Tableof Contents

 

 

 

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C.  20549**

 

# **FORM 10-K**

#  

**(Mark One)**

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

 

**For the fiscal year ended December 31,2008**

 

**Or**

 

**o****TRANSITION REPORTPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934**

 

**Commission file number 001-31387**

 

# **NORTHERN STATES 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) of theAct:  **None**

 

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

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed allreports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days.    xYes   oNo

 

Indicate by check mark if disclosure of delinquent filers pursuant toItem 405 of Regulations S-K (§229.405 of this chapter) is not contained herein,and will not be contained, to the best of the registrant’s knowledge, indefinitive proxy or information statements incorporated by reference in Part IIIof this Form 10-K or any amendment to this Form 10-K.    x

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company.  See the definitions of “large acceleratedfiler,” “accelerated filer” and “ smaller reporting company” in Rule 12b-2of the Exchange Act.

o Large accelerated filer  o Acceleratedfiler  xNon-accelerated filer (Do not check if a smaller reporting company)o Smaller Reporting Company

 

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theAct).    oYes   xNo

 

As of March 2, 2009,1,000,000 shares of common stock, par value $0.01 per share, were outstanding,all of which were held by Xcel Energy Inc., a Minnesota corporation.

 

DOCUMENTSINCORPORATED BY REFERENCE

 

Xcel Energy Inc.’sDefinitive Proxy Statement for its 2009 Annual Meeting of Shareholders isincorporated by reference into Part III of this Form 10-K.

 

Northern States PowerCompany meets the conditions set forth in General Instruction I(1)(a) and (b) ofForm 10-K and is therefore filing this form with the reduced disclosureformat permitted by General Instruction I(2).

 

 

 

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**INDEX**

 
| **PART I**                                                                                                                  | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------|------------|
| Item 1 — Business                                                                                                           |       |
| DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS                                                                                   |       |
| COMPANY OVERVIEW                                                                                                                 |       |
| ELECTRIC UTILITY OPERATIONS                                                                                                      |       |
| Overview                                                                                                                         |       |
| Public Utility Regulation                                                                                                        |       |
| Capacity and Demand                                                                                                              |       |
| Energy Sources and Related Transmission Initiatives                                                                              |       |
| Fuel Supply and Costs                                                                                                            |       |
| Fuel Sources                                                                                                                     |       |
| Wholesale Commodity Marketing Operations                                                                                         |       |
| Summary of Recent Federal Regulatory Developments                                                                                |       |
| Electric  Operating Statistics                                                                                                   |       |
| NATURAL  GAS UTILITY OPERATIONS                                                                                                  |       |
| Public  Utility Regulation                                                                                                       |       |
| Capability and Demand                                                                                                            |       |
| Natural  Gas Supply and Costs                                                                                                    |       |
| Natural Gas Operating Statistics                                                                                                 |       |
| ENVIRONMENTAL MATTERS                                                                                                            |       |
| EMPLOYEES                                                                                                                        |       |
| Item 1A  — Risk Factors                                                                                                     |       |
| Item 1B — Unresolved SEC Staff Comments                                                                                     |       |
| Item 2 —  Properties                                                                                                        |       |
| Item  3 — Legal Proceedings                                                                                                 |       |
| Item 4 — Submission of Matters to a Vote of Security  Holders                                                               |       |
|                                                                                                                             |       |
| **PART II**                                                                                                                 | ** ** |
| Item 5 — Market for Registrant’s Common Equity,  Related Stockholder Matters and Issuer Purchases of Equity Securities |       |
| Item  6 — Selected Financial Data                                                                                           |       |
| Item 7 — Management’s Discussion and Analysis of Financial  Condition and Results of Operations                        |       |
| Item 7A — Quantitative and Qualitative Disclosures  About Market Risk                                                       |       |
| Item 8 — Financial Statements and Supplementary Data                                                                        |       |
| Item 9 — Changes in and Disagreements with Accountants  on Accounting and Financial Disclosure                              |       |
| Item 9A(T) — Controls and Procedures                                                                                   |       |
| Item  9B — Other Information                                                                                                |       |
|                                                                                                                             |       |
| **PART III**                                                                                                                | ** ** |
| Item 10 — Directors, Executive Officers and Corporate  Governance                                                           |       |
| Item 11 — Executive Compensation                                                                                            |       |
| Item 12 — Security Ownership of Certain Beneficial  Owners and Management and Related Stockholder Matters                   |       |
| Item 13 — Certain Relationships, Related Transactions  and Director Independence                                            |       |
| Item 14 — Principal Accounting Fees and Services                                                                            |       |
|                                                                                                                             |       |
| **PART IV**                                                                                                                 | ** ** |
| Item 15 — Exhibits, Financial Statement Schedules                                                                           |       |
|                                                                                                                             |       |
| **SIGNATURES**                                                                                                                   | ** ** |

 

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

 

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**PART I**

 

**Iteml — Business**

 

# **DEFINITIONOF ABBREVIATIONS AND INDUSTRY TERMS**

 
| ***Xcel Energy Subsidiaries and Affiliates***                  |         |                                                                                                                                                                                                                                                                                                                                                                                                                              |
|----------------------------------------------------------------|--------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| NMC                                                            |         | Nuclear  Management Co., a wholly owned subsidiary of NSP Nuclear Corporation                                                                                                                                                                                                                                                                                                                                                     |
| NSP-Minnesota                                                  |         | Northern  States Power Co., a Minnesota corporation                                                                                                                                                                                                                                                                                                                                                                               |
| NSP-Wisconsin                                                  |         | Northern  States Power Co., a Wisconsin corporation                                                                                                                                                                                                                                                                                                                                                                               |
| PSCo                                                           |         | Public  Service Company of Colorado, a Colorado corporation                                                                                                                                                                                                                                                                                                                                                                       |
| SPS                                                            |         | Southwestern  Public Service Co., a New Mexico corporation                                                                                                                                                                                                                                                                                                                                                                        |
| utility  subsidiaries                                          |         | NSP-Minnesota,  NSP-Wisconsin, PSCo, SPS                                                                                                                                                                                                                                                                                                                                                                                          |
| Xcel Energy                                                    |         | Xcel Energy  Inc., a Minnesota corporation                                                                                                                                                                                                                                                                                                                                                                                        |
| *** ***                                                   | *** *** | *** ***                                                                                                                                                                                                                                                                                                                                                                                                                      |
| ***Federal and State Regulatory Agencies***                    |         |                                                                                                                                                                                                                                                                                                                                                                                                                              |
| DOE                                                            |         | United  States Department of Energy                                                                                                                                                                                                                                                                                                                                                                                               |
| EPA                                                            |         | United  States Environmental Protection Agency                                                                                                                                                                                                                                                                                                                                                                                    |
| FERC                                                           |         | Federal  Energy Regulatory Commission. The U.S. agency that regulates the rates and  services for transportation of electricity and natural gas and the sale of  electricity at wholesale, in interstate commerce, including the sale of  electricity at market-based rates.                                                                                                                                                      |
| 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. Federal Energy Regulatory Commission 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.                                                                                                                                                                                                                                                                                                                         |
| PSCW                                                           |         | Public Service Commission  of Wisconsin. The state agency that regulates the retail rates, services,  securities issuances and other aspects of NSP-Wisconsin’s operations in  Wisconsin.                                                                                                                                                                                                                                    |
| SDPUC                                                          |         | South Dakota  Public Utilities Commission. The state agency that regulates the retail  rates, services and other aspects of NSP-Minnesota’s operations in South  Dakota.                                                                                                                                                                                                                                                     |
| SEC                                                            |         | Securities  and Exchange Commission                                                                                                                                                                                                                                                                                                                                                                                               |
|                                                           |         |                                                                                                                                                                                                                                                                                                                                                                                                                              |
| ***Electric, Purchased Gas and Resource  Adjustment Clauses*** |         |                                                                                                                                                                                                                                                                                                                                                                                                                              |
| DSM                                                            |         | Demand-side management.  Energy conservation, weatherization and other programs to conserve or manage  energy use by customers.                                                                                                                                                                                                                                                                                                   |
| FCA                                                            |         | Fuel clause  adjustment. A clause included in NSP-Minnesota’s retail electric rate  schedules that provides for prospective monthly rate adjustments to reflect  the actual cost of electric fuel and purchased energy compared to a prior  forecast. The difference between the electric costs collected through the FCA  rates and the actual costs incurred in a month are collected or refunded in a  subsequent period. |
| PGA                                                            |         | Purchased  gas adjustment. A clause included in NSP-Minnesota’s retail gas rate  schedules that provides for prospective monthly rate adjustments to reflect  the forecasted cost of purchased gas. The annual difference between                                                                                                                                                                                            |

 

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|                                |   | the gas  costs collected through PGA rates and the actual gas costs is collected or  refunded over the subsequent 12-month period.                                                                                                                                                                                                                                                         |
|-------------------------------------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| TCR                                 |   | Transmission cost recovery  adjustment. Allows NSP-Minnesota to recover the cost of transmission  facilities not included in the determination of NSP-Minnesota’s base electric  rates in retail electric rates in Minnesota. The TCR was approved by the MPUC  in 2006 to be effective in 2007 and will be revised annually as new  transmission investments and costs are incurred. |
|                                |   |                                                                                                                                                                                                                                                                                                                                                                                       |
| ***Other Terms and Abbreviations*** |   |                                                                                                                                                                                                                                                                                                                                                                                       |
| AFDC                                |   | Allowance  for funds used during construction. Defined in regulatory accounts as  non-cash accounting convention that represents the estimated composite  interest costs of debt and a return on equity funds used to finance  construction. The allowance is capitalized in property accounts and included  in income.                                                                    |
| ALJ                                 |   | Administrative  law judge. A judge presiding over regulatory proceedings.                                                                                                                                                                                                                                                                                                                  |
| ARO                                 |   | Asset  Retirement Obligation. Obligations associated with the retirement of tangible  long-lived assets and the associated asset retirement costs.                                                                                                                                                                                                                                         |
| BART                                |   | Best Available Retrofit  Technology                                                                                                                                                                                                                                                                                                                                                        |
| CO2                                 |   | Carbon dioxide                                                                                                                                                                                                                                                                                                                                                                             |
| 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.                                                                                                                                                                                                              |
| COLI                                |   | Corporate-owned life  insurance                                                                                                                                                                                                                                                                                                                                                            |
| decommissioning                     |   | The process of closing down a nuclear facility and  reducing the residual radioactivity to a level that permits the release of  the property and termination of license. Nuclear power plants are required by  the NRC to set aside funds for their decommissioning costs during operation.                                                                                                |
| derivative  instrument              |   | A financial  instrument or other contract with all three of the following  characteristics:                                                                                                                                                                                                                                                                                           |
|                                |   | ·                                                                                                                                                                                                                                                                                                                                                                                     | An  underlying and a notional amount or payment provision or both, |
|                                |   | ·                                                                                                                                                                                                                                                                                                                                                                                     | Requires no  initial investment or an initial net investment that is smaller than would be  required for other types of contracts that would be expected to have a  similar response to changes in market factors, and |
|                                |   | ·                                                                                                                                                                                                                                                                                                                                                                                     | Terms  require or permit a net settlement, can be readily settled net by means  outside the contract or provides for delivery of an asset that puts the  recipient in a position not substantially different from net settlement. |
| distribution                        |   | The system  of lines, transformers, switches and mains that connect electric and natural  gas transmission systems to customers.                                                                                                                                                                                                                                                           |
| 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                                                                                                                                                                                                                                                                                                                                                  |
| generation                          |   | The process  of transforming other forms of energy, such as nuclear or fossil fuels, into  electricity. Also, the amount of electric energy produced, expressed in  megawatts (capacity) or megawatt hours (energy).                                                                                                                                                                       |
| GHG                                 |   | Greenhouse  Gas                                                                                                                                                                                                                                                                                                                                                                            |
| JOA                                 |   | Joint  operating agreement among the Utility Subsidiaries                                                                                                                                                                                                                                                                                                                                  |
| LIBOR                               |   | London  Interbank Offered Rate                                                                                                                                                                                                                                                                                                                                                             |
| LNG                                 |   | Liquefied  natural gas. Natural gas that has been converted to a liquid.                                                                                                                                                                                                                                                                                                                   |
| mark-to-market                      |   | The process  whereby an asset or liability is recognized at fair value.                                                                                                                                                                                                                                                                                                                    |
| MERP                                |   | Metropolitan  emissions reduction project.                                                                                                                                                                                                                                                                                                                                                 |
| MGP                                 |   | Manufactured  gas plant.                                                                                                                                                                                                                                                                                                                                                                   |
| MISO                                |   | Midwest  Independent Transmission System Operator, Inc.                                                                                                                                                                                                                                                                                                                               |

 

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| Moody’s                    |         | Moody’s Investor Services  Inc.                                                                                                                                                                                                                                  |
|---------------------------------|--------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| native load                     |         | The customer  demand of retail and wholesale customers whereby a utility has an obligation  to serve: e.g., an obligation to provide electric or natural gas service  created by statute or long-term contract.                                                       |
| natural gas                     |         | A naturally  occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous  geological formations beneath the earth’s surface, often in association with  petroleum. The principal constituent is methane.                                          |
| NOx                             |         | Nitrogen  oxide                                                                                                                                                                                                                                                       |
| nonutility                      |         | All items of  revenue, expense and investment not associated, either by direct assignment  or by allocation, with providing service to the utility customer.                                                                                                          |
| PFS                             |         | Private Fuel  Storage, LLC. A consortium of private parties (including NSP-Minnesota)  working to establish a private facility for interim storage of spent nuclear  fuel.                                                                                            |
| PUHCA                           |         | Public  Utility Holding Company Act of 1935. Enacted to regulate the corporate  structure and financial operations of utility holding companies.                                                                                                                      |
| QF                              |         | Qualifying  facility. As defined under the Public Utility Regulatory Policies Act of  1978, a QF sells power to a regulated utility at a price equal to that which  it would otherwise pay if it were to build its own power plant or buy power  from another source. |
| Rate base                       |         | The  investor-owned plant facilities for generation, transmission and distribution  and other assets used in supplying utility service to the consumer.                                                                                                               |
| ROE                             |         | Return on  equity                                                                                                                                                                                                                                                     |
| RTO                             |         | Regional  Transmission Organization. An independent entity, which is established to  have “functional control” over a utility’s electric transmission systems, in  order to provide non-discriminatory access to transmission of electricity.          |
| SFAS                            |         | Statement of  Financial Accounting Standards                                                                                                                                                                                                                          |
| SO2                             |         | Sulfur  dioxide                                                                                                                                                                                                                                                       |
| Standard & Poor’s |         | Standard & Poor’s  Ratings Services                                                                                                                                                                                                                     |
| TEMT                            |         | Transmission  and Energy Markets Tariff. The tariff requires RTOs such as the MISO to  provide real-time energy imbalance services and a market-based mechanism for  congestion management.                                                                           |
| 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.                                                                                                |
|                            |         |                                                                                                                                                                                                                                                                  |
| ***Measurements***              | *** *** | *** ***                                                                                                                                                                                                                                                          |
| Btu                             |         | British  thermal unit. A standard unit for measuring thermal energy or heat commonly  used as a gauge for the energy content of natural gas and other fuels.                                                                                                          |
| Bcf                             |         | Billion  cubic feet                                                                                                                                                                                                                                                   |
| KV                              |         | Kilovolts                                                                                                                                                                                                                                                             |
| KW                              |         | Kilowatts                                                                                                                                                                                                                                                             |
| Kwh                             |         | Kilowatt  hours                                                                                                                                                                                                                                                       |
| MMBtu                           |         | One million  Btus                                                                                                                                                                                                                                                     |
| MW                              |         | Megawatts  (one MW equals one thousand KW)                                                                                                                                                                                                                            |
| Watt                            |         | A measure of  power production or usage.                                                                                                                                                                                                                              |

 

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# **COMPANYOVERVIEW**

#  

NSP-Minnesota was incorporated in 2000 under the laws ofMinnesota.  NSP-Minnesota is an operatingutility engaged in the generation, purchase, transmission, distribution andsale of electricity in Minnesota, North Dakota and South Dakota.  The wholesale customers served byNSP-Minnesota comprised approximately 9 percent of its total sales in2008.  NSP-Minnesota also purchases,transports, distributes and sells natural gas to retail customers andtransports customer-owned natural gas in Minnesota and North Dakota.  NSP-Minnesota provides electric utilityservice to approximately 1.4 million customers and natural gas utility serviceto approximately 0.5 million customers. Approximately 89 percent of NSP-Minnesota’s retail electric operatingrevenues were derived from operations in Minnesota during 2008.  Generally, NSP-Minnesota’s earnings rangefrom approximately 40 percent to 50 percent of Xcel Energy’s consolidated netincome.

 

The electric production and transmission system of NSP-Minnesota ismanaged as an integrated system with that of NSP-Wisconsin, jointly referred toas the NSP System.  The electricproduction and transmission costs of the entire NSP System are shared byNSP-Minnesota and NSP-Wisconsin.  AFERC-approved Interchange Agreement between the two companies provides for thesharing of all generation and transmission costs of the NSP System.

 

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

 

NSP-Minnesota conducts its utility business in the following reportablesegments: regulated electric utility, regulated natural gas utility and allother.  Comparative segment revenues andrelated financial information for fiscal 2008, 2007 and 2006 are set forth inNote 17 to the accompanying consolidated financial statements.

 

NSP-Minnesota focuses on growing through investments in electric andnatural gas rate base to meet growing customer demands, environmental andrenewable energy initiatives and to maintain or increase reliability andquality of service to customers. NSP-Minnesota files periodic rate cases or establishes formula rate orautomatic rate adjustment mechanisms with state and federal regulators to earna return on its investments and recover costs of operations.

 

# **ELECTRICUTILITY OPERATIONS**

#  

**Overview**

 

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

 

While NSP-Minnesota is not currently subject to state or federal limitson its GHG emissions, NSP-Minnesota has undertaken a number of initiatives toprepare for climate change regulation and reduce our GHG emissions.  These initiatives include emission reductionprograms, energy efficiency and conservation programs, renewable energydevelopment 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.

 

***UtilityRestructuring and Retail Competition***— The FERChas continued with its efforts to promote more competitive wholesale marketsthrough open-access transmission and other means.  As a consequence, NSP-Minnesota can purchasefrom competing wholesale suppliers and use the transmission systems of theutility subsidiaries on a comparable basis to the utility subsidiaries’ toserve their native load.  In 2008, theFERC approved a MISO proposal to begin operation of a regional AncillaryServices Market (ASM) in January 2009. NSP-Minnesota supports the continued development of wholesalecompetition and non-discriminatory wholesale open-access transmissionservices.  NSP-Minnesota received MPUCapproval in 2008 to construct three new 115 KV transmission lines in 2009 todeliver additional wind generation even if NSP-Minnesota does not purchase thegeneration.

 

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

 

**Public Utility Regulation**

** **

***Summary ofRegulatory Agencies and Areas of Jurisdiction *—**Retail rates, services and other aspects of NSP-Minnesota’s operations areregulated by the MPUC, the NDPSC and the SDPUC within their respectivestates.  The MPUC has regulatoryauthority over aspects of NSP-Minnesota’s financial activities, includingsecurity issuances, property transfers, mergers and transactions betweenNSP-Minnesota and its affiliates.  Inaddition, the MPUC reviews and approves NSP-Minnesota’s electric resource plansfor meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50MW and transmission lines greater than 100 KV.

 

No large power plant or transmission line may be constructed inMinnesota except on a site or route designated by the MPUC.  The NDPSC and SDPUC have regulatory authorityover generating and transmission facilities, and the siting and routing of newgeneration and transmission facilities in North Dakota and South Dakota,respectively.

 

NSP-Minnesota is subject to the jurisdiction of the FERC with respectto its wholesale electric operations, hydroelectric licensing, accountingpractices, wholesale sales for resale and the transmission of electricity ininterstate commerce.  NSP-Minnesota hasreceived authorization from the FERC to make wholesale electric sales atmarket-based prices (see market-based rate authority discussion) and is atransmission-owner member of the MISO RTO.

 

***Fuel, PurchasedEnergy and Conservation Cost Recovery Mechanisms *—**NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota andSouth Dakota include a FCA for monthly billing adjustments for changes inprudently incurred cost 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.

 

The FCAs allow NSP-Minnesota to bill customers for the cost of fuel andfuel related costs used to generate electricity at its plants and energypurchased from other suppliers.  Ingeneral, capacity costs are not recovered through the FCA.  In December 2006, the MPUC authorizedFCA recovery of all MISO Day 2 charges, except certain administrative charges,which NSP-Minnesota partially recovered in base rates and partially deferredfor future recovery in its 2009 Minnesota electric rate case.  The SDPUC and NDPSC have authorized FCArecovery of MISO Day 2 charges.  In 2008,NSP-Minnesota requested that the MPUC, NDPSC and SDPUC allow FCA treatment ofall MISO ASM charges and revenues effective with the start of the ASM on Jan. 6,2009.  The SDPUC approved the request on Feb. 12,2009.  The NDPSC has concluded that therecovery was addressed and permitted through the recent rate casesettlement.  NSP-Minnesota heard thematter on Feb. 26, 2009. NSP-Minnesota’s electric wholesale customers also have a FCA provisionin their contracts.

 

NSP-Minnesota is required by Minnesota law to spend a minimum of2 percent of Minnesota electric revenue on conservation improvementprograms.  These costs are recoveredthrough an annual cost recovery mechanism for electric conservation and energymanagement program expenditures. NSP-Minnesota is required to request a new cost recovery levelannually.  While this law will change toa savings-based requirement beginning in 2010, the costs of providing qualifiedconservation improvement programs will continue to be recoverable through arate adjustment mechanism.

 

***MERP RiderRegulation *—** In December 2003, the MPUCapproved NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generatingplants to natural gas, and to install advanced pollution control equipment at athird coal-fired plant.  Theseimprovements are expected to significantly reduce air emissions from thesefacilities, while increasing the capacity at system peak by 300 MW.  The first MERP project at the A. S. Kingplant went into service in July 2007. The second project at the High Bridge plant went into service in May 2008.  The remaining project at the Riversidefacility is expected to begin operations in 2009.  The MPUC approved a rate rider to recoverprudent costs of the projects from Minnesota customers beginning Jan. 1,2006, including a rate of return on the construction work in progress.

 

The MPUC approval has a sliding ROE scale with a range of 9.87 to 11.47percent, based on actual construction cost compared with a target level ofconstruction costs (based on an equity ratio of 48.5 percent and debt of51.5 percent) to incentivize NSP-Minnesota to control construction costs.  At Dec. 31, 2008, the estimated ROE was10.71 percent, based on construction progress to date.

 

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**Capacity and Demand**

** **

Uninterrupted system peak demand for the NSP System’s electric utilityfor each of the last three years and the forecast for 2009, assuming normalweather, is listed below.

 
| ** ** | ** ** | **System Peak Demand (in MW)** | ** ** |
|------------|------------|----------------------------------------------------|------------|
| ** ** | ** ** | **2006**                                           | ** ** | **2007** | ** ** | **2008** | ** ** | **2009 Forecast** | ** ** |
| NSP System |       | 9,859                                              |       | 9,427 |   | 8,697 |   | 9,662 |   |

 

The peak demand for the NSP System typically occurs in the summer.  The 2008 system peak demand for the NSPSystem occurred on July 29, 2008.

 

**Energy Sources and Related Transmission Initiatives**

** **

NSP-Minnesota expects to use existing power plants, powerpurchases, DSM options, new generation facilities and expansion of existingpower plants to meet its system capacity requirements.

 

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

 

On behalf of the NSP System, NSP-Minnesota also makesshort-term purchases to replace generation from company-owned units that areunavailable due to maintenance and unplanned outages, to comply with minimumavailability requirements, to obtain energy at a lower cost than that whichcould be produced by other resource options, including company-owned generationand/or long-term purchase power contracts and for various other operatingrequirements.

 

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

 

***Excelsior Energy*****—**In December 2005,Excelsior, an independent energy developer, filed a power purchase agreement withthe 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.  Excelsior filed this petition making claimspursuant to Minnesota statutes relating to an Innovative Energy Project andClean Energy Technology.  NSP-Minnesotaopposed the petition.

 

The MPUC referred this matter toa contested case hearing before an ALJ to act on Excelsior’s petition.  The contested case proceeding considered a600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba EnergyProject.

 

The MPUC issued its order for phase 1 of the hearing on Aug. 30,2007.  In it, the MPUC found among otherthings, that Excelsior and NSP-Minnesota should resume negotiations toward anacceptable purchase power agreement, with assistance from the MinnesotaDepartment of Commerce (MDOC) and the guidance provided by the order.

 

On Sept. 24, 2008, the MPUC denied Excelsior Energy’s Phase 2 requestto approve a power purchase agreement related to its proposed second 600 MWIGCC generating facility.  The MPUC alsoset a May 1, 2009 deadline for Phase 1 of the proceeding in which it hadpreviously ordered negotiations.  On Oct. 14,2008, Excelsior sought rehearing of the MPUC’s Sept. 24, 2008 order.  On Dec. 9, 2008, the MPUC held furtheraction in abeyance until after the May 1, 2009 deadline.

 

***GHG Emissions *—**The 2007 Minnesota legislature adopted the goal to reduce statewide GHGemissions across all sectors to a level at least 15 percent below 2005levels by 2015, to a level at least 30 percent below 2005 levels by 2025,and to a level at least 80 percent below 2005 levels by 2050.

 

The legislation also prohibits the construction within Minnesota of anew large energy facility, the import or commitment to import from outsideMinnesota power from a new large energy facility, or entering into a newlong-term power purchase agreement that would increase statewide power sectorCO2 emissions. The statute does not impose limitations on CO2 or

 

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other GHG emissions on NSP-Minnesota and provides for certainexemptions.  On Feb. 1, 2008, theMDOC submitted to the legislature a climate change action plan that proposescertain changes to meet the requirements of this section.

 

***Renewable EnergyStandard (RES) *—** The 2007 Minnesotalegislature adopted a RES statute requiring that 30 percent of NSP-Minnesota’senergy requirements by 2020 come from qualifying renewable sources, primarilywind energy.  Costs associated withcomplying with the standard are recoverable through automatic recoverymechanisms.

 

NSP-Minnesota has filed with the MPUC a renewable energy plan foradding wind resources.  This plan seeksto achieve balance in the wind portfolio, with roughly half of new resourcesbeing owned by NSP-Minnesota and achieving roughly proportionate shares betweencommunity-based energy developments, other power purchase agreements andutility projects.

 

***Conservation and DSMLegislation *—** The 2007 Minnesota legislatureadopted a statute establishing a statewide goal to reduce energy demand by1.5 percent per year and fossil fuel use by 15 percent.  The bill requires utilities to proposeconservation and DSM programs that achieve at least 1.0 percent per yearreduction in energy demand, subject to limitations regarding excessive costsfor customers, reliability or other negative consequences.  The statute also allows utilities to fundinternal infrastructure changes that will contribute to lower energy use andprovides for cost recovery outside a rate case for such projects.

 

***2008 MinnesotaLegislative Session*****—**The2008 Minnesota legislature considered and adopted several measures related toenergy policy and regulation, including:

 

·                  Encouraging Minnesota’s participationin the Midwest Governors’ Association’s GHG accord and commissioning of aneconomic study of the potential impacts of a carbon cap-and-trade program;

·                  Modifying the existing TCR mechanismto allow for recovery of costs associated with MISO charges for regionaltransmission expansion;

·                  Providing for recovery via a raterider mechanism of certain energy storage projects associated with renewableenergy projects; and

·                  Providing for a streamlined approvalprocess for wind and solar projects needed to comply with Minnesota’s RES.

 

The legislature considered, but did not adopt, increased taxes onutility property.

 

***NSP System ResourcePlan *—** In December 2007, NSP-Minnesotafiled its 2007 resource plan with the MPUC. The plan incorporates the actions needed to comply with expansive newlegislation regarding GHG emissions control, renewable energy procurement andDSM adopted by the 2007 Minnesota legislature. Due to the expansion of wind generation procurement and DSM obligations,the plan indicates that the type of incremental resources has changed fromprior plans.  Key provisions of the planinclude the following:

 

·                  Adding2,600 MW of wind generation resources to comply with our RES of 30 percentrenewable energy by 2020.

·                  Increasesin DSM of approximately 30 percent energy savings and 50 percentdemand savings.

·                  Seeklicense renewals for Prairie Island’s two units through 2033 and 2034,respectively, and expand capacity at Prairie Island by 160 MW and Monticello by71 MW.

·                  Requestapproval to make environmental and capacity upgrades at Sherburne County(Sherco).  The environmental upgradeswould result in a significant reduction in overall SO2, NOx and mercury emissions from thefacility.

·                  Negotiateand seek approval of purchases from Manitoba Hydro Electric Board (ManitobaHydro) for 375 MW of intermediate and 350 MW of peaking resources beginning in2015.

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

·                  Carbonemission reductions of 22 percent below 2005 levels by 2020.

 

In June 2008, intervenors filed commentson this plan.  The Minnesota Officeof Energy Security (OES) recommendedapproval, subject to further expansion of DSM goals.  Environmental intervenors recommendedexpanded DSM goals and expressed concerns regarding carbon management with theproposed expansion of certain coal resources. Excelsior Energy recommended inclusion of its proposed project in theplan.  The Prairie Island Communityexpressed health and safety concerns regarding nuclear resources.  The Minnesota Chamber of Commerce expressedinterest in cost and rate management. NSP-Minnesota filed reply comments in September 2008 providingupdated information, including a revised forecast.  As discussed below it also withdrew itsrequest for upgrades at Sherco Units 1 and 2. The MPUC is expected to act on the plan in the first half 2009.

 

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***Additional Base LoadCapacity Projects for Sherco, Monticello and Prairie Island *—**The MPUC order in the 2004 NSP-Minnesota resource plan indicated thatadditional capacity from the Sherco, Monticello, and Prairie Island plantswould be cost-effective and should be pursued. The disclosure regarding the Monticello and Prairie Island plans isincluded below under “Nuclear Power Operations and Waste Disposal.”

 

In December 2007, NSP-Minnesota filed a plan for major pollutioncontrol and efficiency improvements at Sherco Units 1 and 2 with the MPUC.  The plan proposed conversion of the pollutioncontrol systems at the plant from wet scrubber precipitator technology to dryspray absorber/ baghouse equipment as well as efficiency improvements thatwould increase the production capacity of the plant by 70 MW.  The total cost of the proposed plan wasestimated at $1 billion.  In November 2008,NSP-Minnesota filed a request with the MPUC to withdraw the plan to reevaluatealternatives, due to significant changes in the national economy, lowerforecast of energy consumption, and new information concerning an emergingtechnology that may be more cost effective. The MPUC granted the withdrawal request on Dec. 9, 2008.

 

***Wind Generation******—*** In December 2008,the first NSP-Minnesota owned wind generation plant, the 100 MW Grand Meadowwind farm, went into service.  Theproject was developed through a build-own-transfer arrangement with a largewind energy developer (enXco) at a cost of approximately $210 million.  NSP-Minnesotaplans to invest approximately $900 million over three years for a 201 MWproject in southwestern Minnesota, called the Nobles Wind Project, and a 150 MWproject in southeastern North Dakota, called the Merricourt Wind Project.  These projects are expected to be operationalby the end of 2010 and 2011, respectively. On Dec. 3, 2008, NSP-Minnesota filed petitions with the MPUCand the NDPSC seeking the required regulatory approvals for the two windpowered generating facilities.  See additional discussion of wind generationin Item 7**—** Management’s Discussionand Analysis of Financial Condition and Results of Operations.

 

***NSP-MinnesotaTransmission Certificates of Need —***In August 2007,NSP-Minnesota and Great River Energy (on behalf of eight other regionaltransmission providers) filed a certificate of need application, for three 345KV transmission lines, as part of the CapX 2020 project.  The project to build the three lines includesconstruction of approximately 600 miles of new facilities at a cost ofapproximately $1.7 billion, with construction to be completed inphases.  The cost of the project toNSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900million.  These cost estimates will berevised after the regulatory process is completed.  Evidentiary hearings were completed in September 2008.  The OES recommended an increase in capacityfor the Fargo, N. D. project.  Anenvironmental coalition supported the projects subject to conditions for windpurchases or commitments for the transmission capacity, while two otherintervenors opposed the proposal.  Theapplicants filed rebuttal testimony recommending the modification of all threeprojects to be constructed as double circuit compatible with the first circuitstrung during initial construction and the second circuit strung asneeded.  NSP-Minnesota expects the ALJ toissue a report and recommendation in the first quarter of 2009.  The MPUC is expected to make a final decisionin 2009 after receipt of the ALJ report.

 

As part of CapX 2020, Otter Tail Power Company, Minnesota Power andMinnkota Power Cooperative (on behalf of themselves and NSP-Minnesota and GreatRiver Energy) filed a certificate of need application in March 2008 for a230 KV transmission line between Bemidji and Grand Rapids, Minn.  A route application for this project wasfiled in June 2008.  The needapplication is uncontested; route hearings are expected to be conducted in late2009, and an MPUC decision is anticipated by the second 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 end of 2011.  The estimated cost to NSP-Minnesota is approximately$26 million.

 

In the second quarter of 2009, NSP-Minnesota plans to file acertificate of need application with the MPUC for two 161 KV transmission linesin the Rochester, Minn. area to support ongoing development of wind poweredgeneration in southeastern Minnesota. The proposal consists of an approximately 15 mile long, 161 KVtransmission line north of Rochester, and an approximately 30 mile long, 161 KVtransmission line southeast of Rochester. The project’s estimated cost is $30 million.  An MPUC decision is anticipated late in 2009.

 

***FCAInvestigation *—** In 2003, the MPUC opened aninvestigation to consider the continuing usefulness of the FCAs for electricutilities in Minnesota.  There was nofurther activity until the MPUC issued a notice for comments on April 5,2007, as to whether to continue the statewide investigation.

 

Pursuant to the notice, utilities in Minnesota, the MDOC and theMinnesota Office of Attorney General (MOAG) filed comments.  The utilities generally argued the 2003investigation could be closed, with remaining issues addressed in the separateinvestigation initiated by the Dec. 20, 2006 order in the MISO Day 2 costrecovery docket.  The MDOC filed commentsseeking to continue the investigations. In response, the utilities filed additional comments on Sept. 28,2007, that indicated a willingness to continue with the investigation andprovide more information to both regulators and customers

 

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regarding fuel and purchased power costs, plant outages and otherfactors affecting fuel clause levels. Continued discussions among utilities, the MDOC, MOAG and businesscustomers regarding appropriate FCA reporting detail and provision ofadditional information to customers is on going.

 

***Mercury Reductionand Emissions Reduction Filings *—** In December 2007,NSP-Minnesota filed a plan with the MPCA and MPUC for reducing mercuryemissions at the Sherco Unit 3 and A. S. King plants.  Currently, the estimated project costs areapproximately $8.5 million.  TheMPUC has approved the mercury control plans. Implementation will begin in 2009. NSP-Minnesota plans to seek cost recovery of mercury control investmentsthrough an automatic rate adjustment mechanism (rate rider) filing later in2009.  As discussed above, NSP-Minnesotais reexamining its plans for emission controls at Sherco Units 1 and 2 andanticipates submitting an alternative mercury control plan with the MPUC in2009.

