031 | ) |
| Current  liabilities                                                                                                        |       | (2,240              | )          | (4,928              | )          |
| Noncurrent  liabilities                                                                                                     |       | (341,973            | )          | (490,103            | )          |
| Net  pension amounts recognized on consolidated balance sheets                                                              |       | $                   | (344,213   | )                   | $          | (495,031 | ) |
|                                                                                                                        |       |                |       |                |       |
| **NSP-Minnesota Amounts Not Yet Recognized as Components of  Net Periodic Benefit Cost:**                                   |       |                |       |                |       |
| Net  loss                                                                                                                   |       | $                   | 49,444     |                | $          | 78,140 |   |
| Net  prior service credit                                                                                                   |       | (1,152              | )          | —              |       |
| Transition  obligation                                                                                                      |       | 4,073               |       | 5,419               |       |
| Total                                                                                                                       |       | $                   | 52,365     |                | $          | 83,559 |   |
|                                                                                                                        |       |                |       |                |       |
| **Amounts Related to the Funded Status of the Plans Have Been  Recorded as Follows Based Upon Expected Recovery in Rates:** |       |                |       |                |       |
| Regulatory  assets                                                                                                          |       | $                   | 49,240     |                | $          | 80,105 |   |
| Deferred  Income taxes                                                                                                      |       | 1,277               |       | 1,411               |       |
| Net-of-tax  accumulated comprehensive income                                                                                |       | 1,848               |       | 2,043               |       |
| Total                                                                                                                       |       | $                   | 52,365     |                | $          | 83,559 |   |
|                                                                                                                        |       |                |       |                |       |
| NSP-Minnesota  accrued benefit liability recorded                                                                           |       | $                   | 124,657    |                | $          | 152,792 |   |
|                                                                                                                        |       |                |       |                |       |
| Measurement  date                                                                                                           |       | Dec. 31,  2009 |       | Dec. 31,  2008 |       |
|                                                                                                                        |       |                |       |                |       |
| **Significant Assumptions Used to Measure Benefit  Obligations:**                                                           |       |                |       |                |       |
| Discount  rate for year-end valuation                                                                                       |       | 6.00                | %          | 6.75                | %          |
| Mortality  table                                                                                                            |       | RP 2000             |       | RP 2000             |       |

 

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EffectiveDec. 31, 2009, Xcel Energy and NSP-Minnesota reduced the initial medicaltrend assumption from 7.4 percent to 6.8 percent.  The ultimate trend assumption remainedunchanged at 5.0 percent.  Theperiod until the ultimate rate is reached is three years.  Xcel Energy and NSP-Minnesota base themedical trend assumption on the long-term cost inflation expected in the healthcare market, considering the levels projected and recommended by industryexperts, as well as recent actual medical cost increases experienced by theretiree medical plan.

 

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

 
| **(Thousands of Dollars)**                                             |   |    |   |
|----------------------------------------------------------------------------------|--------|---------|--------|
| 1-percent  increase in APBO components of Dec. 31, 2009                     |   | $       | 12,757 |   |
| 1-percent  decrease in APBO components of Dec. 31, 2009                     |   | (10,801 | )      |
| 1-percent  increase in service and interest components of the net periodic cost. |   | 1,123   |   |
| 1-percent  decrease in service and interest components of the net periodic cost. |   | (933    | )      |
|                                                                                  |        |         |        |  |

 

***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.  Additional cash funding requirements areprescribed by certain state and federal rate regulatory authorities, asdiscussed previously.  Xcel Energy, whichincludes NSP-Minnesota, contributed $62.2 million during 2009 and $55.6 millionduring 2008 and expects to contribute approximately $45.4 million during 2010.

 

***Plan Amendments —***The decrease inthe projected benefit obligation for the plan amendment is due to a change inthe medical experience rate resulting from negotiations with the PSCoBargaining Postretirement Health Care Plan.

 

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

 
| **(Thousands of Dollars)**                              | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service  cost                                                     |       | $        | 4,665      |     | $          | 5,350    |       | $ | 5,813 |   |
| Interest  cost                                                    |       | 50,412   |       | 51,047   |       | 50,475   |       |
| Expected  return on plan assets                                   |       | (22,775  | )          | (31,851  | )          | (30,401  | )          |
| Amortization  of transition obligation                            |       | 14,444   |       | 14,577   |       | 14,577   |       |
| Amortization  of prior service cost                               |       | (2,726   | )          | (2,175   | )          | (2,178   | )          |
| Amortization  of net loss                                         |       | 19,329   |       | 11,498   |       | 14,198   |       |
| Net  periodic postretirement benefit cost                         |       | $        | 63,349     |     | $          | 48,446   |       | $ | 52,484 |   |
|                                                              |       |     |       |     |       |     |       |
| **NSP-Minnesota**:                                                |       |     |       |     |       |     |       |
| Net  periodic postretirement benefit cost                         |       | 13,419   |       | 13,958   |       | 13,761   |       |
|                                                              |       |     |       |     |       |     |       |
| **Significant Assumptions Used to Measure Costs**:                |       |     |       |     |       |     |       |
| Discount  rate for year-end valuation                             |       | 6.75     | %          | 6.25     | %          | 6.00     | %          |
| Expected  average long-term rate of return on assets (before tax) |       | 7.50     |       | 7.50     |       | 7.50     |       |

 

# **Benefit Payments**

#  

Thefollowing table lists the projected benefit payments for the pension andpostretirement benefit plans.

 
| **(Thousands of Dollars)** | ** ** | **Projected  Pension  Benefit Payments** | ** ** | **Gross  Projected  Postretirement  Health Care  Benefit Payments** | ** ** | **Expected  Medicare Part D  Subsidies** | ** ** | **Net  Projected  Postretirement  Health Care  Benefit Payments** | ** ** |
|--------------------------------------|------------|------------------------------------------|------------|---------------------------------------------------------------------|------------|-----------------------------------------------|------------|-------------------------------------------------------------------|------------|
| 2010                                 |       | $                                        | 238,929    |                                                                | $          | 58,738                                        |       | $                                                                 | 4,901      |   | $ | 53,837 |   |
| 2011                                 |       | 230,833                                  |       | 60,202                                                              |       | 5,184                                         |       | 55,018                                                            |       |
| 2012                                 |       | 234,256                                  |       | 60,665                                                              |       | 5,529                                         |       | 55,136                                                            |       |
| 2013                                 |       | 237,817                                  |       | 60,785                                                              |       | 5,841                                         |       | 54,944                                                            |       |
| 2014                                 |       | 244,160                                  |       | 61,260                                                              |       | 6,075                                         |       | 55,185                                                            |       |
| 2015-2019                            |       | 1,256,824                                |       | 313,040                                                             |       | 33,598                                        |       | 279,442                                                           |       |
|                                      |            |                                          |            |                                                                     |            |                                               |            |                                                                   |            |  |  |  |  |

 

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**9.****    ****OtherIncome, Net**

 

Other income (expense), netfor the years ended Dec. 31 consisted of the following:

 
| **(Thousands of Dollars)** | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest  income                     |       | $        | 7,473      |     | $          | 10,005   |       | $ | 10,208 |   |
| Other  nonoperating (expense) income |       | (6       | )          | 1,274    |       | 1,818    |       |
| Insurance  policy expenses           |       | (5,895   | )          | (384     | )          | (5,921   | )          |
| Other  income, net                   |       | $        | 1,572      |     | $          | 10,895   |       | $ | 6,105 |   |

 

**10.**  DerivativeInstruments

** **

EffectiveJan. 1, 2009, NSP-Minnesota adopted new guidance on disclosures aboutderivative instruments and hedging activities contained in *ASC 815 Derivatives and Hedging*, whichrequires additional disclosures regarding why an entity uses derivativeinstruments, the volume of an entity’s derivative activities, the fair valueamounts recorded to the consolidated balance sheet for derivatives, the gainsand losses on derivative instruments included in the consolidated statement ofincome or deferred, and information regarding certain credit-risk-relatedcontingent features in derivative contracts.

 

NSP-Minnesotaenters into derivative instruments, including forward contracts, futures, swapsand options, for trading purposes and to reduce risk in connection with changesin interest rates, utility commodity prices and vehicle fuel prices, as well asvariances in forecasted weather.  Seeadditional information pertaining to the valuation of derivative instruments inNote 12 to the consolidated financial statements.

 

***Interest Rate Derivatives —***NSP-Minnesotaenters into various instruments that effectively fix the interest payments oncertain floating rate debt obligations or effectively fix the yield or price ona specified benchmark interest rate for a specific period.  These derivative instruments are generallydesignated as cash flow hedges for accounting purposes.

 

AtDec. 31, 2009, accumulated other comprehensive income related to interestrate derivatives included $0.2 million of net gains expected to be reclassifiedinto earnings during the next 12 months as the related hedged interesttransactions impact earnings.

 

***Commodity Derivatives —***NSP-Minnesota enters intoderivative instruments to manage variability of future cash flows from changesin commodity prices in its electric and natural gas operations, as well as fortrading purposes.  This could include thepurchase or sale of energy or energy-related products, natural gas to generateelectric energy, gas for resale, and vehicle fuel.

 

AtDec. 31, 2009, NSP-Minnesota had vehicle fuel contracts designated as cashflow hedges extending through December 2012.  NSP-Minnesota also enters into derivativeinstruments that mitigate commodity price risk on behalf of electric andnatural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivativeinstruments are recorded in other comprehensive income or deferred as aregulatory asset or liability.  Theclassification as a regulatory asset or liability is based on commission approvedregulatory recovery mechanisms.  NSP-Minnesota recorded immaterial amounts to incomerelated to the ineffectiveness of cash flow hedges for the year ended Dec. 31,2009.

 

AtDec. 31, 2009, accumulated other comprehensive income related to vehiclefuel cash flow hedges included $1.8 million of net losses expected to bereclassified into earnings during the next 12 months as the hedgedtransactions occur.

 

Additionally, NSP-Minnesota enters intocommodity derivative instruments for trading purposes not directly related tocommodity price risks associated with serving its electric and natural gascustomers.  Changes in the fair value ofthese commodity derivatives are recorded in income, subject to applicablecustomer margin-sharing mechanisms.

 

NSP-Minnesota had noderivative instruments designated as fair value hedges during the year ended Dec. 31,2009.  Therefore, no gains or losses fromfair value hedges or related hedged transactions for the period wererecognized.

 

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Thefollowing table shows the major components of derivative instruments valuationin the consolidated balance sheets:

 
| ** **                            | ** ** | **2009**             | ** ** | **2008**             | ** ** |
|---------------------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                            | ** ** | **Derivative**       | ** ** | **Derivative**       | ** ** | **Derivative** | ** ** | **Derivative** | ** ** |
| ** **                            | ** ** | **Instruments**      | ** ** | **Instruments**      | ** ** | **Instruments** | ** ** | **Instruments** | ** ** |
| ** **                            | ** ** | **Valuation -** | ** ** | **Valuation -** | ** ** | **Valuation -** | ** ** | **Valuation -** | ** ** |
| **(Thousands of Dollars)**  | ** ** | **Assets**           | ** ** | **Liabilities**      | ** ** | **Assets** | ** ** | **Liabilities** | ** ** |
| Long-term  purchased power agreements |       | $                    | 127,164    |                 | $          | 216,191 |   | $ | 151,884 |   | $ | 230,715 |   |
| Commodity  derivatives                |       | 49,534               |       | 17,998               |       | 47,973 |   | 28,522 |   |
| Total                                 |       | $                    | 176,698    |                 | $          | 234,189 |   | $ | 199,857 |   | $ | 259,237 |   |

 

In 2003, as a result of implementing newguidance on the normal purchase exception for derivative accounting containedin *ASC 815 Derivatives and Hedging*,NSP-Minnesota began recording several long-termpurchased power agreements at fair value due to accounting requirements relatedto underlying price adjustments.  As thesepurchases are recovered through normal regulatory recovery mechanisms in therespective jurisdictions, the changes in fair value for these contracts wereoffset by regulatory assets and liabilities. During 2006, 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 CashFlow Hedges —***The impact of qualifying interest rate and vehiclefuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensiveincome, included as a component of common stockholder’s equity, is detailed inthe following tables:

 
| **(Thousands of Dollars)**                                                          | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Accumulated  other comprehensive income related to cash flow hedges at Jan. 1            |       | $        | 3,053      |     | $          | 8,704    |       | $ | 9,432 |   |
| After-tax  net unrealized losses related to derivatives accounted for as hedges               |       | (1,219   | )          | (5,463   | )          | (346     | )          |
| After-tax  net realized losses (gains) on derivative transactions reclassified into  earnings |       | 2,107    |       | (188     | )          | (382     | )          |
| Accumulated  other comprehensive income related to cash flow hedges at Dec. 31           |       | $        | 3,941      |     | $          | 3,053    |       | $ | 8,704 |   |

 

The following table detailsthe fair value of commodity derivatives recorded to derivative instrumentsvaluation in the consolidated balance sheet, by category:

 
| ** **                                   | ** ** | **Dec. 31,  2009** | ** ** |
|----------------------------------------------|------------|-------------------------|------------|
| ** **                                   | ** ** | ** **              | ** ** | ** ** | ** ** | **Derivative** | ** ** |
| ** **                                   | ** ** | ** **              | ** ** | **Counterparty** | ** ** | **Instruments** | ** ** |
| **(Thousands of Dollars)**         | ** ** | **Fair  Value**         | ** ** | **Netting****(a)** | ** ** | **Valuation** | ** ** |
| **Current derivative assets**                |       |                    |       |   |   |   |   |
| Other  derivative instruments:               |       |                    |       |   |   |   |   |
| Trading  commodity                           |       | $                       | 19,999     |   | $ | (11,638 | ) | $ | 8,361 |   |
| Electric  commodity                          |       | 23,540                  |       | 1,425 |   | 24,965 |   |
| Natural  gas commodity                       |       | 1,580                   |       | 54 |   | 1,634 |   |
| Total  current derivative assets             |       | $                       | 45,119     |   | $ | (10,159 | ) | $ | 34,960 |   |
|                                         |       |                    |       |   |   |   |   |
| **Noncurrent derivative assets**             |       |                    |       |   |   |   |   |
| Derivatives  designated as cash flow hedges: |       |                    |       |   |   |   |   |
| Vehicle  fuel and other commodity            |       | $                       | 85         |   | $ | — |   | $ | 85 |   |
| Other  derivative instruments:               |       |                    |       |   |   |   |   |
| Trading  commodity                           |       | 18,650                  |       | (4,193 | ) | 14,457 |   |
| Natural  gas commodity                       |       | 31                      |       | 1 |   | 32 |   |
|                                         |       | 18,681                  |       | (4,192 | ) | 14,489 |   |
| Total  noncurrent derivative assets          |       | $                       | 18,766     |   | $ | (4,192 | ) | $ | 14,574 |   |

 

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| ** **                                   | ** ** | **Dec. 31,  2009** | ** ** |
|----------------------------------------------|------------|-------------------------|------------|
| ** **                                   | ** ** | ** **              | ** ** | ** ** | ** ** | **Derivative** | ** ** |
| ** **                                   | ** ** | ** **              | ** ** | **Counterparty** | ** ** | **Instruments** | ** ** |
| **(Thousands of Dollars)**         | ** ** | **Fair  Value**         | ** ** | **Netting****(a)** | ** ** | **Valuation** | ** ** |
| **Current derivative liabilities**           |       |                    |       |   |   |   |   |
| Derivatives  designated as cash flow hedges: |       |                    |       |   |   |   |   |
| Vehicle  fuel and other commodity            |       | $                       | 2,266      |   | $ | — |   | $ | 2,266 |   |
|                                         |       |                    |       |   |   |   |   |
| Other  derivative instruments:               |       |                    |       |   |   |   |   |
| Trading  commodity                           |       | 17,979                  |       | (15,504 | ) | 2,475 |   |
| Electric  commodity                          |       | 3,276                   |       | 1,425 |   | 4,701 |   |
| Natural  gas commodity                       |       | 640                     |       | 54 |   | 694 |   |
|                                         |       | 21,895                  |       | (14,025 | ) | 7,870 |   |
| Total  current derivative liabilities        |       | $                       | 24,161     |   | $ | (14,025 | ) | $ | 10,136 |   |
|                                         |       |                    |       |   |   |   |   |
| **Noncurrent derivative liabilities**        |       |                    |       |   |   |   |   |
| Other  derivative instruments:               |       |                    |       |   |   |   |   |
| Trading  commodity                           |       | $                       | 11,694     |   | $ | (4,197 | ) | $ | 7,497 |   |
| Natural  gas commodity                       |       | 364                     |       | 1 |   | 365 |   |
| Total  noncurrent derivative liabilities     |       | $                       | 12,058     |   | $ | (4,196 | ) | $ | 7,862 |   |

 

(a)* **ASC 815**Derivatives and Hedging* permits the netting of receivablesand payables for derivatives and related collateral amounts when a legallyenforceable master netting agreement exists between Xcel Energy and acounterparty.  A master netting agreementis an agreement between two parties who have multiple contracts with each otherthat provides for the net settlement of all contracts in the event of defaulton or termination of any one contract.