 

***Nuclear PowerOperations and Waste Disposal *—** 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.

 

Nuclear power plant operation produces gaseous, liquid and solidradioactive wastes.  The discharge andhandling of such wastes are controlled by federal regulation.  High-level radioactive wastes primarilyinclude used nuclear fuel.  Low-levelradioactive waste (LLW) consists primarily of demineralizer resins, paper,protective clothing, rags, tools and equipment that have become contaminatedthrough use in the plant.

 

*LLW Disposal *—Federal law places responsibility on each state for disposal of LLW generatedwithin its borders.  LLW fromNSP-Minnesota’s Monticello and Prairie Island nuclear plants is currentlydisposed at the Barnwell facility located in South Carolina (all classes ofLLW) and at the Clive facility located in Utah (class A LLW only).  NSP-Minnesota had an annual contract withBarnwell that expired on June 30, 2008, but is also able to utilize theClive facility through various LLW processors. NSP-Minnesota has storage capacity available on-site at Prairie Islandand Monticello that would allow both plants to continue to operate until theend of their current licensed lives, if off-site LLW disposal facilities werenot available to NSP-Minnesota.

 

*High-Level Radioactive Waste Disposal**—***The federalgovernment has the responsibility to dispose of, or permanently store, domesticspent nuclear fuel and other high-level radioactive wastes.  The Nuclear Waste Policy Act requires the DOEto implement a program for nuclear high-level waste management.  This includes the siting, licensing,construction and operation of a repository for domestically produced spentnuclear fuel from civilian nuclear power reactors and other high-levelradioactive wastes at a permanent federal storage or disposal facility.  To date, the DOE has not accepted any ofNSP-Minnesota’s spent nuclear fuel.  SeeItem 3 — Legal Proceedings and Note 15 to the consolidated financial statementsfor further discussion of this matter.

 

NSP-Minnesota has on-site storage for spent nuclear fuel at itsMonticello and Prairie Island nuclear plants. At the following dates casks for storage were either authorized or caskswere loaded and stored:

 

·                  In 1993, thePrairie Island plant was licensed by the federal NRC to store up to 48 casks ofspent fuel at the plant.

·                  In 1994, theMinnesota legislature adopted a limit on dry cask storage of 17 casks.

·                  In 2003, theMinnesota legislature enacted revised legislation that will allow NSP-Minnesotato continue to operate the facility and store spent fuel there until itscurrent licenses with the NRC expire in 2013 and 2014.  It is estimated that operation through theend of the current license will require 12 additional storage casks to bestored at Prairie Island, for a total of 29 casks.

·                  In October 2006,the MPUC authorized an on-site storage facility and 30 casks at Monticello,which will allow the plant to operate to 2030. The MPUC decision became effective June 1, 2007.

·                  As of Dec. 31, 2008, there were 24casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant.

 

See Note 15 in the consolidated financial statementsfor further discussion of the matter.

 

*PFS  **—***NSP-Minnesota is part of aconsortium of private parties working to establish a private facility forinterim storage of spent nuclear fuel. In 1997, PFS filed a license application with the NRC for a temporarystorage site for spent nuclear fuel on the Skull Valley Indian Reservation inUtah.  On Feb. 28, 2006, the NRCcommissioners issued the license for PFS. In December 2005, the U.S. Supreme Court denied Utah’s petition fora writ of certiorari to hear an appeal of a lower court’s ruling on a series ofstate statutes aimed at blocking the storage and transportation of spent fuelto PFS.  Also in December 2005,NSP-Minnesota indicated that it would hold in abeyance future investments inthe construction of PFS as 

 

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long as thereis apparent and continuing progress in federally sponsored initiatives forstorage, reuse, and/or disposal for the nation’s spent nuclear fuel.  In September 2006, the Department of theInterior issued two findings: (1) that it would not grant the leases forrail or intermodal sites and (2) that it was revoking its previousconditional approval of the site lease between PFS and the Skull Valley Indiantribe.  The stated reasons wereprincipally lack of progress at Yucca Mountain and lack of Bureau of IndianAffairs staff to monitor this activity. Both findings are expected to be appealed.

 

*Nuclear Plant Power Uprates and Life Extension***—** NSP-Minnesota is pursuing life extensionsand capacity increases for all three of its nuclear units that will totalapproximately 230 MW, to be implemented, if approved, between 2009 and2015.  The life extension and a capacityincrease for Prairie Island Unit 2 is contingent on replacement of the originalsteam generators, currently planned for replacement during the refueling outagein 2013.  Capital investments for lifecycle management and power uprate activities through 2008 have totaled overapproximately $125 million.  For theyears 2009 through 2015, spending is estimated at over $1.0 billion.  See additional discussion in CapitalRequirements in Item 7 —  Management’sDiscussion and Analysis of Financial Condition and Results of Operations.

 

NSP-Minnesotahas filed two applications for certificates of need related to its nucleargenerating facilities to obtain approval for these projects.  The first addresses approximately 71 MW ofpower uprates at the Monticello plant.  TheMPUC approved the Monticello power uprate Certificate of Need in December 2008.  NSP-Minnesotare-submitted its NRC application for the Monticello plant extended poweruprate in November 2008, and the NRC’s Sufficiency review of the license amendmentre-submittal was completed in December 2008.  Althoughthis delays the extended power uprate process slightly, NSP-Minnesotadoes not anticipate a substantial delay in the project at this time.  The operating life of the Monticello nuclearplant has already been extended through 2030.

 

Thesecond application addresses both life extension and approximately 160 MW inpower uprates at Prairie Island Units 1 and 2. In July 2008, the MPUC determined that the application was completeand referred it to an ALJ for contested case hearing.  The Prairie Island Community has indicatedits interest in the power uprate portion of the case and has expressed interestin revisiting its 2003 settlement with NSP-Minnesota, in which it agreed thatcertain concerns it may have regarding Prairie Island life extension would beaddressed in the federal relicensing process.

 

InApril 2008, NSP-Minnesota filed an application with the NRC to renew theoperating license of its two nuclear reactors at Prairie Island for anadditional 20 years, until 2033 and 2034, respectively.  The Prairie Island Indian Community (PIIC)filed contentions in the NRC’s license renewal proceeding in August 2008.  The PIIC request was referred to anAtomic Safety and Licensing Board (ASLB) for review.  The ASLB has granted the PIIC hearing requestand has admitted 7 of the 11 contentions filed. The resulting adjudicatory process and hearings are expected to addapproximately 8 months onto the NRC’s standard 22-month review schedule.  Therefore, the NRC is not expected to make adecision until late 2010.  An applicationfor a Certificate of Need to expand the spent fuel storage capacity at PrairieIsland to support 20 additional years of operation was filed with the MPUC in May 2008.  It is expected that the MPUC will act in late2009, which would result in the MPUC decision being stayed during the 2010session of the Minnesota legislature before going into effect.

 

*NMC *— On Sept.28, 2007, 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 in NSP-Minnesota’sconsolidated financial statements from the Sept. 28, 2007 transactiondate.  NSP-Minnesota has reintegrated itsnuclear operations into its generation operations.  The application to the NRC to transfer thenuclear operating licenses from NMC to NSP-Minnesota was completed on Sept. 22,2008.

 

For further discussion of nuclear obligations, seeNote 15 to the consolidated financial statements.

 

**Fuel Supply and Costs**

 

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

 

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| ** **                 | ** ** | ** ** | ** ** | ** **  | ** ** | ** **           | ** ** | ** **            | ** ** | ** ** | ** ** | ** **  | ** ** | **Weighted** | ** ** |
|----------------------------|------------|------------|------------|-------------|------------|----------------------|------------|-----------------------|------------|------------|------------|-------------|------------|--------------|------------|
| **NSP System**        | ** ** | **Coal***  | ** ** | **Nuclear** | ** ** | **Natural Gas** | ** ** | **Average Fuel** | ** ** |
| **Generating Plants** | ** ** | **Cost**   | ** ** | **Percent** | ** ** | **Cost**             | ** ** | **Percent**           | ** ** | **Cost**   | ** ** | **Percent** | ** ** | **Cost**     | ** ** |
| ** **                 | ** ** | ** ** | ** ** | ** **  | ** ** | ** **           | ** ** | ** **            | ** ** | ** ** | ** ** | ** **  | ** ** | ** **   | ** ** |
| 2008                       |       | $          | 1.73       |        | 58         | %                    | $          | 0.56                  |       | 39         | %          | $           | 10.09      |         | 3          | % | $ | 1.55 |   |
| 2007                       |       | 1.56       |       | 57          |       | 0.51                 |       | 38                    |       | 7.60       |       | 4           |       | 1.47         |       |
| 2006                       |       | 1.12       |       | 59          |       | 0.46                 |       | 38                    |       | 7.28       |       | 3           |       | 1.08         |       |
|                            |            |            |            |             |            |                      |            |                       |            |            |            |             |            |              |            |  |  |  |  |

 

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*Includes refuse-derived fuel and wood

 

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

 

**Fuel Sources**

 

*Coal*****—Coal inventory levels may vary widely among plants.  The NSP System normally maintainsapproximately 39 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2008and 2007, were approximately 49 and 47 days usage, based on the maximum burnrate for all of NSP-Minnesota’s coal-fired plants.  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 11.0 and 12.4 million tons peryear at Dec. 31, 2008 and 2007, respectively.

 

NSP-Minnesota and NSP-Wisconsin have contracted forcoal supplies to provide 100 percent of their coal requirements in 2009,65 percent of their coal requirements in 2010 and 36 percent of theircoal requirements in 2011.  Any remainingrequirements will be filled through a request for proposal (RFP) processaccording to the fuel supply operations procurement strategy.

 

NSP-Minnesota and NSP-Wisconsin have a number of coal transportationcontracts that provide for delivery of 100 percent of their coal requirementsin 2009, 100 percent of their coal requirements in 2010 and 28 percent of theircoal requirements 2011.  Coal deliverymay be subject to short-term interruptions or reductions due to operation ofmines, transportation problems, weather and availability of equipment.

 

*Nuclear*****—To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota securescontracts for uranium concentrates, uranium conversion, uranium enrichment andfuel fabrication.  The contract strategyinvolves a portfolio of spot purchases and medium and long-term contracts foruranium, conversion and enrichment with multiple producers and with a focus ondiversification to minimize potential impacts caused by supply interruptions.

 

·                  Current nuclear fuel supply contractscover 100 percent of uranium concentrates requirements through 2009,approximately 68 percent of the requirements for 2010, 80 percent of therequirements for 2011 through 2013, 47 percent of the requirements for 2014through 2017, with no arrangements for 2018 and beyond.  Contracts for additional uranium concentratesupplies are currently in various stages of negotiations that are expected toprovide a portion of the requirements through 2012.

·                  Current contracts for conversionservices cover 100 percent of the requirements through 2011 and approximately56 percent of the requirements from 2012 through 2015, with no arrangements for2016 and beyond.

·                  Current enrichment services contractscover 100 percent of 2009 through 2012 requirements and approximately 60percent of 2013 requirements.  A contractfor additional enrichment services is being negotiated to provide the remainderof coverage for open requirements in 2013. There is currently no coverage for 2014 and beyond.  Offers for enrichment services for supplycontracts for 2014 and beyond are being reviewed.

·                  The fuel fabrication contract forMonticello was extended during 2007 to cover one additional reload in2011.  Request for proposals from thefuel fabrication vendors for additional supply for Monticello were distributed.  Offers from fuel fabrication vendors arebeing reviewed with plans to enter into a contract with one of the vendors in2009.  Prairie Island’s fuel fabricationis 100 percent committed to at least 2015.

 

NSP-Minnesota expects sufficient uranium, conversion and enrichment tobe available for the total fuel requirements of its nuclear generatingplants.  Contracts for additional uraniumare currently being negotiated that would provide additional supplyrequirements through 2012.  Some exposureto price volatility will remain, due to index-based pricing structures of thecontracts.

 

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*Natural Gas*****—The NSP System uses both firm and interruptible natural gas and standby oil incombustion turbines and certain boilers. Natural gas supplies and associated transportation and storage servicesfor power plants are procured under contracts with various terms to provide anadequate supply of fuel.  The supply,transportation and storage contracts expire in various years from 2009 to2028.  Certain natural gas supply andtransportation agreements include obligations for the purchase and/or deliveryof specified volumes of natural gas or to make payments in lieu ofdelivery.  At Dec. 31, 2008,NSP-Minnesota’s commitments related to supply contracts was $89 million andcommitments related to transportation and storage contracts were approximately$652 million.  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-Minnesota conducts various wholesale marketing operations,including the purchase and sale of electric capacity, energy and energy relatedproducts.  NSP-Minnesota uses physicaland financial instruments to reduce commodity price and credit risk and hedgesupplies and purchases.  See additionaldiscussion under Item 7A — Quantitative and Qualitative Disclosures AboutMarket Risk.

 

**Summary of Recent FederalRegulatory Developments**

** **

The FERC has jurisdiction over rates for electric transmission servicein interstate commerce and electricity sold at wholesale, hydro facilitylicensing, natural gas transportation, accounting practices and certain otheractivities of NSP-Minnesota.  State andlocal agencies have jurisdiction over many of NSP-Minnesota’s activities,including regulation of retail rates and environmental matters.  In addition to the matters discussed below,see Note 13 to the consolidated financial statements for a discussion ofother regulatory matters.

 

***FERC Rules ImplementingEnergy Policy Act of 2005 (Energy Act) *—** TheEnergy Act repealed PUHCA effective Feb. 8, 2006 and required the FERC toconduct several rulemakings to adopt new regulations to implement variousaspects of the Energy Act.  Since August 2005,the FERC has completed a number of rulemaking proceedings to modify itsregulations on a number of subjects, including:

 

·                  Adopting regulations requiring NERCto establish mandatory electric reliability standards; and

·                  Certifying approximately 120 NERCreliability standards mandatory and subject to potential financial penalties upto $1 million per day per violation for non-compliance.

 

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

 

***Electric Reliability Standards Matters*—**The electric production and transmissionsystem of NSP-Minnesota is managed as an integrated system, jointly referred toas the NSP System.  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.  The initial transmission line outage appearsto have occurred on the NSP-Minnesota transmission system due to a failure of a345 KV conductor during severe weather, and approximately 6,000 NSP-Wisconsincustomers temporarily lost power.  TheMidwest Reliability Organization (MRO), the NERC regional entity responsiblefor oversight of electric system reliability in the upper Midwest, includingthe NSP System, initiated an independent incident analysis.  In addition, NERC initiated a complianceinvestigation to determine if violations of mandatory NERC reliabilitystandards contributed to the event.  XcelEnergy is cooperating with the MRO incident analysis and NERC complianceinvestigation.

 

In April 2008, aself-report was filed with MRO indicating that certain tests of generationstation batteries had not been completed in accordance with Xcel Energy’sadopted maintenance plan for generation station relays and batteries.  Xcel Energy has received preliminaryinformation from the MRO indicating that financial penalties are likely to beassessed against NSP-Minnesota and NSP-Wisconsin in conjunction with thisself-report, though the amount of those penalties is not expected to bematerial.

 

In June 2008,PSCo was subject to an audit of its compliance with NERC andregional reliability standards by Western Electricity Coordinating Council ,the NERC regional entity for the PSCo system. In response to information identified during the audit, Xcel Energyconducted a comprehensive review of the maintenance records for all relaydevices on the NSP-Minnesota and NSP-Wisconsin transmission systems.  That review found NSP-Minnesota andNSP-Wisconsin did not 

 

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havedocumentation demonstrating that all relay devices on those systems had beenmaintained on the schedule in Xcel Energy’s adopted maintenance plan.  In June 2008, the NSP System filed aself-report regarding the maintenance plan violations with the MRO.  The NSP System supplemented the self-reporton Feb. 17, 2009.

 

In September 2008,as a result of a review of Xcel Energy’s procedures implementing certain NERCcritical infrastructure protection standards applicable to control centerseffective July 1, 2008, the NSP System filed a self-report with the MRO disclosingcertain deficiencies in requirements applicable to access to criticalinfrastructure assets for the period July to September 2008.  The NSP System filed a mitigation plan withthe MRO within 30 days of the self-report discussing how the deficiencies werecorrected.  The MRO notified the NSPSystem it will not impose a financial penalty related to the self report.

 

Xcel Energy is uncertain if the NERC investigation regarding the Sept.18, 2007 NSP System event or theself-reports of reliability standards violations will result in financialpenalties being imposed on NSP-Minnesota and NSP-Wisconsin.  Ifso, the penalties are not expected to be material.

 

***Electric Transmission RateRegulation —***The FERC regulates the rates charged and terms and conditions for electrictransmission services.  FERC policyencourages utilities to turn over the functional control over their electrictransmission assets for the sale of electric transmission services to an RTO.  NSP-Minnesota and NSP-Wisconsin are members ofthe MISO RTO.  Each RTO separately filesregional transmission tariff rates for approval by the FERC.  All members within that RTO are thensubjected to those rates.

 

In February 2007, the FERC issued final rules (Order No. 890)adopting revisions to its open access transmission service rules.  In December 2007, the FERC issued anorder on rehearing (Order No. 890-A) making certain modifications to OrderNo. 890, effective in March 2008. In June 2008, the FERC issued a further order on rehearing (Order No. 890-B)making certain additional modifications to Order Nos. 890 and 890-A effectivein September 2008.  Xcel Energysubmitted its compliance filing to Order No. 890-B in September 2009.  The various compliance filings are pendingFERC action.

 

***Centralized RegionalWholesale Markets *—** The FERC rules allowRTOs to operate centralized regional wholesale energy markets.  In April 2005, MISO began operation of a“Day 2” regional day-ahead and real time wholesale energy market.  MISO uses security constrained regionaleconomic dispatch and congestion management using locational marginal pricing(LMP) and FTRs.  The Day 2 market isdesigned to provide more efficient generation dispatch over the 15 state MISOregion, including the NSP System.

 

In September 2007, MISO filed for FERC approval to establish acentralized regional wholesale ASM in 2008. The ASM is intended to provide further efficiencies in generationdispatch by allowing for regional regulation response and contingency reserveservices through a bid-based market mechanism co-optimized with the Day 2energy market.  In February 2008,the FERC issued an order conditionally approving the ASM tariff, but requiringcertain changes.  In December 2008,the FERC issued orders approving the MISO filings necessary for MISO to startthe ASM.  MISO began ASM operations in January 2009.  To date, the ASM has generally functioned asanticipated.

 

In December 2007, MISO filed proposed changes to the TEMT (calledModule E) to establish a long-term resource adequacy proposal.  The proposal contains mandatory requirementsfor any market participant serving load in the MISO region, including the NSPSystem, to have and maintain access to sufficient resources to meet adequacystandards.  The resources used to meet aresource adequacy requirement may include self-generation capacity, firmpurchased power and demand response capability.

 

Under the Module E proposal, MISO will establish a Planning ReserveMargin for each Load-Serving Entity (LSE). The MISO resource adequacy tariff would replace the NSP System currentplanning reserve obligations.  In March 2008,the FERC issued an order approving the Module E tariff.  Various parties requested rehearing of theFERC order.  MISO is expected to startModule E on March 1, 2009.

 

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

 

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On Dec. 22,2008, the NSP System submitted their Triennial Market Power Analysis to theFERC to support their market-based rate authority.  Applying the FERC’s required tests, theMarket Power Analysis submitted by the NSP System demonstrates that they haveneither horizontal market power nor vertical market power in the relevantgeographic market.  Consequently, the NSPSystem has requested that the FERC permit them to retain their market-basedrate authority.

 

***AffiliateTransaction Rules *—** On Feb. 21, 2008,the FERC issued Order No. 707, which amended the FERC’s regulations tocodify restrictions on affiliate transactions between franchised publicutilities that have captive customers or that own or provide transmissionservice over jurisdictional transmission facilities, and their market-regulatedpower sales affiliates or non-utility affiliates.  The Xcel Energy utility subsidiaries aresubject to the new rules.  The rules applyhistoric SEC “at cost” pricing standards to transactions between servicecompanies of utility holding company systems and their FERC jurisdictionalpublic utility affiliates.  In September 2008,the National Rural Electric Cooperative Association and the American PublicPower Association filed a petition for review of Order No. 707 with theU.S. Court of Appeals for the District of Columbia.  The appeal is pending.

 

**ElectricOperating Statistics**

 
| ** **                                   | ** ** | **Year Ended Dec. 31,** | ** ** |
|----------------------------------------------|------------|----------------------------------------|------------|
| ** **                                   | ** ** | **2008**                               | ** ** | **2007** | ** ** | **2006** | ** ** |
| **Electric sales (millions of Kwh)**         |       |                                   |       |   |   |   |   |
| Residential                                  |       | 10,099                                 |       | 10,534 |   | 10,223 |   |
| Commercial and industrial                    |       | 25,847                                 |       | 25,844 |   | 25,420 |   |
| Public authorities and other                 |       | 260                                    |       | 275 |   | 280 |   |
| **Total retail**                             |       | 36,206                                 |       | 36,653 |   | 35,923 |   |
| Sales for resale                             |       | 3,692                                  |       | 4,073 |   | 5,435 |   |
| **Total energy sold**                        |       | 39,898                                 |       | 40,726 |   | 41,358 |   |
|                                         |       |                                   |       |   |   |   |   |
| **Number of customers at end of period**     |       |                                   |       |   |   |   |   |
| Residential                                  |       | 1,227,889                              |       | 1,218,340 |   | 1,206,278 |   |
| Commercial and industrial                    |       | 148,060                                |       | 146,487 |   | 144,315 |   |
| Public authorities and other                 |       | 6,067                                  |       | 6,072 |   | 5,998 |   |
| **Total retail**                             |       | 1,382,016                              |       | 1,370,899 |   | 1,356,591 |   |
| Wholesale                                    |       | 31                                     |       | 31 |   | 35 |   |
| **Total customers**                          |       | 1,382,047                              |       | 1,370,930 |   | 1,356,626 |   |
|                                         |       |                                   |       |   |   |   |   |
| **Electric revenues (thousands of dollars)** |       |                                   |       |   |   |   |   |
| Residential                                  |       | $                                      | 1,018,810  |   | $ | 1,015,315 |   | $ | 929,276 |   |
| Commercial and industrial                    |       | 1,853,451                              |       | 1,774,027 |   | 1,665,004 |   |
| Public authorities and other                 |       | 31,837                                 |       | 31,446 |   | 30,898 |   |
| **Total retail**                             |       | 2,904,098                              |       | 2,820,788 |   | 2,625,178 |   |
| Wholesale                                    |       | 180,618                                |       | 198,248 |   | 227,000 |   |
| Interchange revenues from NSP-Wisconsin      |       | 390,143                                |       | 372,215 |   | 322,733 |   |
| Other electric revenues                      |       | 109,250                                |       | 85,423 |   | 90,460 |   |
| **Total electric revenues**                  |       | $                                      | 3,584,109  |   | $ | 3,476,674 |   | $ | 3,265,371 |   |
|                                         |       |                                   |       |   |   |   |   |
| Kwh sales per retail customer                |       | 26,198                                 |       | 26,737 |   | 26,480 |   |
| Revenue per retail customer                  |       | $                                      | 2,101      |   | $ | 2,058 |   | $ | 1,935 |   |
| Residential revenue per Kwh                  |       | 10.09                                  | ¢     | 9.64 | ¢ | 9.09 | ¢ |
| Commercial and industrial revenue per Kwh    |       | 7.17                                   |       | 6.86 |   | 6.55 |   |
| Wholesale revenue per Kwh                    |       | 4.89                                   |       | 4.87 |   | 4.18 |   |

 

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**NATURAL GAS UTILITYOPERATIONS**

 

The mostsignificant recent developments in the natural gas operations of NSP-Minnesotaare continued volatility in natural gas market prices and the continued trendof declining use per customer by residential customers as a result of improvedbuilding construction technologies, higher appliance efficiencies andconservation.  From 1998 to 2008, averageannual sales to the typical residential customer declined from 111 MMBtu peryear to 88 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 ofRegulatory Agencies and Areas of Jurisdiction****** —***Retail rates, services and other aspects ofNSP-Minnesota’s operations are regulated by the MPUC and the NDPSC within theirrespective states.  The MPUC hasregulatory authority over aspects of NSP-Minnesota’s financial activities,including security issuances, certain property transfers, mergers with otherutilities and transactions between NSP-Minnesota and its affiliates.  In addition, the MPUC reviews and approvesNSP-Minnesota’s natural gas supply plans for meeting customers’ future energyneeds.

 

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

 

NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5percent of Minnesota natural gas revenue on conservation improvementprograms.  These costs are recoveredthrough an annual cost recovery mechanism for natural gas conservation andenergy management program expenditures. This law will change to a savings-based requirement beginning in 2010,and the costs of conservation improvement programs will continue to berecoverable through a rate adjustment mechanism.

 

For a further discussion of rate and regulatory matters see Note 13 tothe consolidated financial statements.

 

**Capability and Demand**

 

Natural gas supply requirements are categorized asfirm or interruptible (customers with an alternate energy supply).  The maximum daily send-out (firm and interruptible)for NSP-Minnesota was 700,323 MMBtu for 2008, which occurred on Dec. 16,2008.

 

NSP-Minnesota purchases natural gas from independentsuppliers.  These purchases are generallypriced based on market indices that reflect current prices.  The natural gas is delivered undertransportation agreements with interstate pipelines.  These agreements provide for firm deliverablepipeline capacity of 573,668 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of undergroundnatural gas storage services.  Thesestorage agreements provide storage for approximately 26 percent of winternatural gas requirements and 32 percent of peak day, firm requirements ofNSP-Minnesota.

 

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

 

NSP-Minnesota is required to file for a change innatural gas supply contract levels to meet peak demand, to redistribute demandcosts among classes, or to exchange one form of demand for another.  The 2007-2008 and 2008-2009 entitlementlevels are pending MPUC action.

 

**Natural Gas Supply and Costs**

 

NSP-Minnesota actively seeks natural gas supply, transportation andstorage alternatives to yield a diversified portfolio that provides increasedflexibility, decreased interruption and financial risk and economical rates.  In addition, NSP-Minnesota

 

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conducts natural gas price hedging activity that has been approved bythe MPUC.  This diversification involvesnumerous domestic and Canadian supply sources with varied contract lengths.

 

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

 
| 2008 |   | $    | 8.41   |   |
|------|--------|------|--------|--------|
| 2007 |   | 7.67 |   |
| 2006 |   | 8.32 |   |

 

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

 

NSP-Minnesota has firm natural gas transportation contracts withseveral pipelines, which expire in various years from 2009 through 2028.

 

NSP-Minnesota has certain natural gas supply,transportation and storage agreements that include obligations for the purchaseand/or delivery of specified volumes of natural gas or to make payments in lieuof delivery.  At Dec. 31, 2008,NSP-Minnesota was committed to approximately $688 million in such obligationsunder these contracts.

 

NSP-Minnesota purchases firm natural gas supplyutilizing long-term and short-term agreements from approximately27 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota tomaintain competition from suppliers and minimize supply costs.

 

**Natural Gas Operating Statistics**

 
| ** **                                      | ** ** | **Year Ended Dec. 31,** | ** ** |
|-------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                      | ** ** | **2008**                               | ** ** | **2007** | ** ** | **2006** | ** ** |
| **Natural gas deliveries (thousands of MMBtu)** |       |                                   |       |   |   |   |   |
| Residential                                     |       | 41,589                                 |       | 38,024 |   | 33,896 |   |
| Commercial and industrial                       |       | 42,640                                 |       | 40,184 |   | 35,231 |   |
| Other                                           |       | 529                                    |       | 2,276 |   | 1,370 |   |
| **Total retail**                                |       | 84,758                                 |       | 80,484 |   | 70,497 |   |
| Transportation and other                        |       | 12,484                                 |       | 8,528 |   | 8,727 |   |
| **Total deliveries**                            |       | 97,242                                 |       | 89,012 |   | 79,224 |   |
|                                            |       |                                   |       |   |   |   |   |
| **Number of customers at end of period**        |       |                                   |       |   |   |   |   |
| Residential                                     |       | 434,987                                |       | 430,048 |   | 426,479 |   |
| Commercial and industrial                       |       | 40,174                                 |       | 39,570 |   | 39,056 |   |
| **Total retail**                                |       | 475,161                                |       | 469,618 |   | 465,535 |   |
| Transportation and other                        |       | 15                                     |       | 14 |   | 14 |   |
| **Total customers**                             |       | 475,176                                |       | 469,632 |   | 465,549 |   |
|                                            |       |                                   |       |   |   |   |   |
| **Natural gas revenues (thousands of dollars)** |       |                                   |       |   |   |   |   |
| Residential                                     |       | $                                      | 467,751    |   | $ | 413,790 |   | $ | 394,204 |   |
| Commercial and industrial                       |       | 413,871                                |       | 350,640 |   | 335,392 |   |
| **Total retail**                                |       | 881,622                                |       | 764,430 |   | 729,596 |   |
| Transportation and other                        |       | 8,336                                  |       | 12,541 |   | 15,039 |   |
| **Total natural gas revenues**                  |       | $                                      | 889,958    |   | $ | 776,971 |   | $ | 744,635 |   |
|                                            |       |                                   |       |   |   |   |   |
| MMBtu sales per retail customer                 |       | 178.38                                 |       | 171.38 |   | 151.43 |   |
| Revenue per retail customer                     |       | $                                      | 1,855      |   | $ | 1,628 |   | $ | 1,567 |   |
| Residential revenue per MMBtu                   |       | 11.25                                  |       | 10.88 |   | 11.63 |   |
| Commercial and industrial revenue per MMBtu     |       | 9.71                                   |       | 8.73 |   | 9.52 |   |
| Transportation and other revenue per MMBtu      |       | 0.67                                   |       | 1.47 |   | 1.72 |   |

 

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**ENVIRONMENTAL MATTERS**

 

NSP-Minnesota’sfacilities are 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-Minnesotastrives to comply with all environmental regulations applicable to itsoperations.  However, it is not possibleto determine when or to what extent additional facilities or modifications ofexisting or planned facilities will be required as a result of changes toenvironmental regulations, interpretations or enforcement policies or, whateffect future laws or regulations may have upon NSP-Minnesota’soperations.  For more information onenvironmental contingencies, see Notes 14 and 15 to the consolidated financialstatements.

 

**EMPLOYEES**

** **

The number of full-time NSP-Minnesota employees on Dec. 31, 2008was 3,637.  Of these full-time employees,2,279 or 63 percent, are covered under collective bargaining agreements.  See Note 8 in the consolidated financialstatements for further discussion of the bargaining agreements.  Employees of Xcel Energy Services Inc., asubsidiary of Xcel Energy, also provide services to NSP-Minnesota and are notconsidered in the above amounts.

 

# **Item 1A — Risk Factors**

#  

**RisksAssociated with Our Business**

 

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

 

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

 

Ourprofitability is dependent on our ability to recover the costs of providingenergy and utility services to our customers. We currently provide service at rates approved by one or more regulatorycommissions.  These rates are generallyregulated based on an analysis of our expenses incurred in a test year.  Thus, the rates we are allowed to charge mayor may not match our expenses at any given time.  While rate regulation is premised onproviding a reasonable opportunity to earn a reasonable rate of return oninvested capital, there can be no assurance that the applicable regulatorycommission will judge all of our costs to have been prudently incurred or thatthe regulatory process in which rates are determined will always result inrates that will produce full recovery of our costs.  Rising fuel costs could increase the riskthat we will not be able to fully recover our fuel costs from ourcustomers.  Furthermore, there could bechanges in the regulatory environment that would impair our ability to recovercosts historically collected from our customers.  If all of our costs are not recovered throughcustomer rates, we could incur financial operating losses, which, over the longterm, could jeopardize our ability to meet our financial obligations.

 

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

 

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

 

We cannot beassured that any of our current ratings will remain in effect for any givenperiod of time or that a rating will not be lowered or withdrawn entirely by arating agency.  In addition, our creditratings may change as a result of the differing methodologies or change in themethodologies used by the various rating agencies.  For example, Standard & Poor’scalculates an imputed debt associated with capacity payments from purchasepower contracts.  An increase in theoverall 

 

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level ofcapacity payments 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 interestrates increase, we may incur increased interest expense on variable interestdebt, short-term borrowings or incremental long-term debt, which could have anadverse impact on our operating results.

 

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

*** ***

NSP-Minnesota’s operations require significant capitalinvestment in property, plant and equipment; consequently, NSP-Minnesota is anactive participant in debt markets.  Anydisruption in capital markets could have a material impact on our ability tofund our operations.  Capital markets areglobal in nature and are impacted by numerous events throughout the worldeconomy.  Capital market disruptionevents, as evidenced by the collapse in the U.S. sub-prime mortgage market andsubsequent broad financial market stress, could prevent NSP-Minnesota fromissuing new securities or cause us to issue securities with less than idealterms and conditions, such as higher interest rates.

 

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

 

Credit risk includes the risk that our retail customers will not paytheir bills, which may lead to a reduction in liquidity and an eventualincrease in bad debt expense.  Retailcredit risk is comprised of numerous factors including the overall economy andthe price of products and services provided.

 

Credit risk also includes the risk that various counterparties that oweus money or product will breach their obligations.  Should the counterparties to thesearrangements fail to perform, we may be forced to enter into alternativearrangements.  In that event, ourfinancial results could be adversely affected and we could incur losses.

 

NSP-Minnesotamay at times have direct credit exposure in itsshort-term wholesale and commodity trading activity to various financialinstitutions trading for their own accounts or issuing collateral support onbehalf of other counterparties. NSP-Minnesota may also have some indirect credit exposure due toparticipation in organized markets such as the PJM Interconnection and MISO inwhich any credit losses are socialized to all market participants.

 

NSP-Minnesotadoes have additional indirect credit exposures to various financialinstitutions in the form of letters of credit provided as security bypower suppliers under various long-term physical purchasedpower contracts.  If any of thecredit ratings of the letter of credit issuers were to drop below thedesignated investment grade rating stipulated in the underlying long termpurchased power contracts, the supplier would need to replace that securitywith an acceptable substitute.  If the security were not replaced, theparty would be in technical default under the contract, which would enableNSP-Minnesota to exercise its contractual rights.

 

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

 

We engage in wholesale sales and purchases of electriccapacity, energy and energy-related products and are subject to market supplyand commodity price risk.  Commodity pricechanges 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.  We utilize quotedobservable market prices to the maximum extent possible in determining thevalue of these derivative commodity instruments.  For positions for which observable marketprices are not available, we utilize observable quoted market prices of similarassets or liabilities or indirectly observable prices based on forward pricecurves of similar markets.  For positionsfor which we have unobservable market prices, we incorporate estimates andassumptions as to a variety of factors such as pricing relationships betweenvarious energy commodities and geographic locations.  Actual experience can vary significantly fromthese estimates and assumptions and significant changes from our assumptionscould cause significant earnings variability.

 

If we encounter market supply shortages, we may beunable to fulfill contractual obligations to our retail, wholesale and othercustomers at previously authorized or anticipated costs.  Any such supply shortages could cause us toseek alternative supply services at potentially higher costs or suffer increasedliability 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

 

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supply sources and such interruptions may causeshort-term disruptions in our ability to provide electric and/or natural gasservices to our customers.

 

***We are subject to environmental laws and regulations, with whichcompliance could be difficult and costly.***

 

We are subjectto environmental laws and regulations that affect many aspects of our past,present and future operations, including air emissions, water quality,wastewater discharges and the generation, transport and disposal of solidwastes and hazardous substances.  Theselaws and regulations require us to obtain and comply with a wide variety ofenvironmental registrations, licenses, permits, inspections and otherapprovals.  Environmental laws andregulations can also require us to restrict or limit the output of certainfacilities or the use of certain fuels, to install pollution control equipmentat our facilities, clean up spills and correct environmental hazards and othercontamination.  Both public officials andprivate individuals may seek to enforce the applicable environmental laws andregulations against us.  We may be requiredto pay all or a portion of the cost to remediate (i.e. clean-up) sites whereour past activities, or the activities of certain other parties, causedenvironmental contamination.  At Dec. 31,2008, these sites included:

 

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

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

 

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

 

In addition, existing environmental laws orregulations may be revised, new laws or regulations seeking to protect theenvironment may be adopted or become applicable to us and we may incuradditional unanticipated obligations or liabilities under existingenvironmental laws and regulations.

 

***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 inweather conditions, such as an increase in changes in precipitation and extremeweather events.  NSP-Minnesota does notserve any coastal communities so the possibility of sea level rises does notdirectly affect NSP-Minnesota or its customers. Our customers’ energy needs vary with weather conditions, primarilytemperature and humidity.  Forresidential customers, heating and cooling represent their largest energyuse.  To the extent weather conditionsare affected by climate change, customers’ energy use could increase ordecrease depending on the duration and magnitude of the changes.  Increased energy use due to weather changesmay require us to invest in more generating assets, transmission and otherinfrastructure to serve increased load. Decreased energy use due to weather changes may affect our financialcondition, through decreased revenues. Extreme weather conditions in general require more system backup, addingto costs, and can contribute to increased system stresses, including serviceinterruptions.  Weather conditionsoutside of the company’s service territory could also have an impact onNSP-Minnesota’s revenues.  NSP-Minnesotabuys and sells electricity depending upon system needs and marketopportunities.  Extreme weatherconditions creating high energy demand on our own and/or other systems mayraise electricity prices as we buy short-term energy to serve our own system,which would increase the cost of energy we provide to our customers.  Severe weather impacts NSP-Minnesota’sservice territories, primarily through thunderstorms, tornadoes and snow or icestorms.  We include storm restoration inour budgeting process as a normal business expense and we anticipate continuingto do so.  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 NSP-Minnesota’s revenues. NSP-Minnesota’s financial performance is tied to the health of theregional economies we serve.  The priceof energy, as a factor in a region’s cost of living as well as an importantinput into the cost of goods, has an impact on the economic health of ourcommunities.  The cost of additionalregulatory requirements, such as a tax on GHGs or additional environmentalregulation, 

 

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wouldnormally be borne by consumers through higher prices for energy and purchasedgoods.  To the extent financial marketsview climate change and emissions of GHGs as a financial risk, this couldnegatively affect our ability to access capital markets or cause NSP-Minnesotato receive less than ideal terms and conditions.

 

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

 

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

 

Many of the federal and state climate changelegislative proposals use a “cap and trade” policy structure, in which GHGemissions from a broad cross-section of the economy would be subject to anoverall cap.  Under the proposals, thecap becomes more stringent with the passage of time.  The proposals establish mechanisms for GHG sources,such as power plants, to obtain “allowances” or permits to emit GHGs during thecourse of a year.  The sources may usethe allowances to cover their own emissions or sell them to other sources thatdo not hold enough emissions for their own operations.  Proponents of the cap and trade policybelieve it will result in the most cost effective, flexible emissionreductions.  **The impact of legislation and regulations, includinga “cap and trade” structure, on NSP-Minnesota and its customers will depend ona number of factors, including whether GHG sources in multiple sectors of theeconomy are regulated, the overall GHG emissions cap level, the degree to whichGHG offsets are allowed, the allocation of emission allowances to specificsources and the indirect impact of carbon regulation on natural gas and coalprices.  An important factor isNSP-Minnesota’s ability to recover the costs incurred to comply with anyregulatory requirements that are ultimately imposed. **We may not recover allcosts related to complying with regulatory requirements imposed onNSP-Minnesota.  If our regulators do notallow us to recover all or a part of the cost of capital investment or theoperating and maintenance costs incurred to comply with the mandates, it couldhave a material adverse effect on our results of operations.

 

For further discussion see Note 14 to the consolidatedfinancial statements.

 

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

 

Our twonuclear stations, Prairie Island and Monticello, subject us to the risks ofnuclear generation, which include:

 

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

·                  Limitationson the amounts and types of insurance commercially available to cover lossesthat might arise in connection with nuclear operations; and

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

 

The NRC hasauthority to impose licensing and safety-related requirements for the operationof nuclear generation facilities.  In theevent of non-compliance, the NRC has the authority to impose fines or shut downa unit, or both, depending upon its assessment of the severity of thesituation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitatesubstantial capital expenditures at NSP-Minnesota’s nuclear plants.  In addition, the Institute for Nuclear PowerOperations (INPO) reviews our nuclear operations and nuclear generationfacilities. Compliance with INPO recommendations could result in substantialcapital expenditures or a substantial increase in operating expenses.

 

If an incidentdid occur, it could have a material adverse effect on our results of operationsor financial condition.  Furthermore, thenon-compliance of other nuclear facilities operators with applicableregulations or the occurrence of a serious nuclear incident at other facilitiescould result in increased regulation of the industry as a whole, which couldthen increase NSP-Minnesota’s compliance costs and impact the results ofoperations of its facilities.

 

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***Economic conditions could negatively 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 regarding energy prices and the capital and commoditymarkets.  A lower level of economicactivity might result in a decline in energy consumption, which may adverselyaffect our revenues and future growth. Instability in the financial markets, as a result of recession orotherwise, also may affect the cost of capital and our ability to raisecapital, which are discussed in greater detail in the Capital Markets risksection above.

 

Current economic conditions may be exacerbated by insufficientfinancial sector liquidity leading to potential increased unemployment, whichmay impact customers’ ability to pay timely, increase customer bankruptcies,and may lead to increased bad debt.  Itis expected that commercial and industrial customers will be impacted firstwith residential customers following, if such circumstances occur.  See credit risk section for more relatedinformation.

 

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.

 

***Our utility operations are subject to long termplanning 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 impacted by war, acts of terrorism, threats ofterrorism or disruptions in normal operating conditions due to localized orregional events.***

 

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

 

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

 

A disruption of the regional electric transmission grid, interstatenatural gas pipeline infrastructure or other fuel sources, could negativelyimpact our business.  Because ourgeneration, transmission systems and local natural gas distribution companiesare part of an interconnected system, we face the risk of possible loss ofbusiness due to a disruption caused by an event (severe storm, severetemperature extremes, generator or transmission facility outage, pipelinerupture, railroad disruption, sudden and significant increase or decrease inwind generation, or any disruption of work force such as may be caused by fluepidemic) within our operating systems or on a neighboring system or theactions of a neighboring utility.  Anysuch disruption could result in a significant decrease in revenues andsignificant additional costs to repair assets, which could have a materialadverse impact on our financial condition and results.

 

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

 

The term business continuity refers to the ability of the firm tomaintain day-to-day operations in response to unforeseen events, such as thosein the preceding section, which describes numerous disruptions to our normaloperating environment.  While theimmediate response to such events may be part of a pre-existing disasterrecovery plan, business continuity is a broader concept that refers to how wellthe company responds to subsequent pressures on its day-to-day operations.  The 

 

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company’s response may have been initially triggered by an event, butwhen 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.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

The Energy Act increased the FERC’s civil penalty authority forviolation 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 with our defined benefit retirement plansand other employee-related benefits may adversely affect our results ofoperations, financial position or liquidity.***

 

We havedefined benefit and postretirement plans that cover substantially all of ouremployees.  Assumptions related to futurecosts, return on investments, interest rates and other actuarial assumptionshave a significant impact on our funding requirements related to these plans.  These estimates and assumptions may changebased on economic conditions, actual 

 

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stock marketperformance, changes in interest rates and any changes in governmentalregulations.  In addition, the PensionProtection Act of 2006, as amended, changed the minimum funding requirementsfor defined benefit pension plans beginning in 2008.  Therefore, our funding requirements andrelated contributions may change in the future.

 

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

** **

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

 

***As we are asubsidiary of Xcel Energy, we may be negatively affected by events at XcelEnergy and its affiliates.  If XcelEnergy were to become obligated to make payments under various guarantees andbond indemnities or to fund its other contingent liabilities, or if Xcel Energy’scredit ratings and access to capital were restricted, this could limit XcelEnergy’s ability to contribute equity or make loans to us, or may cause 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, 2008, Xcel Energy had approximately $7.7 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. 31,2008, Xcel Energy had guarantees outstanding with a maximum stated amount ofapproximately $67.5 million and $18.2 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, 2008, was approximately $27.9million.  Xcel Energy’s total exposureunder these indemnities cannot be determined at this time.  If Xcel Energy were to become obligated tomake payments under these guarantees and bond indemnities or become obligatedto fund the other contingent liabilities, it could limit Xcel Energy’s abilityto contribute equity or make loans to us, or may cause Xcel Energy to seekadditional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need toseek alternative sources of funds to meet our cash needs.

 

***We are a whollyowned subsidiary of Xcel Energy.  XcelEnergy can exercise substantial control over our dividend policy and businessand operations and may exercise that control in a manner that may be perceived tobe adverse to our interests.***

 

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

 

We havehistorically paid quarterly dividends to Xcel Energy.  In 2008, 2007 and 2006 we paid $229.7million, $226.8 million and $219.6 million of dividends to Xcel Energy,respectively.  If Xcel Energy’s cashrequirements increase, our board of directors could decide to increase thedividends we pay to Xcel Energy to help support Xcel Energy’s cash needs.  This could adversely affect ourliquidity.  The amount of dividends thatwe can pay is also limited to some extent by our indenture for our first mortgagebonds.

 

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

 

None.

 

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**Item 2 — Properties**

 

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

 

Electricutility generating stations:

 
| **Station, City and Unit** | ** ** | **Fuel**         | ** ** | **Installed** | ** ** | **Summer 2008 Net  Dependable  Capability (MW)** | ** ** |
|-------------------------------------------|------------|------------------|------------|---------------|------------|-----------------------------------------------------------------|------------|
| ***Steam:***                              |       |             |       |          |       |                                                            |       |
| Sherburne-Becker, MN                      |       |             |       |          |       |                                                            |       |
| Unit 1                                    |       | Coal             |       | 1976          |       | 697                                                             |       |
| Unit 2                                    |       | Coal             |       | 1977          |       | 697                                                             |       |
| Unit 3                                    |       | Coal             |       | 1987          |       | 510                                                             | (a)        |
| Prairie Island-Welch, MN                  |       |             |       |          |       |                                                            |       |
| Unit 1                                    |       | Nuclear          |       | 1973          |       | 551                                                             |       |
| Unit 2                                    |       | Nuclear          |       | 1974          |       | 545                                                             |       |
| Monticello-Monticello, MN                 |       | Nuclear          |       | 1971          |       | 572                                                             |       |
| King-Bayport, MN                          |       | Coal             |       | 1968          |       | 555                                                             |       |
| Black Dog-Burnsville, MN                  |       |             |       |          |       |                                                            |       |
| 2 Units                                   |       | Coal/Natural Gas |       | 1955-1960     |       | 282                                                             |       |
| 2 Units                                   |       | Natural Gas      |       | 1987-2002     |       | 298                                                             |       |
| Riverside-Minneapolis, MN                 |       |             |       |          |       |                                                            |       |
| 2 Units                                   |       | Coal             |       | 1964-1987     |       | 371                                                             |       |
|                                      |       |             |       |          |       |                                                            |       |
| ***Combustion Turbine:***                 |       |             |       |          |       |                                                            |       |
| Angus Anson-Sioux Falls, SD               |       |             |       |          |       |                                                            |       |
| 3 Units                                   |       | Natural Gas      |       | 1994-2005     |       | 384                                                             |       |
| High Bridge-St. Paul, MN                  |       |             |       |          |       |                                                            |       |
| 3 Units                                   |       | Natural Gas      |       | 2008          |       | 566                                                             |       |
| Inver Hills-Inver Grove Heights, MN       |       |             |       |          |       |                                                            |       |
| 6 Units                                   |       | Natural Gas      |       | 1972          |       | 350                                                             |       |
| Blue Lake-Shakopee, MN                    |       |             |       |          |       |                                                            |       |
| 6 Units                                   |       | Natural Gas      |       | 1974-2005     |       | 490                                                             |       |
| Various locations                         |       |             |       |          |       |                                                            |       |
| 28 Units                                  |       | Various          |       | Various       |       | 165                                                             |       |
|                                      |       |             |       |          |       |                                                            |       |
| ***Wind:***                               |       |             |       |          |       |                                                            |       |
| Grand Meadow-Mower County, MN             |       |             |       | 2008          |       | 101                                                             | (b)        |
|                                      |       |             |       | Total         |       | 7,134                                                           |       |

 

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

(b)            InstalledDecember 2008; Amount represents nameplate rating capacity.

 

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Electricutility overhead and underground transmission and distribution lines (measuredin conductor miles) at Dec. 31, 2008:

 

**Conductor Miles**

 
| 500 KV           |   | 2,917  |   |
|------------------|--------|--------|--------|
| 345 KV           |   | 5,852  |   |
| 230 KV           |   | 1,801  |   |
| 161 KV           |   | 405    |   |
| 115 KV           |   | 6,743  |   |
| Less than 115 KV |   | 82,448 |   |

 

NSP-Minnesotahad 372 electric utility transmission and distribution substations at Dec. 31,2008.

 

Naturalgas utility mains at Dec. 31, 2008:

 
| ** **   | ** ** | **Miles** | ** ** |
|--------------|------------|-----------|------------|
| Transmission |       | 135       |       |
| Distribution |       | 9,506     |       |

 

**Item 3 — Legal Proceedings**

 

In the normalcourse of business, various lawsuits and claims have arisen againstNSP-Minnesota.  Management, afterconsultation with legal counsel, has recorded an estimate of the probable costof settlement or other disposition for such matters.

 

**Additional Information**

** **

For adiscussion of legal claims and environmental proceedings, see Note 14 to theconsolidated financial statements.  For adiscussion of proceedings involving utility rates, see Public UtilityRegulation and Summary of Recent Federal Regulatory Developments under Item 1and Note 13 to the consolidated financial statements.

 

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

 

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

 

**PART II**

 

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

 

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

 

NSP-Minnesota’sfirst mortgage indenture places certain restrictions on the amount of cashdividends it can pay to Xcel Energy, the holder of its common stock.  Even with these restrictions, NSP-Minnesotacould have paid more than $999 million in additional cash dividends on commonstock at Dec. 31, 2008.  Inaddition, NSP-Minnesota had dividend restrictions imposed by its creditagreement, FERC rules and state regulatory commissions.

 

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

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

·                  Stateregulatory commissions indirectly limit the amount of dividends NSP-Minnesotacan pay to Xcel Energy by requiring a minimum equity ratio of 46.26%.

 

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The dividendsdeclared during 2008 and 2007 were as follows:

 
| **Quarter Ended  (Thousands of Dollars)** | ** ** |
|----------------------------------------------------------|------------|
| **March 31, 2008**                             | ** ** | **June 30, 2008** | ** ** | **Sept. 30, 2008** | ** ** | **Dec. 31, 2008** | ** ** |
| $                                                        | 56,668     |   | $ | 58,449 |   | $ | 58,501 |   | $ | 58,414 |   |
|                                                          |            |  |  |  |  |  |  |  |  |  |  |

 
| **Quarter Ended  (Thousands of Dollars)** | ** ** |
|----------------------------------------------------------|------------|
| **March 31, 2007**                             | ** ** | **June 30, 2007** | ** ** | **Sept. 30, 2007** | ** ** | **Dec. 31, 2007** | ** ** |
| $                                                        | 57,124     |   | $ | 57,312 |   | $ | 56,282 |   | $ | 56,094 |   |
|                                                          |            |  |  |  |  |  |  |  |  |  |  |

 

**Item 6 — Selected Financial Data**

 

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

 

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

 

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

 

**ForwardLooking Information**

 

The followingdiscussion and analysis by management focuses on those factors that had a materialeffect on the financial condition and results of operations of NSP-Minnesotaduring the periods 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 thehistorical statements contained in this report, the matters discussed in thefollowing discussion and analysis are forward-looking statements that aresubject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intendedto be identified in this document by the words “anticipate,” “believe,” “estimate,”“expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,”“potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made andwe do not undertake any obligation to update them to reflect changes that occurafter that date.  Factors that couldcause actual results to differ materially include, but are not limited to:general economic conditions, including the availability of credit and itsimpact on capital expenditures and the ability of NSP- Minnesota to obtainfinancing on favorable terms; business conditions in the energy industry;actions of credit rating agencies; competitive factors, including the extentand timing of the entry of additional competition in the markets served byNSP-Minnesota; unusual weather; effects of geopolitical events, including warand acts of terrorism; state, federal and foreign legislative and regulatoryinitiatives that affect cost and investment recovery, have an impact on rates,have an impact on asset operation or ownership or impose environmental complianceconditions; structures that affect the speed and degree to which competitionenters the electric and natural gas markets; costs and other effects of legaland administrative proceedings, settlements, investigations and claims; actionsof accounting regulatory bodies; the items described under “Risk Factors” inItem 1A and Exhibit 99.01 of NSP-Minnesota’s Form 10-K for the yearended Dec. 31, 2008.

 

**Results of Operations**

** **

NSP-Minnesota’s net income was approximately $285.1 million for 2008,compared with approximately $267.3 million for 2007.

 

***Electric Revenues and Margins***

*** ***

Electric fuel and purchased power expenses tend to vary with changingretail and wholesale sales requirements and unit cost changes in fuel andpurchased power.  Due to fuel and purchasedenergy cost-recovery mechanisms for customers, fluctuations in these costs do not materially affect electric utilitymargin.

 

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NSP-Minnesota has two distinct forms of wholesale sales: short-termwholesale and commodity trading activities. Short-term wholesale refers to energy-related purchase and salesactivity and the use of certain financial instruments associated with the fuelrequired for and energy produced from, NSP-Minnesota’s generation assets andenergy and capacity purchased to serve native load.  Commodity trading is not associated withNSP-Minnesota’s generation assets or the energy or capacity purchased to servenative load.  Wholesale sales wereimmaterial to revenue and gross margin as a percentage of revenue at Dec. 31,2008 and 2007.

 

***Electric***—******Thefollowing tables detail the electric revenues and margin:

 
| **(Millions of Dollars)** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|
| Electric revenues                   |       | $        | 3,584      |     | $          | 3,477 |   |
| Electric fuel and purchased power   |       | (1,681   | )          | (1,577   | )          |
| Electric margin                     |       | $        | 1,903      |     | $          | 1,900 |   |

 

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

 

***Electric Revenues***

 
| **(Millions of Dollars)**                                                  | ** ** | **2008 vs. 2007** | ** ** |
|--------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| Fuel and purchased power cost recovery                                               |       | $                           | 94         |   |
| MERP rider                                                                           |       | 23                          |       |
| Interchange agreement billing with  NSP-Wisconsin                                    |       | 18                          |       |
| Conservation and non-fuel riders                                                     |       | 17                          |       |
| Transmission revenues                                                                |       | 15                          |       |
| North Dakota interim rate increase                                                   |       | 9                           |       |
| Increased revenues due to leap year  (weather-normalized impact)                     |       | 4                           |       |
| Estimated impact of weather                                                          |       | (31                         | )          |
| Trading revenue                                                                      |       | (25                         | )          |
| Revenue subject to refund due to change in  nuclear refueling outage recovery method |       | (14                         | )          |
| Other                                                                                |       | (3                          | )          |
| Total increase in electric revenues                                                  |       | $                           | 107        |   |

 

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

 
| **(Millions of Dollars)**                                                  | ** ** | **2008 vs. 2007** | ** ** |
|--------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| Estimated impact of weather                                                          |       | $                           | (31        | ) |
| Purchased capacity costs                                                             |       | (20                         | )          |
| Revenue subject to refund due to change in  nuclear refueling outage recovery method |       | (14                         | )          |
| MERP rider                                                                           |       | 23                          |       |
| Conservation and non-fuel riders                                                     |       | 17                          |       |
| Interchange agreement billing with  NSP-Wisconsin                                    |       | 13                          |       |
| North Dakota interim rate increase                                                   |       | 9                           |       |
| Increased margin due to leap year  (weather-normalized impact)                       |       | 4                           |       |
| Transmission revenues, net                                                           |       | 3                           |       |
| Firm wholesale                                                                       |       | 3                           |       |
| Other                                                                                |       | (4                          | )          |
| Total increase in electric margin                                                    |       | $                           | 3          |   |

 

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**NaturalGas Revenues and Margins**

 

The followingtable details natural gas revenues and margin. The cost of natural gas tends to vary with changing sales requirementsand unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms forretail customers, fluctuations in the cost of natural gas have little effect onnatural gas margin.

 
| **(Millions of Dollars)**      | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|
| Natural gas revenues                     |       | $        | 890        |     | $          | 777 |   |
| Cost of natural gas sold and transported |       | (702     | )          | (603     | )          |
| Natural gas margin                       |       | $        | 188        |     | $          | 174 |   |

 

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

 

***Natural Gas Revenues***

 
| **(Millions of Dollars)**               | ** ** | **2008 vs. 2007** | ** ** |
|---------------------------------------------------|------------|-----------------------------|------------|
| Purchased natural gas adjustment clause  recovery |       | $                           | 97         |   |
| Estimated impact of weather                       |       | 8                           |       |
| 2007 Kansas property tax refund                   |       | 4                           |       |
| Conservation revenues                             |       | 3                           |       |
| Other                                             |       | 1                           |       |
| Total increase in natural gas revenues            |       | $                           | 113        |   |

 

***Natural Gas Margin***

 
| **(Millions of Dollars)**  | ** ** | **2008 vs. 2007** | ** ** |
|--------------------------------------|------------|-----------------------------|------------|
| Estimated impact of weather          |       | $                           | 8          |   |
| 2007 Kansas property tax refund      |       | 4                           |       |
| Conservation revenues                |       | 3                           |       |
| Other                                |       | (1                          | )          |
| Total increase in natural gas margin |       | $                           | 14         |   |

 

**Non-Fuel OperatingExpense and Other Items**

** **

***Other Operating and Maintenance Expenses****—* Operating and maintenance expenses for2008 decreased $7.1 million, or 0.8 percent, compared to 2007.  The following summarizes the components ofthe changes for the year ended Dec. 31:

 
| **(Millions of Dollars)**                         | ** ** | **2008 vs. 2007** | ** ** |
|-------------------------------------------------------------|------------|-----------------------------|------------|
| Nuclear outage expenses, net of deferral                    |       | $                           | (13        | ) |
| Lower employee benefit costs                                |       | (12                         | )          |
| Higher labor costs                                          |       | 9                           |       |
| Higher contract labor costs                                 |       | 5                           |       |
| Higher consulting costs                                     |       | 3                           |       |
| Higher allowance for bad debts                              |       | 3                           |       |
| Other                                                       |       | (2                          | )          |
| Total decrease in other operating and  maintenance expenses |       | $                           | (7         | ) |

 

***Depreciation and Amortization****—* Depreciation and amortization expenseincreased by approximately $6.8 million, or 1.7 percent, for 2008,compared to 2007.  The increase was primarily due to plannedsystem expansion, which was partially offset by a decrease in depreciation dueto the MPUC approval of two NSP-Minnesota depreciation filings in September 2008,and an NDPSC settlement agreement in December 2008.

 

***Allowance for Funds Used During Construction, Equity and Debt (AFDC)***— AFDC is a non-cash amount capitalized as apart of construction costs representing the cost of financing theconstruction.  Generally, these costs arerecovered from customers, in future rates, as the related property isdepreciated.  AFDC, resulting in partfrom these projects, increased by approximately $4.5 million, or 11.5 percent,for the twelve months of 2008 compared with the same period in 2007.  NSP-Minnesota’s overall increase in AFDC isdue to the RES Project (which is partially offset by the current recovery fromcustomers of the financing costs through a rate rider) and various nuclearprojects.

 

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***Interest Charges****—* Interest charges increased byapproximately $12.1 million, or 6.5 percent, for 2008, compared with 2007.  The increase was due to higher average debtbalances.

 

***Income Taxes****—* Income tax expense decreased byapproximately $3.8 million for 2008 compared with 2007.  The decrease in tax expense in 2008 wasprimarily due to higher state tax expense in 2007 and higher plant-relateddeductions in 2008.  The effective taxrate was 38.5 percent for 2008, compared with 40.5 percent for 2007.  Without the increases in these charges andbenefits, the effective tax rate for 2008 and 2007 would have been 39.2 percentand 39.9 percent, respectively.

 

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

** **

**Derivatives, Risk Managementand Market Risk**

** **

In the normal course of business, NSP-Minnesota is exposed to a varietyof market risks.  Market risk is thepotential loss or gain that may occur as a result of changes in the market orfair value of a particular instrument or commodity.  All financial and commodity-relatedinstruments, including derivatives, are subject to market risk.  These risks, as applicable to NSP-Minnesota,are discussed in further detail in Note 10 to the consolidated financialstatements.

 

NSP-Minnesota is exposed to the impact of changes in price for energyand energy-related products, which is partially mitigated by the company’s useof commodity derivatives.  Though no materialnon-performance risk currently exists with the counterparties to NSP-Minnesota’scommodity derivative contracts, the continued turmoil in the financial marketsmay in the future impact that risk to the extent it impacts thosecounterparties.  Continued distress inthe financial markets may also impact the fair value of the debt and equitysecurities in the nuclear decommissioning trust fund and master pension trust,as well as NSP-Minnesota’s ability to earn a return on short-term investmentsof excess cash.  Also, the current stateof the financial markets may negatively impact NSP-Minnesota’s ability toobtain debt financing under favorable terms.

 

***Commodity Price Risk—*** NSP-Minnesota is exposed to commodity price riskin its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-termphysical purchase and sales contracts for electric capacity, energy andenergy-related products and for various fuels used in the generation anddistribution activities.  Commodity pricerisk is also managed through the use of financial derivative instruments.  NSP-Minnesota’s risk-management policy allowsit to manage commodity price risk within each rate-regulated operation to theextent such exposure exists, as allowed by regulation.

 

***Short-Term Wholesaleand Commodity Trading Risk —***NSP Minnesotaconducts various short-term wholesale and commodity trading activities,including the purchase and sale of electric capacity, energy and energy-relatedinstruments.  These marketing activitiesgenerally have terms of less than one year in length.  NSP Minnesota’s risk-management policy allowsmanagement to conduct these activities within guidelines and limitations asapproved by its risk management committee, which is made up of managementpersonnel not directly involved in the activities governed by the policy.

 

The fair value of the commodity trading contracts at Dec. 31, wereas follows:

 
| **(Thousands of Dollars)**                                                                                              | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Fair value of commodity trading contract  assets (liabilities) outstanding at Jan. 1 |       | $        | 2,112      |     | $          | (1,174 | ) |
| Contracts realized or settled during the  period                                                                                  |       | (2,391   | )          | (12,073  | )          |
| Fair value of commodity trading contract  additions and changes during the period                                                 |       | 3,894    |       | 15,359   |       |
| Fair value of commodity trading contract  assets outstanding at Dec. 31                                                      |       | $        | 3,615      |     | $          | 2,112 |   |

 

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At Dec. 31, 2008, the fair values by source for the commoditytrading net asset (liability) balances were as follows:

 
| ** **                           | ** ** | **Futures/Forwards**                | ** ** |
|--------------------------------------|------------|-------------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **Source of  Fair Value** | ** ** | **Maturity  Less Than  1 Year** | ** ** | **Maturity  1 to 3  Years** | ** ** | **Maturity  4 to 5  Years** | ** ** | **Maturity  Greater  Than 5 Years** | ** ** | **Total Futures/   Forwards  Fair Value** | ** ** |
|                                 |       | 1                                   |       | $ | 1,936 |   | $ | 1,133 |   | $ | — |   | $ | — |   | $ | 3,069 |   |
|                                 |       | 2                                   |       | 91 |   | 291 |   | 359 |   | 158 |   | 899 |   |
| Total Futures/Forwards Fair Value    |       |                                |       | $ | 2,027 |   | $ | 1,424 |   | $ | 359 |   | $ | 158 |   | $ | 3,968 |   |

 
| ** **                           | ** ** | **Options**                         | ** ** |
|--------------------------------------|------------|-------------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **Source of  Fair Value** | ** ** | **Maturity  Less Than  1 Year** | ** ** | **Maturity  1 to 3  Years** | ** ** | **Maturity  4 to 5  Years** | ** ** | **Maturity  Greater  Than 5 Years** | ** ** | **Total Options  Fair Value** | ** ** |
|                                 |       | 2                                   |       | $ | (353 | ) | $ | — |   | $ | — |   | $ | — |   | $ | (353 | ) |
| Total Options Fair Value             |       |                                |       | $ | (353 | ) | $ | — |   | $ | — |   | $ | — |   | $ | (353 | ) |

 

----

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

 

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

 

NSP-Minnesota’s short-term wholesale andcommodity trading operations measure the outstanding risk exposure to pricechanges on transactions, contracts and obligations that have been entered into,but not closed, using an industry standard methodology known as Value-at-Risk(VaR).  VaR expresses the potentialchange in fair value on the outstanding transactions, contracts and obligationsover a particular period of time under normal market conditions.

 

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

 
| ** **                          | ** ** | **Year ended**         | ** ** | ** **         | ** ** | **During 2008** | ** ** |
|-------------------------------------|------------|-----------------------------|------------|--------------------|------------|----------------------|------------|
| **(Millions of Dollars)** | ** ** | **Dec. 31, 2008** | ** ** | **VaR Limit** | ** ** | **Average**          | ** ** | **High** | ** ** | **Low** | ** ** |
| Commodity trading (a)               |       | $                           | 0.30       |               | $          | 5.00                 |       | $ | 0.30 |   | $ | 1.14 |   | $ | 0.01 |   |
|                                     |            |                             |            |                    |            |                      |            |  |  |  |  |  |  |  |  |  |

 
| ** **                          | ** ** | **Year ended**         | ** ** | ** **         | ** ** | **During 2007** | ** ** |
|-------------------------------------|------------|-----------------------------|------------|--------------------|------------|----------------------|------------|
| **(Millions of Dollars)** | ** ** | **Dec. 31, 2007** | ** ** | **VaR Limit** | ** ** | **Average**          | ** ** | **High** | ** ** | **Low** | ** ** |
| Commodity trading (a)               |       | $                           | 0.26       |               | $          | 5.00                 |       | $ | 0.47 |   | $ | 1.45 |   | $ | 0.09 |   |
|                                     |            |                             |            |                    |            |                      |            |  |  |  |  |  |  |  |  |  |

 

----

(a) Includestransactions for NSP-Minnesota and PSCo.

 

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

 

At Dec. 31, 2008, a 100-basis-point change in the benchmark rateon NSP-Minnesota’s variable rate debt would impact pretax interest expense byapproximately $1.3 million.

 

NSP-Minnesota also maintains trust funds, as required by the NRC, tofund certain costs of nuclear decommissioning. These trust funds are subject to interest rate risk and equity pricerisk.  At Dec. 31, 2008, these fundswere invested in a diversified portfolio of taxable and municipal fixed incomesecurities and equity securities.  Thesefunds may be used only for activities

 

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related to nuclear decommissioning. The accounting for nuclear decommissioning recognizes that costs arerecovered through rates; therefore fluctuations in equity prices, or interestrates do not have an impact on earnings.

 

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

 

NSP-Minnesota conducts standard credit reviews for allcounterparties.  NSP-Minnesota employsadditional credit risk control mechanisms when appropriate, such as letters ofcredit, parental guarantees, standardized master netting agreements andtermination provisions that allow for offsetting of positive and negativeexposures.  The credit exposure is monitoredand, when necessary, the activity with a specific counterparty is limited untilcredit enhancement is provided.  Therecent volatility in financial markets could increase our credit risk.

 

At Dec. 31, 2008, a 10-percent increase in prices would have resultedin a net mark-to-market increase in credit risk exposure of $1.0 million, whilea decrease of 10 percent would have resulted in a decrease of $0.9 million.

 

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**Item 8 — Financial Statements andSupplementary Data**

 

**Management Report onInternal Controls Over Financial Reporting**

** **

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

 

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

 

NSP-Minnesota management assessed the effectiveness ofthe company’s internal control over financial reporting as of Dec. 31,2008.  In making this assessment, it usedthe criteria set forth by the Committee of Sponsoring Organizations of theTreadway Commission (COSO) in *InternalControl — Integrated Framework. *Basedon our assessment, we believe that, as of Dec. 31, 2008, the company’sinternal control over financial reporting is effective based on those criteria.

 

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

 
| /S/ DAVID M. SPARBY                      |     | /S/ BENJAMIN  G.S. FOWKE III                            |
|------------------------------------------|----------|---------------------------------------------------------|
| David M. Sparby                          |     | Benjamin G.S. Fowke III                                 |
| *President  and Chief Executive Officer* | * * | *Executive  Vice President and Chief Financial Officer* |
| March 2,  2009                      |     | March 2,  2009                                     |

 

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**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

Board of Directors and StockholdersNorthern States Power Company — Minnesota

 

We have audited the accompanying consolidated balance sheets andconsolidated statements of capitalization of Northern States Power Company —Minnesota and subsidiaries (the “Company”) as of December 31, 2008 and2007, and the related consolidated statements of income, common stockholder’sequity and comprehensive income, and cash flows for each of the three years inthe period ended December 31, 2008.  Our audits also includedthe financial statement 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 our audits in accordance with the standards of the PublicCompany Accounting Oversight Board (United States).  Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whetherthe financial statements are free of material misstatement.  The Companyis not required to have, nor were we engaged to perform, an audit of itsinternal control over financial reporting.  Our audits includedconsideration of internal control over financial reporting as a basis fordesigning audit procedures that are appropriate in the circumstances, but notfor the purpose of expressing an opinion on the effectiveness of the Company’sinternal control over financial reporting.  Accordingly, we express nosuch opinion.  An audit also includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements, assessingthe accounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation.  Webelieve that our audits provide 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 — Minnesotaand subsidiaries as of December 31, 2008 and 2007, and the results oftheir operations and their cash flows for each of the three years in the periodended December 31, 2008, 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.  As discussed in Note 7 to the consolidatedfinancial statements, the Company adopted Financial Accounting Standards Board(FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes —an interpretation of FASB Statement No. 109,” as of January 1, 2007.