 

Thefollowing table details the impact of derivative activity during the year endedDec. 31, 2009, on other comprehensive income, regulatory assets andliabilities, and income:

 
| ** **                                     | ** ** | **Fair  Value Changes Recognized** | ** ** | **Pre-Tax  Amounts Reclassified into** | ** ** | ** **                  | ** ** |
|------------------------------------------------|------------|------------------------------------|------------|----------------------------------------|------------|-----------------------------|------------|
| ** **                                     | ** ** | **During  the Period in:**         | ** ** | **Income  During the Period from:**    | ** ** | **Pre-Tax  Gains (Losses)** | ** ** |
| ** **                                     | ** ** | **Other**                          | ** ** | **Regulatory**                         | ** ** | **Other**                   | ** ** | **Regulatory** | ** ** | **Recognized** | ** ** |
| ** **                                     | ** ** | **Comprehensive**                  | ** ** | **Assets  and**                        | ** ** | **Comprehensive**           | ** ** | **Assets  and** | ** ** | **During  the Period** | ** ** |
| **(Thousands of Dollars)**           | ** ** | **Income  (Loss)**                 | ** ** | **Liabilities**                        | ** ** | **Income  (Loss)**          | ** ** | **Liabilities** | ** ** | **in  Income** | ** ** |
| ** **                                     | ** ** | ** **                         | ** ** | ** **                             | ** ** | ** **                  | ** ** | ** ** |   |   |   |
| **Derivatives designated as cash flow hedges** | ** ** | ** **                         | ** ** | ** **                             | ** ** | ** **                  | ** ** | ** ** |   |   |   |
| Interest  rate                                 |       | $                                  | (3,209     | )                                      | $          |                        | $          | (201 | )(a) | $ |   | $ | ** ** |
| Electric  commodity                            |       |                               |       | (18,600                                | )          |                        |       | (4,755) | (c) |   |   |
| Natural  gas commodity                         |       |                               |       | (811                                   | )          |                        |       | 8,915 | (d) | (6,951 | )(d) |
| Vehicle  fuel and other commodity              |       | 1,147                              |       |                                   |       | 3,766                       | (e)        |   |   |   |   |
| Total                                          |       | $                                  | (2,062     | )                                      | $          | (19,411                     | )          | $ | 3,565 |   | $ | 4,160 |   | $ | (6,951 | ) |
|                                           |       |                               |       |                                   |       |                        |       |   |   |   |   |
| **Other derivative instruments**               |       |                               |       |                                   |       |                        |       |   |   |   |   |
| Trading  commodity                             |       |                               |       |                                   |       |                        |       |   |   | 7,857 | (b) |
| Electric  commodity                            |       |                               |       | 20,607                                 |       |                        |       | (343) | (c) |   |   |
| Natural  gas commodity                         |       |                               |       | (373                                   | )          |                        |       | 980 | (d) |   |   |
| Other                                          |       |                               |       |                                   |       |                        |       |   |   | (160 | )(b) |
| Total                                          |       | $                                  | —     |                                   | $          | 20,234                      |       | $ | — |   | $ | 637 |   | $ | 7,697 |   |

 

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(a)              Recorded to interest charges.

(b)             Recorded to electric operating revenues.  Portions of these gains and losses are sharedwith electric customers through margin-sharing mechanisms and    deducted from gross revenue, asappropriate.

(c)              Recorded toelectric fuel and purchased power; these derivative settlement gains and lossesare shared with electric customers through fuel and    purchased energy cost-recovery mechanisms,and reclassified out of income as regulatory assets or liabilities, asappropriate.

(d)             Recorded to costof natural gas sold and transported; these derivative settlement gains andlosses are shared with natural gas customers through purchased natural gascost-recovery mechanisms, and reclassified out of income as regulatory assetsor liabilities, as appropriate.

(e)              Recorded to other operatingand maintenance expenses.

 

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At Dec. 31, 2009, commodity derivatives recordedto derivative instruments valuation included derivative contracts with grossnotional amounts of approximately 34,374,000 megawatt hours (MwH) ofelectricity, 9,777,000 MMBtu of natural gas and 2,021,000 gallons of vehiclefuel.  These amounts reflect the grossnotional amounts of futures, forwards and financial transmission rights and arenot reflective of net positions in the underlying commodities.  Notional amounts for options are alsoincluded on a gross basis, but are weighted for the probability of exercise.

 

***Credit RelatedContingent Features******—*** Contract provisions of the derivativeinstruments that NSP-Minnesota enters into may require the posting ofcollateral or settlement of the contracts for various reasons, including ifNSP-Minnesota is unable to maintain its credit rating.****** If the credit rating of NSP-Minnesota at Dec. 31,2009 were downgraded below investment grade, no contracts underlyingNSP-Minnesota’s derivative liabilities would require the posting of collateralor contract settlement upon the downgrade.

 

Certain of NSP-Minnesota’s derivative instruments arealso subject to contract provisions that contain adequate assuranceclauses.  These provisions allowcounterparties to seek performance assurance, including cash collateral, in theevent that NSP-Minnesota’s ability to fulfill its contractual obligations isreasonably expected to be impaired.  Asof Dec. 31, 2009, NSP-Minnesota had no collateral posted related toadequate assurance clauses in derivative contracts.

 

**11. Financial Instruments**

 

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

 
| ** **                                 | ** ** | **2009**             | ** ** | **2008**        | ** ** |
|--------------------------------------------|------------|----------------------|------------|-----------------|------------|
| **(Thousands of Dollars)**       | ** ** | **Carrying  Amount** | ** ** | **Fair  Value** | ** ** | **Carrying  Amount** | ** ** | **Fair  Value** | ** ** |
| Nuclear  decommissioning fund              |       | $                    | 1,248,739  |            | $          | 1,248,739 |   | $ | 1,075,294 |   | $ | 1,075,294 |   |
| Other  investments                         |       | 695                  |       | 695             |       | 725 |   | 725 |   |
| Long-term  debt, including current portion |       | 3,013,178            |       | 3,238,854       |       | 2,962,749 |   | 3,100,223 |   |
|                                            |            |                      |            |                 |            |  |  |  |  |  |  |  |  |

 

The fair value of cash andcash equivalents, notes and accounts receivable and notes and accounts payableare not materially different from their carrying amounts.  The fair value of NSP-Minnesota’s nucleardecommissioning fund is based on published trading data and pricing models,generally using the most observable inputs available for each class ofsecurity.  The fair value ofNSP-Minnesota’s other investments are estimated based on quoted market pricesfor those or similar investments.  Thefair value of NSP-Minnesota’s long-term debt is estimated based on the quotedmarket prices for the same or similar issues, or the current rates for debt ofthe same remaining maturities and credit quality.

 

Thefair value estimates presented are based on information available to managementas of Dec. 31, 2009 and 2008.  Thesefair value estimates have not been comprehensively revalued for purposes ofthese consolidated financial statements since that date, and current estimatesof fair values may differ significantly.

 

**Letters of Credit**

** **

NSP-Minnesotauses letters of credit, generally with terms of one year, to provide financialguarantees for certain operating obligations. At Dec. 31, 2009 and 2008, there were $6.9 million letters ofcredit outstanding.  The contract amountsof these letters of credit approximate their fair value and are subject to feesdetermined in the marketplace.

 

**12.****      ****Fair Value Measurements**

 

Effective Jan. 1, 2008, NSP-Minnesota adopted new guidance for recurring fair valuemeasurements contained in *ASC 820 Fair ValueMeasurements and Disclosures* which provides a single definition offair value and requires enhanced disclosures about assets and liabilitiesmeasured at fair value.  A hierarchalframework for disclosing the observability of the inputs utilized in measuringassets and liabilities at fair value was established by this guidance.  The three levels in the hierarchy andexamples of each level are as follows:

 

Level 1 — Quoted pricesare available in active markets for identical assets or liabilities as of thereported date.  The types of assets and liabilitiesincluded in Level 1 are highly liquid and actively traded instruments withquoted prices, such as equities listed by the New York Stock Exchange andcommodity derivative contracts listed on the New York Mercantile Exchange.

 

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Level 2 — Pricing inputsare other than quoted prices in active markets, but are either directly orindirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typicallyeither comparable to actively traded securities or contracts, such as treasurysecurities with pricing interpolated from recent trades of similar securities,or priced with models using highly observable inputs, such as commodity optionspriced using observable forward prices and volatilities.

 

Level 3 — Significantinputs to pricing have little or no observability as of the reportingdate.  The types of assets and liabilitiesincluded in Level 3 are those with inputs requiring significant managementjudgment or estimation, such as the complex and subjective models and forecastsused to determine the fair value of financial transmission rights.

 

NSP-Minnesota continuously monitorsthe creditworthiness of the counterparties to its commodity derivativecontracts and assesses each counterparty’s ability to perform on thetransactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of NSP-Minnesota’sown credit risk when determining the fair value of commodity derivativeliabilities, the impact of considering credit risk was immaterial to the fairvalue of commodity derivative assets and liabilities presented in theconsolidated balance sheets.

 

Thefollowing tables present, for each of these hierarchy levels, NSP-Minnesota’sassets and liabilities that are measured at fair value on a recurring basis:

 
| ** **                           | ** ** | **Dec. 31,  2009** | ** ** |
|--------------------------------------|------------|-------------------------|------------|
| ** **                           | ** ** | ** **              | ** ** | ** ** | ** ** | ** ** | ** ** | **Counterparty** | ** ** | ** ** | ** ** |
| **(Thousands of Dollars)** | ** ** | **Level 1**        | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Netting** | ** ** | **Net  Balance** | ** ** |
| **Assets**                           |       |                    |       |   |   |   |   |   |   |   |   |
| Nuclear  decommissioning fund        |       |                    |       |   |   |   |   |   |   |   |   |
| Cash  equivalents                    |       | $                       | —     |   | $ | 28,134 |   | $ | — |   | $ | — |   | $ | 28,134 |   |
| Debt  securities                     |       | —                  |       | 545,503 |   | 93,107 |   | — |   | 638,610 |   |
| Equity  securities                   |       | 581,995                 |       | — |   | — |   | — |   | 581,995 |   |
| Commodity  derivatives               |       | —                  |       | 22,481 |   | 41,404 |   | (14,351 | ) | 49,534 |   |
| Total                                | ** ** | **$**                   | 581,995    | ** ** | **$** | 596,118 | ** ** | **$** | 134,511 | ** ** | **$** | (14,351 | ) | **$** | 1,298,273 | ** ** |
|                                 |       |                    |       |   |   |   |   |   |   |   |   |
| **Liabilities**                      |       |                    |       |   |   |   |   |   |   |   |   |
| Commodity  derivatives               |       | $                       | —     |   | $ | 22,052 |   | $ | 14,167 |   | $ | (18,221 | ) | $ | 17,998 |   |

 
| ** **                           | ** ** | **Dec. 31,  2008** | ** ** |
|--------------------------------------|------------|-------------------------|------------|
| ** **                           | ** ** | ** **              | ** ** | ** ** | ** ** | ** ** | ** ** | **Counterparty** | ** ** | ** ** | ** ** |
| **(Thousands of Dollars)** | ** ** | **Level 1**        | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Netting** | ** ** | **Net  Balance** | ** ** |
| **Assets**                           |       |                    |       |   |   |   |   |   |   |   |   |
| Nuclear  decommissioning fund        |       |                    |       |   |   |   |   |   |   |   |   |
| Cash  equivalents                    |       | $                       | —     |   | $ | 8,449 |   | $ | — |   | $ | — |   | $ | 8,449 |   |
| Debt  securities                     |       | —                  |       | 491,486 |   | 109,423 |   | — |   | 600,909 |   |
| Equity  securities                   |       | 465,936                 |       | — |   | — |   | — |   | 465,936 |   |
| Commodity  derivatives               |       | —                  |       | 17,039 |   | 38,207 |   | (7,273 | ) | 47,973 |   |
| Total                                | ** ** | **$**                   | 465,936    | ** ** | **$** | 516,974 | ** ** | **$** | 147,630 | ** ** | **$** | (7,273 | ) | **$** | 1,123,267 | ** ** |
|                                 |       |                    |       |   |   |   |   |   |   |   |   |
| **Liabilities**                      |       |                    |       |   |   |   |   |   |   |   |   |
| Commodity  derivatives               | ** ** | **$**                   | —     | ** ** | **$** | 21,509 | ** ** | **$** | 14,960 | ** ** | **$** | (7,947 | ) | **$** | 28,522 | ** ** |

 

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The following table presents the changes inLevel 3 recurring fair value measurements:

 
| ** **                                                      | ** ** | **Dec. 31,** | ** ** |
|-----------------------------------------------------------------|------------|-------------------|------------|
| ** **                                                      | ** ** | **2009**          | ** ** | **2008** | ** ** |
| ** **                                                      | ** ** | **Commodity**     | ** ** | **Nuclear** | ** ** | **Commodity** | ** ** | **Nuclear** | ** ** |
| ** **                                                      | ** ** | **Derivatives,**  | ** ** | **Decommissioning** | ** ** | **Derivatives,** | ** ** | **Decommissioning** | ** ** |
| **(Thousands of Dollars)**                            | ** ** | **Net**           | ** ** | **Fund** | ** ** | **Net** | ** ** | **Fund** | ** ** |
| Balance  at Jan. 1                                         |       | $                 | 23,247     |   | $ | 109,423 |   | $ | 15,345 |   | $ | 108,656 |   |
| Purchases,  issuances, and settlements, net                     |       | (476              | )          | (28,356 | ) | (1,585 | ) | 12,198 |   |
| Transfers  into (out of) Level 3                                |       | 700               |       | — |   | (2,578 | ) | — |   |
| (Losses)  gains recognized in earnings                          |       | (3,115            | )          | — |   | 496 |   | — |   |
| Gains  (losses) recognized as regulatory assets and liabilities |       | 6,881             |       | 12,040 |   | 11,569 |   | (11,431 | ) |
| Balance  at Dec. 31                                        |       | $                 | 27,237     |   | $ | 93,107 |   | $ | 23,247 |   | $ | 109,423 |   |

 

Losseson Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31,2009, include $5.7 million of net unrealized gains relating to commodityderivatives held at Dec. 31, 2009. Gains on Level 3 commodity derivatives recognized in earnings for theyear ended Dec. 31, 2008, include $2.9 million of net unrealized gainsrelating to commodity derivatives held at Dec. 31, 2008.  Realized and unrealized gains and losses oncommodity trading activities are included in electric revenues.  Realized and unrealized gains and losses onnon-trading derivative instruments are recorded in other comprehensive incomeor deferred as regulatory assets and liabilities.  The classification as a regulatory asset orliability is based on the commission approved regulatory recoverymechanisms.  Realized and unrealizedgains and losses on nuclear decommissioning fund investments are deferred as acomponent of a nuclear decommissioning regulatory asset.

 

**13.  Rate Matters**

 

**NSP-Minnesota**

** **

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

*** ***

**Base Rate**

 

***NSP-MinnesotaElectric Rate Case***** —**In November 2008,NSP-Minnesota filed a request with the MPUC to increase Minnesota electricrates by $156 million annually. This request was later modified to $136 million.

 

In September 2009,the MPUC voted to approve a rate increase of approximately $91.4 million.  Aspart of its decision, the MPUC approved a 10-year life extension of thePrairie Island nuclear plant for purposes of determining depreciation anddecommissioning expenses, effective Jan. 1, 2009.  This decision reduced NSP-Minnesota’s overallrevenue deficiency by approximately $40 million, while at the same timereducing expense accruals by a corresponding amount.  A summary of the key terms is listed below:

 
| ** **                                                    | ** ** | **Revised Request** | ** ** | **Approved** | ** ** |
|---------------------------------------------------------------|------------|---------------------|------------|--------------|------------|
| Rate increase                                                 |       | $136 million        |       | $91 million  |       |
| Return on equity                                              |       | 11.0%               |       | 10.88%       |       |
| Equity ratio                                                  |       | 52.5%               |       | 52.5%        |       |
| Electric rate base                                            |       | $4.1 billion        |       | $4.1 billion |       |
| Depreciation life extension for Prairie Island  nuclear plant |       | 0 years             |       | 10 years     |       |

 

The writtenorder was issued Oct. 23, 2009. As of December 2009, NSP-Minnesota recorded a customerrefund of approximately $39.7 million to reflect the difference between interimrates that were implemented Jan. 2, 2009 and the amount approved by theMPUC.

 

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** **

***NSP-Minnesota Gas Rate Case*** — In November 2009,NSP-Minnesota filed a request with the MPUC to increase Minnesota gas rates by $16.2million for 2010, which represents a 2.8 percent overall increase in customerbills.  This request is based on a ROE of11 percent, an equity ratio of 52.46 percent and a rate base of $441 million.  NSP-Minnesota also requested an additionalincrease of $3.45 million, for recovery of pension funding costs effective Jan. 1,2011 to comply with federal law.   In December 2009,the MPUC voted to approve an interim rate increase of $11.1 million, subject torefund.  These rates went into effect on Jan. 11,2010.  The procedural schedule is listedbelow and a decision is expected in the fall of 2010.

** **

·                  Intervenor direct testimony on May 3,2010;

·                  NSP-Minnesota rebuttal testimony on June 2,2010;

·                  Surrebuttal testimony on June 15,2010;

·                  Evidentiary hearings on June 21-25,2010;

·                  Initial briefs on July 27, 2010;

·                  Reply briefs and proposed findings on Aug. 19,2010; and

·                  ALJ report on Oct. 1, 2010.

** **

**Electric, Purchased Gas and ResourceAdjustment Clauses**

 

***TCR Rider*—**The MPUC has approved a TCR rider, which allows annual adjustments toretail electric rates to provide recovery of incremental transmissioninvestments between rate cases.  The MPUCapproved a rider request to recover approximately $14 million in 2009.  NSP-Minnesota has a request pending seekingrecovery of $12.1 million in 2010.  TheOES recommended disallowance of $1.7 million of plant costs because one projectwas over budget and also recommended that the Brookings line, which is subjectto dispute at FERC on cost allocation not be recovered through the rider atthis time. The request is pending MPUC action.

 

***RES Rider* —**The MPUC has approved a rider to recover the costs for utility-owned projectsimplemented in compliance with the RES. In 2009, the MPUC approved the RES rider request to recoverapproximately $22 million in 2009.  In September 2009,NSP-Minnesota submitted its proposed RES rider, seeking to recover $45.6million in 2010.  The OES expressedconcerns because some of the projected costs were slightly higher than thelevels included in NSP-Minnesota’s certificate filings and requested additionalinformation, which has been provided. The request is pending MPUC action.

 

***MERP Rider***** —** The MPUC authorized NSP-Minnesota to recover costsrelated to environmental improvement projects amounting to approximately $113.7million in 2009 through the MERP rider.  In December 2009, the MPUCauthorized a new rate adjustment, which will recover approximately$116.7 million in 2010.

 

***Mercury Cost Rider *****—** The MPUC has approved mercury control plans for reducing mercuryemissions at the Sherco Unit 3 and A. S. King plants.  A sorbent injection control system was putinto service at Sherco Unit 3 in December 2009, with installation at A. S.King scheduled to be completed in December 2010.  Currently, the estimated project costs areapproximately $6.6 million for these two units, and the MPUC authorizedNSP-Minnesota to collect the 2010 revenue requirement associated with theseprojects, which is approximately $3.5 million, from customers through a mercuryrider in 2010.  On Dec. 21, 2009, NSP-Minnesotafiled the plans for mercury control at Sherco Units 1 and 2 with the MPUC andMPCA.  Assuming these plans are approved,NSP-Minnesota expects to file for recovery of the costs to implement theseplans through the mercury cost rider.  The planproposes a flexible program of testing and monitoring as new technology emergesand federal regulations change over the next several years.  The plan calls for the addition of sorbentinjection by the statutory deadline of the end of 2014.  The MPCA has six months to review the plan.

 

***SEP Rider*****—**In September 2009, the MPUCapproved  NSP-Minnesota proposed rider torecover approximately $2.5 million from its electric customers and $0.1 millionfrom its natural gas customers to recover costs related to SEP mandates and a cast iron natural gas pipereplacement project to reduce GHG emissions. The revised SEP rate recovery factors were placed into effect in October 2009.

 

***Energy Innovation Corridor (EIC) Initiative******—*** In December 2009,NSP-Minnesota filed a request with the MPUC for approval of specific projectstotaling $15 million including a $2 million deferral request.  TheEIC initiative will be a first-of-its-kind clean energy and transportationmodel in an established urban center in the upper Midwest.  The 2009legislation authorized rider cost recovery for MPUC approved projects,including NSP-Minnesota’s costs to relocate its facilities along thetransportation corridor.  Rider cost recovery is also authorized for MPUCapproved EIC projects that demonstrate the best energy efficiency managementpractices and the installation of innovative and sustainable energytechnologies and programs for transforming a mature urban center into anational model for the future development of transportation and energycorridors.   The EIC initiative will advance critical local, state,regional and federal efforts to invest in energy efficiency, transportationelectrification, renewable energy and smart grid technology.  MPUC actionis pending.

 

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***Annual Automatic Adjustment Report for2007/2008 —*** In September 2008, NSP-Minnesota filed itsannual automatic adjustment reports for July 1, 2007 through June 30,2008.  During that time period, $848.5million in fuel and purchased energy costs, including $258.8 million of MISOcharges, were recovered from Minnesota electric customers through the FCA.  In addition, approximately $680 millionof purchased natural gas and transportation costs were recovered through thePGA.   In February 2010, theMPUC voted to accept the 2008 natural gas annual automatic adjustment report.

 

***Annual Automatic Adjustment Report for2008/2009*****—** In September 2009,NSP-Minnesota filed its annual automatic adjustment reports for July 1,2008 through June 30, 2009.  Duringthat time period, $803.6 million in fuel and purchased energy costs wererecovered from Minnesota electric customers through the FCA.  In addition, approximately $499.4 million ofpurchased natural gas and transportation costs were recovered through thePGA.  Comments are due in May 2010on NSP-Minnesota’s 2008/2009 electric and natural gas annual automaticadjustment reports.  The request ispending MPUC action.

 

***Conservation Incentive Filing*****—** In July 2009, NSP-Minnesota filed its proposed incentive plan forachieving significantly higher DSM goals. The incentive would allow for sharing of savings of up to 15 percent ofthe net present value of benefits, depending on the level of savingsachieved.  In December 2009, theMPUC approved the proposed shared savings model.  The plan would allow NSP-Minnesota to earn ahigher incentive than under the previous method if it achieves the higher goalsestablished by the OES.  The amount ofthe incentive increases to the extent that NSP-Minnesota cost-effectivelyexceeds the goal.  A written order wasissued in January 2010.

 

***Gas Meter Module Failures*****—** Approximately 8,700 customers in the St.Cloud and East Grand Forks areas of Minnesota and about 4,000 customers in theFargo, N.D. area were under billed for a period of time during the 2007-2008heating season due to the failure of the automated meter reading (AMR) moduleinstalled on their natural gas meters. While the modules failed to register usage, the meters continued tofunction.

 

Pursuantto the NDPSC-approved plan, which provided customers with a $50 service qualitycredit for each customer experiencing a module failure, NSP-Minnesota beganimplementing the service quality credits and the rebilling of remaining NorthDakota customers in June 2009.  Intotal, NSP-Minnesota rebilled North Dakota customers approximately $1.5 millionfor the estimated gas usage during the module failure period.

 

InJuly 2009, NSP-Minnesota filed with the MPUC a withdrawal of its requestto rebill Minnesota customers experiencing a module failure, which the MPUCapproved in October 2009. NSP-Minnesota completed the customer refunds in January 2010.  In November 2009, NSP-Minnesotacompleted its dispute resolution with its provider of the AMR modules and meterreading services, and filed a summary of the resolution and proposeddisposition of any proceeds with the MPUC. MPUC action is pending.  NSP-Minnesotahas determined that a number of AMR modules designed for commercial customersare defective and as a result  broadenedits efforts to evaluate the performance of both gas and electric AMR modules.

 

***Annual Review of Remaining Lives —*** In February 2009,NSP-Minnesota filed a petition with the MPUC requesting an increase in proposedservice lives, salvage rates and resulting depreciation rates for its electricand gas production facilities and a depreciation study for other gas andelectric assets, effective Jan 1, 2009. In addition, the OES recommended a 10-year lengthening of depreciationlife of the Prairie Island nuclear plant. In July 2009, the MPUC approved the proposed service lives, salvagerates, and resulting depreciation rates effective Jan. 1, 2009, for plantin service, with the exception of the Prairie Island nuclear plant.  In the NSP-Minnesota electric rate case, theMPUC extended the depreciation life of the Prairie Island nuclear plant by 10years beyond the current license life in light of NSP-Minnesota’s applicationto extend the life of its nuclear plants by 20 years.

 

***Nuclear Decommissioning Expenses —***In June 2009, the MPUCissued its order in its review of NSP-Minnesota’s 2009 nuclear plantdecommissioning accruals.****** The order extended thedecommissioning life for the Prairie Island nuclear plant by 10 years.  The order reduced the amount of futurenuclear decommissioning expenses that must be collected from customers from $32million to zero, effective Jan. 1, 2009.

 

In August 2009,NSP-Minnesota filed a proposal with the MPUC to provide one-time refunds to returnto customers their contributions of $22.8 million made to the external escrowdecommissioning fund for the Monticello nuclear plant, which the MPUC approvedin November 2009.  NSP-Minnesotabegan refunding the excess escrow to customers in February 2010.

 

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*** ***

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

*** ***

***South Dakota Electric Rate Case —*******In June 2009,NSP-Minnesota filed a request with the SDPUC to increase South Dakota electricrates by $18.6 million annually, or 12.7 percent.  This proposed increase includes approximately$2.9 million in revenues currently recovered through automatic recoverymechanisms.  Thus, the requestedincrease, net of current automatic recovery mechanisms, is approximately $15.7million or 10.7 percent.  The request is based on a 2008 historic testyear adjusted for known and measurable changes in rate base and O&Mexpenses, an electric rate base of $282 million, a requested ROE of 11.25percent, and an equity ratio of 51.63 percent.

 

On Jan. 5, 2010, theSouth Dakota Commission approved a settlement agreement, which increaseselectric base rates by $10.9 million. The primary difference between the approved rate increase and requestedamount was due to a lower ROE and the use of a 20-year life for the PrairieIsland nuclear plant, which reduced the revenue deficiency and expense accrualsby a corresponding amount.  New rateswere effective on Jan. 18, 2010.

 

***Pending and RecentlyConcluded Regulatory Proceedings — FERC***

*** ***

***Revenue Sufficiency Guarantee (RSG) Charges —***The MISO tariff charges certain marketparticipants a real-time RSG charge, which is designed to ensure that anygenerator scheduled or dispatched by MISO will receive no less than its offerprice for start-up, no-load and incremental energy.  A proposal in 2005 by MISO to refine the RSGcharge initiated protracted proceedings. In the subsequent compliance proceeding, the FERC has issued numerousorders, attempting to refine and clarify the RSG charge.  With the issuance of these orders, the FERChas directed certain refunds to market participants, but has subsequentlyrefined or waived various refund requirements. The FERC granted rehearing in part of certain earlier orders directingrefunds to correct a rate mismatch in the RSG charge.

 

In August 2007,numerous parties filed complaints against MISO, arguing that the allocation ofthe RSG charge (only to certain market participants actually withdrawingenergy) was unjust, unreasonable, and unduly discriminatory.  After protracted proceedings, the FERC foundin November 2008 that the RSG charge was unjust and unreasonable, anddirected refunds.  In May 2009, FERCgranted rehearing in part regarding the applicability of refunds for the RSGcharges.  Specifically, the FERCdetermined that the refund-effective date is November 2008, the date ofthe FERC order determining that the allocation to market participants of theRSG charges was unjust and unreasonable.

 

The FERC directed MISOto implement an interim RSG cost allocation to be effective starting in August 2007.  The FERC further directed MISO to submit acomplete and final proposal, to be implemented on a prospective basis after thecommencement of the MISO’s ASMs in January 2009.  In February 2009,MISO submitted a filing to implement the new RSG rate design; however, the FERChas not yet rendered a final decision to implement the new rate design.  In August 2009, the FERC issued an orderin which it invalidated numerous exemptions to the RSG that had previously beenutilized by MISO through its business practice manuals.  Several parties have sought rehearing of theorder and a final FERC decision is still pending.