 

 
| /S/ DELOITTE &  TOUCHE LLP |   |
|-------------------------------------|--------|
| Minneapolis,  Minnesota             |   |
| March 2,  2009                 |   |

 

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**NSP-MINNESOTA AND SUBSIDIARIES****CONSOLIDATED STATEMENTS OFINCOME***(amounts in thousands ofdollars)*

 
| ** **                                                                                    | ** ** | **Year Ended Dec. 31** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                    | ** ** | **2008**                              | ** ** | **2007** | ** ** | **2006** | ** ** |
| **Operating revenues**                                                                        |       |                                  |       |   |   |   |   |
| Electric                                                                                      |       | $                                     | 3,584,109  |   | $ | 3,476,674 |   | $ | 3,265,371 |   |
| Natural gas                                                                                   |       | 889,958                               |       | 776,971 |   | 744,635 |   |
| Other                                                                                         |       | 19,569                                |       | 18,569 |   | 17,609 |   |
| Total operating revenues                                                                      |       | 4,493,636                             |       | 4,272,214 |   | 4,027,615 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Operating expenses**                                                                        |       |                                  |       |   |   |   |   |
| Electric fuel and purchased power                                                             |       | 1,680,795                             |       | 1,576,901 |   | 1,445,590 |   |
| Cost of natural gas sold and transported                                                      |       | 701,687                               |       | 602,617 |   | 590,094 |   |
| Cost of sales — nonregulated and other                                                   |       | 10,034                                |       | 9,212 |   | 7,769 |   |
| Other operating and maintenance expenses                                                      |       | 877,497                               |       | 884,554 |   | 842,801 |   |
| Conservation program expenses                                                                 |       | 65,876                                |       | 72,912 |   | 59,436 |   |
| Depreciation and amortization                                                                 |       | 412,362                               |       | 405,569 |   | 425,511 |   |
| Taxes (other than income taxes)                                                               |       | 138,184                               |       | 130,094 |   | 135,903 |   |
| Total operating expenses                                                                      |       | 3,886,435                             |       | 3,681,859 |   | 3,507,104 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Operating income**                                                                          |       | 607,201                               |       | 590,355 |   | 520,511 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| Interest and other income — net                                                          |       | 10,895                                |       | 6,105 |   | 9,431 |   |
| Allowance for funds used during  construction — equity                                   |       | 26,510                                |       | 21,826 |   | 20,896 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| **Interest charges and financing costs**                                                      |       |                                  |       |   |   |   |   |
| Interest charges — including financing  costs of $5,834, $5,271 and $6,480, respectively |       | 198,369                               |       | 186,293 |   | 165,381 |   |
| Allowance for funds used during  construction — debt                                     |       | (17,140                               | )          | (17,334 | ) | (14,459 | ) |
| Total interest charges and financing costs                                                    |       | 181,229                               |       | 168,959 |   | 150,922 |   |
|                                                                                          |       |                                  |       |   |   |   |   |
| Income before income taxes                                                                    |       | 463,377                               |       | 449,327 |   | 399,916 |   |
| Income taxes                                                                                  |       | 178,236                               |       | 182,025 |   | 127,606 |   |
| **Net income**                                                                                |       | $                                     | 285,141    |   | $ | 267,302 |   | $ | 272,310 |   |

 

See Notes to Consolidated Financial Statements

 

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

 
| ** **                                                                                             | ** ** | **Year Ended Dec. 31** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                             | ** ** | **2008**                              | ** ** | **2007** | ** ** | **2006** | ** ** |
| **Operating activities**                                                                               |       |                                  |       |   |   |   |   |
| Net income                                                                                             |       | $                                     | 285,141    |   | $ | 267,302 |   | $ | 272,310 |   |
| Adjustments to reconcile net income to cash  provided by operating activities:                         | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Depreciation and amortization                                                                          |       | 407,343                               |       | 415,651 |   | 433,883 |   |
| Nuclear fuel amortization                                                                              |       | 64,203                                |       | 53,453 |   | 47,531 |   |
| Deferred income taxes                                                                                  |       | 140,701                               |       | 172,004 |   | (83,361 | ) |
| Amortization of investment tax credits                                                                 |       | (3,503                                | )          | (3,897 | ) | (4,846 | ) |
| Allowance for equity funds used during  construction                                                   |       | (26,510                               | )          | (21,826 | ) | (20,896 | ) |
| Allowance for bad debts                                                                                |       | 25,506                                |       | 23,336 |   | 19,972 |   |
| Net realized and unrealized hedging and  derivative transactions                                       |       | (4,484                                | )          | (5 | ) | 17,587 |   |
| Changes in operating assets and liabilities  (net of the effects of consolidation of NMC, see Note 18) |       |                                  |       |   |   |   |   |
| Accounts receivable                                                                                    |       | 3,268                                 |       | (86,108 | ) | 8,071 |   |
| Accounts receivable from affiliates                                                                    |       | 18,660                                |       | 1,858 |   | 20,479 |   |
| Accrued unbilled revenues                                                                              |       | (22,050                               | )          | (6,367 | ) | 37,994 |   |
| Inventories                                                                                            |       | (75,265                               | )          | (52,226 | ) | (6,475 | ) |
| Recoverable purchased natural gas and  electric energy costs                                           |       | 10,252                                |       | (19,184 | ) | (1,347 | ) |
| Other current assets                                                                                   |       | 11,394                                |       | (2,790 | ) | (1,905 | ) |
| Accounts payable                                                                                       |       | 14,557                                |       | (66,920 | ) | 49,691 |   |
| Net regulatory assets and liabilities                                                                  |       | (23,128                               | )          | (14,661 | ) | (79,181 | ) |
| Other current liabilities                                                                              |       | (13,348                               | )          | 7,624 |   | (1,264 | ) |
| Change in other noncurrent assets                                                                      |       | 15,781                                |       | 17,719 |   | 28,675 |   |
| Change in other noncurrent liabilities                                                                 |       | (37,139                               | )          | (38,139 | ) | 16,626 |   |
| Net cash provided by operating activities                                                              |       | 791,379                               |       | 646,824 |   | 753,544 |   |
|                                                                                                   |       |                                  |       |   |   |   |   |
| **Investing activities**                                                                               |       |                                  |       |   |   |   |   |
| Utility capital/construction expenditures                                                              |       | (1,015,827                            | )          | (1,060,796 | ) | (905,352 | ) |
| Allowance for equity funds used during  construction                                                   |       | 26,510                                |       | 21,826 |   | 20,896 |   |
| Purchase of investments in external  decommissioning fund                                              |       | (957,752                              | )          | (712,462 | ) | (1,288,104 | ) |
| Proceeds from sale of investments in  external decommissioning fund                                    |       | 914,514                               |       | 669,070 |   | 1,240,034 |   |
| Cash obtained from consolidation of NMC                                                                |       | —                                |       | 38,950 |   | — |   |
| Investments in utility money pool  arrangement                                                         |       | (943,400                              | )          | (423,500 | ) | (1,359,000 | ) |
| Receipts from utility money pool  arrangement                                                          |       | 943,400                               |       | 423,500 |   | 1,359,000 |   |
| Investments in affiliates                                                                              |       | (337,600                              | )          | (371,250 | ) | (345,500 | ) |
| Advances from affiliates                                                                               |       | 396,200                               |       | 342,950 |   | 379,200 |   |
| Other investments                                                                                      |       | 10,501                                |       | 5,224 |   | 6,439 |   |
| Net cash used in investing activities                                                                  |       | (963,454                              | )          | (1,066,488 | ) | (892,387 | ) |
|                                                                                                   |       |                                  |       |   |   |   |   |
| **Financing activities**                                                                               |       |                                  |       |   |   |   |   |
| Proceeds from (repayment of) short-term  borrowings — net                                         |       | (276,500                              | )          | 252,500 |   | 89,000 |   |
| Borrowings under utility money pool arrangement                                                        |       | 433,300                               |       | 937,600 |   | — |   |
| Repayments under utility money pool  arrangement                                                       |       | (464,900                              | )          | (842,500 | ) | — |   |
| Proceeds from issuance of long-term debt                                                               |       | 493,751                               |       | 343,670 |   | 393,724 |   |
| Borrowings under 5-year unsecured credit  facility                                                     |       | —                                |       | 200,000 |   | 194,000 |   |
| Repayment of long-term debt, including  reacquisition premiums                                         |       | (10                                   | )          | (186,689 | ) | (210,662 | ) |
| Repayments under 5-year unsecured credit  facility                                                     |       | —                                |       | (200,000 | ) | (444,000 | ) |
| Capital contributions from parent                                                                      |       | 203,863                               |       | 150,514 |   | 313,856 |   |
| Dividends paid to parent                                                                               |       | (229,712                              | )          | (226,824 | ) | (219,598 | ) |
| Net cash provided by financing activities                                                              |       | 159,792                               |       | 428,271 |   | 116,320 |   |
|                                                                                                   |       |                                  |       |   |   |   |   |
| Net (decrease) increase in cash and cash  equivalents                                                  |       | (12,283                               | )          | 8,607 |   | (22,523 | ) |
| Cash and cash equivalents at beginning of year                                                         |       | 24,626                                |       | 16,019 |   | 38,542 |   |
| Cash and cash equivalents at end of year                                                               |       | $                                     | 12,343     |   | $ | 24,626 |   | $ | 16,019 |   |
|                                                                                                   |       |                                  |       |   |   |   |   |
| Supplemental disclosure of cash flow  information                                                      |       |                                  |       |   |   |   |   |
| Cash paid for interest (net of amounts  capitalized)                                                   |       | $                                     | 170,168    |   | $ | 151,409 |   | $ | 145,585 |   |
| Cash paid for income taxes (net of refunds  received)                                                  |       | 27,292                                |       | 50,016 |   | 227,285 |   |
|                                                                                                   |       |                                  |       |   |   |   |   |
| Supplemental disclosure of non-cash flow  information                                                  |       |                                  |       |   |   |   |   |
| Property, plant and equipment additions in  accounts payable                                           |       | $                                     | 24,109     |   | $ | 15,670 |   | $ | 36,613 |   |

 

See Notes to Consolidated Financial Statements

 

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**NSP-MINNESOTA AND SUBSIDIARIES**

**CONSOLIDATED BALANCE SHEETS**

*(amounts in thousands of dollars)*

 
| ** **                                                                                        | ** ** | **Dec. 31, 2008** | ** ** | **Dec. 31, 2007** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| **Assets**                                                                                        | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Current assets:                                                                                   |       |                        |       |                        |       |
| Cash and cash equivalents                                                                         |       | $                           | 12,343     |                        | $          | 24,626 |   |
| Notes receivable from affiliates                                                                  |       | —                      |       | 58,600                      |       |
| Accounts receivable, net                                                                          |       | 413,156                     |       | 441,930                     |       |
| Accounts receivable from affiliates                                                               |       | 12,418                      |       | 31,078                      |       |
| Accrued unbilled revenues                                                                         |       | 248,451                     |       | 226,401                     |       |
| Recoverable purchased natural gas and  electric energy costs                                      |       | 26,605                      |       | 36,857                      |       |
| Inventories                                                                                       |       | 345,903                     |       | 270,638                     |       |
| Derivative instruments valuation                                                                  |       | 70,252                      |       | 51,233                      |       |
| Prepayments and other                                                                             |       | 48,493                      |       | 52,875                      |       |
| Total current assets                                                                              |       | 1,177,621                   |       | 1,194,238                   |       |
|                                                                                              |       |                        |       |                        |       |
| Property, plant and equipment, net                                                                |       | 6,804,794                   |       | 6,482,681                   |       |
|                                                                                              |       |                        |       |                        |       |
| Other assets:                                                                                     |       |                        |       |                        |       |
| Nuclear decommissioning fund and other  investments                                               |       | 1,084,827                   |       | 1,337,598                   |       |
| Regulatory assets                                                                                 |       | 828,712                     |       | 359,782                     |       |
| Prepaid pension asset                                                                             |       | —                      |       | 270,436                     |       |
| Derivative instruments valuation                                                                  |       | 129,605                     |       | 156,975                     |       |
| Other                                                                                             |       | 21,266                      |       | 18,622                      |       |
| Total other assets                                                                                |       | 2,064,410                   |       | 2,143,413                   |       |
| Total assets                                                                                      |       | $                           | 10,046,825 |                        | $          | 9,820,332 |   |
| **Liabilities and Equity**                                                                        | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Current liabilities:                                                                              |       |                        |       |                        |       |
| Current portion of long-term debt                                                                 |       | $                           | 250,060    |                        | $          | 31 |   |
| Short-term debt                                                                                   |       | 65,000                      |       | 341,500                     |       |
| Borrowings under utility money pool  arrangement                                                  |       | 63,500                      |       | 95,100                      |       |
| Accounts payable                                                                                  |       | 389,676                     |       | 369,394                     |       |
| Accounts payable to affiliates                                                                    |       | 52,291                      |       | 53,975                      |       |
| Taxes accrued                                                                                     |       | 121,163                     |       | 122,648                     |       |
| Accrued interest                                                                                  |       | 68,009                      |       | 61,485                      |       |
| Dividends payable to parent                                                                       |       | 58,414                      |       | 56,094                      |       |
| Derivative instruments valuation                                                                  |       | 39,816                      |       | 23,311                      |       |
| Other                                                                                             |       | 50,696                      |       | 64,968                      |       |
| Total current liabilities                                                                         |       | 1,158,625                   |       | 1,188,506                   |       |
|                                                                                              |       |                        |       |                        |       |
| Deferred credits and other liabilities:                                                           |       |                        |       |                        |       |
| Deferred income taxes                                                                             |       | 987,050                     |       | 898,725                     |       |
| Deferred investment tax credits                                                                   |       | 40,254                      |       | 43,757                      |       |
| Asset retirement obligations                                                                      |       | 1,055,689                   |       | 1,264,368                   |       |
| Regulatory liabilities                                                                            |       | 459,880                     |       | 639,228                     |       |
| Derivative instruments valuation                                                                  |       | 219,421                     |       | 236,832                     |       |
| Pension and employee benefit obligations                                                          |       | 269,537                     |       | 201,624                     |       |
| Other liabilities                                                                                 |       | 77,775                      |       | 68,585                      |       |
| Total deferred credits and other  liabilities                                                     |       | 3,109,606                   |       | 3,353,119                   |       |
|                                                                                              |       |                        |       |                        |       |
| Commitments and contingent liabilities                                                            |       |                        |       |                        |       |
| Capitalization:                                                                                   |       |                        |       |                        |       |
| Long-term debt                                                                                    |       | 2,712,689                   |       | 2,463,078                   |       |
| Common stock — authorized 5,000,000 shares  of $0.01 par value; outstanding 1,000,000 shares |       | 10                          |       | 10                          |       |
| Additional paid in capital                                                                        |       | 1,915,857                   |       | 1,711,994                   |       |
| Retained earnings                                                                                 |       | 1,149,833                   |       | 1,097,357                   |       |
| Accumulated other comprehensive income                                                            |       | 205                         |       | 6,268                       |       |
| Total common stockholder’s equity                                                            |       | 3,065,905                   |       | 2,815,629                   |       |
| Total liabilities and equity                                                                      |       | $                           | 10,046,825 |                        | $          | 9,820,332 |   |

 

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)*

 
| ** **                                                                                     | ** ** | ** **            | ** ** | ** **               | ** ** | ** **          | ** ** | **Accumulated**   | ** ** | **Total**              | ** ** |
|------------------------------------------------------------------------------------------------|------------|-----------------------|------------|--------------------------|------------|---------------------|------------|-------------------|------------|------------------------|------------|
| ** **                                                                                     | ** ** | ** **            | ** ** | ** **               | ** ** | ** **          | ** ** | **Other**         | ** ** | **Common**             | ** ** |
| ** **                                                                                     | ** ** | **Common Stock** | ** ** | **Additional Paid** | ** ** | **Retained**        | ** ** | **Comprehensive** | ** ** | **Stockholder’s** | ** ** |
| ** **                                                                                     | ** ** | **Shares**            | ** ** | **Amount**               | ** ** | **in Capital** | ** ** | **Earnings**      | ** ** | **Income (Loss)** | ** ** | **Equity** | ** ** |
| ** **                                                                                     | ** ** | ** **            | ** ** | ** **               | ** ** | ** **          | ** ** | ** **        | ** ** | ** **             | ** ** | ** ** | ** ** |
| **Balance at Dec. 31, 2005**                                                              |       | 1,000,000             |       | $                        | 10         |                | $          | 1,247,624         |       | $                      | 1,004,762  |   | $ | — |   | $ | 2,252,396 |   |
| Net income                                                                                     |       |                  |       |                     |       |                |       | 272,310           |       |                   |       | 272,310 |   |
| Net derivative instrument fair value  changes during the period, net of tax of $6,513          |       |                  |       |                     |       |                |       |              |       | 9,433                  |       | 9,433 |   |
| Comprehensive income for 2006                                                                  |       |                  |       |                     |       |                |       |              |       |                   |       | 281,743 |   |
| SFAS No. 158 adoption, net of tax of  $(2,233)                                            |       |                  |       |                     |       |                |       |              |       | (3,234                 | )          | (3,234 | ) |
| Common dividends declared to parent                                                            |       |                  |       |                     |       |                |       | (221,089          | )          |                   |       | (221,089 | ) |
| Contribution of capital by parent                                                              |       |                  |       |                     |       | 313,856             |       |              |       |                   |       | 313,856 |   |
| **Balance at Dec. 31, 2006**                                                              |       | 1,000,000             |       | $                        | 10         |                | $          | 1,561,480         |       | $                      | 1,055,983  |   | $ | 6,199 |   | $ | 2,623,672 |   |
|                                                                                           |       |                  |       |                     |       |                |       |              |       |                   |       |   |   |
| FIN 48 adoption                                                                                |       |                  |       |                     |       |                |       | 884               |       |                   |       | 884 |   |
| Net income                                                                                     |       |                  |       |                     |       |                |       | 267,302           |       |                   |       | 267,302 |   |
| Changes in unrecognized amounts of pension  and retiree medical benefits, net of tax of $551   |       |                  |       |                     |       |                |       |              |       | 797                    |       | 797 |   |
| Net derivative instrument fair value  changes during the period, net of tax of $(503)          |       |                  |       |                     |       |                |       |              |       | (728                   | )          | (728 | ) |
| Comprehensive income for 2007                                                                  |       |                  |       |                     |       |                |       |              |       |                   |       | 268,255 |   |
| Common dividends declared to parent                                                            |       |                  |       |                     |       |                |       | (226,812          | )          |                   |       | (226,812 | ) |
| Contribution of capital by parent                                                              |       |                  |       |                     |       | 150,514             |       |              |       |                   |       | 150,514 |   |
| **Balance at Dec. 31, 2007**                                                              |       | 1,000,000             |       | $                        | 10         |                | $          | 1,711,994         |       | $                      | 1,097,357  |   | $ | 6,268 |   | $ | 2,815,629 |   |
|                                                                                           |       |                  |       |                     |       |                |       |              |       |                   |       |   |   |
| EITF 06-4 adoption, 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 $(285) |       |                  |       |                     |       |                |       |              |       | (412                   | )          | (412 | ) |
| Net derivative instrument fair value  changes during the period, net of tax of $(3,901)        |       |                  |       |                     |       |                |       |              |       | (5,651                 | )          | (5,651 | ) |
| 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 |   |

 

See Notes to Consolidated Financial Statements

 

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

 
| ** **                                                                                                         | ** ** | **Dec. 31** | ** ** |
|--------------------------------------------------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                                                         | ** ** | **2008**         | ** ** | **2007** | ** ** |
| **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          |       | — |   |
| 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 |   |
| Senior Notes due Aug. 1, 2009, 6.875%                                                                         |       | 250,000          |       | 250,000 |   |
| Other                                                                                                              |       | 107              |       | 31 |   |
| Unamortized discount                                                                                               |       | (9,258           | )          | (8,822 | ) |
| Total                                                                                                              |       | 2,962,749        |       | 2,463,109 |   |
| Less current maturities                                                                                            |       | 250,060          |       | 31 |   |
| Total long-term debt                                                                                               |       | $                | 2,712,689  |   | $ | 2,463,078 |   |
|                                                                                                               |       |             |       |   |   |
| **Common Stockholder’s Equity**                                                                               |       |             |       |   |   |
| Common stock — authorized 5,000,000 shares  of $0.01 par value; outstanding 1,000,000 shares in 2008 and 2007 |       | $                | 10         |   | $ | 10 |   |
| Additional paid in capital                                                                                         |       | 1,915,857        |       | 1,711,994 |   |
| Retained earnings                                                                                                  |       | 1,149,833        |       | 1,097,357 |   |
| Accumulated other comprehensive income                                                                             |       | 205              |       | 6,268 |   |
| Total common stockholder’s equity                                                                             |       | $                | 3,065,905  |   | $ | 2,815,629 |   |

 

----

(a)  Pollution control financing

 

See Notes toConsolidated Financial Statements

 

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**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

 

**1.Summary of Significant Accounting Policies**

 

***Business and System of Accounts*****— NSP-Minnesota is principally engaged inthe generation, purchase, transmission, distribution and sale of electricityand in the purchase, transportation, distribution and sale of natural gas.  NSP-Minnesota is subject to regulation by theFERC and state utility commissions.  Allof NSP-Minnesota’s accounting records conform to the FERC uniform system ofaccounts or to systems required by various state regulatory commissions, whichare the same in all material respects.

 

***Principles of Consolidation*****— NSP-Minnesota has subsidiaries, whichhave been consolidated and for which all intercompany transactions and balanceshave been eliminated.

 

During 2007, NSP-Minnesota became the sole remaining partner inNMC.  This is the result of the remainingpartner leaving NMC during 2007.  Theexiting company was required to pay an exit fee and surrender its equityinterest in NMC.  NSP-Minnesota owns100 percent of the equity and has a controlling interest in NMC.

 

***Revenue Recognition*****— Revenues related to the sale of energyare generally recorded when service is rendered or energy is delivered tocustomers.  However, the determination ofthe energy sales to individual customers is based on the reading of theirmeter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energydelivered to customers since the date of the last meter reading are estimatedand the corresponding unbilled revenue is estimated.  NSP-Minnesota presents its revenue net of anyexcise or other fiduciary-type taxes or fees.

 

NSP-Minnesotahas various rate-adjustment mechanisms in place that currently provide for therecovery of purchased natural gas and electric fuel and purchased energycosts.  These cost-adjustment tariffs mayincrease or decrease the level of costs recovered through base rates, and arerevised periodically for any difference between the total amount collectedunder the clauses and the recoverable costs incurred.  Where applicable under governing stateregulatory commission rate orders, fuel costs over-recoveries (the excess of fuelrevenue billed to customers over fuel costs incurred) are deferred as currentregulatory liabilities and under-recoveries (the excess of fuel costs incurredover fuel revenues billed to customers) are deferred as current regulatoryassets.  A summary of significant rateadjustment mechanisms follows:

 

·                  NSP-Minnesota’srates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recoverymechanism allowing recovery of the respective costs, which are trued-up on atwo-month and annual basis, respectively. The electric cost-of-fuel-and-purchased-energy mechanism in Minnesotaand North Dakota also provides a sharing among shareholders and customers ofcertain margins on short-term wholesale and commodity trading.

·                  NSP-Minnesotaoperates under various service quality standards, which could require customerrefunds if certain 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-Minnesotasells firm power and energy in wholesale markets, which are regulated by theFERC.  Certain of these rates includemonthly wholesale fuel cost-recovery mechanisms.

 

***Commodity Trading Operations*****— All applicable gains and losses relatedto commodity trading activities, whether or not settled physically, are shownon a net basis in the consolidated statements of income.

 

Pursuant tothe JOA approved by the FERC, some of the commodity trading margins fromNSP-Minnesota are apportioned to PSCo and SPS. Commodity trading activities are not associated with energy producedfrom NSP-Minnesota’s generation assets or energy and capacity purchased toserve native load.  Commodity tradingcontracts are recorded at fair market value in accordance with SFAS No. 133*Accounting for Derivative Instruments andHedging Activities* (SFAS No. 133).  In addition, commodity trading resultsinclude the impact of all margin-sharing mechanisms.  For more information, see Note 10 to theconsolidated financial statements.

 

***Fair Value Measurements******—*********NSP-Minnesota presents cashequivalents, commodity derivatives and nuclear decommissioning fund assets atestimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accruedinterest to approximate fair value. Changes in the observed trading prices and liquidity of cashequivalents, including commercial paper and money market funds, are alsomonitored as additional support for determining fair value, and losses arerecorded in earnings if fair value falls below recorded cost.  For commodity derivatives, the most 

 

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observableinputs available are generally used to determine the fair value of eachcontract.  In the absence of a quotedprice for an identical contract in an active market, NSP-Minnesota may usequoted prices for similar contracts, or internally prepared valuation models asprimary inputs to determine fair value. For the nuclear decommissioning fund, published trading data and pricingmodels, generally using the most observable inputs available, are utilized toestimate fair value for each class of security.

 

***Types of and Accountingfor Derivative Instruments****—*NSP-Minnesota uses derivativeinstruments in connection with its interest rate, utility commodity price,vehicle fuel price, short-term wholesale and commodity trading activities,including forward contracts, futures, swaps and options.  All derivative instruments not designated andqualifying for the normal purchases and normal sales exception, as defined bySFAS No. 133, are recorded on the consolidated balance sheets at fairvalue 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.

 

Gains or losses on hedging transactions for the sales of energy orenergy-related products are primarily recorded as a component of revenue;hedging transactions for fuel used in energy generation are recorded as acomponent of fuel costs; hedging transactions for natural gas purchased forresale are recorded as a component of natural gas costs; vehicle fuel costs arerecorded as a component of capital project 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 hedging relationships are designated as a hedge of a forecastedtransaction or future cash flow (cash flow hedge).  The designation of a cash flow hedge permitschanges in fair value to be recorded within other comprehensive income (OCI),to the extent the hedge is effective, or deferred as a regulatory asset orliability.

 

SFAS No. 133 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 SFAS No. 133.  The documentation includes, among otherfactors, the identification of the hedging instrument and the hedgedtransaction, as well as the risk management objectives and strategies forundertaking the hedging transaction.  Inaddition, at inception and on a quarterly basis, NSP-Minnesota formallyassesses whether the derivative instruments being used are highly effective inoffsetting changes in the cash flows of the hedged items.

 

Changes in the fair value of a derivative designated and qualified as acash flow hedge, to the extent effective are included in OCI, or deferred as aregulatory asset or liability until earnings are affected by the hedgedtransaction.  NSP-Minnesota discontinueshedge accounting prospectively when it has determined that a derivative nolonger qualifies as an effective hedge, or when it is no longer probable thatthe hedged forecasted transaction will occur. To test the effectiveness of hedges, a hypothetical hedge is used tomirror all the critical terms of the hedged transaction and the dollar-offsetmethod is utilized to assess the effectiveness of the actual hedge at inceptionand on an ongoing basis.  Gains andlosses related to discontinued hedges that were previously deferred in OCI ordeferred as regulatory assets or liabilities will remain deferred until thehedged transaction is reflected in earnings, unless it is probable that thehedged forecasted transaction will not occur, in which case, associateddeferred amounts are immediately recognized in current earnings.

 

*Normal Purchases and Normal Sales*— NSP-Minnesota enters into contracts for the purchase and sale of commoditiesfor use in their business operations. SFAS No. 133 requires a company to evaluate these contracts todetermine whether the contracts are derivatives.  Certain contracts that meet the definition ofa derivative may be exempted from SFAS No. 133 as normal purchases ornormal sales.

 

NSP-Minnesota evaluates all of its contracts at inception to determine ifthey are derivatives and, if so, if they qualify to meet the normal purchasesand normal sales designation requirements under SFAS No. 133.  None of the contracts entered into within thecommodity trading operations qualify for a normal purchases and normal salesdesignation.

 

For further discussion of NSP-Minnesota’s risk management andderivative activities, see Note 10 to the consolidated financial statements.

 

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***Property, Plant, and Equipment andDepreciation*****—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-Minnesotarecords depreciation expense related to its plant by using the straight-linemethod over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodicbasis and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions,the resulting lives and net salvage rates are used to calculatedepreciation.  Depreciation expense,expressed as a percentage of average depreciable property, for the years ended Dec. 31,2008, 2007 and 2006 was 3.6 percent, 3.6 percent and 3.9 percent, respectively.

 

***AFDC*****— AFDC represents the cost of capitalused to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualifiedconstruction work in progress.  Theamount of AFDC capitalized as a utility construction cost is credited tononoperating income (for equity capital) and interest charges (for debtcapital).  AFDC amounts capitalized areincluded in NSP-Minnesota’s rate base for establishing utility servicerates.  In addition toconstruction-related amounts, AFDC also is recorded to reflect returns oncapital used to finance conservation programs in Minnesota.

 

Generally AFDC costs are recovered from customers, in future rates, asthe related property is depreciated.  In2003, the MPUC voted to approve NSP-Minnesota’s MERP proposal to convert twocoal-fueled electric generating plants located in the Minneapolis-St. Paulmetropolitan area to natural gas and to install advanced pollution controlequipment at a third coal-fired plant. These improvements are expected to significantly reduce air emissionsfrom these facilities, while increasing 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 June 2008and the remaining projects are expected to begin operations in 2009, at acumulative investment of approximately $1 billion.  The MPUC has approved a more current recoveryof the financing costs related to the MERP. The in-service plant costs, including the financing costs duringconstruction, are recovered from customers through a MERP rider resulting in alower recognition of AFDC.

 

***Decommissioning*****— NSP-Minnesota accounts for the futurecost of decommissioning, or retirement, of its nuclear generating plantsthrough annual depreciation accruals using an annuity approach designed toprovide for full rate recovery of the future decommissioning costs.  The decommissioning calculation covers allexpenses, including decontamination and removal of radioactive material andextends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota will recover those coststhrough rates.  The fair value ofexternal nuclear decommissioning fund investments is determined based on quotedmarket prices for those or similar investments. Unrealized gains or losses on the fund’s assets are included withregulatory assets on the consolidated balance sheets.  For more information on nucleardecommissioning, see Note 15 to the consolidated financial statements.

 

***Nuclear Fuel Expense*****— Nuclear fuel expense, which is recordedas NSP-Minnesota’s nuclear generating plants use fuel, includes the cost offuel used in the current period (including AFDC), as well as future disposalcosts of spent nuclear fuel, costs associated with the end-of-life fuelsegments and fees assessed by the DOE for NSP-Minnesota’s portion of the costof decommissioning the DOE’s fuel enrichment facility.

 

***Nuclear RefuelingOutage Costs* —** Prior to the third quarter of2008, NSP-Minnesota expensed the costs associated with refueling outages asincurred at its nuclear plants.  In September 2008,the MPUC authorized NSP-Minnesota to use a deferral and amortization method forthe nuclear refueling operating and maintenance costs effective Jan. 1,2008.  This method amortizes refuelingoutage costs over the period between refueling outages to better match revenuesand expenses.

 

***Environmental Costs*****— Environmental costs are recorded on anundiscounted basis when it is probable NSP-Minnesota is liable for the costsand the liability can be reasonably estimated. Costs may be deferred as 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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Estimatedremediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, anassessment of the current situation and the technology currently available foruse in the remediation.  The recordedcosts are regularly 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. The depreciation expense levels recoverable in rates include a provisionfor removal expenses, which may include final remediation costs.  Removal costs recovered in rates areclassified as a regulatory liability.

 

***Legal Costs*** —Litigation accruals are recorded when it is probable NSP-Minnesota is liablefor the costs and the liability can be reasonably estimated.  External legal fees related to settlementsare expensed as incurred.

 

***Income Taxes*****— NSP-Minnesota accounts for income taxesusing the asset and liability method under FAS 109, which requires therecognition of deferred tax assets and liabilities for the expected future taxconsequences 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 to turnaround, or reverse.  The effect of achange in tax rates on deferred tax assets and liabilities is recognized inincome in the period that includes the enactment date.  Deferred tax assets are reduced by avaluation allowance if, based on the weight of available evidence, it is morelikely than not that some portion or all of the deferred tax asset will not berealized.  In making such adetermination, all available positive and negative evidence, includingscheduled reversals of deferred tax liabilities, projected future taxableincome, tax planning strategies and recent financial operations, is considered.

 

Due to theeffects of past regulatory practices, when deferred taxes were not required tobe recorded, the reversal of some temporary differences are accounted for ascurrent income tax expense.  Investmenttax credits are deferred and their benefits amortized over the book depreciablelives of the related property.  Utilityrate regulation also has created certain regulatory assets and liabilitiesrelated to income taxes, which are summarized in Note 16 to the consolidatedfinancial statements.  For moreinformation on income taxes, see Note 7 to the consolidated financialstatements.

 

In July 2006, the FASB issued FIN 48, which prescribes how acompany should recognize, measure, present and disclose uncertain tax positionsthat such company has taken or expects to take in its income tax returns.  FIN 48 requires that only income tax benefitsthat meet the “more likely than not” recognition threshold be recognized orcontinue to be recognized on its effective date.  As required, NSP-Minnesota adopted FIN 48 asof Jan. 1, 2007 and the initial derecognition amounts were reported as acumulative effect of a change in accounting principle.  The cumulative effect of the change, whichwas reported as an adjustment to the beginning balance of retained earnings,was not material.  Followingimplementation, the ongoing recognition of changes in measurement of uncertaintax positions will be reflected as a component of income tax expense.

 

NSP-Minnesotareports interest and penalties related to income taxes within the interestcharges section in the consolidated statements of income.

 

Xcel Energyand its subsidiaries, including NSP- Minnesota, file consolidated federalincome tax returns 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.  Xcel Energy makes a similar allocation forstate income taxes paid 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 recording transactions and balancesresulting from business operations, NSP-Minnesota uses estimates based on thebest information available.  Estimatesare used for such items as plant depreciable lives, AROs, decommissioning, taxprovisions, uncollectible amounts, environmental costs, unbilled revenues,jurisdictional fuel and energy cost allocations and actuarially determinedbenefit costs.  The recorded estimatesare revised when better information becomes available or when actual amountscan be determined.  Those revisions canaffect operating results.  Thedepreciable lives of certain plant assets are reviewed annually and revised, ifappropriate.

 

***Cash and Cash Equivalents*****— NSP-Minnesota considers investments incertain instruments, including commercial paper and money market funds, with aremaining maturity of three months or less at the time of purchase, to be cashequivalents.

 

***Restricted Cash***— At Dec. 31, 2007, NSP-Minnesota had restricted cash of $8.4million.  The restricted cash balanceprimarily represents margin deposits held in conjunction with short-termwholesale and commodity trading activities. This balance is presented as a component of other investments on theconsolidated balance sheets.

 

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

 

***Regulatory Accounting*****— NSP-Minnesota accounts for certainincome and expense items in accordance with SFAS No. 71– *Accounting for the Effects of Certain Types ofRegulation*(SFAS No. 71). Under SFAS No. 71:

 

·              Certaincosts, which would otherwise be charged to expense, are deferred as regulatoryassets based 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 ofrecovering deferred costs and returning deferred credits are based on specificratemaking decisions or precedent for each item.  Regulatory assets and liabilities areamortized consistent with the period of expected regulatory treatment.  If restructuring or other changes in theregulatory environment occur, NSP-Minnesota may no longer be eligible to applythis accounting treatment and may be required to eliminate such regulatoryassets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results ofoperations in the period the write-off is recorded.  See more discussion of regulatory assets andliabilities at Note 16 to the consolidated financial statements.

 

***Deferred Financing Costs*****— Other assets include deferred financingcosts, net of amortization, of approximately $21.3 million and $18.2 million atDec. 31, 2008 and 2007, respectively. NSP-Minnesota is amortizing these financing costs over the remainingmaturity periods of the related debt.

 

Debt premiums,discounts, expenses and amounts received or paid to settle hedges are amortizedover the life of the related debt.  Thepremiums and costs associated with refinanced debt are deferred and amortizedover the life of the related new issuance, in accordance with regulatoryguidelines.  If NSP-Minnesotaextinguishes the debt, all unamortized balances shall be expensed at the timeof the redemption.