 

Xcel Energy is a party toeach of the relevant RSG-related proceedings. Each of the relevant RSG-related orders has been the subject of requestsfor rehearing at the FERC and petitions for review filed at the United StatesCourt of Appeals for the District of Columbia Circuit (D.C. Circuit).  The separate RSG proceedings have proceededin parallel at the FERC, and the most recent orders  are subject to pending requests forrehearing.  The D.C. Circuit proceedingsare being held in abeyance pending final action in the FERC proceedings.

 

***FERC Section 5 Rate Cases for Interstate Gas Pipelines******—*** In November 2009, theFERC approved orders initiating rate investigations under Section 5 of theNatural Gas Act (NGA) against Northern Natural Gas Company (NNG) and GreatLakes Gas Transmission Company (GLGT).  NSP-Minnesota and NSP-Wisconsinare together the largest customer on NNG, holding $41 million per year ofmaximum rate storage and transportation contracts.

 

Accordingto the FERC orders, FERC staff concluded, based on a review of the financialinformation filed with the FERC by the pipelines, that each of the pipelinesare substantially over-recovering their cost of service and earning excessiveROEs.  The orders require the pipelines to file full cost and revenuestudies, and the matters were set for hearing before an ALJ on an expeditedbasis.  If the FERC orders the pipelinesto reduce their transportation and storage rates, the rate reductions and anyassociated refunds would be reflected in the purchased gas and electric fuelcost adjustment mechanisms of the Xcel Energy utility subsidiaries.

 

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Xcel Energy has filed anintervention as part of a group of similarly-situated GLGT shippers in the GLGTSection 5 case, and filed to intervene individually in the NNG Section 5rate case.  The FERC ALJ conducted apre-hearing conference on Jan. 12, 2010 and established the proceduralschedule for the proceedings.  If fullylitigated, the Section 5 rate cases can be expected to go to hearingsbefore the ALJ beginningAug. 2, 2010.  An initial decisionmust be issued by Nov. 11, 2010.

 

**14.**  Commitmentsand Contingent Liabilities

** **

***Capital Commitments***— As of Dec. 31, 2009,the estimated cost of the capital expenditure programs and other capitalrequirements of NSP-Minnesota is approximately $1.2 billion in 2010, $1.2billion in 2011 and $1.0 billion in 2012. NSP-Minnesota’s capital forecast includes the following major projects.

 

*Nuclear Capacity Increases and Life Extension*— NSP-Minnesotais seeking a 20-year license renewal for the Monticello and Prairie Islandnuclear plants. A renewed operating license was approved and issued forMonticello by the NRC in November 2006 licensing the plant to operateuntil 2030, and the MPUC order approving the spent fuel storage capacity neededto support plant operations until 2030 went into effect in June 2007. Theapplication to renew Prairie Island’s operating licenses was submitted to theNRC in April 2008 and the application for a CON for additional spent fuelstorage capacity to support 20 additional years of plant operation was approvedby the MPUC in December 2009.  Finalstate and federal approvals are expected in 2010.

 

NSP-Minnesotais pursuing capacity increases of Monticello and Prairie Island that will totalapproximately 235 MW, to be implemented, if approved, between 2010 and 2015.The life extension and capacity increase for Prairie Island Unit 2 iscontingent on replacement of Unit 2’s original steam generators, currentlyplanned during the refueling outage in 2013. Total capital investment for theseactivities is estimated to be over $1 billion between 2010 and 2015. NSP-Minnesotasubmitted the CON and site permit applications for Monticello’s power uprate inthe first quarter of 2008 and the CON and site permit applications for PrairieIsland’s power uprate in the second quarter of 2008.  The MPUC approved the Monticello power uprateCON and site permit in December 2008 and the Prairie Island power uprateCON and site permit in December 2009.

 

*Wind Generatio*n — NSP-Minnesota isinvesting approximately $900 million over three years for a 201 MW project insouthwestern Minnesota, called the Nobles Wind Project, and a 150 MW project insoutheastern North Dakota, called the Merricourt Wind Project.  These projects are expected to be operationalby the end of 2010 and 2011, respectively.  NSP-Minnesota has received regulatory approval for the projects, and hasrequested recovery of eligible costs beginning in 2010.

 

*CapX 2020* — In 2006, CapX 2020, analliance of electric cooperatives, municipals and investor-owned utilities inthe upper Midwest, including Xcel Energy, announced that it had identifiedseveral groups of transmission projects that proposed to be complete by2020.  Group 1 project investments areexpected to total approximately $1.7 billion, with major constructiontargeted to begin in 2010 and ending three to five years later. Xcel Energy’sinvestment is expected to be approximately $900 million depending on the routeand configuration approved by the MPUC and the PSCW. Approximately75 percent of the 2010 capital expenditures and return on investment fortransmission projects are expected to be recovered under an NSP-Minnesota TCRtariff rider mechanism authorized by Minnesota legislation, as well as asimilar TCR mechanism passed in South Dakota. Cost-recovery by NSP-Wisconsin isexpected to occur through the biennial PSCW rate case process.

 

Thecapital expenditure programs of NSP-Minnesota are subject to continuing reviewand modification.  Actual utilityconstruction expenditures may vary from the estimates due to changes inelectric and natural gas projected load growth regulatory decisions, thedesired reserve margin and the availability of purchased power, as well asalternative plans for meeting NSP-Minnesota’s long-term energy needs.  In addition, NSP-Minnesota’s ongoingevaluation of compliance with future requirements to install emission-controlequipment and merger, acquisition and divestiture opportunities to supportcorporate strategies may impact actual capital requirements.

 

***Fuel Contracts*****— NSP-Minnesota has contracts providing for the purchase and deliveryof a significant portion of its current coal, nuclear fuel and natural gasrequirements.  These contracts expire invarious years between 2010 and 2028.  Inaddition, NSP-Minnesota may be required to pay additional amounts depending onactual quantities shipped under these agreements.  The potential risk of loss, in the form ofincreased costs from market price changes in fuel, is mitigated through thecost-rate adjustment mechanisms, which provide for pass through of most fuel,storage and transportation costs.

 

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The estimatedminimum purchases for NSP-Minnesota under these contracts as of Dec. 31,2009, is as follows:

 
| **(Millions of Dollars)** | ** ** | **2009** | ** ** |
|-------------------------------------|------------|----------|------------|
| Coal                                |       | $        | 599.1      |   |
| Nuclear  fuel                       |       | 598.3    |       |
| Natural  gas supply                 |       | 278.0    |       |
| Gas  storage and transportation     |       | 950.1    |       |
|                                     |            |          |            |  |

 

***Purchased Power Agreements****—*NSP-Minnesota has entered into agreements with utilities and otherenergy suppliers for purchased power to meet system load and energyrequirements, replace generation from company-owned units under maintenance andduring outages and meet operating reserve obligations.  NSP-Minnesota has various pay-for-performancecontracts with expiration dates through the year 2033.  In general, these contracts provide forcapacity payments, subject to meeting certain contract obligations and energypayments based on actual power taken under the contracts.  Certain contractual payment obligations areadjusted based on indices.  However, theeffects of these price adjustments are mitigated through cost-of-energy rateadjustment mechanisms.

 

At Dec. 31, 2009, theestimated future payments for capacity, accounted for as executory contracts,that NSP-Minnesota is obligated to purchase, subject to availability, were asfollows:

 
| **(Millions of Dollars)** |   |   |   |
|-------------------------------------|--------|--------|--------|
| 2010                                |   | $      | 110.7  |   |
| 2011                                |   | 110.0  |   |
| 2012                                |   | 109.2  |   |
| 2013                                |   | 111.8  |   |
| 2014                                |   | 114.3  |   |
| 2015  and thereafter                |   | 319.8  |   |
| Total  *                            |   | $      | 875.8  |   |

 

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*  Includes amounts allocated to NSP-Wisconsinthrough intercompany charges.

 

***Leases*****— NSP-Minnesota leases a variety of equipment and facilities used inthe normal course of business, which are accounted for as operatingleases.  Total rental expense underoperating lease obligations was approximately $76.2 million, $70.7 million and$53.3 million for 2009, 2008 and 2007, respectively.  Included in total rental expense werepurchase power agreement payments of $56.2 million, $48.6 million and $29.5million in 2009, 2008 and 2007, respectively.

 

Includedin the future commitments under operating leases are estimated future paymentsunder purchase power agreements that have been accounted for as operatingleases in accordance with *ASC 840 Leases*.  Future commitments under operating leasesare:

 
| **(Millions of Dollars)** | ** ** | **Other  Operating  Leases** | ** ** | **Purchased  Power  Agreement  Operating  Leases****(a) (b)** | ** ** | **Total  Operating  Leases** | ** ** |
|-------------------------------------|------------|------------------------------|------------|--------------------------------------------------------------------|------------|------------------------------|------------|
| 2010                                |       | $                            | 10.5       |                                                               | $          | 53.1                         |       | $ | 63.6 |   |
| 2011                                |       | 11.2                         |       | 54.0                                                               |       | 65.2                         |       |
| 2012                                |       | 9.5                          |       | 55.0                                                               |       | 64.5                         |       |
| 2013                                |       | 8.9                          |       | 55.9                                                               |       | 64.8                         |       |
| 2014                                |       | 8.5                          |       | 56.8                                                               |       | 65.3                         |       |
| Thereafter                          |       | 51.1                         |       | 674.1                                                              |       | 725.2                        |       |
|                                     |            |                              |            |                                                                    |            |                              |            |  |  |  |

 

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(a) Amounts notincluded in purchase power agreement estimated future payments above.

(b) Purchase poweragreement operating leases contractually expire through 2025.

 

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**Environmental Contingencies**

 

NSP-Minnesotahas been, or is currently, involved with the cleanup of contamination fromcertain hazardous substances at several sites. In many situations, NSP-Minnesota believes it will recover some portionof these costs through insurance claims. Additionally, where applicable, NSP-Minnesota is pursuing, or intends topursue, recovery from other PRPs and through the rate regulatory process.  New and changing federal and stateenvironmental mandates can also create added financial liabilities forNSP-Minnesota, which are normally recovered through the rate regulatoryprocess.  To the extent any costs are notrecovered through the options listed above, NSP-Minnesota would be required torecognize an expense.

 

***Site Remediation******—*****NSP-Minnesotamust pay all or a portion of the cost to remediate sites where past activitiesof NSP-Minnesota or other parties have caused environmental contamination.  Environmental contingencies could arise fromvarious situations including sites of former manufactured gas plants operatedby NSP-Minnesota, its predecessors or other entities; and third party sites,such as landfills, to which NSP-Minnesota is alleged to be a PRP that senthazardous materials and wastes.  At Dec. 31,2009, the liability for the cost of remediating these sites was estimated to be$0.3 million, of which $0.2 million was considered to be a current liability.

 

***Asbestos Removal******—*****Some ofNSP-Minnesota’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that containit are demolished or removed. NSP-Minnesota has recorded an estimate for final removal of the asbestosas an ARO.  See additional discussion ofAROs below.  It may be necessary toremove some asbestos to perform maintenance or make improvements to otherequipment.  The cost of removing asbestosas part of other work is immaterial and is recorded as incurred as operatingexpenses for maintenance projects, capital expenditures for constructionprojects or removal costs for demolition projects.

 

***Other Environmental Requirements***

 

***EPA GHG Endangerment Finding***— On Dec. 7, 2009, in response to theU. S. Supreme Court’s decision in Massachusetts v. EPA, 549 U. S. 497 (2007),the EPA issued its “endangerment” finding that GHG emissions endanger publichealth and welfare and that emissions from motor vehicles contribute to theGHGs in the atmosphere.  Thisendangerment finding creates a mandatory duty for the EPA to regulate GHGs fromlight duty vehicles.  The EPA hasproposed to finalize GHG efficiency standards for light duty vehiclesby spring 2010.  Thereafter, the EPA anticipatesphasing-in permit requirements and regulation of GHGs for large stationarysources, such as power plants, in calendar year 2011.

 

***CAIR *****—** In March 2005,the EPA issued the CAIR to further regulate SO2 and NOx emissions.  The objective of CAIR is to cap emissions ofSO2 and NOx in theeastern United States, including Minnesota. In response tothe decisions by the D.C. Circuit Court of Appeals vacating but reinstatingCAIR while the EPA develops revised regulations, the EPA has indicated thata CAIR replacement rule will be proposed in early 2010 with finalizationplanned for early 2011.

 

As currently written,CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010for SO2, with a final compliance deadline in2015 for both emissions.  Under CAIR,each affected state will be allocated an emissions budget for SO2 and NOx thatwill result in significant emission reductions. It will be based on stringent emission controls and forms the basis fora cap and trade program.  State emissionbudgets or caps decline over time. States can choose to implement an emissions reduction program based onthe EPA’s proposed model program, or they can propose another method, which theEPA would need to approve.

 

OnNov. 3, 2009, the EPA published a rule staying the effectiveness ofCAIR in Minnesota effective Dec. 3, 2009. Cost estimates are therefore not included at this time forNSP-Minnesota.

 

***CAMR*****—** In March 2005,the EPA issued the CAMR, which regulated mercury emissions from powerplants.  In February 2008, the U. S.Court of Appeals for the District of Columbia vacated CAMR, which impactsfederal CAMR requirements, but not necessarily state-only mercury legislationand rules.  The EPA has agreed to finalize MACT emissionstandards for all hazardous air pollutants from electric utility steamgenerating units by November 2011 to replace CAMR.  Xcel Energy, the parent company ofNSP-Minnesota, anticipates that the EPA will require affected facilities todemonstrate compliance within 18 to 36 months thereafter.

 

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***Minnesota Mercury Legislation —***In May 2006,the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006(Act) providing a process for plans, implementation and cost recovery forutility efforts to curb mercury emissions at certain power plants.****** For NSP-Minnesota, the Act covers units at theA. S. King and Sherco generating facilities. Xcel Energy installed and is operating and maintaining continuous mercuryemission monitoring systems at these generating facilities.

 

In September 2006,NSP-Minnesota filed a request with the MPUC for recovery of up to$6.3 million of certain environmental improvement costs recoverable underthe Act.  In January 2007, the MPUCapproved this request to defer these costs as a regulatory asset with a cap of$6.3 million.  In November 2008,NSP-Minnesota filed a request with the MPUC to reflect its requested recoveryof these emission reduction compliance costs incurred through 2009 in theNSP-Minnesota electric rate case.  In June 2009,NSP-Minnesota received an order from the MPUC closing the docket to correspondwith the inclusion of costs in the electric rate case.  The recovery of the costs was allowed as partof the rate case.

 

InNovember 2008, the MPUC approved and ordered the implementation of theSherco Unit 3 and A. S. King mercury emission reduction plans.  A sorbent injection control system wasinstalled at Sherco Unit 3 in December 2009, with installation at A. S.King scheduled for December 2010. In an order dated Nov. 4, 2009, the MPUC authorized NSP-Minnesotato collect approximately $3.5 million from customers through a mercury rider in2010.

 

OnDec. 21, 2009, NSP-Minnesota filed the plans for mercury control at ShercoUnits 1 and 2 with the MPUC and the MPCA. Assuming these plans are approved, NSP-Minnesota expects to file forrecovery of the costs to implement these plans through the mercury costrecovery rider.

 

***Regional Haze Rules *****—** In June 2005,the EPA finalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions ofthe regional haze rule that require emission controls, known as BART, forindustrial facilities emitting air pollutants that reduce visibility by causingor contributing to regional haze.