 

***Accounts Receivable and Allowance for BadDebts*—**Accounts receivable are stated at theactual billed amount 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 (RECs)******—***RECs are******marketable environmental commodities that represent proof that energy wasgenerated from eligible renewable energy sources.  RECs are awarded upon delivery of theassociated energy and can be boughtand sold.  RECs are typically usedas a form of measurement of compliance to Renewable Portfolio Standards (RPS)enacted by those states that are encouraging construction and consumption ofrenewable energy, but can also be sold separately from the energyproduced.  Currently, NSP-Minnesotaacquires RECs from the generation or purchase of renewable power.

 

***WhenRECs are acquired in the course of generation or purchase as a result ofmeeting the load obligation, they are recorded as inventory at actualcost.  RECs acquired for trading purposesare recorded as other investments at actual 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, including the annual SO2 and NOx emission allowance entitlementreceived at no cost from the EPA. NSP-Minnesota follows the inventory accounting model for allallowances.  The sales of allowances arereported in the operating activities section of the consolidated statements ofcash flows.  The net margin on sales ofemission allowances is included in electric utility operating revenues as it isintegral to the production process of energy and our revenue optimizationstrategy for our utility operations.

 

***Reclassifications*—**Conservationprogram expenses were reclassified asa separate item from other operating and maintenance expenses on the consolidated statements of income.  Activityfrom the allowance for bad debts was reclassified from the change in accountsreceivable on the consolidated statements of cash flows. Thesereclassifications did not have an impact on total operating expenses or net cash provided by operating activities.

 

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**2.**             Accounting Pronouncements

** **

***RecentlyIssued***

** **

***BusinessCombinations (SFAS No. 141 (revised 2007)) —***InDecember 2007, the FASB issued SFAS No. 141R, 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. SFAS No. 141R 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 will apply SFAS No. 141Rto business combinations occurring subsequent to Jan. 1, 2009.

 

***NoncontrollingInterests in Consolidated Financial Statements, an Amendment of ARB No. 51(SFAS No. 160) —***In December 2007,the FASB issued SFAS No. 160, which establishes accounting and reportingstandards that require the ownership interest in subsidiaries held by partiesother than the parent be clearly identified and presented in the consolidatedbalance sheets within equity, but separate from the parent’s equity; the amountof consolidated net income attributable to the parent and the noncontrollinginterest be clearly identified and presented on the face of the consolidatedstatement of earnings; and changes in a parent’s ownership interest while theparent retains its controlling financial interest in its subsidiary beaccounted for consistently as equity transactions. This statement is effectivefor fiscal years and interim periods beginning on or after Dec. 15,2008.  NSP-Minnesota does not expect theimplementation of SFAS No. 160 to have a material impact on itsconsolidated financial statements.

 

***Disclosures about Derivative Instruments andHedging Activities, an Amendment of FASB Statement No. 133 (SFAS No. 161)—***In March 2008,the FASB issued SFAS No. 161, which is intended to enhance disclosures tohelp users of the financial statements better understand how derivativeinstruments and hedging activities affect an entity’s financial position,financial performance and cash flows. SFAS No. 161 amends and expands the disclosure requirements of SFASNo. 133, *Accounting for DerivativeInstruments and Hedging Activities*, to require disclosures ofobjectives and strategies for using derivatives, gains and losses on derivativeinstruments, and credit-risk-related contingent features in derivativeagreements.  SFAS No. 161 iseffective for fiscal years and interim periods beginning after Nov. 15,2008, with early application encouraged. NSP-Minnesota does not expect the implementation of SFAS No. 161 tohave a material impact on its consolidated financial statements.

 

***Employers’ Disclosures about PostretirementBenefit Plan Assets (FSP FAS 132(R)-1) —***In December 2008, the FASB issued FSPFAS 132(R)-1, which amends SFAS No. 132 (revised 2003), *Employers’ Disclosures about Pensions and OtherPostretirement Benefits,*to expand on an employer’s requireddisclosures about plan assets of a defined benefit pension or otherpostretirement plan to include investment policies and strategies, majorcategories of plan assets, information regarding fair value measurements, andsignificant concentrations of credit risk. FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15,2009.  NSP-Minnesota does not expect thatimplementation of FSP FAS 132(R)-1 to have a material impact on itsconsolidated financial statements.

 

***RecentlyAdopted***

** **

***Fair ValueMeasurements (SFAS No. 157) —***In September 2006,the FASB issued SFAS No. 157, which provides a single definition of fairvalue, together with a framework for measuring it, and requires additionaldisclosure about the use of fair value to measure assets and liabilities.  SFAS No. 157 also emphasizes that fairvalue is a market-based measurement, and sets out a fair value hierarchy withthe highest priority being quoted prices in active markets.  Fair value measurements are disclosed bylevel within that hierarchy.  SFAS No. 157was effective for financial statements issued for fiscal years beginning after Nov. 15,2007.

 

On Jan. 1, 2008, NSP-Minnesota adopted SFAS No. 157 for allassets and liabilities measured at fair value except for non-financial assetsand non-financial liabilities measured at fair value on a non-recurring basis,as permitted by FSP FAS 157-2, *EffectiveDate of FASB Statement No. 157*. The adoption did not have a material impact on NSP-Minnesota’sconsolidated financial statements.  Foradditional discussion and SFAS No. 157 required disclosures, see Note 12to the consolidated financial statements.

 

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***The Fair ValueOption for Financial Assets and Financial Liabilities — Including anAmendment of FASB Statement No. 115 (SFAS No. 159)*** —In February 2007, the FASB issued SFAS No. 159, which providescompanies with an option to measure, at specified election dates, manyfinancial instruments and certain other items at fair value that are notcurrently measured at fair value.  Acompany that adopts SFAS No. 159 will report unrealized gains and losseson items for which the fair value option has been elected in earnings at eachsubsequent reporting date.  Thisstatement also establishes presentation and disclosure requirements designed tofacilitate comparisons between entities that choose different measurementattributes for similar types of assets and liabilities.  This statement was effective for fiscal yearsbeginning after Nov. 15, 2007. NSP-Minnesota adopted SFAS No. 159 on Jan. 1, 2008, and theadoption did not have a material impact on its consolidated financialstatements.

 

***Determining the Fair Value of a FinancialAsset When the Market for That Asset is Not Active  (FSP FAS 157-3)*** — In October 2008, the FASB issued FSPFAS 157-3, which clarifies the application of SFAS No. 157 in a marketthat is not active.  FSP FAS 157-3 waseffective immediately upon issuance, and applied to prior periods for whichfinancial statements had not yet been issued. NSP-Minnesota adopted FSP FAS 157-3 as of Sept. 30, 2008, and theadoption did not have a material impact on its consolidated financialstatements.

 

***Accounting for Deferred Compensation andPostretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements(Emerging Issues Task Force (EITF) Issue No. 06-4)*****—**In June 2006, the EITF reached aconsensus on EITF No. 06-4, which provides guidance on the recognition ofa liability and related compensation costs for endorsement split-dollar lifeinsurance policies that provide a benefit to an employee that extends topostretirement periods.  Therefore, thisEITF would not apply to a split-dollar life insurance arrangement that providesa specified benefit to an employee that is limited to the employee’s activeservice period with an employer.  EITF No. 06-4was effective for fiscal years beginning after Dec. 15, 2007, with earlierapplication permitted.  Upon adoption ofEITF No. 06-4 on Jan. 1, 2008, NSP-Minnesota recorded a liability of$0.6 million, net of tax, as a reduction of retained earnings.  Thereafter, changes in the liability arereflected in operating results.

 

***Amendment of FASBInterpretation No. 39 (FSP FIN 39-1) —***InApril 2007, the FASB issued FSP FIN 39-1, which amends FIN 39, *Offsetting of Amounts Related to Certain Contracts*,to permit companies to offset fair value amounts recognized for the right toreclaim cash collateral (a receivable) or the obligation to return cash collateral(a payable) against fair value amounts recognized for derivative instrumentsexecuted with the same counterparty under a master netting arrangement.  FSP FIN 39-1 was effective for fiscal yearsbeginning after Nov. 15, 2007. NSP-Minnesota adopted FSP FIN 39-1 on Jan. 1, 2008, and theadoption did not have a material impact on its consolidated financialstatements.

 

***Accounting for Income Tax Benefits ofDividends on Share-Based Payment Awards (EITF No. 06-11) —***In June 2007, the EITF reached a consensuson EITF No. 06-11, which states that an entity should recognize a realizedtax benefit associated with dividends on nonvested equity shares and nonvestedequity share units charged to retained earnings as an increase in additionalpaid in capital.  The amount recognizedin additional paid in capital should be included in the pool of excess taxbenefits available to absorb potential future tax deficiencies on share-basedpayment awards.  EITF No. 06-11 wasto be applied prospectively to income tax benefits of dividends onequity-classified share-based payment awards that were declared in fiscal yearsbeginning after Dec. 15, 2007. NSP-Minnesota adopted EITF No. 06-11 on Jan. 1, 2008, and theadoption did not have a material impact on its consolidated financialstatements.

 

***The Hierarchy of GAAP (SFAS No. 162) —***In May 2008,the FASB issued SFAS No. 162, which establishes the GAAP hierarchy,identifying the sources of accounting principles and the framework forselecting the principles to be used in the preparation of financialstatements.  SFAS No. 162 waseffective Nov. 15, 2008*. *NSP-Minnesota adopted SFAS No. 162on Dec. 31, 2008, and the adoption did not have a material impact on itsconsolidated financial statements.

 

***Disclosures by Public Entities (Enterprises)about Transfers of Financial Assets and Interests in Variable Interest Entities(FSP FAS 140-4 and FIN 46(R)-8)******—***InDecember 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, which amends******SFAS No. 140***,****Accounting for Transfers and Servicing of FinancialAssets and Extinguishments of Liabilities,*to require publicentities to provide additional disclosures about transfers of financialassets.  It also amends FIN 46 (revised December 2003),*Consolidation of Variable Interest Entities,*to require public enterprises, including sponsors that have avariable interest in a variable interest entity, to provide additionaldisclosures about their involvement with variable interest entities.  FSP FAS 140-4 and FIN 46(R)-8 was effectivefor the interim and annual periods ending after Dec. 15, 2008.  NSP-Minnesota adopted FSP FAS 140-4 and FIN46(R)-8 on Dec. 31, 2008, and the adoption did not have a material impacton its consolidated financial statements.

 

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**3.****              Selected BalanceSheet Data**

 
| **(Thousands of Dollars)** | ** ** | **Dec. 31, 2008** | ** ** | **Dec. 31, 2007** | ** ** |
|--------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
|                                 |       |                        |       |                        |       |
| Accounts receivable, net:            |       |                        |       |                        |       |
| Accounts receivable                  |       | $                           | 438,855    |                        | $          | 462,033 |   |
| Less allowance for bad debts         |       | (25,699                     | )          | (20,103                     | )          |
|                                 |       | $                           | 413,156    |                        | $          | 441,930 |   |
|                                 |       |                        |       |                        |       |
| Inventories:                         |       |                        |       |                        |       |
| Materials and supplies               |       | $                           | 97,945     |                        | $          | 93,853 |   |
| Fuel                                 |       | 141,190                     |       | 77,257                      |       |
| Natural gas                          |       | 106,768                     |       | 99,528                      |       |
|                                 |       | $                           | 345,903    |                        | $          | 270,638 |   |
|                                 |       |                        |       |                        |       |
| Property, plant and equipment, net:  |       |                        |       |                        |       |
| Electric utility plant               |       | $                           | 9,472,073  |                        | $          | 8,855,144 |   |
| Natural gas utility plant            |       | 916,740                     |       | 890,371                     |       |
| Construction work in progress        |       | 615,734                     |       | 818,276                     |       |
| Common utility and other property    |       | 452,308                     |       | 447,527                     |       |
| Total property, plant and equipment  |       | 11,456,855                  |       | 11,011,318                  |       |
| Less accumulated depreciation        |       | (4,907,681                  | )          | (4,708,496                  | )          |
| Nuclear fuel                         |       | 1,611,193                   |       | 1,471,229                   |       |
| Less accumulated amortization        |       | (1,355,573                  | )          | (1,291,370                  | )          |
|                                 |       | $                           | 6,804,794  |                        | $          | 6,482,681 |   |

 

**4.**             Short-Term Borrowings

** **

***Commercial Paper*****— At Dec. 31, 2008 and 2007,NSP-Minnesota had commercial paper outstanding of $65.0 million and $341.5million, respectively.  NSP-Minnesota hasboard approval to issue up to $500 million of commercial paper.  The weighted average interest rates at Dec. 31,2008 and 2007, were 2.57 percent and 5.58 percent, respectively.

 

***Money Pool*****— Xcel Energy and its utilitysubsidiaries have established a utility money pool arrangement that allows forshort-term loans between the utility subsidiaries and from the holding companyto the utility subsidiaries at market-based interest rates.  The utility money pool arrangement does notallow loans from the utility subsidiaries to the holding company.  NSP-Minnesota has approval to borrow up to$250 million under the arrangement.  At Dec. 31,2008 and 2007, NSP-Minnesota had money pool borrowings of $63.5 million and$95.1 million, respectively.  Theweighted average interest rates at Dec. 31, 2008 and 2007, were 3.48percent and 5.64 percent, respectively.

 

**5.**             Long-Term Debt

** **

***Credit Facilities***—At Dec. 31, 2008, NSP-Minnesota had the following committed creditfacility in effect, in millions of dollars:

 
| **Credit  Facility** | ** ** | **Credit Facility  Borrowings** | ** ** | **Available*** | ** ** | **Original  Term** | ** ** | **Maturity** | ** ** |
|----------------------|------------|--------------------------------------|------------|----------------|------------|--------------------|------------|--------------|------------|
| $                    | 482.2      |                                 | $          | —         |       | $                  | 411.4      |         | Five year  |   | December 2011 |   |
|                      |            |                                      |            |                |            |                    |            |              |            |  |  |  |

 

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

 

The line of credit provides short-term financing in the form of notespayable to banks, letters of credit and back-up support for commercial paperborrowings.  NSP-Minnesota has the rightto request an extension of the final maturity date by one year.  The maturity extension is subject to majoritybank group approval.

 

·                  The credit facility has one financialcovenant requiring that NSP-Minnesota’s debt-to-total capitalization ratio beless than or equal to 65 percent with which NSP-Minnesota was in compliance at Dec. 31,2008 and 2007.  If NSP-Minnesota 

 

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does not comply with thecovenant, it is deemed an event of default and any outstanding amounts dueunder the facility can be declared due by the lender.

 

·                  The credit facility has a 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 eitherthe agent 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.  The commitment fees arecalculated for the unused portion of the credit facility at 6 basis points forNSP-Minnesota.

 

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

 

·                  AtDec. 31, 2007, NSP-Minnesota had no direct borrowings on this line ofcredit; however, the credit facility was used to provide back-up support for$341.5 million of commercial paper outstanding and $6.1 million of letters ofcredit.

 

***Long-Term Borrowings***

*** ***

On March 18, 2008, NSP-Minnesota issued $500 million of 5.25percent first 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.

 

On Aug. 1, 2007, NSP-Minnesota redeemed all of its outstanding8.00 percent Notes, series due 2042, at a redemption price equal to100 percent of the principal amount of the notes ($25.00), plus accruedand unpaid interest on the notes, if any, to the redemption date.  Upon redemption, Xcel Energy recognized approximately$9.3 million in interest expense due to unwinding a fair value interestrate derivative.

 

On June 26, 2007, NSP-Minnesota issued $350 million of6.20 percent first mortgage bonds, series due July 1, 2037.  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.

 

All property of NSP-Minnesota is subject to the lien of its firstmortgage indenture.  NSP-Minnesota’sfirst mortgage indenture places certain restrictions on the amount of cashdividends it can pay Xcel Energy, the holder of its common stock.  Even with these restrictions, NSP-Minnesotacould have paid more than $999 million and $946 million in additional cashdividends on common stock at Dec. 31, 2008 and 2007, respectively.

 

Maturities of long-term debt are:

 
| **(Millions of Dollars)** | ** ** | ** ** | ** ** |
|-------------------------------------|------------|------------|------------|
| 2009                                |       | $          | 250.1      |   |
| 2010                                |       | 175.0      |       |
| 2011                                |       | —     |       |
| 2012                                |       | 450.0      |       |
| 2013                                |       | —     |       |
|                                     |            |            |            |  |

** **

**6.**             Joint PlantOwnership

** **

Following arethe investments by NSP-Minnesota in jointly owned plants and the relatedownership percentages as of Dec. 31, 2008:

 
| **(Thousands of Dollars)**              | ** ** | **Plant in  Service** | ** ** | **Accumulated  Depreciation** | ** ** | **Construction  Work in  Progress** | ** ** | **Ownership%** | ** ** |
|---------------------------------------------------|------------|----------------------------|------------|-------------------------------|------------|------------------------------------------|------------|----------------|------------|
| Sherco Unit 3                                     |       | $                          | 527,647    |                          | $          | 325,472                                  |       | $              | 128        |   | 59.0 |   |
| Sherco Common Facilities Units 1,  2 & 3 |       | 122,812                    |       | 73,779                        |       | 180                                      |       | 75.0           |       |
| Transmission facilities, including  substations   |       | 4,790                      |       | 2,231                         |       | —                                   |       | 59.0           |       |
| Total                                             |       | $                          | 655,249    |                          | $          | 401,482                                  |       | $              | 308        |   |   |   |

 

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NSP-Minnesota is part owner of Sherco 3, an 860 MW, coal-fueledelectric generating unit.  NSP-Minnesotais the operating agent under the joint ownership agreement.  NSP-Minnesota’s share of operating expensesand construction expenditures are included in the applicable utilityaccounts.  Each of the respective ownersis responsible for funding its portion of construction and operating costs.

 

***Nuclear PlantOperation —*** On Sept. 28, 2007, NSP-Minnesotaobtained 100 percent ownership in NMC as a result of Wisconsin EnergyCorporation (WEC), exiting the partnership due to the sale of its Point BeachNuclear Plant to FPL Energy.  Accordingly,the results of operations of NMC and the estimated fair value of assets andliabilities were included in NSP-Minnesota’s consolidated financial statementsfrom the Sept. 28, 2007, transaction date. WEC was required to pay an exit fee and surrender all of its equityinterest in NMC upon exiting.  The effectof this transaction was not material to the financial position or the resultsof operations to NSP-Minnesota for the year ended Dec. 31, 2007.  NSP-Minnesota has reintegrated its nuclearoperations into its generation operations. The NRC transferred the nuclearoperating licenses from NMC to NSP-Minnesota effective Sept. 22, 2008.

 

**7.**             Income Taxes

** **

***Accounting forUncertainty in Income Taxes — an interpretation of FASB Statement No. 109(FIN 48)*** — NSP-Minnesota is a member of theXcel Energy affiliated group that files consolidated income tax returns.  In the first quarter of 2008, theIRS completed an examination of Xcel Energy’s federal income tax returns for2004 and 2005 (and research credits for 2003). The IRS did not propose any material adjustments for those taxyears.  Tax year 2004 is the earliestopen year and the statute of limitations applicable to Xcel Energy’s 2004federal income tax return remains open until Dec. 31, 2009.  In the third quarter of 2008, the IRScommenced an examination of tax years 2006 and 2007.  As of Dec. 31, 2008, the IRS had notproposed any material adjustments to tax years 2006 and 2007.

 

In the first quarter of 2008, thestate of Minnesota concluded an income tax audit through tax year 2001. No material adjustments were proposed for this audit.  As of Dec. 31, 2008, NSP-Minnesota’searliest open tax year in which an audit can be initiated by state taxingauthorities under applicable statutes of limitations is 2004.  There currently are no state income taxaudits in progress.

 

The amountof unrecognized tax benefits reported was $14.3 million and $20.2 million on Dec. 31,2007 and 2008, respectively.  A reconciliation of the beginning and endingamount of unrecognized tax benefit is as follows:

 
| **(Millions of Dollars)**                            | ** ** | **2008** | ** ** | **2007** | ** ** |
|----------------------------------------------------------------|------------|----------|------------|----------|------------|
| Balance at  Jan. 1                                        |       | $        | 14.3       |     | $          | 22.5 |   |
| Additions based  on tax positions related to the current year  |       | 5.4      |       | 5.6      |       |
| Reductions based  on tax positions related to the current year |       | (0.4     | )          | (0.2     | )          |
| Additions for tax  positions of prior years                    |       | 4.9      |       | 8.4      |       |
| Reductions for  tax positions of prior years                   |       | —   |       | (3.4     | )          |
| Settlements with  taxing authorities                           |       | (4.0     | )          | (18.6    | )          |
| Balance at Dec. 31                                        |       | $        | 20.2       |     | $          | 14.3 |   |

 

These unrecognized tax benefitamounts were reduced by the tax benefits associated with tax credit carryoversof $2.2 million and $4.4 million as of Dec. 31, 2007 and 2008,respectively.

 

The unrecognized tax benefitbalance included $6.6 million and $7.2 million of tax positions on Dec. 31,2007 and 2008, respectively, which if recognized would affect the annualeffective tax rate.  In addition, the unrecognized tax benefit balanceincluded $7.7 million and $13.0 million of tax positions on Dec. 31, 2007and 2008, respectively, for which the ultimate deductibility is highly certainbut 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 increase in the unrecognizedtax benefit balance of $5.9 million from Dec. 31, 2007 to Dec. 31,2008, was due to the addition of similar uncertain tax positions related toongoing activity.  NSP-Minnesota’s amountof unrecognized tax benefits could significantly change in the next 12 monthsas the IRS audit progresses and when state audits resume.  At this time,due to the uncertain nature of the audit process, it is not reasonably possibleto estimate an overall range of possible change.

 

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The liability forinterest related to unrecognized tax benefits is partially offset by theinterest benefit associated with tax credit carryovers.  The amount of interestincome related to unrecognized tax benefits reported within interest chargeswas $0.6 million for both 2007 and 2008.  The liability for interestrelated to unrecognized tax benefits was $1.9 million and $1.3 million on Dec. 31,2007 and 2008, respectively.  No amountswere accrued for penalties as of Dec. 31, 2007 and 2008.

 

***Other Income TaxMatters****—*****NSP-Minnesota’s federal netoperating loss carryforward is estimated to be $22.1 million and $20.6 millionas of Dec. 31, 2008 and Dec. 31, 2007, respectively.  NSP-Minnesota’s federal tax creditcarryforward is estimated to be $14.8 million and $11.9 million as of Dec. 31,2008 and Dec. 31, 2007, respectively. The carryforward periods expire between 2021 and 2028.  NSP-Minnesota also has state tax creditcarryforwards of $1.6 million and $1.3 million as of Dec. 31, 2008 and Dec. 31,2007, respectively.  The statecarryforward periods expire between 2018 and 2027.

 

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

 
| ** **                                                 | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal statutory rate                                     |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases (decreases) in tax from:                         |       |     |       |     |       |     |       |
| State income taxes, net of federal income  tax benefit     |       | 7.6      |       | 8.4      |       | 3.6      |       |
| Resolution of income tax audits and other                  |       | —   |       | 0.4      |       | (2.5     | )          |
| Tax credits recognized, net of federal  income tax expense |       | (1.6     | )          | (1.5     | )          | (2.0     | )          |
| Regulatory differences — utility plant  items         |       | (2.3     | )          | (1.7     | )          | (1.6     | )          |
| Life insurance policies                                    |       | (0.2     | )          | (0.2     | )          | (0.2     | )          |
| FIN 48 expense – unrecognized tax benefits            |       | 0.1      |       | 0.2      |       | —   |       |
| Other, net                                                 |       | (0.1     | )          | (0.1     | )          | (0.4     | )          |
| Effective income tax rate                                  |       | 38.5     | %          | 40.5     | %          | 31.9     | %          |

 

The componentsof income tax expense for the years ending Dec. 31 were:

 
| **(Thousands of Dollars)**   | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current federal tax expense            |       | $        | 9,527      |     | $          | 15,277   |       | $ | 178,668 |   |
| Current state tax expense              |       | 27,802   |       | 4,987    |       | 37,145   |       |
| Current FIN 48 tax expense (benefit)   |       | 3,709    |       | (6,346   | )          | —   |       |
| Deferred federal tax expense (benefit) |       | 122,485  |       | 117,433  |       | (66,226  | )          |
| Deferred state tax expense (benefit)   |       | 25,653   |       | 50,151   |       | (13,752  | )          |
| Deferred FIN 48 tax (benefit) expense  |       | (3,106   | )          | 7,416    |       | —   |       |
| Deferred tax credits                   |       | (4,331   | )          | (2,996   | )          | (3,383   | )          |
| Deferred investment tax credits        |       | (3,503   | )          | (3,897   | )          | (4,846   | )          |
| Total income tax expense               |       | $        | 178,236    |     | $          | 182,025  |       | $ | 127,606 |   |

 

The componentsof deferred income tax at Dec. 31 were:

 
| **(Thousands of Dollars)**                                                                           | ** ** | **2008** | ** ** | **2007** | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax expense excluding items below                                                                     |       | $        | 80,493     |     | $          | 185,214 |   |
| Amortization and adjustments to deferred  income taxes on income tax regulatory assets and liabilities         |       | 55,322   |       | (26,444  | )          |
| FIN 48 adoption: Deferred tax expense  reported as an adjustment to the beginning balance of retained earnings |       | —   |       | 13,981   |       |
| Tax expense (benefit) allocated to other  comprehensive income and other                                       |       | 4,886    |       | (747     | )          |
| Deferred tax expense                                                                                           |       | $        | 140,701    |     | $          | 172,004 |   |

 

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

 
| **(Thousands of Dollars)**                | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax liabilities:                           |       |     |       |     |       |
| Differences between book and tax bases of  property |       | $        | 1,003,706  |     | $          | 905,225 |   |
| Regulatory assets                                   |       | 81,411   |       | 74,831   |       |
| Deferred costs                                      |       | 9,211    |       | 14,135   |       |
| Unbilled revenues                                   |       | 6,342    |       | 9,934    |       |
| Other                                               |       | 17,083   |       | 19,079   |       |
| Total deferred tax liabilities                      |       | $        | 1,117,753  |     | $          | 1,023,204 |   |
|                                                |       |     |       |     |       |
| Deferred tax assets:                                |       |     |       |     |       |
| Employee benefits                                   |       | $        | 62,410     |     | $          | 71,314 |   |
| Deferred investment tax credits                     |       | 16,443   |       | 17,872   |       |
| Regulatory liabilities                              |       | 12,927   |       | 15,013   |       |
| Tax credit carry forward                            |       | 16,392   |       | 13,141   |       |
| Bad debts                                           |       | 10,497   |       | 8,211    |       |
| Rate refund                                         |       | 19,144   |       | 6,710    |       |
| Net operating loss carry forward                    |       | 6,790    |       | 3,358    |       |
| Other                                               |       | 11,198   |       | 6,126    |       |
| Total deferred tax assets                           |       | $        | 155,801    |     | $          | 141,745 |   |
| Net deferred tax liability                          |       | $        | 961,952    |     | $          | 881,459 |   |

 

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

** **

Pension and other postretirement benefit disclosures below generallyrepresent Xcel Energy consolidated information unless specifically identifiedas being attributable to NSP-Minnesota.

 

Xcel Energy offers various benefit plans to its employees, includingthose of NSP-Minnesota.  Approximately 50percent of Xcel Energy employees that receive benefits are represented byseveral local labor unions under several collective-bargaining agreements.  At Dec. 31, 2008, NSP-Minnesota had2,279 bargaining employees covered under a collective-bargaining agreement,which expires at the end of 2010. NSP-Minnesota also had an additional 209 nuclear operation bargainingemployees covered under several collective-bargaining agreements, whichexpire at various dates through September 2010.

 

***Employers’Accounting for Defined Benefit Pension and Other Postretirement Plans — anamendment of FASB Statements No. 87, 88, 106 and 132(R) (SFAS No. 158)—*** In September 2006, the FASB issued SFAS No. 158,which requires companies to fully recognize the funded status of each pensionand other postretirement benefit plan as a liability or asset on their balancesheets with all unrecognized amounts to be recorded in other comprehensiveincome.  NSP-Minnesota applied regulatoryaccounting treatment for unrecognized amounts of regulated utility subsidiaryemployees, which allowed recognition as a regulatory liability reduction ratherthan as a charge to accumulated other comprehensive income.  The effect of adopting in 2006 for theremaining unrecognized amounts was a decrease in accumulated othercomprehensive income of $3.2 million.

 

**Pension Benefits**

** **

Xcel Energy has several noncontributory, defined benefit pension plansthat cover almost all employees. Benefits are based on a combination of years of service, the employee’saverage pay and Social Security benefits.

 

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

 

***Pension Plan Assets*—**Plan assets principally consist of the common stock of public companies,corporate bonds and U.S. government securities. The target range for our pension asset allocation is 52 percent inequity investments, 25 percent in fixed income investments and 23 percent innontraditional investments, such as real estate, private equity and adiversified commodities index.

 

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

 
| ** **                 | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|----------------------------|------------|------------|------------|------------|------------|
| ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Equity securities          |       | 55         | %          | 60         | %          |
| Debt securities            |       | 26         |       | 22         |       |
| Real estate                |       | 5          |       | 4          |       |
| Cash                       |       | 3          |       | 2          |       |
| Nontraditional investments |       | 11         |       | 12         |       |
|                       |       | 100        | %          | 100        | %          |

 

Xcel Energy bases its investment-return assumption on expectedlong-term performance for each of the investment types included in its pensionasset portfolio.  Xcel Energy considersthe actual historical returns achieved by its asset portfolio over the past20-year or longer period, as well as the long-term return levels projected andrecommended by investment experts.  Thehistorical weighted average annual return for the past 20 years for theXcel Energy portfolio of pension investments is 9.56 percent, which isgreater than the current assumption level. The pension cost determination assumes the continued current mix ofinvestment types over the long term.  TheXcel Energy portfolio is heavily weighted toward equity securities and includesnontraditional investments.  A higherweighting in equity investments can increase the volatility in the returnlevels achieved by pension assets in any year. Investment returns in 2008 and 2007 were below the assumed level of8.75 percent while returns in 2006 exceeded the assumed level of8.75 percent.  Xcel Energycontinually reviews its pension assumptions. In 2009, Xcel Energy will use an investment-return assumption of8.50 percent.

 

***Benefit Obligations***—A comparison of the actuarially computed pension benefit obligation and planassets, on a combined basis, is presented in the following table:

 
| **(Thousands of Dollars)**                           | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|----------------------------------------------------------------|------------|------------|------------|------------|------------|
| **Accumulated Benefit Obligation at  Dec. 31**            |       | $          | 2,435,513  |       | $          | 2,497,898 |   |
|                                                           |       |       |       |       |       |
| **Change in Projected Benefit Obligation:**                    |       |       |       |       |       |
| Obligation at Jan. 1                                      |       | $          | 2,662,759  |       | $          | 2,666,555 |   |
| Service cost                                                   |       | 62,698     |       | 61,392     |       |
| Interest cost                                                  |       | 167,881    |       | 162,774    |       |
| Plan amendments                                                |       | —     |       | (19,955    | )          |
| Actuarial (gain) loss                                          |       | (47,509    | )          | 23,325     |       |
| Benefit payments                                               |       | (247,797   | )          | (231,332   | )          |
| Obligation at Dec. 31                                     |       | $          | 2,598,032  |       | $          | 2,662,759 |   |
| ** **                                                     | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Change in Fair Value of Plan Assets:**                       |       |       |       |       |       |
| Fair value of plan assets at Jan. 1                       |       | $          | 3,186,273  |       | $          | 3,183,375 |   |
| Actual (loss) return on plan assets                            |       | (788,273   | )          | 199,230    |       |
| Employer contributions                                         |       | 35,000     |       | 35,000     |       |
| Benefit payments                                               |       | (247,797   | )          | (231,332   | )          |
| Fair value of plan assets at Dec. 31                      |       | $          | 2,185,203  |       | $          | 3,186,273 |   |
|                                                           |       |       |       |       |       |
| **Funded Status of Plans at Dec. 31:**                    |       |       |       |       |       |
| Funded Status                                                  |       | $          | (412,829   | )          | $          | 523,514 |   |
| Noncurrent assets                                              |       | 15,612     |       | 568,055    |       |
| Noncurrent liabilities                                         |       | (428,441   | )          | (44,541    | )          |
| Net pension amounts recognized on  consolidated balance sheets |       | $          | (412,829   | )          | $          | 523,514 |   |
|                                                           |       |       |       |       |       |
| NSP-Minnesota accrued benefit liability  recorded              |       | $          | 91,095     |       | $          | — |   |
| NSP-Minnesota prepaid pension asset  recorded                  |       | —     |       | 270,436    |       |

 

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| **(Thousands of Dollars)**                                                                | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| **NSP-Minnesota Amounts Not Yet Recognized as  Components of Net Periodic Benefit Cost:**           |       |     |       |     |       |
| Net loss                                                                                            |       | $        | 454,770    |     | $          | 72,479 |   |
| Prior service cost                                                                                  |       | 46,222   |       | 57,948   |       |
| Total                                                                                               |       | $        | 500,992    |     | $          | 130,427 |   |
|                                                                                                |       |     |       |     |       |
| **SFAS No. 158 Amounts Have Been  Recorded as Follows Based Upon Expected Recovery in Rates:** |       |     |       |     |       |
| Regulatory assets                                                                                   |       | $        | 500,992    |     | $          | — |   |
| Regulatory liabilities                                                                              |       | —   |       | 130,427  |       |
| Total                                                                                               |       | $        | 500,992    |     | $          | 130,427 |   |

 
| **Measurement Date**                                         | ** ** | **Dec. 31, 2008** | ** ** | **Dec. 31, 2007** | ** ** |
|-------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
|                                                              |       |                        |       |                        |       |
| **Significant Assumptions Used to Measure  Benefit Obligations:** |       |                        |       |                        |       |   |   |
| Discount rate for year-end valuation                              |       |                        | 6.75       | %                           |       | 6.25 | % |
| Expected average long-term increase in  compensation level        |       |                        | 4.00       |                        |       | 4.00 |   |
| Mortality table                                                   |       | RP                          | 2000       |                        | RP         | 2000 |   |

 

At Dec. 31, 2008, one of Xcel Energy’s pension plans had planassets of $259.9 million, which exceeded projected benefit obligations of$244.3 million.  At Dec. 31,2007, the plan assets of $369.8 million exceeded projected benefitobligations of $253.6 million.  Allother Xcel Energy plans in the aggregate had plan assets of $1.9 billion and$2.8 billion and projected benefit obligations of $2.4 billion and$2.4 billion on Dec. 31, 2008 and 2007.

 

***Cash Flows —***Cashfunding requirements can be impacted by changes to actuarial assumptions,actual asset levels and other calculations prescribed by the fundingrequirements of income tax and other pension-related regulations.  These regulations did not require cashfunding for 2006 through 2008 for Xcel Energy’s pension plans and are notexpected to require cash funding in 2009.

 

·                  Voluntarycontributions were made to the PSCo Bargaining Pension Plan of $35 million in2008, $35 million in 2007 and $30 million in 2006.

·                  Voluntarycontributions were made to the NCE Non-Bargaining Pension Plan of$2 million in 2006.  No voluntarycontributions were made to the plan during 2007 or 2008.

·                  XcelEnergy projects cash funding of $70 million to $130 million in 2009.  Pension funding contributions for 2010, whichwill be dependent on several factors including, realized asset performance,future discount rate, IRS and legislative initiatives as well as otheractuarial assumptions, are estimated to range between $150 million to $250million.

 

***Plan Changes —***ThePension Protection Act of 2006 (PPA) was effective Dec. 31, 2006.  PPA requires a change in the conversion basisfor lump-sum payments and three-year vesting for plans with account balance orpension equity benefits.  These changesare reflected as a plan amendment for purposes of SFAS No. 87, *Employers’ Accounting for Pensions*.

 

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

 
| **(Thousands of Dollars)**                       | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service cost                                               |       | $        | 62,698     |     | $          | 61,392   |       | $ | 61,627 |   |
| Interest cost                                              |       | 167,881  |       | 162,774  |       | 155,413  |       |
| Expected return on plan assets                             |       | (274,338 | )          | (264,831 | )          | (268,065 | )          |
| Amortization of prior service cost                         |       | 20,584   |       | 25,056   |       | 29,696   |       |
| Amortization of net loss                                   |       | 11,156   |       | 15,845   |       | 17,353   |       |
| Net periodic pension (credit) cost under  SFAS No. 87 |       | $        | (12,019    | )        | $          | 236      |       | $ | (3,976 | ) |
|                                                       |       |     |       |     |       |     |       |
| **NSP-Minnesota:**                                         |       |     |       |     |       |     |       |
| Net periodic pension credit                                |       | $        | (9,034     | )        | $          | (9,682   | )          | $ | (11,373 | ) |
| Credits not recognized due to effects of  regulation       |       | 9,034    |       | 11,147   |       | 12,637   |       |
| Net benefit cost recognized for financial  reporting       |       | $        | —     |     | $          | 1,465    |       | $ | 1,264 |   |
|                                                       |       |     |       |     |       |     |       |
| **Significant Assumptions Used to Measure  Costs:**        |       |     |       |     |       |     |       |
| Discount rate                                              |       | 6.25     | %          | 6.00     | %          | 5.75     | %          |
| Expected average long-term increase in  compensation level |       | 4.00     |       | 4.00     |       | 3.50     |       |
| Expected average long-term rate of return  on assets       |       | 8.75     |       | 8.75     |       | 8.75     |       |

 

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Pension costs include an expected return impact for the current yearthat may differ from actual investment performance in the plan.  The return assumption used for 2009 pensioncost calculations will be 8.50 percent. The cost calculation uses a market-related valuation of pensionassets.  Xcel Energy uses a calculatedvalue method to determine the market-related value of the plan assets.  The market-related value begins with the fairmarket value of assets as of the beginning of the year.  The market-related value is determined byadjusting the fair market value of assets to reflect the investment gains andlosses (the difference between the actual investment return and the expectedinvestment return on the market-related value) during each of the previous fiveyears at the rate of 20 percent per year.

 

Xcel Energyalso maintains noncontributory, defined benefit supplemental retirement incomeplans for certain qualifying executive personnel.  Benefits for these unfunded plans are paidout of their operating cash flows.

 

**Defined Contribution Plans**

** **

Xcel Energy maintains 401(k) and other defined contribution plansthat cover substantially all employees. The contributions for NSP-Minnesota were approximately $4.2 million in2008 and 2007 and $3.9 million in 2006.

 

**Postretirement Health CareBenefits**

** **

Xcel Energy has a contributory health and welfare benefit plan thatprovides health care and death benefits to most Xcel Energy retirees.  The former NSP discontinued contributingtoward health care benefits for nonbargaining employees retiring after 1998 andfor bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after1999.  Employees of the former NSP whoretired after 1998 are eligible to participate in the Xcel Energy health careprogram with no employer subsidy.

 

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

 

Regulatory agencies for nearly all of Xcel Energy’s retail andwholesale utility customers have allowed rate recovery of accrued benefit costsunder SFAS No. 106.  NSP-Minnesotatransitioned to full accrual accounting for SFAS No. 106 costs, withregulatory differences fully amortized prior to 1997.

 

***Plan Assets***—Certain state agencies that regulate Xcel Energy’s utility subsidiaries alsohave issued guidelines related to the funding of SFAS No. 106 costs.  Also, a portion of the assets contributed onbehalf of non-bargaining retirees has been funded into a sub-account of theXcel Energy pension plans.  These assetsare invested in a manner consistent with the investment strategy for thepension plan.

 

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

 
| ** **                               | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|
| Equity and equity mutual fund securities |       | 49       | %          | 67       | %          |
| Fixed income/debt securities             |       | 29       |       | 21       |       |
| Cash equivalents                         |       | 22       |       | 11       |       |
| Nontraditional investments               |       | —   |       | 1        |       |
|                                     |       | 100      | %          | 100      | %          |

 

Xcel Energy bases its investment-return assumption for thepostretirement health care fund assets on expected long-term performance foreach of the investment types included in its postretirement health care assetportfolio.  Investment-return volatilityis not considered to be a material factor in postretirement health care costs.

 

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

 

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| **(Thousands of Dollars)**  | ** ** | **2008** | ** ** | **2007** | ** ** |
|---------------------------------------|------------|----------|------------|----------|------------|
| **Change in Benefit Obligation:**     |       |     |       |     |       |
| Obligation at Jan. 1             |       | $        | 830,315    |     | $          | 918,693 |   |
| Service cost                          |       | 5,350    |       | 5,813    |       |
| Interest cost                         |       | 51,047   |       | 50,475   |       |
| Medicare subsidy reimbursements       |       | 6,178    |       | 2,526    |       |
| Plan participants’ contributions |       | 13,892   |       | 13,211   |       |
| Actuarial gain                        |       | (46,827  | )          | (86,576  | )          |
| Benefit payments                      |       | (65,358  | )          | (73,827  | )          |
| Obligation at Dec. 31            |       | $        | 794,597    |     | $          | 830,315 |   |

 
| **(Thousands of Dollars)**                                                                | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| **Change in Fair Value of Plan Assets:**                                                            |       |       |       |       |       |
| Fair value of plan assets at Jan. 1                                                            |       | $          | 427,459    |       | $          | 406,305 |   |
| Actual (loss) return on plan assets                                                                 |       | (132,226   | )          | 24,623     |       |
| Plan participants’ contributions                                                               |       | 13,892     |       | 13,211     |       |
| Employer contributions                                                                              |       | 55,799     |       | 57,147     |       |
| Benefit payments                                                                                    |       | (65,358    | )          | (73,827    | )          |
| Fair value of plan assets at Dec. 31                                                           |       | $          | 299,566    |       | $          | 427,459 |   |
|                                                                                                |       |       |       |       |       |
| **Funded Status at Dec. 31:**                                                                  |       |       |       |       |       |
| Funded status                                                                                       |       | $          | (495,031   | )          | $          | (402,856 | ) |
| Current liabilities                                                                                 |       | (4,928     | )          | (1,755     | )          |
| Noncurrent liabilities                                                                              |       | (490,103   | )          | (401,101   | )          |
| Net amounts recognized in consolidated  balance sheets                                              |       | $          | (495,031   | )          | $          | (402,856 | ) |
|                                                                                                |       |       |       |       |       |
| **NSP-Minnesota Amounts Not Yet Recognized as  Components of Net Periodic Benefit Cost:**           |       |       |       |       |       |
| Net loss                                                                                            |       | $          | 78,140     |       | $          | 88,968 |   |
| Transition obligation                                                                               |       | 5,419      |       | 6,765      |       |
| Total                                                                                               |       | $          | 83,559     |       | $          | 95,733 |   |
| ** **                                                                                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| **SFAS No. 158 Amounts Have Been  Recorded as Follows Based Upon Expected Recovery in Rates:** |       |       |       |       |       |
| Regulatory assets                                                                                   |       | $          | 80,105     |       | $          | — |   |
| Regulatory liabilities                                                                              |       | —     |       | 91,757     |       |
| Deferred income taxes                                                                               |       | 1,411      |       | 1,624      |       |
| Net-of-tax accumulated other comprehensive  income                                                  |       | 2,043      |       | 2,352      |       |
| Total                                                                                               |       | $          | 83,559     |       | $          | 95,733 |   |
|                                                                                                |       |       |       |       |       |
| NSP-Minnesota accrued benefit liability  recorded                                                   |       | $          | 152,792    |       | $          | 164,405 |   |

 
| **Measurement Date**                                         | ** ** | **Dec. 31, 2008** | ** ** | **Dec. 31, 2007** | ** ** |
|-------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
|                                                              |       |                        |       |                        |       |
| **Significant Assumptions Used to Measure  Benefit Obligations:** |       |                        |       |                        |       |
| Discount rate for year-end valuation                              |       | 6.75                        | %          | 6.25                        | %          |
| Mortality table                                                   |       | RP                          | 2000       |                        | RP         | 2000 |   |
|                                                                   |            |                             |            |                             |            |  |  |

 

Effective Dec. 31, 2008, Xcel Energy reduced its initial medicaltrend assumption from 8.0 percent to 7.4 percent.  The ultimate trend assumption remainedunchanged at 5.0 percent.  Theperiod until the ultimate rate is reached is five years.  Xcel Energy bases its medical trendassumption on the long-term cost inflation expected in the health care market,considering the levels projected and recommended by industry experts, as wellas recent actual medical cost increases experienced by Xcel Energy’s retireemedical plan.

 

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

 
| **(Thousands of Dollars)**                                            | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------|------------|------------|------------|
| 1-percent increase in APBO components at  Dec. 31, 2008                    |       | $          | 16,627     |   |
| 1-percent decrease in APBO components at  Dec. 31, 2008                    |       | (14,031    | )          |
| 1-percent increase in service and interest  components of the net periodic cost |       | 1,389      |       |
| 1-percent decrease in service and interest  components of the net periodic cost |       | (1,146     | )          |
|                                                                                 |            |            |            |  |

 

***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 contributed$55.6 million during 2008 and expects to contribute approximately $63.1 millionduring 2009.

 

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

 
| **(Thousands of Dollars)**                                               | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service cost                                                                       |       | $        | 5,350      |     | $          | 5,813    |       | $ | 6,633 |   |
| Interest cost                                                                      |       | 51,047   |       | 50,475   |       | 52,939   |       |
| Expected return on plan assets                                                     |       | (31,851  | )          | (30,401  | )          | (26,757  | )          |
| Amortization of transition obligation                                              |       | 14,577   |       | 14,577   |       | 14,444   |       |
| Amortization of prior service credit                                               |       | (2,175   | )          | (2,178   | )          | (2,178   | )          |
| Amortization of net loss                                                           |       | 11,498   |       | 14,198   |       | 24,797   |       |
| Net periodic postretirement benefit cost  under SFAS No. 106                  |       | $        | 48,446     |     | $          | 52,484   |       | $ | 69,878 |   |
|                                                                               |       |     |       |     |       |     |       |
| **NSP-Minnesota:**                                                                 |       |     |       |     |       |     |       |
| Net periodic postretirement benefit cost  recognized — SFAS No. 106 |       | $        | 13,958     |     | $          | 13,761   |       | $ | 17,154 |   |
|                                                                               |       |     |       |     |       |     |       |
| **Significant assumptions used to measure  costs (income):**                       |       |     |       |     |       |     |       |
| Discount rate                                                                      |       | 6.25     | %          | 6.00     | %          | 5.75     | %          |
| Expected average long-term rate of return  on assets (before tax)             |       | 7.50     |       | 7.50     |       | 7.50     |       |

#  

# **Projected Benefit Payments**

#  

The following table lists Xcel Energy’s projected benefit payments forthe pension and postretirement benefit plans.

 
| **(Thousands of Dollars)** | ** ** | **Projected Pension  Benefit Payments** | ** ** | **Gross Projected  Postretirement Health  Care Benefit  Payments** | ** ** | **Expected Medicare  Part D Subsidies** | ** ** | **Net Projected  Postretirement Health  Care Benefit  Payments** | ** ** |
|--------------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|--------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| 2009                                 |       | $                                                 | 224,558    |                                                                              | $          | 62,975                                                 |       | $                                                                               | 5,725      |   | $ | 57,250 |   |
| 2010                                 |       | 226,585                                           |       | 64,468                                                                            |       | 6,117                                                  |       | 58,351                                                                          |       |
| 2011                                 |       | 226,446                                           |       | 66,390                                                                            |       | 6,433                                                  |       | 59,957                                                                          |       |
| 2012                                 |       | 230,763                                           |       | 67,400                                                                            |       | 6,804                                                  |       | 60,596                                                                          |       |
| 2013                                 |       | 234,149                                           |       | 68,008                                                                            |       | 7,127                                                  |       | 60,881                                                                          |       |
| 2014-2018                            |       | 1,237,114                                         |       | 351,249                                                                           |       | 38,796                                                 |       | 312,453                                                                         |       |
|                                      |            |                                                   |            |                                                                                   |            |                                                        |            |                                                                                 |            |  |  |  |  |

 

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**9.****              Detailof Interest and Other Income (Expense), Net**

 

Interest andother income, net of nonoperating expenses, for the years ended Dec. 31consisted of the following:

 
| **(Thousands of Dollars)**       | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|--------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest income                            |       | $        | 10,005     |     | $          | 10,208   |       | $ | 13,294 |   |
| Equity income in unconsolidated affiliates |       | —   |       | 770      |       | 1,312    |       |
| Other nonoperating income                  |       | 1,274    |       | 1,048    |       | 945      |       |
| Insurance policy expenses                  |       | (384     | )          | (5,921   | )          | (6,120   | )          |
| Total interest and other income, net       |       | $        | 10,895     |     | $          | 6,105    |       | $ | 9,431 |   |

 

**10.**       Derivative Instruments

** **

In the normal course of business, NSP-Minnesota is exposed to a varietyof market risks.  Market risk is thepotential loss or gain that may occur as a result of changes in the market orfair value of a particular instrument or commodity.  NSP-Minnesota utilizes, in accordance withapproved risk management policies, a variety of derivative instruments tomitigate market risk and to enhance its operations.

 

***Commodity Price Risk—*** NSP-Minnesota is exposed to commodity price riskin its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-termphysical purchase and sales contracts for electric capacity, energy andenergy-related products and for various fuels used for generation anddistribution activities.  Commodity riskis also managed through the use of financial derivative instruments.  NSP-Minnesota utilizes these derivativeinstruments to reduce the volatility in the cost of commodities acquired onbehalf of its retail customers even though the regulatory jurisdiction may providefor recovery of actual costs.  NSP-Minnesota’srisk-management policy allows it to manage commodity price risk within eachrate-regulated operation to the extent such exposure exists.

 

***Short-Term Wholesaleand Commodity Trading Risk —*** NSP-Minnesotaconducts various short-term wholesale and commodity trading activities,including the purchase and sale of electric capacity, energy and energy-relatedinstruments.  NSP-Minnesota’srisk-management policy allows management to conduct these activities withinguidelines and limitations as approved by the risk management committee, whichis made up of management personnel not directly involved in the activitiesgoverned by this policy.

 

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

 

**Types of and Accounting forDerivative Instruments**

** **

NSP-Minnesota uses derivative instruments in connection with itsinterest rate, utility commodity price, vehicle fuel price, short-termwholesale and commodity trading activities, including forward contracts,futures, swaps and options.  Allderivative instruments not designated and qualifying for the normal purchasesand normal sales exception, as defined by SFAS No. 133, are recordedon the consolidated balance sheets at fair value as derivative instrumentsvaluation.  This includes certaininstruments used to mitigate market risk for NSP-Minnesota and all instrumentsrelated to the commodity trading operations. The classification of changes in fair value for those derivativeinstruments is dependent on the designation of a qualified hedgingrelationship.  Changes in fair value ofderivative instruments not designated in a qualifying hedging relationship arereflected in current earnings or as a regulatory asset or liability.  The classification is dependent on theapplicability of specific regulation.

 

Qualifying hedging relationships are designated as a hedge of aforecasted transaction or future cash flow (cash flow hedge).  The types of qualifying hedging transactionsthat NSP-Minnesota is currently engaged in are discussed below.

 

**Cash Flow Hedges**

** **

***Commodity Cash FlowHedges******—***NSP-Minnesota enters into derivativeinstruments to manage variability of future cash flows from changes incommodity prices.  This could include thepurchase or sale of energy or energy-related products, natural gas to generateelectric energy, gas for resale, and vehicle fuel.  Certain derivative instruments entered intoto manage this variability are designated as cash flow hedges for accountingpurposes.  At Dec. 31, 2008,NSP-Minnesota had various 

 

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commodity-related contracts designated as cash flow hedges extending throughDecember 2010.  Changes in thefair value of cash flow hedges are recorded in other comprehensive income ordeferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms inplace.

 

At Dec. 31, 2008, NSP-Minnesota had $6.6 million of net losses inaccumulated other comprehensive income related to commodity cash flow hedgecontracts; $3.9 million is expected to be recognized in earnings during thenext 12 months as the hedged transactions settle.

 

NSP-Minnesota had immaterial ineffectiveness related to commodity cashflow hedges during 2008 and 2007.

 

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

 

At Dec. 31, 2008, NSP-Minnesota had net gains of approximately$0.1 million in accumulated other comprehensive income related to interest ratehedges that it expects to recognize in earnings during the next 12 months.

 

NSP-Minnesota had no ineffectiveness related to interest rate cash flowhedges during 2008 and 2007.

 

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

*** ***
| ** **                                                   | ** ** | **2008**                                                   | ** ** | **2007**                                                   | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------------|------------|------------------------------------------------------------|------------|
| **(Thousands of Dollars)**                         | ** ** | **Derivative  Instruments  Valuation –  Assets** | ** ** | **Derivative  Instruments  Valuation -  Liabilities** | ** ** | **Derivative  Instruments  Valuation -  Assets** | ** ** | **Derivative  Instruments  Valuation -  Liabilities** | ** ** |
| Long term purchased power agreements                         |       | $                                                          | 151,884    |                                                       | $          | 230,715 |   | $ | 176,443 |   | $ | 245,240 |   |
| Electricity and natural gas trading and  hedging instruments |       | 47,973                                                     |       | 28,522                                                     |       | 31,765 |   | 12,176 |   |
| Interest rate hedging instruments                            |       | —                                                     |       | —                                                     |       | — |   | 2,727 |   |
| Total                                                        |       | $                                                          | 199,857    |                                                       | $          | 259,237 |   | $ | 208,208 |   | $ | 260,143 |   |

 

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

 

***Financial Impact of Qualifying Cash FlowHedges*** — The impact of qualifying cash flow hedgeson NSP-Minnesota’s accumulated other comprehensive income, included in theconsolidated statements of common stockholder’s equity and comprehensiveincome, is detailed in the following table:

 
| **(Millions of Dollars)**                                                 | ** ** | ** ** | ** ** |
|-------------------------------------------------------------------------------------|------------|------------|------------|
| Accumulated other comprehensive income  related to hedges at Dec. 31, 2005     |       | $          | —     |   |
| After-tax net unrealized gains related to  derivatives accounted for as hedges      |       | 9.6        |       |
| After-tax net realized gains on derivative  transactions reclassified into earnings |       | (0.2       | )          |
| Accumulated other comprehensive income  related to hedges at Dec. 31, 2006     |       | $          | 9.4        |   |
| After-tax net unrealized losses related to  derivatives accounted for as hedges     |       | (0.3       | )          |
| After-tax net realized gains on derivative  transactions reclassified into earnings |       | (0.4       | )          |
| Accumulated other comprehensive income  related to hedges at Dec. 31, 2007     |       | $          | 8.7        |   |
| After-tax net unrealized losses related to  derivatives accounted for as hedges     |       | (5.5       | )          |
| After-tax net realized gains on derivative  transactions reclassified into earnings |       | (0.2       | )          |
| Accumulated other comprehensive income  related to hedges at Dec. 31, 2008     |       | $          | 3.0        |   |

 

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**11.**       Financial Instruments

** **

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

 
| ** **                                | ** ** | **2008**             | ** ** | **2007**            | ** ** |
|-------------------------------------------|------------|----------------------|------------|---------------------|------------|
| **(Thousands of Dollars)**      | ** ** | **Carrying  Amount** | ** ** | **Fair Value** | ** ** | **Carrying  Amount** | ** ** | **Fair Value** | ** ** |
| Nuclear decommissioning fund              |       | $                    | 1,075,294  |                | $          | 1,075,294 |   | $ | 1,317,564 |   | $ | 1,317,564 |   |
| Other investments                         |       | 725                  |       | 725                 |       | 9,154 |   | 9,154 |   |
| Long-term debt, including current portion |       | 2,962,749            |       | 3,100,223           |       | 2,463,109 |   | 2,628,580 |   |
|                                           |            |                      |            |                     |            |  |  |  |  |  |  |  |  |

 

The fair value of cash and cash equivalents, notes and accountsreceivable and notes and accounts payable are not materially different fromtheir carrying amounts.  The fair valueof NSP-Minnesota’s nuclear decommissioning fund is based on published tradingdata and pricing models, generally using the most observable inputs availablefor each class of security.  The fairvalue of NSP-Minnesota’s other investments are estimated based on quoted marketprices for those or similar investments. The fair value of NSP-Minnesota’s long-term debt is estimated based onthe quoted market prices for the same or similar issues, or the current ratesfor debt of the same remaining maturities and credit quality.

 

The fair value estimates presented are based on information availableto management as of Dec. 31, 2008 and 2007.  These fair value estimates have not beencomprehensively revalued for purposes of these consolidated financialstatements since that date, and current estimates of fair values may differsignificantly.

 

All unrealized gains and losses in the external decommissioning fundare recorded as a regulatory asset or liability pursuant to SFAS No. 71.  The following tables provide the externaldecommissioning fund’s approximate gains, losses and proceeds from the sale ofsecurities for the years ended Dec. 31:

 
| **(Thousands of Dollars)** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Realized gains                       |       | $        | 65,779     |     | $          | 38,745   |       | $ | 310,066 |   |
| Realized losses                      |       | 107,272  |       | 35,794   |       | 32,412   |       |
| Proceeds from sale of securities     |       | 914,514  |       | 669,070  |       | 958,294  |       |
|                                      |            |          |            |          |            |          |            |  |  |  |

 

**Letters of Credit**

** **

NSP-Minnesota uses letters of credit, generally with terms of one year,to provide financial guarantees for certain operating obligations.  At Dec. 31, 2008 and 2007, there were$6.9 million and $7.2 million of letters of credit outstanding.  The contract amounts of these letters ofcredit approximate their fair value and are subject to fees determined in themarketplace.

 

**12.****       FairValue Measurements**

 

Effective Jan. 1, 2008, NSP-Minnesota adopted SFAS No. 157for recurring fair value measurements. SFAS No. 157 provides a single definition of fair value and requiresenhanced disclosures about assets and liabilities measured at fair value.  SFAS No. 157 establishes a hierarchalframework for disclosing the observability of the inputs utilized in measuringassets and liabilities at fair value. The three levels defined by the SFAS No. 157 hierarchy and examplesof each level are as follows:

 

Level1 — Quoted prices are available in active markets for identical assets orliabilities as of the reported date.  Thetypes of assets and liabilities included in Level 1 are highly liquid andactively traded instruments with quoted prices, such as equities listed by theNew York Stock Exchange and commodity derivative contracts listed on the NewYork Mercantile Exchange.

 

Level2 — Pricing inputs are other than quoted prices in active markets, but areeither directly or indirectly observable as of the reported date.  The types of assets and liabilities includedin Level 2 are typically either comparable to actively traded securities orcontracts, such as treasury securities with pricing interpolated from recenttrades of similar securities, or priced with models using highly observableinputs, such as commodity options priced using observable forward prices andvolatilities.

 

Level3 — Significant inputs to pricing have little or no observability as of thereporting date.  The types of assets andliabilities included in Level 3 are those with inputs requiring significantmanagement judgment or estimation, such as the complex and subjective modelsand forecasts used to determine the fair value of FTRs.

 

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NSP-Minnesota continuously monitors the creditworthiness of thecounterparties to its commodity derivative contracts and assesses eachcounterparty’s ability to perform on the transactions set forth in thecontracts.  Given this assessment, aswell an assessment of the impact of NSP-Minnesota’s own credit risk whendetermining the fair value of commodity derivative liabilities, the impact ofconsidering credit risk was immaterial to the fair value of commodityderivative assets and liabilities at Dec. 31, 2008.

 

The following table presents, for each of these hierarchy levels,NSP-Minnesota’s assets and liabilities that are measured at fair value on arecurring basis as of Dec. 31, 2008:

 
| **(Thousands of Dollars)** | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Counterparty   Netting (a)** | ** ** | **Net Balance** | ** ** |
|--------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|------------------------------------------|------------|----------------------|------------|
| Assets:                              |       |             |       |             |       |             |       |                                     |       |                 |       |
| Nuclear decommissioning fund         |       | $                | 465,936    |             | $          | 499,935          |       | $                                        | 109,423    |                 | $          | — |   | $ | 1,075,294 |   |
| 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 |   |
| Total                                |       | $                | —     |             | $          | 21,509           |       | $                                        | 14,960     |                 | $          | (7,947 | ) | $ | 28,522 |   |

 

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(a) FASB Interpretation No. 39 *Offsetting of Amounts Relating to Certain Contracts*,as amended by FASB Staff Position FIN 39-1 *Amendmentof FASB Interpretation No. 39*, permits the netting ofreceivables and payables for derivatives and related collateral amounts when alegally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreementbetween two parties who have multiple contracts with each other that providesfor the net settlement of all contracts in the event of default on ortermination of any one contract.

 

The following table presents the changes inLevel 3 recurring fair value measurements for the year ended Dec. 31, 2008:

 
| **(Thousands of Dollars)**                            | ** ** | **Commodity  Derivatives,  Net** | ** ** | **Nuclear  Decommissioning  Fund** | ** ** |
|-----------------------------------------------------------------|------------|----------------------------------|------------|------------------------------------|------------|
| Balance Jan. 1, 2008                                       |       | $                                | 15,345     |                               | $          | 108,656 |   |
| Purchases, issuances, and settlements, net                      |       | (1,585                           | )          | 12,198                             |       |
| Transfers out of Level 3                                        |       | (2,578                           | )          | —                             |       |
| Gains recognized in earnings                                    |       | 496                              |       | —                             |       |
| Gains (losses) recognized as regulatory  assets and liabilities |       | 11,569                           |       | (11,431                            | )          |
| Balance Dec. 31, 2008                                      |       | $                                | 23,247     |                               | $          | 109,423 |   |

 

Gains on Level3 commodity derivatives recognized in earnings for the year ended Dec. 31,2008, include $2.9 million of net unrealized gains relating to commodityderivatives held at Dec. 31, 2008. Realized and unrealized gains and losses on commodity trading activitiesare included in electric revenues. Realized and unrealized gains and losses on short-term wholesaleactivities reflect the impact of regulatory recovery and are deferred asregulatory assets and liabilities. Realized and unrealized gains and losses on nuclear decommissioning fundinvestments are deferred as a component of a nuclear decommissioning regulatoryasset.

 

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**13.****       Rate Matters**

 

**NSP-Minnesota**

** **

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

*** ***

**Base Rate**

** **

***NSP-MinnesotaElectric Rate Case* —**On Nov. 3, 2008, NSP-Minnesota filed arequest with the MPUC to increase Minnesota electric rates by $156 millionannually, or 6.05 percent.  Therequest is based on a 2009 forecast test year, an electric rate base of $4.1billion, a requested ROE of 11.0 percent and an equity ratio of52.5 percent.

 

In December 2008, the MPUC approved an interimrate increase of $132 million, or 5.12 percent, effective Jan. 2,2009.  The primary difference betweeninterim rate levels approved and NSP-Minnesota’s request of $156 million is dueto a previously authorized ROE of 10.54 percent and NSP-Minnesota’s requestedROE of 11.0 percent.

 

A final decision from the MPUC is expected in the third quarter of2009.  The following procedural schedulehas been established:

 

·                  Staffand intervenor direct testimony on April 7, 2009;

·                  NSP-Minnesota rebuttal testimony on May 5,2009;

·                  Staff and intervenor surrebuttal testimony onMay 26, 2009; and

·                  Evidentiary hearings are scheduled for June 2-9,2009.

 

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

** **

***TCR Rider*—**In November 2006, the MPUC approved a TCR rider pursuant tolegislation, which allows annual adjustments to retail electric rates toprovide recovery of incremental transmission investments between rate cases.  In December 2007, NSP-Minnesota filedadjustments to the TCR rate factors and implemented a rider to recover $18.5million beginning Jan. 1, 2008.  In March 2008,the MPUC approved the 2008 rider, but required certain procedural changes forfuture TCR filings if costs are disputed. On Oct. 30, 2008, NSP-Minnesota submitted its proposed TCR ratefactors for proposed recovery in 2009, seeking to recover $14 million beginningJan. 1, 2009.  A portion of amountspreviously collected through the TCR rider prior to 2009 has been included forrecovery in the electric rate case described above.  MPUC approval is pending.

 

***RES Rider* —**In March 2008, the MPUC approved an RES rider to recover the costs forutility-owned projects implemented in compliance with the RES, and the RESrider was implemented on April 1, 2008. Under the rider, NSP-Minnesota could recover up to approximately $14.5million in 2008 attributable to the Grand Meadow wind farm, a 100 MW windproject, subject to true-up.  In 2008,NSP-Minnesota submitted the RES rider for recovery of approximately $22 millionin 2009 attributable to the Grand Meadow wind farm.  On Feb. 12, 2009, the MPUC approved therider request but required that the issue of whether these costs should bemoved to base rates in the currently pending electric rate case or left in therider, as NSP-Minnesota has proposed, to be addressed through supplementaltestimony in the rate case.

 

***MERP Rider* —**On Oct. 1, 2008, NSP-Minnesota filed a proposed MERP rider for 2009designed to recover costs related to MERP environmental improvementprojects.  Under this rider,NSP-Minnesota proposes to recover $114 million in 2009, an increase ofapproximately $23 million over 2008.  Newrates went into effect automatically on Jan. 1, 2009 as stipulated.  MPUC approval is still pending.

 

***AnnualAutomatic Adjustment Report for 2007* —** In September 2007,NSP-Minnesota filed its annual automatic adjustment reports for July 1,2006 through June 30, 2007, which is the basis for the MPUC review ofcharges that flow through the FCA and PGA mechanisms.  During that time period, $1.2 billion infuel and purchased energy costs, including $384 million of MISO chargeswere recovered from electric customers through the FCA.  In addition, approximately $590 millionof purchased natural gas and transportation costs were recovered through thePGA.  In October 2008, the MPUCvoted to accept the 2007 gas annual automatic adjustment report.  The 2007 annual electric automatic adjustmentreport is pending further MPUC action.

 

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***AnnualAutomatic Adjustment Report for 2008* —** In September 2008,NSP-Minnesota filed its annual automatic adjustment reports for July 1,2007 through June 30, 2008.  Duringthat time period, $848.5 million in fuel and purchased energy costs, including$258.8 million of MISO charges, were recovered from Minnesota electriccustomers through the FCA.  In addition,approximately $680 million of purchased natural gas and transportationcosts were recovered through the PGA. The 2008 annual automatic adjustment reports are pending initialcomments and MPUC action.

** **

***MISO ASM CostRecovery*****—**On May 9, 2008, NSP-Minnesota and several other Minnesota electricutilities filed jointly for MPUC regulatory approval to recover ASM coststhrough the Minnesota FCA cost recovery mechanism.  The filing is pending MPUC action after aninitial hearing on Dec. 18, 2008. The MPUC voted to approve FCA recovery of these charges, subject torefund, and required NSP-Minnesota to make a filing that demonstrates thatthere were benefits of the ASM market after one year of operation.

 

***Gas Meter ModuleFailures*****—**Approximately 8,700 customers in the St. Cloud and East Grand Forks areas ofMinnesota and about 4,000 customers in the Fargo, N.D. area were under billedfor a period of time during the 2007-2008 heating season due to the failure ofthe automated meter reading (AMR) module installed on their natural gasmeters.  While the modules failed toregister usage, the meters continued to function.  In the May to July 2008 timeframe,NSP-Minnesota rebilled approximately 5,000 of these customers for theirestimated consumption during the period the modules registered no consumptionand then ceased rebilling as both the MPUC and NDPSC opened investigations intothis matter.

 

On July 2, 2008, NSP-Minnesota received a letter from the NDPSCrequesting further information on the module failure.  Subsequent meetings between NSP-Minnesota andNDPSC staff were held in September and October 2008 to discussNSP-Minnesota’s progress in addressing various NDPSC concerns aboutNSP-Minnesota’s response.

 

OnAug. 1, 2008, the MPUC opened a docket and issued a notice directingNSP-Minnesota to file information about the AMR module failure.  NSP-Minnesota responded to the MPUC on Aug. 21,2008, proposing to rebill affected customers for the unrecorded natural gasusage during the months that no consumption or intermittent usage wasrecorded.  NSP-Minnesota proposed toemploy the process provided by NSP-Minnesota’s natural gas tariff and the MPUC’srules to estimate usage, which would be consistent with the process usedwhenever any other type of meter or module failure affecting the measurement ofcustomer consumption occurs.  The MOAGand the OES subsequently submitted comments on NSP-Minnesota’s filing.  The OES comments indicated support for therebilling plan with certain conditions. The MOAG raisedconcerns about the timing of the remediation efforts, and questions whethercustomers should be responsible for the entire cost of the unbilled naturalgas.

 

On Nov. 6, 2008, the MPUC reviewed the matter and directedNSP-Minnesota to provide additional information prior to making a finaldecision on the rebilling plan.

 

On Dec. 3, 2008, NSP-Minnesota made a filing with the NDPSCregarding its commitments and proposed remedies for rebilling affectedcustomers.  The filing outlined theproposed rebilling plan in detail, which committed to a 10-day, go-forwardfield response to customer inquiries regarding meter accuracy, offered anadjustment to the natural gas true-up to remove the commodity cost for theunder recovered gas due to the rebilling process and indicated willingness towork with NDPSC staff on a service quality credit for customers experiencing amodule failure.

 

On Dec. 19, 2008, NSP-Minnesota met with MPUC staff, the OES andMOAG and in January 2009 filed its response to the questions with theMPUC.  NSP-Minnesota indicated awillingness to work with parties to develop a remedy for the current situation,and to develop prospective service quality standards to address this and otherconcerns around billing accuracy.  NSP-Minnesotahas determined that a number of AMR modules designed for commercial customersare defective and as a result is broadening efforts to evaluate the performanceof both gas and electric AMR modules.

 

***Annual Review ofRemaining Lives —*** On Oct. 8, 2008, the MPUCapproved NSP-Minnesota’s service lives, salvage rates and resultingdepreciation rates for its electric and gas production facilities as well asthe depreciation study for other gas and electric assets, effective Jan. 1,2008.  The net impact resulted in areduction to depreciation expense of $5.6 million recognized in the thirdquarter, or $7.5 million on an annual basis.

 

**Other**

** **

***Nuclear RefuelingOutage Costs* —** In November 2007, NSP-Minnesota requested a change in therecovery method for costs associated with refueling outages at its nuclearplants.  The request sought approval toamortize refueling outage costs over the period between refueling outages tobetter match revenues and expenses.  Thisrequest would have reduced 2008 

 

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expenses for the NSP-Minnesota jurisdiction by approximately$25 million due to deferral and amortization over an 18-month periodversus expensed as incurred.