 

NSP-Minnesota submitted its BART alternativesanalysis for Sherco Units 1 and 2 in October 2006.  The MPCA reviewed the BART analyses for allunits in Minnesota and determined that overall, compliance with CAIR is betterthan BART.  On Nov. 13, 2008,NSP-Minnesota submitted a revised BART alternatives analysis letter to the MPCAto account for increased construction and equipment costs.  The underlying conclusions and proposedemission control equipment, however, remained unchanged from the original 2006BART analysis.  The MPCA completed their BART determination andproposed SO2 and NOx limits in the draft stateimplementation plan (SIP) that are equivalent to the reductions made underCAIR.

 

On Oct. 21,2009, the United States Department of Interior certified that a portion of thevisibility impairment in Voyageurs and Isle Royale National Parks is reasonablyattributable to pollution emissions from Xcel Energy’s Sherco Plant  Units 1 and 2.  The EPA currently administers the 1980Visibility Protection Rules for the State of Minnesota through a FederalImplementation Plan.  As such, EPA Region5 is required to make its own determination as to whether Sherco Units 1 and 2cause or contribute to visibility impairment and if so, to determine theappropriate BART levels of control.

 

The MPCA determined thatthis certification does not alter the proposed SIP.  The SIP proposes BART controls for Shercothat are designed to improve visibility in the national parks, but does not requireSelective Catalytic Reduction (SCR) on Units 1 and 2.  The MPCA concluded that the minor visibilitybenefits derived from SCR do not outweigh the substantial costs.  On Dec. 15, 2009, the MPCA CitizensBoard approved the SIP, which has been submitted to the EPA for approval.

 

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***Federal Clean Water Act —***The federal Clean Water Actrequires the EPA to regulate cooling water intake structures to assure thatthese structures reflect the best technology available (BTA) for minimizingadverse environmental impacts.****** In July 2004,the EPA published phase II of the rule, which applies to existing coolingwater intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Courtof Appeals for the Second Circuit (Court of Appeals) challenging thephase II rulemaking.  In January 2007,the Court of Appeals issued its decision and remanded the rule to the EPAfor reconsideration.  In June 2007,the EPA suspended the deadlines and referred any implementation to each state’sbest professional judgment until the EPA is able to fully respond to theremand.  In April 2008, the U. S. SupremeCourt granted limited review of the Court of Appeals’ opinion to determinewhether the EPA has the authority to consider costs and benefits in assessingBTA.  On April 1, 2009, the U. S.Supreme Court issued a decision in *EntergyCorp. v. Riverkeeper, Inc.*, concluding that the EPA canconsider a cost benefit analysis when establishing BTA.  The decision overturned only one aspect ofthe Court of Appeals’ earlier opinion, and gives the EPA the discretion toconsider costs and benefits when it reconsiders its phase II rules.  Until the EPA fully responds to the Court ofAppeals’ decision, the rule’s compliance requirements and associated deadlineswill remain unknown.  As such, it is notpossible to provide an accurate estimate of the overall cost of this rulemakingat this time.

 

TheMPCA exercised its authority under best professional judgment to require theBlack Dog Generating Station in its recently renewed wastewater dischargepermit to create a plan by April 2010 to reduce the plant intake’s impacton aquatic wildlife.  NSP-Minnesota isdiscussing alternatives with the local community and regulatory agencies toaddress this concern.

 

# **AssetRetirement Obligations**

#  

NSP-Minnesotarecords future plant removal obligations as a liability at fair value with acorresponding increase to the carrying values of the related long-lived assetsin accordance with *ASC 410 Asset Retirementand Environmental Obligations. *Thisliability will be increased over time by applying the interest method ofaccretion to the liability and the capitalized costs will be depreciated overthe useful life of the related long-lived assets.  The recording of the obligation for regulatedoperations has no income statement impact due to the deferral of theadjustments through the establishment of a regulatory asset.

 

***Recorded ARO —***AROs have been recorded forplant related to nuclear production, steam production, electric transmissionand distribution, gas distribution and office buildings.  The steam production obligation includesasbestos, ash containment facilities, radiation sources anddecommissioning.  The asbestosrecognition associated with the steam production includes certain plants atNSP-Minnesota.  NSP-Minnesota alsorecorded asbestos recognition for its general office building.

 

Generally,this asbestos abatement removal obligation originated in 1973 with the CAA,which applied to the demolition of buildings or removal of equipment containingasbestos that can become airborne on removal. AROs also have been recorded for NSP-Minnesota steam production relatedto ash-containment facilities such as bottom ash ponds, evaporation ponds andsolid waste landfills.  The originationdate on the ARO recognition for ash-containment facilities at steam plants wasthe in-service date of various facilities. Additional AROs have been recorded for NSP-Minnesota steam productionplant related to radiation sources in equipment used to monitor the flow ofcoal, lime and other materials through feeders.

 

NSP-Minnesota recognized anARO for the retirement costs of natural gas mains and for the removal ofelectric 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 a particularyear.  Therefore, the obligation wasmeasured using an average service life.

 

For the nuclear assets, theARO associated with the decommissioning of two NSP-Minnesota nuclear generatingplants, Monticello and Prairie Island, originates with the in-service date ofthe facility.  Monticello began operationin 1971.  Prairie Island units 1 and 2began operation in 1973 and 1974, respectively. See Note 15 to the consolidated financial statements for further discussionof nuclear obligations.

 

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A reconciliation of thebeginning and ending aggregate carrying amounts of NSP-Minnesota’s AROs isshown in the table below for the 12 months ended Dec. 31, 2009 and Dec. 31,2008, respectively:

 
| ** **                              | ** ** | **Beginning**          | ** ** | ** **      | ** ** | ** **      | ** ** | ** **    | ** ** | **Revisions** | ** ** | **Ending**              | ** ** |
|-----------------------------------------|------------|------------------------|------------|-----------------|------------|-----------------|------------|---------------|------------|---------------|------------|-------------------------|------------|
| ** **                              | ** ** | **Balance**            | ** ** | **Liabilities** | ** ** | **Liabilities** | ** ** | ** **    | ** ** | **to  Prior** | ** ** | **Balance**             | ** ** |
| **(Thousands of Dollars)**    | ** ** | **Jan. 1,  2009** | ** ** | **Recognized**  | ** ** | **Settled**     | ** ** | **Accretion** | ** ** | **Estimates** | ** ** | **Dec. 31,  2009** | ** ** |
| **Electric plant**                      | ** ** | ** **             | ** ** | ** **      | ** ** | ** **      | ** ** | ** **    | ** ** | ** **    | ** ** | ** **              | ** ** |
| Steam  production asbestos              |       | $                      | 19,520     |            | $          | —          |       | $             | —     |          | $          | 1,126                   |       | $ | (3,870 | ) | $ | 16,776 |   |
| Steam  production ash containment       |       | 13,844                 |       | —          |       | —          |       | 814           |       | (2,111        | )          | 12,547                  |       |
| Steam  production radiation sources     |       | 61                     |       | —          |       | —          |       | 4             |       | (8            | )          | 57                      |       |
| Nuclear  production decommissioning     |       | 1,013,342              |       | —          |       | —          |       | 61,469        |       | (315,888      | )          | 758,923                 |       |
| Wind  production                        |       | 7,447                  |       | —          |       | —          |       | 483           |       | (179          | )          | 7,751                   |       |
| Electric  transmission and distribution |       | 151                    |       | —          |       | —          |       | 9             |       | (20           | )          | 140                     |       |
| **Natural gas plant**                   |       |                   |       |            |       |            |       |          |       |          |       |                    |       |
| Gas  transmission and distribution      |       | 245                    |       | —          |       | —          |       | 16            |       | —        |       | 261                     |       |
| **Common and other property**           |       |                   |       |            |       |            |       |          |       |          |       |                    |       |
| Common  general plant asbestos          |       | 1,079                  |       | —          |       | —          |       | 59            |       | (117          | )          | 1,021                   |       |
| Total  liability                        |       | $                      | 1,055,689  |            | $          | —          |       | $             | —     |          | $          | 63,980                  |       | $ | (322,193 | ) | $ | 797,476 |   |

 

The fair value ofNSP-Minnesota assets legally restricted for purposes of settling the nuclearAROs is $1.2 billion as of Dec. 31, 2009, including external nucleardecommissioning investment funds and internally funded amounts.

 

NSP-Minnesotaalso incurred revisions for asbestos, nuclear production, radiation sources,wind turbines, ash-containment facilities and electric transmission anddistribution asset retirement obligations due to revised estimates and end oflife dates.

 

Therevised end of life date for the Prairie Island nuclear plant approved by theMPUC in 2008 and effective Jan. 1, 2009 resulted in the nuclear productiondecommissioning ARO and related regulatory asset decreasing by $315.9 millionin the fourth quarter of 2009.

 
| ** **                              | ** ** | **Beginning**          | ** ** | ** **      | ** ** | ** **      | ** ** | ** **    | ** ** | **Revisions** | ** ** | **Ending**              | ** ** |
|-----------------------------------------|------------|------------------------|------------|-----------------|------------|-----------------|------------|---------------|------------|---------------|------------|-------------------------|------------|
| ** **                              | ** ** | **Balance**            | ** ** | **Liabilities** | ** ** | **Liabilities** | ** ** | ** **    | ** ** | **to  Prior** | ** ** | **Balance**             | ** ** |
| **(Thousands of Dollars)**    | ** ** | **Jan. 1,  2008** | ** ** | **Recognized**  | ** ** | **Settled**     | ** ** | **Accretion** | ** ** | **Estimates** | ** ** | **Dec. 31,  2008** | ** ** |
| **Electric plant**                      | ** ** | ** **             | ** ** | ** **      | ** ** | ** **      | ** ** | ** **    | ** ** | ** **    | ** ** | ** **              | ** ** |
| Steam  production asbestos              |       | $                      | 22,423     |            | $          | —          |       | $             | —     |          | $          | 1,279                   |       | $ | (4,182 | ) | $ | 19,520 |   |
| Steam  production ash containment       |       | 18,111                 |       | —          |       | —          |       | 1,001         |       | (5,268        | )          | 13,844                  |       |
| Steam  production radiation sources     |       | —                 |       | 61              |       | —          |       | —        |       | —        |       | 61                      |       |
| Nuclear  production decommissioning     |       | 1,209,746              |       | —          |       | —          |       | 71,370        |       | (267,774      | )          | 1,013,342               |       |
| Wind  production                        |       | —                 |       | 7,408           |       | —          |       | 39            |       | —        |       | 7,447                   |       |
| Electric  transmission and distribution |       | 125                    |       | —          |       | —          |       | 7             |       | 19            |       | 151                     |       |
| **Natural gas plant**                   |       |                   |       |            |       |            |       |          |       |          |       |                    |       |
| Gas  transmission and distribution      |       | 12,685                 |       | —          |       | —          |       | 314           |       | (12,754       | )          | 245                     |       |
| **Common and other property**           |       |                   |       |            |       |            |       |          |       |          |       |                    |       |
| Common  general plant asbestos          |       | 1,278                  |       | —          |       | —          |       | 70            |       | (269          | )          | 1,079                   |       |
| Total  liability                        |       | $                      | 1,264,368  |            | $          | 7,469           |       | $             | —     |          | $          | 74,080                  |       | $ | (290,228 | ) | $ | 1,055,689 |   |

 

Anew decommissioning study filed with the MPUC in 2008 proposed the extension ofthe final removal date of the Monticello and Prairie Island nuclear plants by14 and 26 years, respectively, effective Jan. 1, 2009.  As a result of the studies for the Monticelloand Prairie Island nuclear plants, the nuclear production decommissioning AROand related regulatory asset decreased by $128.5 million and $139.3 million,respectively, in the fourth quarter of 2008.

 

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***Removal Costs*****— NSP-Minnesotaaccrues an obligation for plant removal costs for generation, transmission anddistribution facilities.  Generally, theaccrual of future 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 costs have accumulated over anumber of years based on varying rates as authorized by the appropriateregulatory entities.  Given the longperiods over which the amounts were accrued and the changing of rates throughtime, NSP-Minnesota has estimated the amount of removal costs accumulatedthrough historic depreciation expense based on current factors used in theexisting depreciation rates. Accordingly, the recorded amounts of estimated future removal costs areconsidered regulatory liabilities. Removal costs as of Dec. 31, 2009 and 2008 were $372 million and$354 million, respectively.

 

**Nuclear Insurance**

** **

NSP-Minnesota’spublic liability for claims resulting from any nuclear incident is limited to$12.5 billion under the Price-Anderson amendment to the Atomic Energy Actof 1954, as amended.  NSP-Minnesota hassecured $300 million of coverage for its public liability exposure with apool of insurance companies.  Theremaining $12.2 billion of exposure is funded by the Secondary FinancialProtection Program, available from assessments by the federal government incase of a nuclear accident. NSP-Minnesota is subject to assessments of up to $117.5 million perreactor per accident for each of its three licensed reactors, to be applied forpublic liability arising from a nuclear incident at any licensed nuclearfacility in the United States.  Themaximum funding requirement is $17.5 million per reactor during any oneyear.  These maximum assessment amountsare both subject to inflation adjustment by the NRC and state premiumtaxes.  The NRC’s last adjustment waseffective Oct. 29, 2008.  The nextadjustment is due on or before Oct. 29, 2013.

 

NSP-Minnesotapurchases insurance for property damage and site decontamination cleanup costsfrom Nuclear Electric Insurance Ltd. (NEIL).  The coverage limits are $2.3 billion foreach of NSP-Minnesota’s two nuclear plant sites.  NEIL also provides business interruptioninsurance coverage, including the cost of replacement power obtained duringcertain prolonged accidental outages of nuclear generating units.  Premiums are expensed over the policyterm.  All companies insured with NEILare subject to retroactive premium adjustments if losses exceed accumulatedreserve funds.  Capital has been accumulatedin the reserve funds of NEIL to the extent that NSP-Minnesota would have noexposure for retroactive premium assessments in case of a single incident underthe business interruption and the property damage insurance coverage.  However, in each calendar year, NSP-Minnesotacould be subject to maximum assessments of approximately $15.2 million forbusiness interruption insurance and $30.9 million for property damageinsurance if losses exceed accumulated reserve funds.

 

**Legal Contingencies**

 

Lawsuitsand claims arise in the normal course of business.  Management, after consultation with legalcounsel, has recorded an estimate of the probable cost of settlement or otherdisposition of them.  The ultimateoutcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of thesematters could have a material adverse effect on NSP-Minnesota’s financialposition and results of operations.

 

***Environmental Litigation***

 

***Carbon Dioxide EmissionsLawsuit —***In 2004, the attorneys general of eight states andNew York City, as well as several environmental groups, filed lawsuits in U. S.District Court in the Southern District of New York against five utilities,including Xcel Energy, the parent company of NSP-Minnesota, to force reductionsin CO2 emissions.****** Theother utilities include American Electric Power Co., Southern Co.,Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted byeach company is a public nuisance as defined under state and federal common lawbecause it has contributed to global warming. The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to ordereach utility to cap and reduce its CO2 emissions. On Sept. 19, 2005, the court granted a motion to dismiss on constitutionalgrounds.  Plaintiffs filed an appeal tothe U. S. Court of Appeals for the Second Circuit.  On Sept. 21, 2009, the Court of Appealsissued an opinion reversing the lower court decision.  On Nov. 5, 2009 the defendants,including Xcel Energy, filed a petition for rehearing and en banc review.  It is uncertain when the Court of Appealswill respond to the petition.

 

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***Comer vs. Xcel Energy Inc. etal. —***In 2006, Xcel Energy, the parent company ofNSP-Minnesota, received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi.****** The lawsuit names more than 45 oil, chemicaland utility companies, including Xcel Energy, as defendants and alleges thatdefendants’ CO2 emissions “were a proximate and direct causeof the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim,several legal theories, including negligence and public and private nuisanceand seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is withoutmerit and intends to vigorously defend itself against these claims.  In August 2007, the court dismissed thelawsuit in its entirety against all defendants on constitutional grounds.  Plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. On Oct. 16, 2009, the U. S. Court of Appeals for the Fifth Circuitreversed the district court decision, in part, concluding that the plaintiffspleaded sufficient facts to overcome the constitutional challenges that formedthe basis for dismissal by the district court. On Nov. 27, 2009, defendants, including Xcel Energy, filed apetition for en banc review.  It isuncertain when the Court of Appeals will respond to the petition.

 

***Native Village of Kivalina vs. XcelEnergy Inc. et al. —***In 2008, the City and NativeVillage of Kivalina, Alaska, filed a lawsuit in U. S. District Court for theNorthern District of California against Xcel Energy, the parent company ofNSP-Minnesota, and 23 other utilities, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission ofCO2 and other GHGs contribute to global warming,which is harming their village.  XcelEnergy believes the claims asserted in this lawsuit are without merit andjoined with other utility defendants in filing a motion to dismiss on June 30,2008.  On Oct. 15, 2009, the U. S.District Court dismissed the lawsuit on constitutional grounds.  On Nov. 5, 2009, plaintiffs filed anotice of appeal to the U. S. Court of Appeals for the Ninth Circuit.

 

**Employment,Tort and Commercial Litigation**

** **

***Nuclear Waste Disposal Litigation —***In 1998, NSP-Minnesota filed a complaint in the U. S. Court of FederalClaims against the United States requesting breach of contract damages for theU. S. Department of Energy’s (DOE) failure to begin accepting spent nuclearfuel by Jan. 31, 1998, as required by the contract between the DOE andNSP-Minnesota.****** At trial, NSP-Minnesota claimed damages inexcess of $100 million through Dec. 31, 2004.  On Sept. 26, 2007, the court awardedNSP-Minnesota $116.5 million in damages. In December 2007, the court denied the DOE’s motion forreconsideration.  In February 2008,the DOE filed an appeal to the U. S. Court of Appeals for the Federal Circuit,and NSP-Minnesota cross-appealed on the cost of capital issue.  In April 2008, the DOE asked the Courtof Appeals to stay briefing until the appeals in several other nuclear wastecases have been decided, and the Court of Appeals granted the request.  In December 2008, NSP-Minnesota made amotion in the Court of Appeals to lift the stay, which was denied by the Courtof Appeals in February 2009. Results of the judgment will not be recorded in earnings until theappeal, regulatory treatment and amounts to be shared with ratepayers have beenresolved.  Given the uncertainties, it isunclear as to how much, if any, of this judgment will ultimately have a netimpact on earnings.

 

InAugust 2007, NSP-Minnesota filed a second complaint against the DOE in theU. S. Court of Federal Claims (NSP II), again claiming breach of contractdamages for the DOE’s continuing failure to abide by the terms of thecontract.  This lawsuit will claimdamages for the period Jan. 1, 2005 through Dec. 31, 2008, whichincludes costs associated with the storage of spent nuclear fuel at PrairieIsland and Monticello, as well as the costs of complying with state regulationrelating to the storage of spent nuclear fuel. Per the court’s scheduling order, NSP-Minnesota’s expert report ondamages was submitted on April 15, 2009, and asserts damages in excess of$250 million.  In November 2009, theCourt ordered the DOE to submit its expert report by May 17, 2010.  Trial is expected to take place in mid tolate 2010.

 

***Siewert vs. Xcel Energy —***In 2004,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 systems;negligence in the construction and maintenance of distribution systems; andfailure to warn or adequately test such systems.****** Plaintiffs allege decreased milk production,injury, and damage to a dairy herd as a result of stray voltage resulting fromNSP-Minnesota’s distribution system. Plaintiffs claim losses of approximately $7 million.  NSP-Minnesota denies all allegations.  In December 2008, the Court of Appealsissued a decision ordering dismissal of Plaintiffs’ claims for injunctiverelief, but otherwise rejecting NSP-Minnesota’s contentions and ordering thematter remanded for trial.  The MinnesotaSupreme Court subsequently granted NSP-Minnesota’s petition for further reviewand heard oral arguments on Dec. 2, 2009. It isuncertain when the Minnesota Supreme Court will render a decision.

 

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**15. Nuclear Obligations**

 

***Fuel Disposal —***NSP-Minnesotais responsible for temporarily storing used or spent nuclear fuel from itsnuclear plants.  The DOE is responsiblefor permanently storing spent fuel from NSP-Minnesota’s nuclear plants as wellas from other U. S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposalprogram since 1981.  The fuel disposalfees are based on a charge of 0.1 cent per Kwh sold to customers from nucleargeneration.  Fuel expense includes theDOE fuel disposal assessments of approximately $12 million in 2009, $13 millionin 2008 and $13 million 2007, respectively. In total, NSP-Minnesota had paid approximately $398 million to theDOE through Dec. 31, 2009.  TheNuclear Waste Policy Act of 1982 required the DOE to begin accepting spentnuclear fuel no later than Jan. 31, 1998. NSP-Minnesota and other utilities have commenced lawsuits against theDOE to recover damages caused by the DOE’s failure to meet its statutory andcontractual obligations.

 

NSP-Minnesotahas its own temporary on-site storage facilities for spent fuel at itsMonticello and Prairie Island nuclear plants, which consist of storage poolsand dry cask facilities at both sites. The amount of spent fuel storage capacity currently authorized by theNRC and the MPUC will allow NSP-Minnesota to continue operation of its PrairieIsland nuclear plant until the end of its current license terms in 2013 and2014 and its Monticello nuclear plant until the end of its renewed operatinglicense in 2030.  Other alternatives forspent fuel 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.

 

***Regulatory Plant DecommissioningRecovery —***Decommissioning of NSP-Minnesota’s nuclearfacilities is planned for the period from cessation of operations through 2067,assuming the prompt dismantlement method. NSP-Minnesota is currently recordingthe regulatory costs for decommissioning over the MPUC-approved cost-recoveryperiod and including the accruals in a regulatory liability account. The totaldecommissioning cost obligation is recorded as an ARO in accordance with *ASC 410 Asset Retirement and Environmental Obligations*.

 

Monticellobegan operation in 1971 and with its renewed operating license and CON forspent fuel capacity to support 20 years of extended operation can operate until2030.  The Monticello 20-yeardepreciation life extension until September 2030 was granted by the MPUCin 2007. Construction of the Monticello dry-cask storage facility is completeand 10 of the 30 canisters authorized have been filled and placed in thefacility.

 

PrairieIsland units 1 and 2 began operation in 1973 and 1974, respectively, and arecurrently licensed to operate until 2013 and 2014, respectively.  In April 2008, NSP-Minnesota filed an applicationwith the NRC to renew the operating license of its two nuclear reactors atPrairie Island for an additional 20 years until 2033 and 2034,respectively.   The PIIC filedcontentions in the NRC’s license renewal proceeding in August 2008.  The PIIC request wasreferred to an ASLB for review.  The ASLBhas granted the PIIC hearing request and has admitted seven of the 11contentions filed.  To date, all sevenadmitted contentions have been resolved and removed from the ASLB docket.  Subsequent to the NRC issuance of the finalSafety Evaluation Report and the draft supplemental environmental impactstatement, the PIIC filed four additional contentions.  The ASLB has admitted one of the contentionsand has not issued a decision on the other three.  NSP-Minnesota is challenging the admittedcontention, and a decision on whether the other contentions will be acceptedwill be made in early 2010.  If thecontentions are not resolved, the resulting adjudicatory process is expected toadd approximately eight months onto the NRC’s standard 22 month reviewschedule, resulting in a decision on the Prairie Island license renewal in late2010.

 

Thetotal obligation for decommissioning currently is expected to be funded100 percent by external funds, as approved by the MPUC, when decommissioningcommences. The MPUC last approved NSP-Minnesota’s nuclear decommissioning studyrequest in October 2009, using 2008 cost data.  The next study update will be submitted in October 2011for the 2012 accrual. The MPUC approval, eliminated 2009 decommissioningfunding for Minnesota retail customers, due to a full extension of the accrualperiod for the Monticello unit from 2020 to 2030, along with an extension ofthe accrual period for Prairie Island (from 2013 for Unit 1 and 2014 for Unit 2to 2023 and 2024 respectively).  Further,in November 2009, the MPUC also approved a proposal to refund theMinnesota portion of the Monticello escrow fund in a supplemental filing.

 

Theassets held in trusts, primarily consist of investments in fixed incomesecurities, such as tax-exempt municipal bonds and U. S. government securitiesthat mature in one to 20 years and common stock of public companies.NSP-Minnesota plans to reinvest matured securities until decommissioningbegins.

 

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Consistentwith cost-recovery in utility customer rates, NSP-Minnesota previously recordedannual decommissioning accruals based on periodic site-specific cost studiesand a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars.  The most recent study, which resulted in anauthorization of no funding presumes that costs will escalate in the future ata rate of 2.89 percent per year. The total estimated decommissioning costs that will ultimately be paid,net of income earned by external trust funds, is currently being accrued usingan annuity approach over the approved plant-recovery period.  This annuity approach uses an assumed rate ofreturn on funding, which is currently 6.30 percent, net of tax, forexternal funding.  The net unrealizedloss on nuclear decommissioning investments is deferred as a regulatoryliability based on the assumed offsetting against decommissioning costs incurrent ratemaking treatment.

 

Theexternal funds are held in trust and in escrow. The portion in escrow is subject to refund if approved by the variousrate commissions.  The MPUC authorizedthe return of $23.5 million of funds associated with the Monticello plant forthe Minnesota retail jurisdictions.  Thisamount was withdrawn in December 2009 and was refunded on customer’s billsin February 2010.

 

AtDec. 31, 2009, NSP-Minnesota had recorded and recovered in rates cumulativedecommissioning expense of $1.3 billion. The following table summarizes the funded status of NSP-Minnesota’sdecommissioning obligation based on approved regulatory recoveryparameters.  Xcel Energy believes futuredecommissioning cost expense, if necessary, will continue to be recovered incustomer rates.  These amounts are notthose recorded in the financial statements for the ARO.

 
| **(Thousands of Dollars)**                                                                 | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| Estimated  decommissioning cost obligation from most recently approved study (2008  dollars)         |       | $          | 2,308,196  |       | $          | 1,683,750 |   |
| Effect  of escalating costs to 2009 and 2008 dollars (2.89 and 3.61 percent per year,  respectively) |       | 66,707     |       | 189,012    |       |
| Estimated  decommissioning cost obligation in current dollars                                        |       | 2,374,903  |       | 1,872,762  |       |
| Effect  of escalating costs to payment date (2.89 and 3.61 percent per year,  respectively)          |       | 2,741,460  |       | 1,254,064  |       |
| Estimated  future decommissioning costs (undiscounted)                                               |       | 5,116,363  |       | 3,126,826  |       |
| Effect  of discounting obligation (using risk-free interest rate)                                    |       | (3,973,493 | )          | (1,847,526 | )          |
| Discounted  decommissioning cost obligation                                                          |       | 1,142,870  |       | 1,279,300  |       |
| Assets  held in external decommissioning trust                                                       |       | 1,248,739  |       | 1,075,294  |       |
| Discounting  decommissioning obligation compared to assets currently held in external  trust         |       | $          | (105,869   | )          | $          | 204,006 |   |

 

Decommissioningexpenses recognized include the following components:

 
| **(Thousands of Dollars)**                                   | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Annual  decommissioning cost expense reported as depreciation expense: |       |     |       |     |       |     |       |
| Externally  funded                                                     |       | $        | 2,849      |     | $          | 43,239   |       | $ | 43,392 |   |
| Internally  funded (including interest costs)                          |       | (884     | )          | (819     | )          | (759     | )          |
| Net  decommissioning expense recorded                                  |       | $        | 1,965      |     | $          | 42,420   |       | $ | 42,633 |   |

 

Reductionsto expense for internally-funded portions in 2009, 2008 and 2007 are a directresult of the 2008 and 2005 decommissioning study jurisdictional allocation and100 percent external funding approval, effectively unwinding the remaininginternal fund over the remaining operating life of the unit.  The 2008 nuclear decommissioning filingapproved in 2009 has been used for the regulatory presentation.  The change in estimated decommissioningobligations was calculated using a cost estimate for Monticello assuming a60-year operating life.

 

**16.Regulatory Assets and Liabilities**

 

NSP-Minnesota’sconsolidated financial statements are prepared in accordance with theprovisions of *ASC 980 Regulated Operations*, asdiscussed in Note 1 to the consolidated financial statements.  Under this guidance, regulatory assets andliabilities can be created for amounts that regulators may allow to becollected, or may require to be paid back to customers in future electric andnatural gas rates.  Any portion of thebusiness that is not rate regulated cannot establish regulatory assets andliabilities.  If changes in the utilityindustry or the business of NSP-Minnesota no longer allow for the applicationof regulatory accounting guidance under GAAP, NSP-Minnesota would be requiredto recognize the write-off of regulatory assets and liabilities in itsconsolidated statement of income.