 

On Sept. 16, 2008, the MPUC authorized NSP-Minnesota to use a deferraland amortization method for the nuclear refueling operating and maintenancecosts effective Jan. 1, 2008.  The ruling reduced operating andmaintenance expenses, but also resulted in revenue deferrals.  The net result is a positive adjustment toyear-end earnings of approximately $21 million.

 

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

*** ***

***NSP-Minnesota NorthDakota Electric Rate Case* —**In December 2007,NSP-Minnesota filed a request with the NDPSC to increase North Dakota retailelectric rates by $20.5 million, which would be an $18.2 million impact toNSP-Minnesota due to the transfer of certain costs and revenues between baserates and the fuel cost recovery mechanism. The request was based on an 11.50 percent ROE, an equity ratio of51.77 percent, and a rate base of approximately $242 million.  Interim rates of $17.2 million becameeffective in February 2008.

 

The NDPSC approveda settlement agreement on Dec. 31, 2008, which calls for a base rateincrease of $12.8 million, based on an authorized ROE of 10.75 percent.  Key terms of the settlement are listed below:

 

·                  Adjustments in depreciationexpenses related to service life changes for generation plants and removalrates for transmission and distribution plant, resulting in a $2.5 milliondecrease in the revenue deficiency.

·                  Sharing of wholesalemargins, refunding to customers 85 percent of asset-based wholesale margins and50 percent of non-asset-based margins through the fuel clause.  Test year wholesale margins to be shared withcustomers are estimated to be $1.9 million.

·                  An electric rate moratorium,under which NSP-Minnesota agreed to not implement an increase in electric ratesuntil Jan. 1, 2011.

·                  Sharing any earnings inexcess of the authorized 10.75 percent ROE, providing customers 50 percent ofany earnings above 10.75 percent and 75 percent of any earnings above 11.25percent.

·                  The settlement outlines aprocess for more NDPSC involvement in NSP-Minnesota’s resource planningprocess.

 

In addition toapproving the settlement, the NDPSC terminated a 2005 filing regarding recoveryof MISO Day 2 market charges, thus approving FCA recovery of all MISO Day 2charges through the FCA retroactively and prospectively.  Based on the final order, there will be anestimated interim rate refund of $6.3 million, which will be refunded back tocustomers by June 1, 2009.  Thisrefund was accrued for in 2008 and will have no impact on 2009 results.  Final rates will be implemented for serviceon and after March 1, 2009.

 

***Nuclear RefuelingOutage Costs*—**In late 2007, NSP-Minnesota filedwith both the NDPSC and SDPUC a request asking for a change in the recoverymethod for costs associated with refueling outages at its nuclear plants.  The request is comparable to that filed withthe MPUC.  In February 2008, theNDPSC approved the request, indicating that appropriate cost recovery levelswould be determined in the pending electric rate case.

 

The SDPUC approved the NSP-Minnesota’s request to change the accountingmethod for nuclear refueling outage operating and maintenance cost from adirect expense method to a method that amortizes these costs over the periodbetween outages.

 

***MISO ASM Cost Recovery —***On Dec. 24, 2008, NSP-Minnesota filed forNDPSC and SDPUC regulatory approval to recover MISO ASM costs via an FCA costrecovery mechanism.  NSP-Minnesotarequested a regulatory order prior to March 1, 2009, when ASM charges andrevenues would affect the North Dakota and South Dakota FCA.  On Feb. 11, 2009, the NDPSC concludedthat FCA treatment of these costs was already provided for by the rate casesettlement. Based on this information, NSP-Minnesota filed to withdraw itsrequest.  The MPUC granted the withdrawalrequest at its Feb. 25, 2009 open meeting.  On Feb. 12, 2009 the SDPUC approvedNSP-Minnesota’s request.

*** ***

***NSP-Minnesota South Dakota TCR and ECR RateRiders —*** In December 2008, the SDPUC approved tworate riders for recovery of transmission investments and environmental costseffective Feb. 1, 2009.

 

InFebruary 2007, NSP-Minnesota filed a petition for approval of a tariffestablishing a TCR rider for recovery of certain transmission investments.  The TCR rider rate is set to recoverapproximately $1.9 million during 2009. In September 2007, NSP-Minnesota filed a petition for approval of atariff establishing an environmental cost recovery (ECR) rider for recovery ofpollution control equipment installed at NSP-Minnesota’s A. S. King plant.  The ECR Rider rate is set to recoverapproximately $2.5 million during 2009.

 

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Both rate riders were allowed a return on equity of 9.5 percentaccording to the terms of their respective settlement agreements.  However, if NSP-Minnesota makes a generalrate filing utilizing a 2008 test year, the SDPUC may order that an appropriateROE value to be utilized under the rider mechanism, subject to true-up for theperiod from July 1, 2008 to the effective date of the order.

 

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

*** ***

***MISO Long-Term TransmissionPricing —***In October 2005, MISO filed aproposed change to its TEMT to regionalize future cost recovery of certain highvoltage transmission projects.  Thetariff, called the Regional Expansion Criteria Benefits tariff, would recovercertain eligible transmission investments from all transmission servicecustomers in the MISO 15 state region. In November 2006, the FERC issued an order accepting the regionaleconomic benefits (RECB) I tariff, including a 20 percent limitation onthe portion of transmission reliability expansion costs that would beregionalized and recovered from all loads in the MISO region.

 

Transmission service rates in the MISO region have historically used arate design in which the transmission cost depends on the location of the loadbeing served, which is referred to as license plate rates.  Costs of existing transmission facilities arethus not regionalized.  In August 2007,MISO and its transmission owners filed a successor rate methodology, to beeffective February 2008.American Electric Power (AEP) filed a competing rateproposal that would regionalize certain costs of the existing AEP system overthe MISO and PJM RTO regions.  The AEPproposal would shift several million dollars in transmission costs annually tothe NSP System.  In January 2008,the FERC rejected the AEP proposal.  On Dec. 18,2008, the FERC denied AEP’s request for rehearing.

 

***Revenue Sufficiency Guarantee Charges —***In April 2006, the FERC issued an orderdetermining that MISO had incorrectly applied its TEMT regarding theapplication of the revenue sufficiency guarantee (RSG) charge to certaintransactions.  The FERC ordered MISO toresettle all affected transactions retroactive to April 2005.  The RSG charges are collected from MISOcustomers and paid to generators.  In October 2006,the FERC issued an order granting rehearing in part and reversed the priorruling requiring MISO to issue retroactive refunds, and ordered MISO to submita compliance filing to implement prospective changes.

 

InMarch 2007, the FERC issued orders separately denying rehearing of theFERC order.  Several parties filedappeals to the U.S Court of Appeals for the District of Columbia seekingjudicial review of the FERC’s determinations of the allocation of RSG costsamong MISO market participants.  XcelEnergy intervened in each of these proceedings. In August 2007, Ameren Services Company (Ameren) and the NorthernIndiana Public Service Company (NIPSCO) filed a joint complaint against MISO atthe FERC, challenging the MISO’s FERC-approved methodology for the recovery ofRSG costs.  In November 2007, theFERC issued an order instituting a proceeding to review evidence and toestablish a RSG cost allocation methodology for market participants under theMISO TEMT.  In March 2008, theMISO filed indicative tariff revisions that reflect an alternative mechanismfor allocating RSG charges and costs.  InAugust 2008, the FERC rejected this filing and issued an order commencinga hearing.

 

In November 2008, the FERC issued two orders related to RSG.  One order requires the RSG charge allocationto include virtual supply transactions and requires resettlement of RSG chargesretroactive to August 2007.  Thesecond order reversed a prior FERC decision and changed the RSG calculationmethodology for the May 2006 to August 2007 retroactive period.  Several parties filed requests for rehearingof the November 2008 FERC orders, arguing that the change in RSGallocation should be prospective.  TheRSG-related dockets are pending FERC action.

 

**14.**       Commitments and Contingent Liabilities

** **

***Capital Commitments***—As of Dec. 31, 2008, the estimated cost of the capital expenditureprograms and other capital requirements of NSP-Minnesota is approximately $880million in 2009, $1.3 billion in 2010 and $1.4 billion in 2011.  NSP-Minnesota’s capital forecast includes thefollowing major projects.

 

*Nuclear Capacity Increases and Life Extension*— In August 2004, NSP-Minnesota announced plansto pursue 20-year license renewals for the Monticello and Prairie Islandnuclear plants.  A renewed operatinglicense was approved and issued for Monticello by the NRC in November 2006licensing the plant to operate until 2030, and the MPUC order approving thespent fuel storage capacity needed to support plant operations until 2030 wentinto effect in June 2007.  Theapplication to renew Prairie Island’s operating licenses was submitted to theNRC in April 2008 and the application for a certificate of need 

 

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for additional spent fuel storage capacity to support 20 additionalyears of plant operation was submitted to the MPUC in May 2008.  Final state and federal approvals areexpected in 2010.

 

NSP-Minnesota is pursuing capacity increases of Monticello and PrairieIsland that will total approximately 230 MW, to be implemented, if approved,between 2009 and 2015.  The lifeextension and capacity increase for Prairie Island Unit 2 is contingent onreplacement of Unit 2’s original steam generators, currently planned during therefueling outage in 2013.  Total capitalinvestment for these activities is estimated to be over $1 billion between2006 and 2015.  NSP-Minnesota submittedthe certificate of need and site permit applications for Monticello’s poweruprate in the first quarter of 2008 and the certificate of need and site permitapplications for Prairie Island’s power uprate in the second quarter of2008.  The MPUC approved the Monticellopower uprate certificate of need and site permit in December 2008.  Action by the MPUC on the Prairie Islandpower uprate certificate of need and site permit is expected in fourth quarterof 2009.

 

*Wind Generatio*n —NSP-Minnesota plans to invest approximately $900 million over three years for a201 MW project in southwestern Minnesota’s Nobles County, called the NoblesWind Project, and a 150 MW project in Dickey and McIntosh counties insoutheastern North Dakota, called the Merricourt Wind Project, expected to beoperational by the end of 2010 and 2011, respectively.  NSP-Minnesota is in the process of seekingregulatory approval for the projects, which would be eligible for riderrecovery in Minnesota.

 

*CAPX 2020* — In June 2006,CapX 2020, an alliance of electric cooperatives, municipals and investor-ownedutilities in the upper Midwest, including Xcel Energy, announced that it hadidentified several groups of transmission projects that proposed to be completeby 2020.  Group 1 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’s investment is expected to beapproximately $900 million depending on the route and configurationapproved by the MPUC.  Approximately75 percent of the 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 is expected to occur through the biennialPSCW rate case process.

 

*MERP Project*— In December 2003,the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueledelectric generating plants to natural gas, and to install advanced pollutioncontrol equipment at a third coal-fired plant. These improvements are expected to significantly reduce air emissionsfrom these facilities, while increasing the capacity at system peak by 300 MW.  New state-of-the-art emission controlequipment was placed in-service for the Allen S. King plant in 2007, and theexisting High Bridge facility was replaced with a 575 MW natural gas combinedcycle unit, which went into service in May 2008.  The final phase of the MERP program, the newRiverside combined cycle plant, is currently in start-up and scheduled to bein-service by May 2009.  Thecumulative investment is approximately $1 billion.  The MPUC has approved a more current recoveryof the financing costs related to the MERP. The in-service plant costs, including the financing costs duringconstruction, are recovered from customers through a MERP rider, which waseffective Jan. 1, 2006.

 

The capitalexpenditure programs of NSP-Minnesota are subject to continuing review andmodification.  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 providingfor the purchase and delivery of a significant portion of its current coal,nuclear fuel and natural gas requirements. These contracts expire in various years between 2009 and 2028.  In addition, NSP-Minnesota may be required topay additional amounts depending on actual quantities shipped under theseagreements.  The potential risk of loss,in the form of increased costs from market price changes in fuel, is mitigatedthrough the cost-rate adjustment mechanisms, which provide for pass through ofmost fuel, storage and transportation costs.

 

The estimatedminimum purchases for NSP-Minnesota under these contracts as of Dec. 31,2008, is as follows:

 
| **Coal**                            | ** ** | **Nuclear Fuel** | ** ** | **Natural Gas  Supply** | ** ** | **Gas Storage &  Transportation** | ** ** |
|-------------------------------------|------------|-----------------------|------------|------------------------------|------------|-------------------------------------------------|------------|
| **(Millions of Dollars)** |
| $                                   | 665        |                  | $          | 345                          |       | $                                               | 347        |   | $ | 993 |   |
|                                     |            |                       |            |                              |            |                                                 |            |  |  |  |  |

 

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***Purchased PowerAgreements****—*NSP-Minnesotahas entered into agreements with utilities and other energy suppliers forpurchased power to meet system load and energy requirements, replace generationfrom company-owned units under maintenance and during outages and meetoperating reserve obligations. NSP-Minnesota has various pay-for-performance contracts with expirationdates through the year 2032.  In general,these contracts provide for capacity payments, subject to meeting certaincontract obligations and energy payments based on actual power taken under thecontracts.  Certain contractual paymentobligations are adjusted based on indices. However, the effects of these price adjustments are mitigated throughcost-of-energy rate adjustment mechanisms.

 

At Dec. 31,2008, the estimated future payments for capacity, accounted for as executorycontracts, that NSP-Minnesota is obligated to purchase, subject to availability,were as follows:

 
| **(Millions of Dollars)** | ** ** | ** ** | ** ** |
|-------------------------------------|------------|------------|------------|
| 2009                                |       | $          | 108.3      |   |
| 2010                                |       | 111.3      |       |
| 2011                                |       | 110.7      |       |
| 2012                                |       | 108.9      |       |
| 2013                                |       | 111.1      |       |
| 2014 and thereafter                 |       | 399.5      |       |
| Total*                              |       | $          | 949.8      |   |

 

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* Includes amounts allocated to NSP-Wisconsin through intercompanycharges.

 

***Leases*****— NSP-Minnesota leases a variety ofequipment and facilities used in the normal course of business, which areaccounted for as operating leases.  Totalrental expense under operating lease obligations was approximately $70.7million, $53.3 million and $35.7 million for 2008, 2007 and 2006,respectively.  Included in total rentalexpense were purchase power agreement payments of $48.6 million, $29.5 millionand $14.5 million in 2008, 2007 and 2006, respectively.

 

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

 
| **(Millions of Dollars)** | ** ** | **Other  Operating Leases** | ** ** | **Purchased Power  Agreement  Operating Leases (a) (b)** | ** ** | **Total  Operating Leases** | ** ** |
|-------------------------------------|------------|----------------------------------|------------|------------------------------------------------------------------------------|------------|----------------------------------|------------|
| 2009                                |       | $                                | 11.1       |                                                                         | $          | 52.3                             |       | $ | 63.4 |   |
| 2010                                |       | 8.6                              |       | 53.1                                                                         |       | 61.7                             |       |
| 2011                                |       | 6.7                              |       | 54.0                                                                         |       | 60.7                             |       |
| 2012                                |       | 5.3                              |       | 55.0                                                                         |       | 60.3                             |       |
| 2013                                |       | 5.1                              |       | 55.9                                                                         |       | 61.0                             |       |
| Thereafter                          |       | 9.5                              |       | 731.0                                                                        |       | 740.5                            |       |
|                                     |            |                                  |            |                                                                              |            |                                  |            |  |  |  |

 

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(a)             Amountsnot included in purchase power agreement estimated future payments above.

(b)            Purchasepower agreement operating leases expire contractually through 2025.

 

**EnvironmentalContingencies**

** **

NSP-Minnesota has been, or is currently, involved with the cleanup ofcontamination from certain hazardous substances at several sites.  In many situations, NSP-Minnesota believes itwill recover some portion of these costs through insurance claims.  Additionally, where applicable, NSP-Minnesotais pursuing, or intends to pursue, recovery from other potentially responsibleparties (PRPs) and through the rate regulatory process.  New and changing federal and state environmentalmandates can also create added financial liabilities for NSP-Minnesota, whichare normally recovered through the rate regulatory process.  To the extent any costs are not recoveredthrough the options listed above, NSP-Minnesota would be required to recognizean expense.

 

***Site Remediation******—*****NSP-Minnesota must pay all or a portionof the cost to remediate sites where past activities of NSP-Minnesota or otherparties have caused environmental contamination.  Environmental contingencies could arise fromvarious situations including sites of former MGPs operated by 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 sent hazardous materials andwastes.  At Dec. 31, 2008, 

 

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the liability for the cost of remediating these sites was estimated tobe $0.4 million, of which $0.2 million was considered to be a currentliability.

 

***Third Party andOther Environmental Site Remediation***

 

***Asbestos Removal******—*****Some of NSP-Minnesota’s facilitiescontain asbestos.  Most asbestos willremain undisturbed until the facilities that contain it are demolished orremoved.  NSP-Minnesota has recorded anestimate for final removal of the asbestos as an asset retirementobligation.  See additional discussion ofasset retirement obligations below.  Itmay be necessary to remove some asbestos to perform maintenance or makeimprovements to other equipment.  Thecost of removing asbestos as part of other work is immaterial and is recordedas incurred as operating expenses for maintenance projects, capital expendituresfor construction projects or removal costs for demolition projects.

 

***Other EnvironmentalRequirements***

 

***CAIR *—** In March 2005,the EPA issued the CAIR to further regulate SO2 and NOx emissions.  The objective of CAIR was to cap emissions ofSO2 and NOx inthe eastern United States, including Minnesota. In July 2008, the U. S. Court of Appeals for the District ofColumbia vacated CAIR and remanded the rule to the EPA.  On Dec. 23, 2008, the court reinstatedCAIR while the EPA develops new regulations in accordance with the court’s July opinion.

 

Ascurrently written, CAIR has a two-phase compliance schedule, beginning in 2009for NOx and 2010 for SO2, with a final compliance deadline in 2015for both emissions.  Under CAIR, eachaffected state will be allocated an emissions budget for SO2 and NOx that will result in significantemission reductions.  It will be based onstringent emission controls and forms the basis for a cap-and-tradeprogram.  State emission budgets or capsdecline over time.  States can choose toimplement an emissions reduction program based on the EPA’s proposed modelprogram, or they can propose another method, which the EPA would need toapprove.

 

The EPA has drafted a proposed rule to stay the effectiveness ofCAIR in Minnesota.  As such, costestimates are not included at this time for NSP-Minnesota.

 

***CAMR*****—** In March 2005, the EPA issued the CAMR, whichregulated mercury emissions from power plants. In February 2008, the U.S. Court of Appeals for the District ofColumbia vacated CAMR, which impacts federal CAMR requirements, but notnecessarily state-only mercury rules and legislation.  Costs to comply with the Minnesota MercuryEmissions Reduction Act of 2006 are discussed below.

 

***Minnesota MercuryLegislation —***In May 2006, the Minnesotalegislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providinga process for plans, implementation and cost recovery for utility efforts tocurb mercury emissions at certain power plants. For NSP-Minnesota, the Act covers units at the A. S. King and Shercogenerating facilities.  Under the Act,NSP-Minnesota is operating and maintaining continuous mercury emissionmonitoring systems.  The informationobtained will be used to establish a baseline from which to measure mercuryemission reductions.

 

On Dec. 21, 2007, NSP-Minnesota filed mercury emission reductionplans for two dry scrubbed units, Sherco Unit 3 and A. S. King, as well as acomprehensive emissions reduction and capacity upgrade proposal for ShercoUnits 1 and 2 (wet scrubbed units).  Arevised specific mercury reduction proposals for these units will be filed by Dec. 31,2009, as required by the legislation. Current plans are to install a sorbent injection system at both A. S.King and Sherco Unit 3.  Implementationwould occur by Dec. 31, 2009, at Sherco Unit 3 and by Dec. 31, 2010,for A. S. King.  For these units, thecurrent total capital costs estimate is $8.5 million, with the annual costestimate of $4.3 million for A. S. King and $4.2 million for Sherco Unit 3.  For Sherco Units 1 and 2, the current costestimate is $13.6 million for capital and $10 million annual expenses.

 

Utilities subject to the Act may also submit plans to addressnon-mercury pollutants subject to federal and state statutes and regulations,which became effective after Dec. 31, 2004.  Cost recovery provisions of the Act alsoapply to these other environmental initiatives. In September 2006, NSP-Minnesota filed a request with the MPUC forrecovery of up to $6.3 million of certain environmental improvement coststhat are expected to be recoverable under the Act.  In January 2007, the MPUC approved thisrequest to defer these costs as a regulatory asset with a cap of$6.3 million.  On Aug. 26,2008, NSP-Minnesota filed a request with the MPUC to increase the deferral to$19.4 million as NSP-Minnesota anticipated exceeding the authorized deferralamount in September 2008.  On Nov. 6,2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 andA. S. King mercury emission reduction plans.

 

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***Voluntary CapacityUpgrade and Emissions Reduction Filing*** — In December 2007,NSP-Minnesota filed a plan with the MPCA and MPUC for reducing mercuryemissions by up to 90 percent at the Sherco Unit 3 and A. S. King plants.  Currently, the estimated project costs areapproximately $8.5 million.  At the sametime, NSP-Minnesota submitted a revised filing to the MPUC for a majoremissions reduction project at Sherco Units 1 and 2 to reduce emissions andexpand capacity.  The revised filing hasestimated project costs of approximately $1.1 billion.  The filing also contains alternatives for theMPUC to consider to add additional capacity and to achieve even loweremissions.  If selected, thesealternatives could range from $90.8 to $330.8 million in addition to the $1.1billion proposal.  NSP-Minnesota’sinvestments are subject to MPUC approval of a cost recovery mechanism.  The MPCA has issued its assessment that theSherco Unit 3 and A. S. King plans are appropriate.  In light of recent significant changes in thenational economy, lower forecast of energy consumption, and new informationconcerning an emerging technology that may be more cost effective,NSP-Minnesota filed a request with the MPUC to withdraw the plan on Nov. 6,2008, to allow NSP-Minnesota to reevaluate alternatives.  The MPUC granted the withdrawal request on Dec. 9,2008.

 

***Regional Haze Rules *****—** In June 2005, the EPA finalized amendments to the July 1999regional haze rules.  These amendmentsapply to the provisions of the regional haze rule that require emissioncontrols, known as BART, for industrial facilities emitting air pollutants thatreduce visibility by causing or contributing to regional haze.

 

The EPA required states to develop implementation plans to comply withBART by December 2007. NSP-Minnesota submitted its BART alternatives analysis for Sherco Units1 and 2 in October 2006.  The MPCAreviewed the BART analyses for all units in Minnesota and determined thatoverall, compliance with CAIR is better than BART.  In July 2008, the U. S. Circuit Court ofAppeals for the District of Columbia vacated CAIR and remanded the rule tothe EPA.  In December 2008, theCourt of Appeals reinstated CAIR while the EPA develops new regulations inaccordance with the Court’s July opinion. For Minnesota facilities, however, the EPA has drafted a proposed rule thatwould stay the effectiveness of CAIR within the state.  Therefore, the MPCA has reestablished theBART process and requested that companies with BART-eligible units inform theMPCA whether the company will rely on the initial 2006 BART determinationsubmittal or if they intend to submit a revised analysis.  On Nov. 13, 2008, NSP-Minnesotasubmitted a revised BART alternatives analysis letter to the MPCA to accountfor increased construction and equipment costs. The underlying conclusions and proposed emission control equipment,however, remained unchanged from the original 2006 BART analysis.

 

***Federal Clean Water Act —***Thefederal Clean Water Act requires the EPA to regulate cooling water intakestructures to assure that these structures reflect the best technologyavailable (BTA) for minimizing adverse environmental impacts.  In July 2004, the EPA published phase IIof the rule, which applies to existing cooling water intakes at steam-electricpower plants.  Several lawsuits werefiled against the EPA in the United States Court of Appeals for the SecondCircuit challenging the phase II rulemaking. In January 2007, the court issued its decision and remandedvirtually every aspect of the rule to the EPA for reconsideration.  In June 2007, the EPA suspended thedeadlines and referred any implementation to each state’s best professionaljudgment until the EPA is able to fully respond to the court-orderedremand.  As a result, the rule’scompliance requirements and associated deadlines are currently unknown.  It is not possible to provide an accurateestimate of the overall cost of this rulemaking at this time due to the manyuncertainties involved.  In April 2008, the U.S. Supreme Courtgranted limited review of the Second Circuit’s opinion to determine whether theEPA has the authority to consider costs and benefits in assessing BTA.  A decision is not expected until 2009.

 

The MPCA exercised its authority under “best professional judgment” torequire Black Dog Generating Station in its recently renewed wastewaterdischarge permit to create a plan by April 2010 to reduce the plant intake’simpact on aquatic wildlife. NSP-Minnesota is discussing alternatives with the local community andregulatory agencies to address this concern.

 

# **AssetRetirement Obligations**

#  

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

 

***Recorded ARO —***AROshave been recorded for plant related to nuclear production, steam production,electric transmission and distribution, gas distribution and officebuildings.  The steam productionobligation includes asbestos, ash containment facilities, 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.  

 

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Generally,this asbestos abatement removal obligation originated in 1973 with the CleanAir Act, which applied to the demolition of buildings or removal of equipmentcontaining asbestos that can become airborne on removal.  AROs also have been recorded for NSP-Minnesotasteam production related to ash-containment facilities such as bottom ashponds, evaporation ponds and solid waste landfills.  The origination date on the ARO recognitionfor ash-containment facilities at steam plants was the in-service date of variousfacilities.  A new ARO has been recordedfor steam production plant related to radiation sources in equipment used tomonitor the flow of coal, lime and other materials through feeders.  The origination date on the new ARO is 2008,the in-service date of the monitoring equipment.

 

In 2008, NSP-Minnesota recognized an ARO associated with the windturbines at the new Grand Meadow Wind Farm. The turbines are located on leased property, and under the leaseagreements, must be removed when no longer used.  The recognition of the ARO was due to theunits being placed in service in the fourth quarter of 2008.

 

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

 

For thenuclear assets, the ARO associated with the decommissioning of twoNSP-Minnesota nuclear generating plants, Monticello and Prairie Island,originates with the in-service date of the facility.  Monticello began operation in 1971.  Prairie Island units 1 and 2 began operationin 1973 and 1974, respectively.  See Note15 to the consolidated financial statements for further discussion of nuclearobligations.

 

Areconciliation of the beginning and ending aggregate carrying amounts ofNSP-Minnesota’s AROs is shown in the table below for the 12 months ended Dec. 31,2008 and Dec. 31, 2007, respectively:

 
| **(Thousands of Dollars)**   | ** ** | **Beginning  Balance  Jan. 1, 2008** | ** ** | **Liabilities  Recognized** | ** ** | **Liabilities  Settled** | ** ** | **Accretion** | ** ** | **Revisions  To Prior  Estimates** | ** ** | **Ending  Balance  Dec. 31, 2008** | ** ** |
|----------------------------------------|------------|------------------------------------------------|------------|-----------------------------|------------|--------------------------|------------|---------------|------------|-----------------------------------------|------------|----------------------------------------------|------------|
| ** **                             | ** ** | ** **                                     | ** ** | ** **                  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                              | ** ** | ** **                                   | ** ** |
| **Electric Utility 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                                          |       |
| **Gas Utility Plant:**                 |       |                                           |       |                        |       |                     |       |          |       |                                    |       |                                         |       |
| Gas transmission and distribution      |       | 12,685                                         |       | —                      |       | —                   |       | 314           |       | (12,754                                 | )          | 245                                          |       |
| **Common Utility 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 |   |

 

The fair valueof NSP-Minnesota assets legally restricted for purposes of settling the nuclearAROs is $1.1 billion as of Dec. 31, 2008, including external nucleardecommissioning investment funds and internally funded amounts.

 

A new decommissioning study filed with the MPUC in 2008 proposed theextension of the final removal date of the Monticello and Prairie Islandnuclear plants by 14 and 26 years, respectively, effective Jan. 1,2009.  As a result of the studies for theMonticello and Prairie Island nuclear plants, the nuclear productiondecommissioning ARO and related regulatory asset decreased by $128.5 millionand $139.3 million, respectively, in the fourth quarter of 2008.

 

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NSP-Minnesota also incurred revisions to prior estimates for asbestos,ash ponds, gas distribution and electric transmission and distribution assetretirement obligations due to revised estimates and end of life dates.

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

 

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

 

***Removal Costs*****— NSP-Minnesota accrues an obligation forplant removal costs for generation, transmission and distributionfacilities.  Generally, the accrual offuture non-ARO removal obligations is not required.  However, long-standing ratemaking practicesapproved by applicable state and federal regulatory commissions have allowedprovisions for such costs in historical depreciation rates.  These removal 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 under SFAS No. 71.  Removal costs as of Dec. 31, 2008 and2007 were $354 million and $342 million, respectively.

 

**Nuclear Insurance**

** **

NSP-Minnesota’s public liability for claims resulting from any nuclearincident is limited to $12.5 billion under the Price-Anderson amendment tothe Atomic Energy Act of 1954, as amended. NSP-Minnesota has secured $300 million of coverage for its publicliability exposure with a pool of insurance companies.  The remaining $12.2 billion of exposureis funded by the Secondary Financial Protection Program, available fromassessments by the federal government in case of a nuclear accident.  NSP-Minnesota is subject to assessments of upto $117.5 million per reactor per accident for each of its three licensedreactors, to be applied for public liability arising from a nuclear incident atany licensed nuclear facility in the United States.  The maximum funding requirement is$17.5 million per reactor during any one year.  These maximum assessment amounts are bothsubject to inflation adjustment by the NRC and state premium taxes.  The NRC’s last adjustment was effective Oct. 29,2008.  The next adjustment is due on orbefore Oct. 29, 2013.

 

NSP-Minnesota purchases insurance for property damage and sitedecontamination cleanup costs from Nuclear Electric Insurance Ltd.(NEIL).  The coverage limits are$2.3 billion for each 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 beenaccumulated in the reserve funds of NEIL to the extent that NSP-Minnesota wouldhave no exposure for retroactive premium assessments in case of a singleincident under the business interruption and the property damage insurance 

 

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coverage.  However, in eachcalendar year, NSP-Minnesota could be subject to maximum assessments ofapproximately $16.1 million for business interruption insurance and$29.7 million for property damage insurance if losses exceed accumulatedreserve funds.

 

**Legal Contingencies**

 

Lawsuits and 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 DioxideEmissions Lawsuit —***In July 2004, theattorneys general of eight states and New York City, as well as severalenvironmental groups, filed lawsuits in U.S. District Court in the SouthernDistrict of New York against five utilities, including Xcel Energy, to forcereductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co.,Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisanceas defined under state and federal common law because it has contributed toglobal warming.  The lawsuits do notdemand monetary damages.  Instead, thelawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and the other defendants filed amotion to dismiss the lawsuit.  On Sept.19, 2005, the court granted the motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the U.S. Courtof Appeals for the Second Circuit.  In June 2007the Court of Appeals issued an order requesting the parties to file a letterbrief regarding the impact of the United States Supreme Court’s decision inMassachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raisedby the parties on appeal.  Among otherthings, in its decision in *Massachusetts v.EPA*, the United States Supreme Court held that CO2 emissions are a “pollutant” subject toregulation by the EPA under the CAA.  In July 2007,in response to the request of the Court of Appeals,  the defendant utilities filed a letter briefstating the position that the United States Supreme Court’s decision supportsthe arguments raised by the utilities on appeal.  The Court of Appeals has taken the matterunder advisement and is expected to issue an opinion in due course.

 

## ***Comer vs. Xcel Energy Inc. et al. —*** In April 2006, Xcel Energy receivednotice of a purported class action lawsuit filed in U.S. District Court in theSouthern District of Mississippi.  Thelawsuit names more than 45 oil, chemical and utility companies, including XcelEnergy, as defendants and alleges that defendants’ 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.  In September 2007, plaintiffs filed anotice of appeal to the U.S. Court of Appeals for the Fifth Circuit.  Oral arguments were presented to the Court ofAppeals on Aug. 6, 2008.  Pursuantto the court’s order of Sept. 26, 2008, re-argument was held on Nov. 3,2008.  No explanation was given for theorder.  The Court of Appeals has takenthe matter under advisement.

##  

## ***Native Village of Kivalina vs. Xcel Energy Inc. etal. —*** In February 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 utilities, oil, gas and coal companies.  The suit was brought on behalf ofapproximately 400 native Alaskans, the Inupiat Eskimo, who claim thatDefendants’ emission of CO2 and other greenhouse gases (GHG) contribute toglobal warming, which is harming their village. Plaintiffs claim that as a consequence, the entire village must berelocated at a cost of between $95 million and $400 million.  Plaintiffs assert a nuisance claim underfederal and state common law, as well as a claim asserting “concert of action”in which defendants are alleged to have engaged in tortious acts in concertwith each other.  Xcel Energy was not named in the civil conspiracy claim.  Xcel Energy believes the claims asserted inthis lawsuit are without merit and joined with other utility defendants infiling a motion to dismiss on June 30, 2008.  Thematter has now been fully briefed, with oral arguments set for May 19,2009.  It is unknown when the court willrender a decision.

##  

**Employment,Tort and Commercial Litigation**

** **

***Siewert vs. XcelEnergy —***In June 2004, plaintiffs, the ownersand operators of a Minnesota dairy farm, brought an action in Minnesota statecourt against NSP-Minnesota alleging negligence in the handling, supplying,distributing and selling of electrical power systems; negligence in theconstruction and maintenance of distribution systems; and failure to warn oradequately test such systems.  Plaintiffsallege decreased milk production, injury and damage to a dairy herd as a resultof 

 

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stray voltage resulting from NSP-Minnesota’s distribution system.  Plaintiffs claim losses of approximately$7 million.  NSP-Minnesota deniesall allegations.  After its motion todismiss plaintiffs’ claims was denied, NSP-Minnesota filed a motion to certifyquestions for immediate appellate review. In October 2007, the court granted NSP- Minnesota’s motion forcertification, and oral arguments took place on Sept. 11, 2008.  Mediation took place on Oct. 14, 2008,but the matter was not resolved.  In December 2008,the Court of Appeals issued a decision ordering dismissal of Plaintiffs’ claimsfor injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions andordering the matter remanded for trial. The Minnesota Supreme Court subsequently granted NSP-Minnesota’spetition for further review on Feb. 17, 2009.

 

***Hoffman vs. NorthernStates Power Company —***In March 2006, apurported class action complaint was filed in Minnesota state court, on behalfof NSP-Minnesota’s residential customers in Minnesota, North Dakota and SouthDakota for alleged breach of a contractual obligation to maintain and inspectthe points of connection between NSP-Minnesota’s wires and customers’ homeswithin the meter box.  Plaintiffs claimNSP-Minnesota’s alleged breach results in an increased risk of fire and is inviolation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to thevalue of inspections plaintiffs claim NSP-Minnesota was required to performover the past six years.  In August 2006,NSP-Minnesota filed a motion for dismissal on the pleadings.  In November 2006, the court issued anorder denying NSP-Minnesota’s motion, but later, pursuant to a motion byNSP-Minnesota, certified the issues raised in NSP-Minnesota’s original motionfor appeal as important and doubtful, and NSP-Minnesota filed an appeal withthe Minnesota Court of Appeals.  In January 2008,the Minnesota Court of Appeals determined the plaintiffs’ claims are barred bythe filed rate doctrine and remanded the case to the district court fordismissal.  Plaintiffs petitioned theMinnesota Supreme Court for discretionary review, and the Supreme Court grantedthe petition.  Oral argument took placeon Nov. 4, 2008.  It is unknown whena decision will be issued.