 

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Thecomponents of unamortized regulatory assets and liabilities on the consolidatedbalance sheets of NSP-Minnesota are:

 
| **(Thousands of Dollars)**                                                     | ** ** | **See  Note** | ** ** | **Remaining  Amortization Period** | ** ** | **2009** | ** ** | **2008** | ** ** |
|------------------------------------------------------------------------------------------|------------|---------------|------------|------------------------------------|------------|----------|------------|----------|------------|
| **Regulatory Assets**                                                                    |       |          |       |                               |       |     |       |     |       |
| Current  regulatory asset - Recoverable purchased natural gas and electric energy  costs |       | 1             |       | Less than one year                 |       | $        | 30,428     |     | $          | 26,605 |   |
|                                                                                     |       |          |       |                               |       |     |       |     |       |
| Pension  and employee benefit obligations (d)                                       |       |          |       | Various                            |       | $        | 188,139    |     | $          | 153,892 |   |
| Net  AROs (a)                                                                            |       | 14            |       | Plant lives                        |       | 155,773  |       | 256,791  |       |
| AFUDC  recorded in plant  (b)                                                            |       | 14            |       | Plant lives                        |       | 133,602  |       | 124,242  |       |
| Contract  valuation adjustments(c)                                                       |       | 10            |       | Term of contract                   |       | 89,026   |       | 86,937   |       |
| Nuclear  outage costs                                                                    |       | 13            |       | Generally 18-24 months             |       | 60,747   |       | 40,690   |       |
| Conservation  programs (b)                                                          |       |          |       | Up to two years                    |       | 46,028   |       | 23,911   |       |
| Renewable  and environmental initiative costs                                            |       |          |       | Two to three years                 |       | 41,935   |       | 58,056   |       |
| Losses  on reacquired debt                                                               |       | 1             |       | Term of related debt               |       | 23,505   |       | 26,081   |       |
| Purchased  power contracts costs                                                         |       | 10            |       | Term of related  contract          |       | 20,014   |       | 13,228   |       |
| Unrecovered  natural gas costs                                                           |       | 1             |       | One to two years                   |       | 10,620   |       | 14,657   |       |
| MISO  Day 2 costs                                                                        |       | 1             |       | Three years                        |       | 9,829    |       | 8,742    |       |
| Nuclear  fuel storage                                                                    |       | 1             |       | Three to six years                 |       | 8,301    |       | 9,652    |       |
| State  commission accounting adjustments(b)                                              |       | 13            |       | Plant lives                        |       | 4,631    |       | 4,398    |       |
| Other                                                                                    |       |          |       | Various                            |       | 5,513    |       | 7,435    |       |
| Total  noncurrent regulatory assets                                                      |       |          |       |                               |       | $        | 797,663    |     | $          | 828,712 |   |
|                                                                                     |       |          |       |                               |       |     |       |     |       |
| **Regulatory Liabilities**                                                               |       |          |       |                               |       |     |       |     |       |
| Plant  removal costs                                                                     |       | 14            |       |                               |       | $        | 371,867    |     | $          | 354,117 |   |
| Deferred  income tax adjustments                                                         |       |          |       |                               |       | 32,792   |       | 30,787   |       |
| Investment  tax credit deferrals                                                         |       |          |       |                               |       | 25,659   |       | 27,797   |       |
| Contract  valuation adjustments (c)                                                      |       |          |       |                               |       | 20,871   |       | 23,355   |       |
| Nuclear  outage costs collected in advance from customers                                |       |          |       |                               |       | 10,322   |       | 13,678   |       |
| Low  income discount program                                                             |       |          |       |                               |       | 2,634    |       | 3,943    |       |
| Gain  on sale of emission allowances                                                     |       |          |       |                               |       | 2,239    |       | 2,727    |       |
| Interest  on income tax refunds                                                          |       |          |       |                               |       | 1,302    |       | 1,736    |       |
| Other                                                                                    |       |          |       |                               |       | 2,083    |       | 1,740    |       |
| Total  noncurrent regulatory liabilities                                                 |       |          |       |                               |       | $        | 469,769    |     | $          | 459,880 |   |

 

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(a)  Includes amounts recorded forfuture recovery of AROs, less amounts recovered through nuclear decommissioningaccruals and gains from decommissioning investments.

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

(c)  Includes the fair value ofcertain long-term purchased power agreements used to meet energy capacityrequirements.

(d)  Includes $427.2 million forthe regulatory recognition of the pension expense, offset by $1.4 million ofregulatory assets related to the non-qualified pension plan.

 

**17.Segments and Related Information**

 

NSP-Minnesota has tworeportable segments, regulated electric utility and regulated natural gasutility.

 

·                  NSP-Minnesota’s regulated electric utility segmentgenerates, transmits and distributes electricity in Minnesota, North Dakota andSouth Dakota.  In addition, this segmentincludes sales for resale and provides wholesale transmission service tovarious entities in the United States. Regulated electric utility also includes NSP-Minnesota’s commoditytrading operations.

 

·                  NSP-Minnesota’s regulated natural gas utility segmenttransports, stores and distributes natural gas in portions of Minnesota andNorth Dakota.

 

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Revenues from operatingsegments not included above are below the necessary quantitative thresholds andare therefore included in the all other category.  Those primarily include appliance repairservices, nonutility real estate activities and revenues associated withprocessing solid waste into refuse-derived fuel.

 

Operating results fromthe regulated electric utility and regulated natural gas utility serve as theprimary basis for the chief operating decision maker to evaluate the dualperformance of NSP-Minnesota.

 

To report net income forregulated electric and regulated natural gas utility segments, NSP-Minnesotamust assign or allocate all costs and certain other income.  In general, costs are:

 

·      Directly assigned wherever applicable;

·                  Allocated based on cost causation allocators whereverapplicable; or

·                  Allocated based on a general allocator for all othercosts not assigned by the above two methods.

 

The accounting policiesof the segments are the same as those described in Note 1 to the consolidatedfinancial statements.  These segments aremanaged separately because the revenue streams are dependent upon regulatedrate recovery, which is separately determined for each segment.

 
| **(Thousands of Dollars)**        | ** ** | **Regulated  Electric** | ** ** | **Regulated  Natural Gas** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|---------------------------------------------|------------|-------------------------|------------|---------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| **2009**                                    |       |                    |       |                            |       |           |       |                          |       |                    |       |
| Operating  revenues from external customers |       | $                       | 3,407,273  |                            | $          | 640,323        |       | $                             | 19,093     |                    | $          |   |   | $ | 4,066,689 |   |
| Intersegment  revenues                      |       | 414                     |       | 1,799                           |       | —         |       | (2,213                        | )          | —                  |       |
| Total  revenues                             |       | $                       | 3,407,687  |                            | $          | 642,122        |       | $                             | 19,093     |                    | $          | (2,213 | ) | $ | 4,066,689 |   |
|                                        |       |                    |       |                            |       |           |       |                          |       |                    |       |
| Depreciation  and amortization              |       | $                       | 353,089    |                            | $          | 35,854         |       | $                             | 424        |                    | $          | — |   | $ | 389,367 |   |
| Interest  charges and financing cost        |       | 160,091                 |       | 16,608                          |       | 354            |       | (5                            | )          | 177,048                 |       |
| Income  tax expense (benefit)               |       | 167,708                 |       | 11,677                          |       | (4,264         | )          | —                        |       | 175,121                 |       |
| Income  from continuing operations          |       | 261,556                 |       | 21,881                          |       | 10,333         |       | —                        |       | 293,770                 |       |
|                                        |       |                    |       |                            |       |           |       |                          |       |                    |       |
| **2008**                                    |       |                    |       |                            |       |           |       |                          |       |                    |       |
| Operating  revenues from external customers |       | $                       | 3,584,109  |                            | $          | 889,958        |       | $                             | 19,569     |                    | $          | — |   | $ | 4,493,636 |   |
| Intersegment  revenues                      |       | 564                     |       | 4,863                           |       | —         |       | (5,427                        | )          | —                  |       |
| Total  revenues                             |       | $                       | 3,584,673  |                            | $          | 894,821        |       | $                             | 19,569     |                    | $          | (5,427 | ) | $ | 4,493,636 |   |
|                                        |       |                    |       |                            |       |           |       |                          |       |                    |       |
| Depreciation  and amortization              |       | $                       | 376,768    |                            | $          | 35,209         |       | $                             | 385        |                    | $          | — |   | $ | 412,362 |   |
| Interest  charges and financing cost        |       | 162,697                 |       | 17,464                          |       | 1,454          |       | (386                          | )          | 181,229                 |       |
| Income  tax expense (benefit)               |       | 167,961                 |       | 12,509                          |       | (2,234         | )          | —                        |       | 178,236                 |       |
| Income  from continuing operations          |       | 250,785                 |       | 28,887                          |       | 5,469          |       | —                        |       | 285,141                 |       |
|                                        |       |                    |       |                            |       |           |       |                          |       |                    |       |
| **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 |   |
| Interest  charges and financing cost        |       | 151,012                 |       | 17,256                          |       | 707            |       | (16                           | )          | 168,959                 |       |
| Income  tax expense                         |       | 165,531                 |       | 11,315                          |       | 5,179          |       | —                        |       | 182,025                 |       |
| Income  (loss) from continuing operations   |       | 246,086                 |       | 21,485                          |       | (269           | )          | —                        |       | 267,302                 |       |

 

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**18.  Related PartyTransactions**

 

XcelEnergy Services Inc. provides management, administrative and other services forthe subsidiaries of Xcel Energy, including NSP-Minnesota.  The services are provided and billed to eachsubsidiary in accordance with Service Agreements executed by each subsidiary.  Costs are charged directly to the subsidiarywhich uses the service whenever possible and are allocated if they cannot bedirectly assigned.

 

XcelEnergy has established a utility money pool arrangement with the utilitysubsidiaries.  See Note 4 for furtherdiscussion of this borrowing arrangement.

 

***Nuclear Plant Operation —*** On Sept. 28,2007, NSP-Minnesota obtained 100 percent ownership in NMC as a result ofWisconsin Energy Corporation (WEC), exiting the partnership due to the sale ofits Point Beach Nuclear Plant to FPL Energy. Accordingly, the results of operations of NMC and the estimated fairvalue of assets and liabilities were included in NSP-Minnesota’s consolidatedfinancial statements from the Sept. 28, 2007, transaction date.  NSP-Minnesota has reintegrated its nuclearoperations into its generation operations. The NRC transferred the nuclear operating licenses from NMC toNSP-Minnesota effective Sept. 22, 2008.

 

Priorto Sept. 28, 2007, NSP-Minnesota also paid its proportionate share of theoperating expenses and capital improvement costs incurred by NMC, in accordancewith the Nuclear Power Plant Operating Services Agreement.  NSP-Minnesota paid NMC $235.2 million in2007.

 

Theelectric production and transmission costs of the entire NSP system are sharedby NSP-Minnesota and NSP-Wisconsin.  TheInterchange Agreement provides for the sharing of all costs of generation andtransmission facilities of the system, including capital costs.

 

Thetable below contains significant affiliate transactions among the companies andrelated parties including billings under the Interchange Agreement for theyears ended Dec. 31:

 
| **(Thousands of Dollars)**                       | ** ** | **2009**   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Operating  revenues:                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Electric                                                   |       | $          | 389,023    |       | $          | 390,143    |       | $ | 372,215 |   |
| Gas                                                        |       | 309        |       | 312        |       | 366        |       |
| Operating  expenses:                                       |       |       |       |       |       |       |       |
| Purchased  power                                           |       | 64,059     |       | 64,195     |       | 79,345     |       |
| Transmission  expense                                      |       | 45,192     |       | 42,167     |       | 40,872     |       |
| Other  operations — paid to Xcel Energy Services Inc. |       | 303,348    |       | 275,618    |       | 267,281    |       |
| Interest  expense                                          |       | 596        |       | 1,645      |       | 1,742      |       |
| Interest  income                                           |       | 50         |       | 2,536      |       | 1,422      |       |
|                                                            |            |            |            |            |            |            |            |  |  |  |

 

Accountsreceivable and payable with affiliates at Dec. 31, was:

 
| ** **                           | ** ** | **2009**                 | ** ** | **2008**              | ** ** |
|--------------------------------------|------------|--------------------------|------------|-----------------------|------------|
| **(Thousands of Dollars)** | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** |
| NSP-Wisconsin                        |       | $                        | 31,243     |                  | $          | — |   | $ | 12,416 |   | $ | — |   |
| PSCo                                 |       | —                   |       | 15,789                |       | — |   | 15,987 |   |
| SPS                                  |       | —                   |       | 2,268                 |       | — |   | 3,330 |   |
| Other  subsidiaries of Xcel Energy   |       | 2                        |       | 65,702                |       | 2 |   | 32,974 |   |
|                                 |       | $                        | 31,245     |                  | $          | 83,759 |   | $ | 12,418 |   | $ | 52,291 |   |

 

NSP-Wisconsinobtains short-term borrowings from NSP-Minnesota at NSP-Minnesota’s averagedaily interest rate, including the cost of NSP-Minnesota’s compensating balancerequirements.  At Dec. 31, 2009 and2008, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in theamount of $15.5 million and $0.0 million, respectively.

 

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

** **

**Due to the seasonality of**NSP-Minnesota’s electric and natural gas sales, such interimresults are not necessarily an appropriate base from which to project annualresults.  Summarized quarterly unauditedfinancial data is as follows:

 
| ** **                  | ** ** | **Quarter  Ended**       | ** ** |
|-----------------------------|------------|--------------------------|------------|
| **(Thousands  of Dollars)** | ** ** | **March 31,  2009** | ** ** | **June 30,  2009** | ** ** | **Sept.  30, 2009** | ** ** | **Dec. 31,  2009** | ** ** |
| Operating  revenues         |       | $                        | 1,203,383  |   | $ | 866,404 |   | $ | 969,359 |   | $ | 1,027,543 |   |
| Operating  income           |       | 158,984                  |       | 115,290 |   | 196,448 |   | 144,797 |   |
| Net  income                 |       | 76,199                   |       | 49,898 |   | 92,549 |   | 75,124 |   |
|                             |            |                          |            |  |  |  |  |  |  |  |  |  |  |

 
| ** **                  | ** ** | **Quarter  Ended**       | ** ** |
|-----------------------------|------------|--------------------------|------------|
| **(Thousands  of Dollars)** | ** ** | **March 31,  2008** | ** ** | **June 30,  2008** | ** ** | **Sept.  30, 2008** | ** ** | **Dec. 31,  2008** | ** ** |
| Operating  revenues         |       | $                        | 1,267,724  |   | $ | 1,021,865 |   | $ | 1,103,096 |   | $ | 1,100,951 |   |
| Operating  income           |       | 130,865                  |       | 112,003 |   | 218,319 |   | 146,014 |   |
| Net  income                 |       | 63,968                   |       | 48,353 |   | 110,340 |   | 62,480 |   |
|                             |            |                          |            |  |  |  |  |  |  |  |  |  |  |

 

**Item 9 —Changes in and Disagreements With Accountants on Accounting and FinancialDisclosure**

 

During2008 and 2009, and through the date of this report, there were no disagreementswith the independent public accountants for NSP-Minnesota on accountingprinciples or practices, financial statement disclosures or auditing scope orprocedures.

 

**Item 9A — Controls and Procedures**

 

**DisclosureControls and Procedures**

 

NSP-Minnesotamaintains a set of disclosure controls and procedures designed to ensure thatinformation required to be disclosed in reports that it files or submits underthe Securities Exchange Act of 1934 is recorded, processed, summarized andreported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls andprocedures ensure that information required to be disclosed is accumulated andcommunicated to management, including the chief executive officer (CEO) andchief financial officer (CFO), allowing timely decisions regarding requireddisclosure.  As of Dec. 31, 2009,based on an evaluation carried out under the supervision and with theparticipation of NSP-Minnesota’s management, including the CEO and CFO, of theeffectiveness of its disclosure controls and the procedures, the CEO and CFOhave concluded that NSP-Minnesota’s disclosure controls and procedures wereeffective.

 

**InternalControls Over Financial Reporting**

 

Nochange in NSP-Minnesota’s internal control over financial reporting hasoccurred during the most recent fiscal quarter that has materially affected, oris reasonably likely to materially affect, NSP-Minnesota’s internal controlover financial reporting.  NSP-Minnesotamaintains internal control over financial reporting to provide reasonableassurance regarding the reliability of the financial reporting.  NSP-Minnesota has evaluated and documentedits controls in process activities, in general computer activities, and on anentity-wide level.  During the year andin preparation for issuing its report for the year ended Dec. 31, 2009 oninternal controls under section 404 of the Sarbanes-Oxley Act of 2002,NSP-Minnesota conducted testing and monitoring of its internal control overfinancial 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.

 

**Item 9B**— **Other Information**

 

None.

 

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**PART III**

 

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

 

**Item 10 — Directors, Executive Officers and CorporateGovernance**

 

**Item 11 — Executive Compensation**

 

**Item 12 — Security Ownership of Certain Beneficial Owners andManagement and Related Stockholder Matters**

 

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

 

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

 

Informationconcerning fees paid to the principal accountant for each of the last two yearsis contained in the Xcel Energy Proxy Statement for its 2010 Annual Meeting ofShareholders, which is incorporated by reference.

 

**PART IV**

 

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

 
| 1.     |   | Consolidated  Financial Statements:                                                                                           |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                          |
|   |   | Management Report on Internal Controls **—**For the year ended Dec. 31, 2009.                                       |
|   |   | Report of Independent Registered Public Accounting Firm **—**For the years ended Dec. 31, 2009,  2008 and 2007.     |
|   |   | Consolidated  Statements of Income **—**For the  three years ended Dec. 31, 2009, 2008 and 2007.                    |
|   |   | Consolidated Statements of Cash Flows **—** For the three years ended Dec. 31, 2009, 2008 and  2007.                |
|   |   | Consolidated Balance Sheets **—**As  of Dec. 31, 2009 and 2008.                                                     |
|   |   |                                                                                                                          |
| 2.     |   | Schedule II **—**Valuation  and Qualifying Accounts and Reserves for the years ended Dec. 31, 2009,  2008 and 2007. |
|   |   |                                                                                                                          |
| 3.     |   | Exhibits                                                                                                                      |

 

----

*Indicates incorporation by reference

+Executive Compensation Arrangements and BenefitPlans Covering Executive Officers and Directors

 
| 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 NSP-Minnesota  (Exhibit 3.02 to Form 10-12G (file no. 000-31709) dated  Oct. 5, 2000).                                                                                                                                                                                                                      |
| 3.03*  |   | By-Laws of NSP-Minnesota  as Amended and Restated (a Minnesota corporation) (Exhibit 3.02 to  Form 8-K (file no. 001-31387) dated June 3, 2008).                                                                                                                                                                       |
| 4.01*  |   | Supplemental and Restated  Trust Indenture, dated May 1, 1988, from NSP-Minnesota 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, dated  as follows: |
|   |   |  - Supplemental Indenture dated Oct. 1,  1992 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated  Oct. 13, 1992 Rider A).                                                                                                                                                                                  |
|   |   |  - Supplemental Indenture dated April 1,  1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated  March 30, 1993 Rider A).                                                                                                                                                                                |
|   |   |  - Supplemental Indenture dated Dec. 1,  1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated  Dec. 7, 1993 Rider A).                                                                                                                                                                                   |
|   |   |  - Supplemental Indenture dated June 1,  1995 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated  June 28, 1995 Rider A).                                                                                                                                                                                  |
|   |   |  - Supplemental Indenture dated March 1,  1998 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated  March 11, 1998).                                                                                                                                                                                        |
|   |   |  - Supplemental Indenture dated May 1,  1999 (Exhibit 4.49 to NSP-Minnesota Form 10-12G (file no.  000-31709) dated Oct. 5, 2000 Rider A).                                                                                                                                                                   |
|   |   |  - Supplemental Indenture dated June 1,  2000 (Exhibit 4.50 to NSP-Minnesota Form 10-12G (file no.  000-31709) dated Oct. 5, 2000 Rider A).                                                                                                                                                                  |

 

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| 4.02*   |   | - Supplemental Indenture  dated 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).                                                                                                                                                               |
|---------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.03*   |   | Trust Indenture, dated  July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, National  Association (NA), as Trustee.   (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034)  dated July 21, 1999).                                                                                                                       |
| 4.04*   |   | Supplemental Trust  Indenture, dated July 15, 1999, between NSP-Minnesota and Norwest Bank  Minnesota, NA, as Trustee.   (Exhibit 4.02 to NSP-Minnesota Form 8-K (file no. 001-03034)  dated July 21, 1999).                                                                                                                                |
| 4.05*   |   | Supplemental Trust  Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated  July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank  Minnesota, NA, as Trustee.   (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no.  000-31709) dated Oct. 5, 2000).                                                       |
| 4.06*   |   | Supplemental Trust  Indenture dated June 1, 2002, supplemental to the Indentures dated  Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest  Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file  no. 000-31387) for the quarter ended Sept. 30, 2002).                                                        |
| 4.07*   |   | Supplemental Trust  Indenture dated July 1, 2002, supplemental to the Indentures dated  Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest  Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file  no. 000-31387) for the quarter ended Sept. 30, 2002).                                                        |
| 4.08*   |   | Supplemental Trust  Indenture dated July 1, 2002, supplemental to the Indenture dated  July 1, 1999, between NSP-Minnesota and Wells Fargo Bank Minnesota, NA,  as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated  July 8, 2002).                                                                                             |
| 4.09*   |   | Supplemental Trust  Indenture dated Aug. 1, 2002, supplemental to the Indentures dated  Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest  Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no.  001-31387) dated Aug. 22, 2002).                                                                     |
| 4.10*   |   | Supplemental Trust  Indenture dated Aug. 1, 2003 between NSP-Minnesota 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).                                                                                                   |
| 4.11*   |   | Supplemental Trust  Indenture dated May 1, 2003 between NSP-Minnesota and BNY Midwest Trust  Co., supplementing indentures dated Feb. 1, 1937 and May 1,  1988.  (Exhibit 4.73 to  Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2003).                                                                              |
| 4.12*   |   | 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, (file no. 001-31387) dated  July 14, 2005).  |
| 4.13*   |   | 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, (file no. 001-31387) dated  May 18, 2006).     |
| 4.14*   |   | 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).                                                                                                                              |
| 4.15*   |   | Supplemental Indenture  dated March 1, 2008 between NSP-Minnesota and The Bank of New York Trust  Company, NA, as successor trustee (Exhibit 4.01 to Form 8-K (file  no. 001-31387) dated March 11, 2008.                                                                                                                                        |
| 4.16*   |   | Supplemental Indenture  dated as of Nov. 1, 2009 between NSP-Minnesota and The Bank of New York  Mellon Trust Co., NA, as successor Trustee, creating $300,000,000 principal  amount of 5.35 percent First Mortgage Bonds, Series due Sept. 1, 2039 (Exhibit 4.01  of Form 8-K of NSP-Minnesota dated Nov. 16, 2009 (file no.  001-31387)). |
| 10.01*+ |   | Xcel Energy Omnibus  Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034)  filed Aug. 29, 2000).                                                                                                                                                                                                                                            |
| 10.02*+ |   | Xcel Energy Inc.  Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to  Form 10-K of Xcel Energy (file no. 001-03034) for the year ended  Dec. 31, 2008).                                                                                                                                                                                  |
| 10.03*+ |   | Amended and Restated  Executive Long-Term Incentive Award Stock Plan.  (Exhibit 10.02 to Xcel Energy  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).                                                                                                                                                                                                 |
| 10.05*+ |   | Xcel Energy Senior  Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05  to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended  Dec. 31, 2008).                                                                                                                                                                  |
| 10.06*+ |   | Stock Equivalent Plan for  Non-Employee Directors of Xcel Energy as amended and restated Jan. 1,  2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no.  001-03034) for the year ended Dec. 31, 2008.                                                                                                                                        |
| 10.07*+ |   | Xcel Energy Nonqualified  Deferred Compensation Plan as amended and restated Jan. 1, 2009  (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for  the year ended Dec. 31, 2008).                                                                                                                                                   |

 

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| 10.08*+ |   | Xcel Energy Non-employee  Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy  Form 10-K (Exhibit 10.08 to Form 10-K of Xcel Energy (file no.  001-03034) for the year ended Dec. 31, 2008).                                                                                                    |
|---------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.09*+ |   | 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).                                                                                                                                                                                                                                                                                |
| 10.10*+ |   | 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).                                                                                                                                                          |
| 10.11*+ |   | 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).                                                                                                                                                               |
| 10.12*+ |   | 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).                                                                                                                                                          |
| 10.13*+ |   | Xcel Energy Omnibus 2005  Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement to  Xcel Energy (file no. 001-03034) dated April 11, 2005).                                                                                                                                                                         |
| 10.14*+ |   | Xcel Energy Executive  Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy  Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005).                                                                                                                                                               |
| 10.15*+ |   | Xcel Energy Supplemental  Executive Retirement Plan as amended and restated Jan. 1, 2009  (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for  the year ended Dec. 31, 2008).                                                                                                                             |
| 10.16*+ |   | First Amendment to the  Xcel Energy Inc. Executive Annual Incentive Award Plan effective as of  Jan. 1, 2009 (Exhibit 10.21 to Form 10-K of Xcel Energy (file  no. 001-03034) for the year ended Dec. 31, 2008).                                                                                                          |
| 10.17*+ |   | First Amendment to the  Xcel Energy Inc. Omnibus Incentive Award Plan as of Jan. 1, 2009  (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for  the year ended Dec. 31, 2008).                                                                                                                             |
| 10.18*  |   | Facilities Agreement,  dated July 21, 1976, between NSP-Minnesota and the Manitoba  Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06I to file no. 2-54310).                                                                                                                             |
| 10.19*  |   | Transactions Agreement,  dated July 21, 1976, between NSP-Minnesota and the Manitoba  Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06J to file no. 2-54310).                                                                                                                           |
| 10.20*  |   | Coordinating Agreement,  dated July 21, 1976, between NSP-Minnesota and the Manitoba  Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06K to file no. 2-54310).                                                                                                                           |
| 10.21*  |   | Ownership and Operating  Agreement, dated March 11, 1982, between NSP-Minnesota, 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). |
| 10.22*  |   | Power Agreement, dated  June 14, 1984, between NSP-Minnesota 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).                            |
| 10.23*  |   | Power Agreement, dated  August 1988, between NSP-Minnesota and Minnkota Power Co.  (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).                                                                                                                                                                         |
| 10.24*  |   | Amended agreement for the  sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly  known as Norenco Corp.) and NSP-Minnesota and Norenco Corp.  (Exhibit 10.33 to NRG’s Registration on Form S-1, file no.  333-35096).                                                                                   |
| 10.25*  |   | Operations and maintenance  agreement dated Nov. 1, 1996 between NRG Energy and NSP-Minnesota.  (Exhibit 10.34 to NRG’s Registration  on Form S-1, file no. 333-35096).                                                                                                                                              |
| 10.26*  |   | Amended Agreement for the  sale of thermal energy and wood byproduct dated Dec. 1, 1986 between NSP-Minnesota  and Norenco Corp. (Exhibit 10.36 to NRG’s Registration on Form S-1,  file no. 333-35096).                                                                                                                  |
| 10.27*  |   | Restated Interchange  Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota  (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033)  dated Jan. 21, 2004).                                                                                                                                        |
| 10.28*  |   | 500 megawatt System  Participation Power Sale Agreement dated July 30, 2002 between  NSP-Minnesota and the Manitoba Hydro-Electric Board (Exhibit 99.01 to  NSP-Minnesota Form 8-K (file no. 001-31387) dated March 25, 2003).                                                                                            |
| 10.29*  |   | Amendment  dated as of April 13, 2009 to the NSP-Minnesota Credit Agreement dated  as of Dec. 14, 2006.   (Exhibit 10.02 to Form 10-Q of Xcel Energy (file  no. 001-03034) for the quarter ended June. 30, 2009).                                                                                          |
| 10.30*  |   | Credit  Agreement dated Dec. 14, 2006 between NSP-Minnesota and various lenders  (Exhibit 10.02 to Form 10-Q of Xcel Energy (file  no. 001-03034) for the quarter ended Sept. 30, 2009).                                                                                                                             |
| 10.31*+ |   | Second  Amendment to the Xcel Energy 2005 Omnibus Incentive Plan (renaming it the  Xcel Energy 2005 Long-Term Incentive Plan) (Exhibit 10.05 to  Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended  Sept. 30, 2009).                                                                                    |
| 10.32*+ |   | Amendment  dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and  Change-in-Control Policy.  (Exhibit 10.06  to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter  ended Sept. 30, 2009).                                                                                           |
| 10.33*+ |   | Second  Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan  (Effective May 25, 2005) (Exhibit 10.07 to Form 10-Q of Xcel  Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).                                                                                                    |

 

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| 10.34*+ |   | Xcel  Energy Executive Annual Incentive Award Plan Form of Restricted Stock  Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file  no. 001-03034) for the quarter ended Sept. 30, 2009). |
|---------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.35*+ |   | Xcel Energy 2010 Executive  Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel  Energy (file no. 001-03034) for the year ended Dec. 31, 2009).                                     |
| 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, 2009, 2008 and 2007***(amounts in thousands of dollars)*

 
| ** **                                | ** ** | ** **                   | ** ** | **Additions**                       | ** ** | ** **                             | ** ** | ** **                            | ** ** |
|-------------------------------------------|------------|------------------------------|------------|-------------------------------------|------------|----------------------------------------|------------|---------------------------------------|------------|
| ** **                                | ** ** | **Balance  at  Jan. 1** | ** ** | **Charged  to costs and  expenses** | ** ** | **Charged  to other  accounts****(a)** | ** ** | **Deductions  from  reserves****(b)** | ** ** | **Balance  at  Dec. 31** | ** ** |
| **Reserve deducted from related assets:** | ** ** | ** **                   | ** ** | ** **                          | ** ** | ** **                             | ** ** | ** **                            | ** ** | ** ** | ** ** |
| Allowance  for bad debts:                 | ** ** | ** **                   | ** ** | ** **                          | ** ** | ** **                             | ** ** | ** **                            | ** ** | ** ** | ** ** |
| 2009                                      |       | $                            | 25,699     |                                | $          | 19,408                                 |       | $                                     | 5,521      |   | $ | 27,953 |   | $ | 22,675 |   |
| 2008                                      |       | 20,103                       |       | 25,506                              |       | 6,113                                  |       | 26,023                                |       | 25,699 |   |
| 2007                                      |       | 13,408                       |       | 23,336                              |       | 5,853                                  |       | 22,494                                |       | 20,103 |   |
|                                           |            |                              |            |                                     |            |                                        |            |                                       |            |  |  |  |  |  |  |  |

 

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(a)  Recovery of amountspreviously written off.

(b)  Principally bad debts writtenoff or transferred.

 

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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/ DAVID M. SPARBY                                                                                  |
|                   | David M. Sparby  Vice President, Chief Financial Officer and Director  (Principal Financial Officer) |
|                   |                                                                                                 |
| **March 1, 2010** | ** **                                                                                           |

 

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report has been signed below bythe following persons on behalf of the registrant and in the capacities and on March 1,2010.

 
| /s/ JUDY M. POFERL                                                                                  |   | /S/ RICHARD C. KELLY                                                                                 |
|-----------------------------------------------------------------------------------------------------|--------|------------------------------------------------------------------------------------------------------|
| Judy M. Poferl  President, Chief Executive Officer and Director  (Principal Executive Officer) |   | Richard C. Kelly  Chairman and Director                                                              |
|                                                                                                |   |                                                                                                 |
| /S/ TERESA S. MADDEN                                                                                |   | /S/ DAVID M. SPARBY                                                                                  |
| Teresa S. Madden  Vice President and Controller  (Principal Accounting Officer)                     |   | David M. Sparby  Vice President, Chief Financial Officer and Director  (Principal Financial Officer) |
|                                                                                                |   |                                                                                                 |
| /S/ BENJAMIN G.S. FOWKE  III                                                                        |   |                                                                                                 |
| Benjamin G.S. Fowke III  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-Minnesotahas not sent, and does not expect to send, an annual report or proxy statementto its security holder.

 

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