 

***Nuclear WasteDisposal Litigation —***In 1998, NSP-Minnesota fileda complaint in the U.S. Court of Federal Claims against the United Statesrequesting breach of contract damages for the U.S. Department of Energy’s (DOE)failure to begin accepting spent nuclear fuel by Jan. 31, 1998, asrequired by the contract between the DOE and NSP-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 and regulatory treatment and amounts to be shared with ratepayers havebeen resolved.  Given the uncertainties,it is unclear as to how much, if any, of this judgment will ultimately have anet impact on earnings.

 

In August 2007, NSP-Minnesota filed a second complaint against theDOE in the U.S. Court of Federal Claims (NSP II), again claiming breach ofcontract damages 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. The amount of such damages is expected to exceed $40 million.  In January 2008, the court granted theDOE’s motion to stay, but the stay was lifted in November 2008.  The court’s scheduling order provides thatthe parties will exchange expert reports in 2009, and that all discovery willbe completed by the end of 2009.  Trialis expected to take place in 2010.

 

***Fargo Gas Explosion—***In September 2008, an explosion occurred ata duplex in Fargo, N.D.  The explosiondestroyed one side of the duplex and resulted in injuries to some of theresidents.  Xcel Energy subsequentlyprovided a report to the U.S. Dept. of Transportation Pipeline and HazardousMaterials Safety Administration stating that natural gas migrated into thehouse and was ignited by an unknown source. Investigators identified a natural gas leak the size of a pinholelocated 18 inches underground.  Theproperty owners and attorneys representing the injured residents have put XcelEnergy on notice of potential claims. Investigation into the incident is continuing.

 

**15. NuclearObligations**

 

***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 $13 million in 2008, 2007 and2006, respectively.  In total, NSP-Minnesota

 

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had paid approximately $386 million to the DOE through Dec. 31,2008.  The Nuclear Waste Policy Act of1982 required the DOE to begin accepting spent nuclear fuel no later than Jan. 31,1998.  In 1996, the DOE notifiedcommercial spent-fuel owners of an anticipated delay in accepting spent nuclearfuel by the required date and conceded that a permanent storage or disposalfacility will not be available until at least 2010.  NSP-Minnesota and other utilities havecommenced lawsuits against the DOE to recover damages caused by the DOE’sfailure to meet its statutory and contractual obligations.

 

NSP-Minnesota has its own temporary on-site storage facilities forspent fuel at its Monticello and Prairie Island nuclear plants, which consistof storage pools and dry cask facilities at both sites.  The amount of spent fuel storage capacitycurrently authorized by the NRC and the MPUC will allow NSP-Minnesota tocontinue operation of its Prairie Island nuclear plant until the end of itscurrent license terms in 2013 and 2014 and its Monticello nuclear plant untilthe end of its renewed operating license in 2030.  Other alternatives for spent fuel storage arebeing investigated until a DOE facility is available, including pursuing theestablishment of a private facility for interim storage of spent nuclear fuelas part of a consortium of electric utilities.

 

***Regulatory PlantDecommissioning Recovery —***Decommissioning ofNSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is plannedfor the period from cessation of operations through 2067, assuming the promptdismantlement method.  NSP-Minnesota iscurrently recording the regulatory costs for decommissioning over the MPUC-approvedcost-recovery period and including the accruals in a regulatory liabilityaccount.  The total decommissioning costobligation is recorded as an ARO in accordance with SFAS No. 143.

 

Monticello began operation in 1971 and with its renewed operating licenseand certificate of need for spent fuel capacity to support 20 years of extendedoperation can operate until 2030. Prairie Island units 1 and 2 began operation in 1973 and 1974,respectively, and are currently licensed to operate until 2013 and 2014, respectively.  The Monticello 20-year depreciation lifeextension until September 2030 was granted by the MPUC on Sept. 21,2007.  Construction of the Monticellodry-cask storage facility commenced on June 4, 2007.  Construction of the facility is complete and10 of the 30 canisters authorized have been filled and placed in thefacility.  Plant assessments and otherwork for the Prairie Island license renewal applications started in 2006.  In April 2008, NSP-Minnesotafiled an application with the NRC to renew the operating license of its twonuclear reactors at Prairie Island for an additional 20 years until 2033 and2034, respectively.  The PIIC filedcontentions in the NRC’s license renewal proceeding in August 2008.  The PIIC request was referred to an ASLBfor review.  The ASLB has granted thePIIC hearing request and has admitted seven of the 11 contentions filed.  The resulting adjudicatory process andhearings are expected to add approximately eight months onto the NRC’s standard22 month review schedule (without hearings) resulting in the NRC not making adecision on whether or not to renew the Prairie Island operating licenses untillate 2010.  An application for acertificate of need to expand the spent fuel storage capacity at Prairie Islandto support 20 additional years of operation was filed with the MPUC in May 2008.  It is expected that the MPUC will act in late2009 allowing the MPUC decision to be stayed during the 2010 session of theMinnesota legislature before going into effect.

 

The total obligation for decommissioning currently is expected to befunded 100 percent by external funds, as approved by the MPUC, whendecommissioning commences.  The MPUC lastapproved NSP-Minnesota’s nuclear decommissioning study request in March 2006,using 2005 cost data with the next study update submitted in October 2008for the 2009 accrual.  The MPUC approval,decreasing 2006 decommissioning funding for Minnesota retail customers,resulted from an extension of remaining life for the Monticello unit by10 years (from 2010 to 2020). Contributions to the external fund started in 1990 and are expected tocontinue until plant decommissioning begins. The assets held in trusts, primarily consisted of investments in fixedincome securities, such as tax-exempt municipal bonds and U.S. governmentsecurities that mature in one to 20 years and common stock of publiccompanies.  NSP-Minnesota plans toreinvest matured securities until decommissioning begins.

 

Consistent with cost recovery in utility customer rates, NSP-Minnesotarecords annual decommissioning accruals based on periodic site-specific coststudies and a presumed level of dedicated funding.  Cost studies quantify decommissioning costsin current dollars.  Current authorizedfunding presumes that costs will escalate in the future at a rate of3.61 percent per year.  The totalestimated decommissioning costs that will ultimately be paid, net of incomeearned by external trust funds, is currently being accrued using an annuityapproach over the approved plant-recovery period.  This annuity approach uses an assumed rate ofreturn on funding, which is currently 5.40 percent, net of tax, forexternal funding.  The net unrealized gainon nuclear decommissioning investments is deferred as a regulatory liabilitybased on the assumed offsetting against decommissioning costs in currentratemaking treatment.

 

At Dec. 31, 2008, NSP-Minnesota had recorded and recovered inrates cumulative decommissioning expense of $1.3 billion.  The following table summarizes the funded statusof NSP-Minnesota’s decommissioning obligation based on approved

 

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regulatory recovery parameters. Xcel Energy believes future decommissioning cost expense will continueto be recovered in customer rates.  Theseamounts are not those recorded in the financial statements for the ARO inaccordance with SFAS No. 143.

 
| **(Thousands of Dollars)**                                                        | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|---------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| Estimated decommissioning cost obligation  from most recently approved study (2005 dollars) |       | $          | 1,683,750  |       | $          | 1,683,750 |   |
| Effect of escalating costs to 2008 and 2007  dollars (3.61 percent per year)                |       | 189,012    |       | 123,761    |       |
| Estimated decommissioning cost obligation  in current dollars                               |       | 1,872,762  |       | 1,807,511  |       |
| Effect of escalating costs to payment date  (3.61 percent per year)                         |       | 1,254,064  |       | 1,319,315  |       |
| Estimated future decommissioning costs  (undiscounted)                                      |       | 3,126,826  |       | 3,126,826  |       |
| Effect of discounting obligation (using  risk-free interest rate)                           |       | (1,847,526 | )          | (1,502,030 | )          |
| Discounted decommissioning cost obligation                                                  |       | 1,279,300  |       | 1,624,796  |       |
| Assets held in external decommissioning  trust                                              |       | 1,075,294  |       | 1,317,564  |       |
| Discounted decommissioning obligation in  excess of assets currently held in external trust |       | $          | 204,006    |       | $          | 307,232 |   |

 

Decommissioning expenses recognized include the following components:

 
| **(Thousands of Dollars)**                                   | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Annual decommissioning cost expense  reported as depreciation expense: |       |     |       |     |       |     |       |
| Externally funded                                                      |       | $        | 43,239     |     | $          | 43,392   |       | $ | 48,069 |   |
| Internally funded (including interest  costs)                          |       | (819     | )          | (759     | )          | (5,046   | )          |
| Net decommissioning expense recorded                                   |       | $        | 42,420     |     | $          | 42,633   |       | $ | 43,023 |   |

 

Reductions to expense for internally-funded portions in 2008, 2007 and2006 are a direct result of the 2005 decommissioning study jurisdictionalallocation and 100 percent external funding approval, effectivelyunwinding the remaining internal fund over the remaining operating life of theunit.  The 2005 nuclear decommissioningfiling approved in 2006 has been used for the regulatory presentation.  The change in estimated decommission obligationswas calculated using a cost estimate for Monticello assuming a 60-yearoperating life.

 

**16.Regulatory Assets and Liabilities**

 

NSP-Minnesota’s consolidated financial statements are prepared inaccordance with the provisions of SFAS No. 71, as discussed in Note 1 tothe consolidated financial statements. Under SFAS No. 71, regulatory assets and liabilities can be createdfor amounts that regulators may allow to be collected, or may require to bepaid back to customers in future electric and natural gas rates.  Any portion of the business that is not rateregulated cannot use SFAS No. 71 accounting.  If changes in the utility industry or thebusiness of NSP-Minnesota no longer allow for the application of SFAS No. 71under GAAP, NSP-Minnesota would be required to recognize the write-off ofregulatory assets and liabilities in its consolidated statement of income.

 

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The components of unamortized regulatory assets and liabilities on theconsolidated balance sheets of NSP-Minnesota are:

 
| ** **                                                | ** ** | ** **        | ** ** | **Remaining Amortization**              | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------|------------|-------------------|------------|----------------------------------------------|------------|------------|------------|------------|------------|
| **(Thousands of Dollars)**                      | ** ** | **See Note** | ** ** | **Period**                                   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
| ** **                                                | ** ** | ** **        | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Regulatory Assets**                                     |       |              |       |                                         |       |       |       |       |       |
| Current regulatory asset — Unrecovered fuel  costs   |       | 1                 |       | Less than  one year                          |       | $          | 26,605     |       | $          | 36,857 |   |
|                                                      |       |              |       |                                         |       |       |       |       |       |
| Net AROs (a)                                              |       | 14                |       | Plant lives                                  |       | $          | 256,791    |       | $          | 20,776 |   |
| Pension and employee benefit obligations                  |       |              |       | Various                                      |       | 153,892    |       | —     |       |
| AFDC recorded in plant (b)                                |       |              |       | Plant lives                                  |       | 124,242    |       | 112,750    |       |
| Contract valuation adjustments (c)                        |       | 10                |       | Term of  contract                            |       | 86,937     |       | 82,137     |       |
| Renewable resource costs                                  |       |              |       | Two to three  years                          |       | 44,790     |       | 44,238     |       |
| Nuclear outage costs                                      |       | 13                |       | Generally  18-24 months                      |       | 40,690     |       | —     |       |
| Losses on reacquired debt                                 |       | 1                 |       | Term of  related debt                        |       | 26,081     |       | 28,666     |       |
| Conservation programs (b)                                 |       |              |       | Various                                      |       | 23,911     |       | 18,293     |       |
| Unrecovered natural gas costs                             |       | 1                 |       | One to two  years                            |       | 14,657     |       | 22,505     |       |
| Purchased power contracts costs                           |       | 10                |       | Term of  contract                            |       | 13,228     |       | —     |       |
| Nuclear fuel storage                                      |       |              |       | Four years                                   |       | 9,652      |       | 11,578     |       |
| MISO day 2 costs                                          |       |              |       | To be  determined in future rate proceedings |       | 8,742      |       | 5,826      |       |
|                                                      |       |              |       |                                         |       |       |       |       |       |
| State commission accounting  adjustments (b)         |       |              |       | Plant lives                                  |       | 4,398      |       | 4,158      |       |
| Other                                                     |       |              |       | Various                                      |       | 20,701     |       | 8,855      |       |
| Total noncurrent regulatory assets                        |       |              |       |                                         |       | $          | 828,712    |       | $          | 359,782 |   |
|                                                      |       |              |       |                                         |       |       |       |       |       |
| **Regulatory Liabilities**                                |       |              |       |                                         |       |       |       |       |       |
| Plant removal costs                                       |       | 14                |       |                                         |       | $          | 354,117    |       | $          | 342,207 |   |
| Deferred income tax adjustments                           |       |              |       |                                         |       | 30,787     |       | 42,611     |       |
| Investment tax credit deferrals                           |       |              |       |                                         |       | 27,797     |       | 30,211     |       |
| Contract valuation adjustments (c)                        |       |              |       |                                         |       | 23,355     |       | 14,275     |       |
| Nuclear outage costs collected in advance  from customers |       |              |       |                                         |       | 13,678     |       | —     |       |
| Gain on sale of emission allowances                       |       |              |       |                                         |       | 2,727      |       | 2,885      |       |
| Interest on income tax refunds                            |       |              |       |                                         |       | 1,736      |       | 3,472      |       |
| Pension and employee benefit obligations                  |       | 8                 |       |                                         |       | —     |       | 195,394    |       |
| Other                                                     |       |              |       |                                         |       | 5,683      |       | 8,173      |       |
| Total noncurrent regulatory liabilities                   |       |              |       |                                         |       | $          | 459,880    |       | $          | 639,228 |   |

 

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

(b)            Earnsa return on investment in the ratemaking process.  These amounts are amortized consistent withrecovery in rates.

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

 

**17.Segments and Related Information**

 

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

 

·                  NSP-Minnesota’sregulated electric utility segment generates, transmits and distributeselectricity in Minnesota, North Dakota and South Dakota.  In addition, this segment includes sales forresale and provides wholesale transmission service to various entities in theUnited States.  Regulated electricutility also includes NSP-Minnesota’s commodity trading operations.

 

·                  NSP-Minnesota’sregulated natural gas utility segment transports, stores and distributesnatural gas in portions of Minnesota and North Dakota.

 

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Revenues fromoperating segments not included above are below the necessary quantitativethresholds and are 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.

 

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

 

To report net income for regulated electric and regulated natural gas utilitysegments, NSP-Minnesota must assign or allocate all costs and certain otherincome.  In general, costs are:

 

·              Directlyassigned wherever applicable;

·              Allocatedbased on cost causation allocators wherever applicable; or

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

 

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

 
| **(Thousands of Dollars)**       | ** ** | **Regulated  Electric** | ** ** | **Regulated  Natural  Gas** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|--------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| **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 costs       |       | 162,697                 |       | 17,464                      |       | 1,454          |       | (386                          | )          | 181,229                 |       |
| Income tax expense                         |       | 167,961                 |       | 12,509                      |       | (2,234         | )          | —                        |       | 178,236                 |       |
| Net income                                 |       | $                       | 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 costs       |       | 151,012                 |       | 17,256                      |       | 707            |       | (16                           | )          | 168,959                 |       |
| Income tax expense                         |       | 165,531                 |       | 11,315                      |       | 5,179          |       | —                        |       | 182,025                 |       |
| Net income (loss)                          |       | $                       | 246,086    |                        | $          | 21,485         |       | $                             | (269       | )                       | $          | — |   | $ | 267,302 |   |
|                                       |       |                    |       |                        |       |           |       |                          |       |                    |       |
| **2006**                                   |       |                    |       |                        |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                       | 3,265,371  |                        | $          | 744,635        |       | $                             | 17,609     |                    | $          | — |   | $ | 4,027,615 |   |
| Intersegment revenues                      |       | 496                     |       | 8,929                       |       | —         |       | (9,425                        | )          | —                  |       |
| Total revenues                             |       | $                       | 3,265,867  |                        | $          | 753,564        |       | $                             | 17,609     |                    | $          | (9,425 | ) | $ | 4,027,615 |   |
| Depreciation and amortization              |       | $                       | 393,560    |                        | $          | 31,566         |       | $                             | 385        |                    | $          | — |   | $ | 425,511 |   |
| Interest charges and financing costs       |       | 134,347                 |       | 15,539                      |       | 1,040          |       | (4                            | )          | 150,922                 |       |
| Income tax expense (benefit)               |       | 138,077                 |       | 5,448                       |       | (15,919        | )          | —                        |       | 127,606                 |       |
| Net income                                 |       | $                       | 242,815    |                        | $          | 9,674          |       | $                             | 19,821     |                    | $          | — |   | $ | 272,310 |   |

 

**18.  Related Party Transactions**

 

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

 

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Xcel Energy has established a utility money pool arrangement with theutility subsidiaries.  See Note 4 forfurther discussion of this borrowing arrangement.

 

***Nuclear PlantOperation —*** On Sept. 28, 2007, NSP-Minnesotaobtained 100 percent ownership in NMC as a result of Wisconsin EnergyCorporation (WEC), exiting the partnership due to the sale of its Point BeachNuclear Plant to FPL Energy.  Accordingly,the results of operations of NMC and the estimated fair value of assets andliabilities were included in NSP-Minnesota’s consolidated financial statementsfrom the Sept. 28, 2007, transaction date. WEC was required to pay an exit fee and surrender all of its equity interestin NMC upon exiting.  The effect of thistransaction was not material to the financial position or the results ofoperations to NSP-Minnesota for the year ended Dec. 31, 2007.  NSP-Minnesota has reintegrated its nuclearoperations into its generation operations. The NRC transferred the nuclearoperating licenses from NMC to NSP-Minnesota effective Sept. 22, 2008.

 

Prior to Sept. 28, 2007, NSP-Minnesota also paid its proportionateshare of the operating expenses and capital improvement costs incurred by NMC,in accordance with the Nuclear Power Plant Operating Services Agreement.  NSP-Minnesota paid the NMC $235.2 million in2007 and $292.5 million in 2006.

 

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

 

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

 
| **(Thousands of Dollars)**                       | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Operating revenues:                                        |       |     |       |     |       |     |       |
| Electric utility                                           |       | $        | 390,143    |     | $          | 372,215  |       | $ | 322,733 |   |
| Natural gas utility                                        |       | 312      |       | 366      |       | 350      |       |
| Operating expenses:                                        |       |     |       |     |       |     |       |
| Purchased power                                            |       | 64,195   |       | 79,345   |       | 61,342   |       |
| Transmission expense                                       |       | 42,167   |       | 40,872   |       | 38,061   |       |
| Other operations — paid to Xcel Energy  Services Inc. |       | 275,618  |       | 267,281  |       | 284,108  |       |
| Interest expense                                           |       | 1,645    |       | 1,742    |       | 1,083    |       |
| Interest income                                            |       | 2,536    |       | 1,422    |       | 4,497    |       |
|                                                            |            |          |            |          |            |          |            |  |  |  |

 

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

 
| ** **                           | ** ** | **2008**                 | ** ** | **2007**              | ** ** |
|--------------------------------------|------------|--------------------------|------------|-----------------------|------------|
| **(Thousands of Dollars)** | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** | **Accounts  Receivable** | ** ** | **Accounts  Payable** | ** ** |
| NSP-Wisconsin                        |       | $                        | 12,416     |                  | $          | — |   | $ | 20,918 |   | $ | — |   |
| PSCo                                 |       | —                   |       | 15,987                |       | — |   | 17,440 |   |
| SPS                                  |       | —                   |       | 3,330                 |       | — |   | 8,332 |   |
| Other subsidiaries of Xcel Energy    |       | 2                        |       | 32,974                |       | 10,160 |   | 28,203 |   |
|                                 |       | $                        | 12,418     |                  | $          | 52,291 |   | $ | 31,078 |   | $ | 53,975 |   |

 

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota atNSP-Minnesota’s average daily interest rate, including the cost ofNSP-Minnesota’s compensating balance requirements.  At Dec. 31, 2008 and 2007, NSP-Minnesotahad notes receivable outstanding from NSP-Wisconsin in the amount of $0.0 millionand $58.6 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, 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 |   |
|                                      |            |                              |            |  |  |  |  |  |  |  |  |  |  |

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

 

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

 

During 2007 and 2008, and through the date of this report, there wereno disagreements with the independent public accountants for NSP-Minnesota onaccounting principles or practices, financial statement disclosures or auditingscope or procedures.

 

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

 

**DisclosureControls and Procedures**

 

NSP-Minnesota maintains a set of disclosure controls and proceduresdesigned to ensure that information required to be disclosed in reports that itfiles or submits under the Securities Exchange Act of 1934 is recorded,processed, summarized and reported within the time periods specified inSecurities and Exchange Commission rules and forms.  In addition, 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, 2008,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**

 

No change in NSP-Minnesota’s internal control over financial reportinghas occurred during the most recent fiscal quarter that has materiallyaffected, or is reasonably likely to materially affect, NSP-Minnesota’sinternal control over financial reporting. NSP-Minnesota maintains internal control over financial reporting toprovide reasonable assurance regarding the reliability of the financialreporting.  NSP-Minnesota has evaluatedand documented its controls in process activities, in general computeractivities, and on an entity-wide level. During the year and in preparation for issuing its report for the yearended Dec. 31, 2008 on internal controls under section 404 of theSarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring ofits internal control over financial reporting. Based on the control evaluation, testing and remediation performed,NSP-Minnesota did not identify any material control weaknesses, as definedunder the standards and rules issued by the Public Company AccountingOversight Board (PCAOB) and as approved by the SEC and as indicated inManagement Report on Internal Controls herein.

 

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

 

**Item 9B**— **Other Information**

 

None.

 

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**PART III**

 

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

 

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

 

**Item 11 — Executive Compensation**

 

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

 

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

 

**Item 14 — Principal Accounting Fees andServices**

 

Informationconcerning fees paid to the principal accountant for each of the last two yearsis contained in the Xcel Energy Proxy Statement for its 2009 Annual Meeting ofShareholders, which is incorporated by reference.

 

**PART IV**

 

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

 

1.               Consolidated Financial Statements:

 

Management Report on Internal Controls **—**For the year ended Dec. 31, 2008.

Report of Independent Registered PublicAccounting Firm **—**For the yearsended Dec. 31, 2008, 2007 and 2006.

Consolidated Statements of Income **—**For the threeyears ended Dec. 31, 2008, 2007 and 2006.

Consolidated Statements of Cash Flows **—** For the three years ended Dec. 31,2008, 2007 and 2006.

Consolidated Balance Sheets **—**As of Dec. 31, 2008 and 2007.

 

2.               Schedule II **—**Valuation and Qualifying Accounts andReserves for the years ended Dec. 31, 2008, 2007 and 2006.

 

3.               Exhibits

 

----

*Indicates incorporation by reference

+Executive Compensation Arrangements andBenefit Plans 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 Northern States Power Co. (a Minnesota  corporation) (Exhibit 3.02 to Form 10-12G (file no. 000-31709)  dated Oct. 5, 2000).                                                                                                                                                                                                           |
| 3.03* |   | By-Laws of Northern States Power Co. 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 Northern States Power Co. (a Minnesota corporation) to  Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to  Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034).  Supplemental Indentures between NSP-Minnesota and said Trustee, , dated as  follows: |
| 4.02* |   | Oct. 1, 1992 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated Oct. 13, 1992).                                                                                                                                                                                                                                                           |
| 4.03* |   | April 1, 1993 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated March 30, 1993).                                                                                                                                                                                                                                                         |
| 4.04* |   | Dec. 1, 1993 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated Dec. 7, 1993).                                                                                                                                                                                                                                                            |
| 4.05* |   | June 1, 1995 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated June 28, 1995).                                                                                                                                                                                                                                                           |
| 4.06* |   | March 1, 1998 (Exhibit 4.01 to  Form 8-K (file no. 001-03034) dated March 11, 1998).                                                                                                                                                                                                                                                         |
| 4.07* |   | May 1, 1999 (Exhibit 4.49 to NSP-Minnesota  Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).                                                                                                                                                                                                                                            |
| 4.08* |   | June 1, 2000 (Exhibit 4.50 to  NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).                                                                                                                                                                                                                                           |
| 4.09* |   | 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).                                                                                                                                                                                           |
| 4.10* |   | Trust Indenture, dated July 1, 1999, between  Northern States Power Co. (a Minnesota corporation) and                                                                                                                                                                                                                                                       |

 

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|         |   | Norwest Bank Minnesota, National Association, as  Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no.  001-03034) dated July 21, 1999).                                                                                                                                                                                                       |
|---------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.11*   |   | Supplemental Trust Indenture, dated July 15,  1999, between Northern States Power Co. (a Minnesota corporation) and Norwest  Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to  NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).                                                                              |
| 4.12*   |   | Supplemental Trust Indenture, dated Aug. 18,  2000, supplemental to the Indenture dated July 1, 1999, among Xcel  Energy, Northern States Power Co. (a Minnesota corporation) and Wells Fargo  Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to  NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).     |
| 4.13*   |   | Supplemental Trust Indenture dated June 1,  2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1,  1988, between Northern States Power Co. (a Minnesota Corporation) and BNY  Midwest Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q  (file no. 000-31387) dated Sept. 30, 2002).                                 |
| 4.14*   |   | Supplemental Trust Indenture dated July 1,  2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1,  1988, between Northern States Power Co. (a Minnesota Corporation) and BNY  Midwest Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q  (file no. 000-31387) dated Sept. 30, 2002).                                 |
| 4.15*   |   | Supplemental Trust Indenture dated July 1,  2002, supplemental to the Indenture dated July 1, 1999, between Northern  States Power Co. (a Minnesota Corporation) and Wells Fargo Bank Minnesota,  National Association, as trustee (Exhibit 4.01 to Form 8-K (file  no. 000-31709) dated July 8, 2002).                                    |
| 4.16*   |   | Supplemental Trust Indenture dated Aug. 1,  2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1,  1988, between Northern States Power Co. (a Minnesota Corporation) and BNY  Midwest Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K  (file no. 001-31387) dated Aug. 22, 2002).                              |
| 4.17*   |   | Supplemental Trust Indenture dated Aug. 1, 2003  between Northern States Power Co. (a Minnesota corporation) and BNY Midwest  Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1,  1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6,  2003).                                                            |
| 4.18*   |   | Supplemental Trust Indenture dated May 1, 2003  between Northern States Power Co. (a Minnesota corporation) and BNY Midwest  Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1,  1988. (Exhibit 4.73 to Form 10-K (file no. 001-03034) for the year  ended Dec. 31, 2003).                                             |
| 4.19*   |   | 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). |
| 4.20*   |   | 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).     |
| 4.21*   |   | $500,000,000 Credit Agreement dated Dec. 14,  2006 between NSP-Minnesota and various lenders (Exhibit 99.01 to  Form 8-K of Xcel Energy (file no. 001-3034) dated Dec. 14, 2006).                                                                                                                                                               |
| 4.22*   |   | 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).                                                                                                                                    |
| 4.23*   |   | Supplemental Indenture dated March 1, 2008  between Northern States Power Company and The Bank of New York Trust Company,  N.A., as successor trustee (Exhibit 4.01 to Form 8-K (file no.  001-31387) dated March 11, 2008.                                                                                                                     |
| 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 NSP-Minnesota Form 10-Q (file  no. 001-03034) for the quarter ended March 31, 1998).                                                                                                                                                                         |
| 10.04*+ |   | New Century Energies Omnibus Incentive Plan,  (Exhibit A to New Century Energies, Inc. Form DEF 14A (file  no. 001-12927) filed March 26, 1998).                                                                                                                                                                                                |
| 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).                                                                                                                                                  |
| 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                                                                                                                                                                                                                                                       |

 

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|         |   | Form U5B (file no. 001-03034) dated  Nov. 16, 2000).                                                                                                                                                                                                                                                                                                                 |
|---------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.10*+ |   | Employment Agreement, effective Dec. 15, 1997,  between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25  to Xcel Energy Form 10-K (file no. 001-03034) for the year ended  Dec. 31, 2004).                                                                                                                                                 |
| 10.11*+ |   | Xcel Energy Executive Annual Incentive Award Plan  Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy  Form 10-Q (file no. 001-03034) dated June 30, 2005).                                                                                                                                                                                  |
| 10.12*+ |   | 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).                                                                                                                                                                                            |
| 10.13*+ |   | 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).                                                                                                                                                                                                |
| 10.14*+ |   | 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).                                                                                                                                                                                            |
| 10.15*+ |   | Xcel Energy Omnibus 2005 Incentive Plan (Appendix B  to Exhibit 14A, Definitive Proxy Statement dated April 11, 2005).                                                                                                                                                                                                                                               |
| 10.16*+ |   | Xcel Energy Executive Annual Incentive Award Plan  (Appendix C to Exhibit 14A, Definitive Proxy Statement dated  April 11, 2005).                                                                                                                                                                                                                                    |
| 10.17*+ |   | 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).                                                                                                                                                               |
| 10.18*+ |   | Agreement dated  March 20, 2007 between Mr. Gary R. Johnson and Xcel Energy Inc.  (Exhibit 10.1 to Form 8-K (file no. 001-03034) dated March 20,  2007).                                                                                                                                                                                              |
| 10.19*+ |   | Letter dated Sept. 19,  2007, from Xcel Energy Inc. to the U.S. Department of Justice (DOJ)  submitting its offer to settle the COLI tax dispute and Letter dated Sept.  21, 2007 from the DOJ to Xcel Energy Inc. accepting the settlement offer.  (Exhibit 10.1 to Form 10-Q (file no. 001-03034) for the quarter  ended Sept. 30, 2007).                          |
| 10.20*+ |   | Amendment Four to  Employment Agreement between Xcel Energy Inc. and Paul Bonavia  (Exhibit 10.02 to Xcel Energy’s Form 8-K (file no. 001-03034) dated  May 23, 2007).                                                                                                                                                                                     |
| 10.21*+ |   | 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).                                                                                                                                           |
| 10.22*+ |   | 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).                                                                                                                                                              |
| 10.23*  |   | Facilities Agreement, dated July 21, 1976,  between Northern States Power Co. (a Minnesota corporation) and the Manitoba  Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06I to file no. 2-54310).                                                                                                                             |
| 10.24*  |   | Transactions Agreement, dated July 21, 1976,  between Northern States Power Co. (a Minnesota corporation) and the Manitoba  Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06J to file no. 2-54310).                                                                                                                           |
| 10.25*  |   | Coordinating Agreement, dated July 21, 1976,  between Northern States Power Co. (a Minnesota corporation) and the Manitoba  Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06K to file no. 2-54310).                                                                                                                           |
| 10.26*  |   | Ownership and Operating Agreement, dated  March 11, 1982, between Northern States Power Co. (a Minnesota  corporation), Southern Minnesota Municipal Power Agency and United Minnesota  Municipal Power Agency concerning Sherburne County Generating Unit  No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept.  30, 1994, file no. 001-03034). |
| 10.27*  |   | Power Agreement, dated June 14, 1984, between  Northern States Power Co. (a Minnesota corporation) and the Manitoba  Hydro-Electric Board, extending the agreement scheduled to terminate on  April 30, 1993, to April 30, 2005. (Exhibit 10.03 to  Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).                              |
| 10.28*  |   | Power Agreement, dated August 1988, between  Northern States Power Co. (a Minnesota corporation) and Minnkota Power Co.  (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).                                                                                                                                                                    |
| 10.29*  |   | Amended agreement for the sale of thermal energy  dated Jan. 1, 1983 between NRG Energy (formerly known as Norenco Corp.)  and Northern States Power Co. (a Minnesota corporation) and Norenco Corp.  (Exhibit 10.33 to NRG’s Registration on Form S-1, file no.  333-35096).                                                                              |
| 10.30*  |   | Operations and maintenance agreement dated Nov. 1,  1996 between NRG Energy and Northern States Power Co. (a Minnesota  corporation). (Exhibit 10.34 to NRG’s Registration on Form S-1,  file no. 333-35096).                                                                                                                                              |
| 10.31*  |   | Amended Agreement for the sale of thermal energy and  wood byproduct dated Dec. 1, 1986 between Northern States Power Co. (a  Minnesota corporation) and Norenco Corp. (Exhibit 10.36 to NRG’s  Registration on Form S-1, file no. 333-35096).                                                                                                             |
| 10.32*  |   | Restated Interchange Agreement dated Jan. 16,  2001 between Northern States Power Co. (a Wisconsin corporation) and Northern  States Power Co. (a Minnesota corporation) (Exhibit 10.01 to  NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).                                                                                             |
| 10.33*  |   | 500 megawatt System Participation Power Sale  Agreement dated July 30, 2002 between Northern States                                                                                                                                                                                                                                                                       |

 

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|       |   | Power Co. (a Minnesota corporation) and the Manitoba  Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file  no. 001-31387) dated March 25, 2003). |
|-------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 12.01 |   | Statement of Computation of Ratio of Earnings to  Fixed Charges.                                                                                                                |
| 23.01 |   | Consent of Independent Registered Public Accounting  Firm.                                                                                                                      |
| 31.01 |   | Principal Executive Officer’s certification pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of  the Sarbanes-Oxley Act of 2002.          |
| 31.02 |   | Principal Financial Officer’s certification pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of  the Sarbanes-Oxley Act of 2002.          |
| 32.01 |   | Certification pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.                                             |
| 99.01 |   | Statement pursuant to Private Securities Litigation  Reform Act of 1995.                                                                                                        |

 

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# **SCHEDULE II**

#  

**NSP-MINNESOTA AND SUBSIDIARIES****VALUATION AND QUALIFYING ACCOUNTSYears Ended Dec. 31, 2008, 2007 and 2006***(amounts in thousands of dollars)*

 
| ** **                            | ** ** | ** **                                     | ** ** | **Additions**                                 | ** ** | ** **                                    | ** ** | ** **                        | ** ** |
|---------------------------------------|------------|------------------------------------------------|------------|-----------------------------------------------|------------|-----------------------------------------------|------------|-----------------------------------|------------|
| ** **                            | ** ** | **Balance at  beginning  of period** | ** ** | **Charged  to costs and  expenses** | ** ** | **Charged  to other  accounts (1)** | ** ** | **Deductions  from  reserves(2)** | ** ** | **Balance  at end  of period** | ** ** |
| Reserve deducted from related assets: |       |                                           |       |                                          |       |                                          |       |                              |       |   |   |
| Allowance for bad debts:              |       |                                           |       |                                          |       |                                          |       |                              |       |   |   |
| 2008                                  |       | $                                              | 20,103     |                                          | $          | 25,506                                        |       | $                                 | 6,113      |   | $ | 26,023 |   | $ | 25,699 |   |
| 2007                                  |       | 13,408                                         |       | 23,336                                        |       | 5,853                                         |       | 22,494                            |       | 20,103 |   |
| 2006                                  |       | 10,128                                         |       | 19,972                                        |       | 6,102                                         |       | 22,794                            |       | 13,408 |   |
|                                       |            |                                                |            |                                               |            |                                               |            |                                   |            |  |  |  |  |  |  |  |

 

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(1)             Recoveryof amounts previously written off

(2)             Principallybad debts written off 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/ BENJAMIN G.S. FOWKE III                                                                                  |
|                   | Benjamin G.S. Fowke III  Executive Vice President and Chief Financial Officer  (Principal Financial Officer) |
|                   |                                                                                                         |
| **March 2, 2009** | ** **                                                                                                   |

 

Pursuant tothe requirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on March 2, 2009.

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

 

 

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

 

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

 

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